Eversource Energy (ES, NYSE)
Industry: Utilities - Regulated Electric
Annual report, fiscal year 2022


## 2022 Annual Report






Diluted Earnings
Per Share (Non-GAAP) \( ^{(1)} \) 



Dividends Paid
Per Share



(1) Diluted Earnings per Share for 2022 (Non-GAAP) was adjusted to exclude an after-tax charge of $0.04 per share related to transaction- and transition-related charges, primarily related to the October 2020 acquisition of the assets of Columbia Gas of Massachusetts. Diluted Earnings per Share for 2021 (Non-GAAP) was adjusted to exclude an after-tax charge of $0.25 per share related to the settlement of multiple regulatory dockets concerning Eversource Energy subsidiary, The Connecticut Light and Power Company, and after-tax transition-related costs of $0.07 per share associated primarily with the aforementioned acquisition. Diluted Earnings per Share (Non-GAAP) for 2020 was adjusted to exclude after-tax acquisition-related costs of $0.09 per share associated with the aforementioned acquisition. Diluted Earnings per Share (Non-GAAP) for 2019 was adjusted to exclude an after-tax impairment charge of $0.64 per share related to the Northern Pass Transmission Project.

## Total Shareholder Return

(Assumes $100 invested on December 31, 2012 with all dividends reinvested)






## Company Profile

Eversource Energy (NYSE:ES), a Fortune 500 and Standard & Poor's 500 energy company based in Connecticut, Massachusetts and New Hampshire, operates New England's largest energy delivery system. Eversource is committed to safety, reliability, environmental leadership and stewardship for its 4.4 million electric, natural gas and water customers.



## Selected Financial Data

(Thousands of dollars, except share information and statistical data)

<table><tr><td></td><td>2022</td><td>2021</td></tr><tr><td>Operating Revenues</td><td>$12,289,336</td><td>$9,863,085</td></tr><tr><td>Net Income Attributable to Common Shares\(</td><td>1,404,875</td><td>1,220,527</td></tr><tr><td>Diluted Earnings per Common Share (GAAP) \)</td><td>4.05</td><td>$3.54</td></tr><tr><td>Diluted Earnings per Common Share (Non-GAAP) (1) \)</td><td>4.09</td><td>$3.86</td></tr><tr><td>Diluted Common Shares Outstanding (Weighted Average)</td><td>347,246,768</td><td>344,631,056</td></tr><tr><td>Dividends Paid per Share</td><td>$2.55</td><td>$2.41</td></tr><tr><td>Electric Customers (As of Year End)</td><td>3,288,101</td><td>3,261,518</td></tr><tr><td>Natural Gas Customers (As of Year End)</td><td>888,943</td><td>886,510</td></tr><tr><td>Water Customers (As of Year End)</td><td>237,258</td><td>226,410</td></tr><tr><td>Investments in Property, Plant and Equipment</td><td>$3,441,852</td><td>$3,175,080</td></tr><tr><td>Property, Plant and Equipment, Net (As of Year End)</td><td>$36,112,820</td><td>$33,377,650</td></tr><tr><td>Market Capitalization (As of Year End)</td><td>$29,213,533</td><td>$31,333,803</td></tr><tr><td>Share Price (As of Year End)</td><td>$83.84</td><td>$90.98</td></tr></table>

(1) Diluted Earnings per Common Share for 2022 (Non-GAAP) was adjusted to exclude an after-tax charge of $0.04 per share related to transaction- and transition-related charges, primarily related to the October 2020 acquisition of the assets of Columbia Gas of Massachusetts. Diluted Earnings per Share for 2021 (Non-GAAP) was adjusted to exclude an after-tax charge of $0.25 per share related to the settlement of multiple regulatory dockets concerning Eversource Energy subsidiary, The Connecticut Light and Power Company, and after-tax transition-related costs of $0.07 per share associated primarily with the aforementioned acquisition. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of Operations, in the accompanying Form 10-K for a reconciliation to GAAP.



# Chairman and CEO Annual Report Letter

The 9,600 employees of Eversource Energy excelled on many fronts in 2022, providing safe and reliable delivery of energy and water, strong customer service, best-in-the-nation energy efficiency programs, and highly effective storm response to our 4.4 million customers in Connecticut, Massachusetts, and New Hampshire. Our reliability remained in the top decile among our electric utility peers, while we continued to enhance our support for our region’s clean energy future. I’m honored to share an overview of our team’s great success.



We executed well on our operating and capital investment plans throughout the year. We invested a record $3.8 billion in our core businesses in 2022, compared with investments of approximately $3.5 billion in 2021 and $3 billion in 2020. Those increased investments made our systems more reliable, addressed challenges related to climate change, enabled additional homes and businesses to connect to us, and allowed customers to more easily interact with us when and how they chose.

Our earnings per share from recurring operations grew approximately 6 percent from $3.86 in 2021 to $4.09 in 2022. In 2022, we also raised our dividend by 5.8 percent to an annualized level of $2.55 per share, and in February 2023, our Board of Trustees approved a 5.9 percent increase to an annualized rate of $2.70 per share. Our credit ratings continue to be among the highest in the industry with an “A” level rating and positive outlook at Standard and Poor’s. 2022 was a difficult year for the markets, primarily due to sharply rising interest rates, but utility stocks generally fared better than the market as a whole. Eversource’s total return of negative 5 percent was 13 percentage points better than the S&P 500’s.

On the regulatory front, we achieved several important milestones. These included a positive resolution of our NSTAR Electric rate review in Massachusetts, as well as approvals by the Massachusetts Department of Public Utilities of our proposals to implement advanced metering infrastructure (AMI) and a new methodology to resolve a bottleneck that had dramatically slowed the development of third-party solar generation in the state. On the federal level, the Federal Energy Regulatory Commission approved NSTAR Electric’s Settlement Transmission Support Agreement with the Park City Wind project, which sets forth the terms by which NSTAR Electric will support Park City Wind’s interconnection with the regional grid through our Mid-Cape Reliability Project transmission upgrade, a joint effort that will result in customer savings.

Our Aquarion water company provided high-quality service to customers in 2022, despite extreme drought conditions. We have continued to grow our water distribution business through acquisitions, including the completion of the Torrington Water Company acquisition in Connecticut, and have filed with the Massachusetts Department of Public Utilities a request for approval to acquire Pinehills Water Company. We see continued opportunity in water in 2023 and beyond.



Energy supply costs emerged as a major challenge in 2022. Global issues including the war in Ukraine drove up natural gas prices, causing significant increases in the supply portion of customer bills. Additionally, inadequate natural gas pipeline capacity into New England during the winter heating months contributed to an unprecedented spike in electric supply costs this past winter. Eversource has broadened a variety of customer assistance programs, ranging from flexible payment plans to energy efficiency programs and services that help customers lower their energy use. We continue to work with our states on other bill support and relief options for customers.







We achieved several milestones in our work to be a catalyst for clean energy for New England and the Northeast. Our award-winning and innovative battery storage unit in Provincetown, Massachusetts, entered service and, operating as designed, maintained service to thousands of customers during an event that would normally have caused an outage. We began work on a networked geothermal energy pilot in Framingham, Massachusetts, with strong support from the community. We've proposed solar energy projects coupled with storage in Massachusetts, and received approval for additional planned investments to support the growth of electric vehicle charging stations in Massachusetts and New Hampshire.

Our states’ emphasis on electrification as a path to emissions reduction, as well as the continued growth of distributed renewable generation, creates significant opportunities for transmission development. We are working to increase transmission capacity while building all stakeholders’ awareness that the clean energy future will require major network investment as we move forward. In Massachusetts, we proposed six “cluster” projects representing $900 million in combined transmission and distribution investment that will allow 1,000 megawatts of renewable energy to interconnect with our grid. We received approval for the first proposal at the end of 2022.

We expect another source of clean energy — offshore wind — to provide a steadily growing source of energy for the Northeast United States. Our offshore wind joint venture with Ørsted worked effectively to advance our three projects. Construction is well under way on South Fork Wind where in-service is projected for late 2023, while Revolution Wind and Sunrise Wind are moving steadily through the permitting process. However, over the long term, our role in offshore wind may evolve into being of a builder and operator of the transmission network that will bring wind energy onto the New England grid, rather than as an owner of the wind turbines. In May 2022, we commenced a strategic asset review of our offshore wind assets, a review that could result in the divestiture of those investments.



We continue to be an industry leader in sustainability; environmental, social and governance (ESG) areas; and diversity and inclusion. We made progress on our commitment to achieve carbon neutrality from our operations by 2030, reducing emissions in areas such as facility improvements, fleet upgrades, and replacement of older natural gas pipelines. Further, we committed to establishing a science-based target — a best practice that extends our commitment to emissions reductions and places us among industry leaders. We maintained strong ratings from leading ESG evaluators and published a comprehensive Sustainability Report, as well as a new Diversity, Equity and Inclusion report. Together, these reports are generating praise for Eversource as one of the most transparent companies in corporate America. Finally, we deepened our commitment to equity by creating tools, guidelines, and policies to help us incorporate equity into all of our actions and decisions.

Eversource maintained its emphasis on effective storm restoration and timely, informative storm-related communications with our stakeholders. We successfully responded to four major and nine minor activations of our Emergency Response Plans in 2022 across our three states. In late December, our employees worked through the holidays to bring customers back to service.

We strongly supported our communities throughout the year, including through our signature events—the Eversource Walk & 5K for New Hampshire Easterseals, the Eversource Walk for Boston Children’s Hospital, the Massachusetts General Cancer Center/Eversource Everyday Amazing Race, and the Eversource Hartford Marathon. Our employees also returned to support in-person volunteer opportunities as COVID-related restrictions were lifted, donating more than 27,000 volunteer hours at more than 120 events.

We were proud to receive independent national recognition for excellence in a variety of areas, particularly our ESG performance. These honors included:

• Newsweek’s list of Most Responsible Companies, where we again ranked as the #1 utility.

• The JUST Capital and CNBC list of Most JUST Companies, a ranking of most responsible publicly traded companies.

• Investor’s Business Daily magazine’s list of 100 Best Environmental, Social and Governance (ESG) Companies.
• The Bloomberg Gender Equality Index, which recognizes companies that have shown their commitment to advancing women’s equality in the workplace and transparency in gender reporting.

• Multiple #1 and #2 rankings in several categories of Institutional Investor’s annual investor rankings of utilities, based on a poll of institutional investors and analysts.

I want to close my report by thanking Jim Judge, who retired as Executive Chairman on December 31, 2022, following a long and successful career that included service as Eversource’s Chairman, President, and CEO. I appreciate Jim’s many contributions to the success of our company, as well as his friendship and mentorship.



Joe Nolan
Chairman, President, and Chief Executive Officer



# EVERSOURCE
ENERGY

# 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, 2022

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:

<table><tr><td>Title of each class</td><td>Trading Symbol(s)</td><td>Name of each exchange on which registered</td></tr><tr><td>Common Shares, $5.00 par value per share</td><td>ES</td><td>New York Stock Exchange</td></tr><tr><td>Securities registered pursuant to Section 12(g) of the Act:</td><td></td><td></td></tr><tr><td>Registrant</td><td>Title of Class</td><td></td></tr></table>

<table><tr><td>The Connecticut Light and Power Company</td><td>Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are outstanding:</td></tr><tr><td></td><td>$1.90</td></tr><tr><td></td><td>Series of 1947</td></tr><tr><td></td><td>Series of 1947</td></tr><tr><td></td><td>Series of</td></tr></table>

<table><tr><td>NSTAR Electric Company</td><td>Preferred Stock, par value $100.00 per share, issuable in series, of which the following series are outstanding:</td></tr><tr><td></td><td>4.25%</td></tr><tr><td></td><td>Series of 1956</td></tr><tr><td></td><td>4.78%</td></tr></table>

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

<table><tr><td></td><td>Yes</td><td>No</td></tr><tr><td></td><td>☒</td><td>☐</td></tr></table>

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

<table><tr><td></td><td>Yes</td><td>No</td></tr><tr><td></td><td>☐</td><td>☒</td></tr></table>

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.

<table><tr><td></td><td>Yes</td><td>No</td></tr><tr><td></td><td>☒</td><td>☐</td></tr></table>

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).

<table><tr><td></td><td>Yes</td><td>No</td></tr><tr><td></td><td>☒</td><td>☐</td></tr></table>

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.

<table><tr><td>Eversource Energy</td><td>Large accelerated filer</td><td>Accelerated filer</td><td>☐</td><td>Non-accelerated filer</td><td>☐</td><td>Smaller reporting company</td><td>☐</td><td>Emerging growth company</td><td>☐</td></tr><tr><td>The Connecticut Light and Power Company</td><td>Large accelerated filer</td><td>☐</td><td>Accelerated filer</td><td>☐</td><td>Non-accelerated filer</td><td>☒</td><td>Smaller reporting company</td><td>☐</td><td>Emerging growth company</td></tr><tr><td>NSTAR Electric Company</td><td>Large accelerated filer</td><td>☐</td><td>Accelerated filer</td><td>☐</td><td>Non-accelerated filer</td><td>☒</td><td>Smaller reporting company</td><td>☐</td><td>Emerging growth company</td></tr><tr><td>Public Service Company of New Hampshire</td><td>Large accelerated filer</td><td>☐</td><td>Accelerated filer</td><td>☐</td><td>Non-accelerated filer</td><td>☒</td><td>Smaller reporting company</td><td>☐</td><td>Emerging growth company</td></tr></table>



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):

<table><tr><td></td><td>Yes</td><td>No</td></tr><tr><td>Eversource Energy</td><td>☐</td><td>☒</td></tr><tr><td>The Connecticut Light and Power Company</td><td>☐</td><td>☒</td></tr><tr><td>NSTAR Electric Company</td><td>☐</td><td>☒</td></tr><tr><td>Public Service Company of New Hampshire</td><td>☐</td><td>☒</td></tr></table>

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, 2022) was $29,211,450,455 based on a closing market price of $84.47 per share for the 345,820,415 common shares outstanding held by non-affiliates on June 30, 2022.

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

<table><tr><td>Company - Class of Stock</td><td>Outstanding as of January 31, 2023</td></tr><tr><td>Eversource Energy</td><td></td></tr><tr><td>Common Shares, $5.00 par value</td><td>348,483,425 shares</td></tr><tr><td>The Connecticut Light and Power Company</td><td></td></tr><tr><td>Common Stock, $10.00 par value</td><td>6,035,205 shares</td></tr><tr><td>NSTAR Electric Company</td><td></td></tr><tr><td>Common Stock, $1.00 par value</td><td>200 shares</td></tr><tr><td>Public Service Company of New Hampshire</td><td></td></tr><tr><td>Common Stock, $1.00 par value</td><td>301 shares</td></tr></table>

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.

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 2021 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 3, 2023, 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:

<table><tr><td colspan="2">Current or former Eversource Energy companies, segments or investments:</td></tr><tr><td>Eversource, ES or the Company</td><td>Eversource Energy and subsidiaries</td></tr><tr><td>Eversource parent or ES parent</td><td>Eversource Energy, a public utility holding company</td></tr><tr><td>ES parent and other companies</td><td>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&#x27;s equity ownership interests that are not consolidated</td></tr><tr><td>CL&amp;P</td><td>The Connecticut Light and Power Company</td></tr><tr><td>NSTAR Electric</td><td>NSTAR Electric Company</td></tr><tr><td>PSNH</td><td>Public Service Company of New Hampshire</td></tr><tr><td>PSNH Funding</td><td>PSNH Funding LLC 3, a bankruptcy remote, special purpose, wholly-owned subsidiary of PSNH</td></tr><tr><td>NSTAR Gas</td><td>NSTAR Gas Company</td></tr><tr><td>EGMA</td><td>Eversource Gas Company of Massachusetts</td></tr><tr><td>Yankee Gas</td><td>Yankee Gas Services Company</td></tr><tr><td>Aquarion</td><td>Aquarion Company and its subsidiaries</td></tr><tr><td>HEEC</td><td>Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric</td></tr><tr><td>Eversource Service</td><td>Eversource Energy Service Company</td></tr><tr><td>North East Offshore</td><td>North East Offshore, LLC, an offshore wind business being developed jointly by Eversource and Denmark-based Ørsted</td></tr><tr><td>CYAPC</td><td>Connecticut Yankee Atomic Power Company</td></tr><tr><td>MYAPC</td><td>Maine Yankee Atomic Power Company</td></tr><tr><td>YAEC</td><td>Yankee Atomic Electric Company</td></tr><tr><td>Yankee Companies</td><td>CYAPC, YAEC and MYAPC</td></tr><tr><td>Regulated companies</td><td>The Eversource regulated companies are comprised of the electric distribution and transmission businesses of CL&amp;P, NSTAR Electric and PSNH, the natural gas distribution businesses of Yankee Gas, NSTAR Gas and EGMA, Aquarion&#x27;s water distribution businesses, and the solar power facilities of NSTAR Electric</td></tr><tr><td colspan="2">Regulators and Government Agencies:</td></tr><tr><td>BOEM</td><td>U.S. Bureau of Ocean Energy Management</td></tr><tr><td>DEEP</td><td>Connecticut Department of Energy and Environmental Protection</td></tr><tr><td>DOE</td><td>U.S. Department of Energy</td></tr><tr><td>DOER</td><td>Massachusetts Department of Energy Resources</td></tr><tr><td>DPU</td><td>Massachusetts Department of Public Utilities</td></tr><tr><td>EPA</td><td>U.S. Environmental Protection Agency</td></tr><tr><td>FERC</td><td>Federal Energy Regulatory Commission</td></tr><tr><td>ISO-NE</td><td>ISO New England, Inc., the New England Independent System Operator</td></tr><tr><td>MA DEP</td><td>Massachusetts Department of Environmental Protection</td></tr><tr><td>NHPUC</td><td>New Hampshire Public Utilities Commission</td></tr><tr><td>PURA</td><td>Connecticut Public Utilities Regulatory Authority</td></tr><tr><td>SEC</td><td>U.S. Securities and Exchange Commission</td></tr><tr><td colspan="2">Other Terms and Abbreviations:</td></tr><tr><td>ADIT</td><td>Accumulated Deferred Income Taxes</td></tr><tr><td>AFUDC</td><td>Allowance For Funds Used During Construction</td></tr><tr><td>AOCI</td><td>Accumulated Other Comprehensive Income</td></tr><tr><td>ARO</td><td>Asset Retirement Obligation</td></tr><tr><td>Bcf</td><td>Billion cubic feet</td></tr><tr><td>CfD</td><td>Contract for Differences</td></tr><tr><td>CWIP</td><td>Construction Work in Progress</td></tr><tr><td>EDC</td><td>Electric distribution company</td></tr><tr><td>EDIT</td><td>Excess Deferred Income Taxes</td></tr><tr><td>EPS</td><td>Earnings Per Share</td></tr><tr><td>ERISA</td><td>Employee Retirement Income Security Act of 1974</td></tr><tr><td>ESOP</td><td>Employee Stock Ownership Plan</td></tr><tr><td>Eversource 2021 Form 10-K</td><td>The Eversource Energy and Subsidiaries 2021 combined Annual Report on Form 10-K as filed with the SEC</td></tr></table>



<table><tr><td>Fitch</td><td>Fitch Ratings, Inc.</td></tr><tr><td>FMCC</td><td>Federally Mandated Congestion Charge</td></tr><tr><td>GAAP</td><td>Accounting principles generally accepted in the United States of America</td></tr><tr><td>GWh</td><td>Gigawatt-Hours</td></tr><tr><td>IPP</td><td>Independent Power Producers</td></tr><tr><td>ISO-NE Tariff</td><td>ISO-NE FERC Transmission, Markets and Services Tariff</td></tr><tr><td>kV</td><td>Kilovolt</td></tr><tr><td>kVa</td><td>Kilovolt-ampere</td></tr><tr><td>kW</td><td>Kilowatt (equal to one thousand watts)</td></tr><tr><td>LNG</td><td>Liquefied natural gas</td></tr><tr><td>LPG</td><td>Liquefied petroleum gas</td></tr><tr><td>LRS</td><td>Supplier of last resort service</td></tr><tr><td>MG</td><td>Million gallons</td></tr><tr><td>MGP</td><td>Manufactured Gas Plant</td></tr><tr><td>MMBtu</td><td>One million British thermal units</td></tr><tr><td>MMcf</td><td>Million cubic feet</td></tr><tr><td>Moody&#x27;s</td><td>Moody&#x27;s Investors Services, Inc.</td></tr><tr><td>MW</td><td>Megawatt</td></tr><tr><td>MWh</td><td>Megawatt-Hours</td></tr><tr><td>NETOs</td><td>New England Transmission Owners (including Eversource, National Grid and Avangrid)</td></tr><tr><td>OCI</td><td>Other Comprehensive Income/(Loss)</td></tr><tr><td>PAM</td><td>Pension and PBOP Rate Adjustment Mechanism</td></tr><tr><td>PBOP</td><td>Postretirement Benefits Other Than Pension</td></tr><tr><td>PBOP Plan</td><td>Postretirement Benefits Other Than Pension Plan</td></tr><tr><td>Pension Plan</td><td>Single uniform noncontributory defined benefit retirement plan</td></tr><tr><td>PPA</td><td>Power purchase agreement</td></tr><tr><td>RECs</td><td>Renewable Energy Certificates</td></tr><tr><td>Regulatory ROE</td><td>The average cost of capital method for calculating the return on equity related to the distribution business segment excluding the wholesale transmission segment</td></tr><tr><td>ROE</td><td>Return on Equity</td></tr><tr><td>RRBs</td><td>Rate Reduction Bonds or Rate Reduction Certificates</td></tr><tr><td>RSUs</td><td>Restricted share units</td></tr><tr><td>S&amp;P</td><td>Standard &amp; Poor&#x27;s Financial Services LLC</td></tr><tr><td>SERP</td><td>Supplemental Executive Retirement Plans and non-qualified defined benefit retirement plans</td></tr><tr><td>SS</td><td>Standard service</td></tr><tr><td>UI</td><td>The United Illuminating Company</td></tr><tr><td>VIE</td><td>Variable Interest Entity</td></tr></table>



# EVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

## 2022 FORM 10-K ANNUAL REPORT

## TABLE OF CONTENTS

PART I
Item 1. Business 2
Item 1A. Risk Factors 14
Item 1B. Unresolved Staff Comments 20
Item 2. Properties 20
Item 3. Legal Proceedings 22
Item 4. Mine Safety Disclosures 22
Information About Our Executive Officers 23
PART II
Item 5. Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 23
Item 6. Removed and Reserved 24
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 25
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 46
Item 8. Financial Statements and Supplementary Data 47
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 103
Item 9A. Controls and Procedures 103
Item 9B. Other Information 103
PART III
Item 10. Directors, Executive Officers and Corporate Governance 103
Item 11. Executive Compensation 104
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 104
Item 13. Certain Relationships and Related Transactions, and Director Independence 105
Item 14. Principal Accountant Fees and Services 105
PART IV
Item 15. Exhibits and Financial Statement Schedules 105
Item 16. Form 10-K Summary 105
Signatures E-5



# 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 the Private Securities Litigation Reform Act of 1995. 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," "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,

• 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 updated as necessary, 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.



# 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, 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 Energy'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 Energy, 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 Energy. Eversource Energy has four reportable segments: electric distribution, electric transmission, natural gas distribution and water distribution. These segments represent substantially all of Eversource Energy's total consolidated revenues. CL&P, NSTAR Electric and PSNH do not report separate business segments.

Eversource Energy also has an offshore wind business, which includes a 50 percent ownership interest in offshore wind projects that are being developed and constructed through a joint and equal partnership with Ørsted.

## ELECTRIC DISTRIBUTION SEGMENT

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

## ELECTRIC DISTRIBUTION – CONNECTICUT – THE CONNECTICUT LIGHT AND POWER COMPANY

CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2022, CL&P furnished retail franchise electric service to approximately 1.28 million customers in 149 cities and towns in Connecticut, covering an area of approximately 4,400 square miles. 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.

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: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel, Office of the Attorney General and the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory proceedings initiated by PURA. PURA approved the settlement agreement on October 27, 2021. In accordance with the settlement agreement, CL&P agreed that its current base distribution rates shall be frozen, subject to certain customer credits, until no earlier than January 1, 2024. The rate freeze applies 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 does not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings, either currently pending or that may be



initiated during the rate freeze period, that may place additional obligations on CL&P. The approval of the settlement agreement satisfies 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.

## 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 2022, 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 14 percent being on competitive supply, while 86 percent remain with SS or LRS. Because this customer migration is only for 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 80 percent of its SS load for the first half of 2023 and will self-manage the remaining 20 percent of the load obligation through the ISO-NE wholesale markets. For the second half of 2023, CL&P has 20 percent of its SS load under full requirements supply contracts and intends to purchase an additional 80 percent of full requirements. None of the SS load for 2024 has been procured. CL&P was unable to obtain a full requirements supply contract for its LRS load through March 2023 and will self-manage the LRS load through ISO-NE wholesale markets. CL&P intends to purchase 100 percent of full requirements for LRS for the remainder of 2023, but is prepared to self-manage the LRS load if CL&P is 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, 2022, NSTAR Electric furnished retail franchise electric service to approximately 1.47 million customers in 140 cities and towns in eastern and western Massachusetts, including Boston, Cape Cod, Martha's Vineyard and the greater Springfield metropolitan area, covering an aggregate area of approximately 3,200 square miles.

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.

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 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 performance-based ratemaking (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 2022 performance as the company achieved results at or above target for all of its SQ metrics in 2022.

## Sources and Availability of Electric Power Supply

As noted above, NSTAR Electric does not own any 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 35 percent of its residential and 25 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 11 percent of its large C&I customers every three months.

During 2022, 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 operating income of NSTAR Electric.

## 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, 2022, PSNH furnished retail franchise electric service to approximately 535,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles. 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 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.

- 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.

As approved by the NHPUC, PSNH has signed long-term commitments for the purchase of energy from renewable energy facilities.

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.

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. 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 is being collected over the remainder of the rate year (November 1, 2022 – July 31, 2023).

## 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 81 percent of its residential and small C&I customers and for 17 percent of its large C&I customers.

During 2022, PSNH supplied approximately 48 percent of its customer load at default energy service rates while the other 52 percent of its customer load had migrated to competitive energy suppliers. Because this customer migration is only for 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 2022, our estimated transmission rate base was approximately $9.2 billion, including approximately $4.0 billion at CL&P, $3.7 billion at NSTAR Electric, and $1.5 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 its 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 has 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 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.

## NATURAL GAS DISTRIBUTION SEGMENT

On October 9, 2020, Eversource acquired certain assets and liabilities that comprised the NiSource Inc. (NiSource) natural gas distribution business in Massachusetts, which was previously doing business as Columbia Gas of Massachusetts (CMA), pursuant to an asset purchase agreement (the Agreement) entered into on February 26, 2020 between Eversource and NiSource. The cash purchase price was $1.1 billion, plus a working capital amount of $68.6 million, as finalized in 2021. The natural gas distribution assets acquired from CMA were assigned to Eversource Gas Company of Massachusetts (EGMA), an indirect wholly-owned subsidiary of Eversource formed in 2020. The LNG assets acquired from CMA were assigned to Hopkinton LNG Corp, also a subsidiary of Eversource.

NSTAR Gas distributes natural gas to approximately 306,000 customers in 52 communities in central and eastern Massachusetts covering 1,104 square miles. EGMA distributes natural gas to approximately 333,000 customers in 65 communities throughout Massachusetts covering 1,206 square miles. Yankee Gas distributes natural gas to approximately 251,000 customers in 74 cities and towns in Connecticut covering 2,632 square miles. Total throughput (sales and transportation) in 2022 was approximately 66.1 Bcf for NSTAR Gas, 54.3 Bcf for EGMA, and 58.4 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 56 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 Energy. 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.

- 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 for new 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 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 performance-based ratemaking plan through November 1, 2030, which includes inflation-based adjustments to annual base distribution amounts effective annually beginning November 1, 2021.

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, 2019, January 1, 2020 and March 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 an SQ charge for their 2022 performance as each achieved results at or above target for all of their SQ metrics in 2022.

## 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. The DPU will consider new policies and structures that would protect customers as Massachusetts works to decarbonize the building sector, potentially recasting the role of LDCs in Massachusetts, which may require significant changes to the LDCs planning processes and business models. At this time, Eversource cannot predict the ultimate outcome of this proceeding and the resulting impact to its natural gas businesses, however 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 Gas System Improvement (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.

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, Eversource appealed the portion of this order pertaining to the deferral of non-firm margin as a reduction to future rate base. Eversource 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 maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases 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 supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply under a firm, competitively bid annual portfolio management contract. In addition to the firm transportation and natural gas storage supplies discussed above, NSTAR Gas utilizes on-system LNG facilities to meet its winter peaking demands. These LNG facilities are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline natural gas 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 maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. EGMA purchases 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. as well as Canada, including the Gulf Coast, Mid-continent region, Appalachian Shale, and Dawn, Ontario supplies to the final delivery points in the EGMA service area. 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 portfolio itself. In addition to the firm transportation and natural gas storage supplies discussed above, EGMA utilizes on-system LNG and LPG facilities to meet its winter peaking demands. These LNG and LPG facilities are located within EGMA's distribution system 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. 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 237,000 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, 2022, 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.

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 133 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 nine 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 a 50 percent ownership interest in North East Offshore, which holds power purchase agreements (PPAs) and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as an undeveloped offshore lease area. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted.

The offshore leases include a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode Island and a separate, adjacent 300 square-mile ocean lease located approximately 25 miles south of the coast of Massachusetts. In aggregate, these ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy.

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, which will be developed 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 have initiated a strategic review of our offshore wind investment portfolio. As part of that review, we are exploring strategic alternatives that could result in a potential sale of all, or part, of our 50 percent interest in our offshore wind partnership with Ørsted. For more information on these



projects and on the strategic review, 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 2022, as well as projected capital expenditures by business, see "Business Development and Capital Expenditures" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

## FINANCING

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

## NUCLEAR FUEL STORAGE

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

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

## OTHER REGULATORY AND ENVIRONMENTAL MATTERS

## General

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

## Renewable Portfolio Standards

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

Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2022, the total RPS obligation was 33.0 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 2022, the RPS and Clean Energy Standard (CES) requirements were 51.3 percent, and will ultimately reach 64.3 percent in 2025. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 5.5 percent and Clean Peak Energy Standards (CPS) of 4.5 percent in 2022. 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 2022, the total RPS obligation was 22.5 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, 2022, 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 $122.6 million, representing 59 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 $112.6 million of the total $122.6 million as of December 31, 2022. MGP costs are recoverable through rates charged to our customers.

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

## Global Climate Change and Greenhouse Gas Emission Issues

We assess 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 2021 climate legislation, in 2022, Massachusetts finalized sub-limits for the transportation, building and electricity sectors, among others, in support of the state’s net zero emissions target by 2050. These state regulations and related policies may introduce risks and opportunities to our businesses if demands for energy or heating change or if investment opportunities for new projects present themselves.

We are continually evaluating 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 result from sea level rise and shifting weather conditions, such as changes in precipitation, extreme heat, more frequent and severe storms, droughts 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 operating facilities.



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.

We have made a corporate commitment to reduce Scope 1 and 2 greenhouse gas emissions from our operations and reach carbon neutrality by 2030. In November 2022, we committed to setting a science-based target within the next two years, which will expand our emission reduction efforts to 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, cutting fugitive emissions of methane and SF6 by replacing leaky natural gas pipes, improving maintenance of electrical equipment, and piloting innovative technologies.

Our business is also transitioning in response to climate change and we are enabling 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, growing and developing our employees. Leaders at all levels strive to create a workplace where our employees are engaged, advocate for the customer, work collaboratively, raise ideas for improvement and focus on delivering a superior customer experience. We build employee engagement through continuous communication, developing talent, fostering teamwork and creating a diverse, equitable and inclusive workplace.

As of December 31, 2022, Eversource Energy employed a total of 9,626 employees, excluding temporary employees, of which 1,444 were employed by CL&P, 1,648 were employed by NSTAR Electric, and 796 were employed by PSNH. In addition, 3,664 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 50 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 13 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 use metrics such as Eversource Corporate Days Away Restricted Time (DART) and Preventable Motor Vehicle events, among others, to monitor safety performance. Our DART safety performance was 1.0 in 2022, 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 great 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 racial and ethnic 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 diversity, equity and 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 with an increased focus on women and minorities in leadership and has DEI goals and initiatives for diversity in leadership promotions and new hires, diverse external hires, diverse candidate slate, key talent, workforce representation, leadership engagement, community support and supplier spends. 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 2022, 61.6% of our external hires were women and/or people of color and 45.1% percent of new hires and promotions into leadership roles were women and/or people of color.

Eversource’s executive leadership team promotes and supports DEI by leading and building diverse, inclusive work teams with high engagement, growing a pipeline of diverse talent, leveraging multiple perspectives to improve customer service, using diverse suppliers, engaging with multicultural organizations in our communities and supporting the work of our DEI council, racial equity task force, business resource groups, and our cross-functional pro-equity advisory team, which developed and began to implement justice and equity training to all employees in 2022.

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 strategy, 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. We are committed to the health, safety and wellness of our employees. We provide competitive compensation and comprehensive benefit packages, including healthcare, life insurance, long-term disability insurance, 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.

Talent Development, Training Programs and Education Opportunities. Strategic workforce plans are developed every year as part of the annual business planning process to identify immediate and long-range needs to ensure that we acquire, develop and retain 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; a rotational associate engineering program; educational and professional development opportunities for employees who are recent college graduates; tuition assistance program; and paid internships and co-ops.

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, we identify critical roles and develop succession plans to ensure we have a capable supply of talent for the future.

Community & Social Impact. Eversource and our employees support many programs, agencies, and not-for-profit organizations that provide economic and community development, the environment, and initiatives that address local, high-priority concerns and needs. Eversource provides donations and other support to community agencies, including significant volunteer hours of our employees.

See Item 11, Executive Compensation, included in this Annual Report on Form 10-K, as well as our 2021 Sustainability Report and our 2021 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, 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.

## 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 and Data Privacy Risks:

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. In the first quarter of 2022, the federal government notified the owners and operators of critical infrastructure that the conflict between Russia and Ukraine has increased the likelihood of a cyberattack on such systems. 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 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.

The unauthorized access to, and the misappropriation of, confidential and proprietary 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 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 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 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.

## Business and Operational Risks:

Strategic development opportunities associated with offshore wind or investment opportunities in electric transmission, distributed generation, or clean-energy opportunities may not be successful, and projects may not commence operation as scheduled or within budget, or be completed, which could have a material adverse effect on our business prospects.

We are pursuing broader strategic development investment opportunities that will benefit the Northeast region related to the development, construction and operation of offshore wind electric generation facilities, and investment opportunities in electric transmission facilities, distributed generation and other clean-energy infrastructure. The states in which we provide service have implemented selection procedures for such new facilities that require the review of competing projects and permit the selection of only those projects that are expected to provide the greatest benefit to customers. Accordingly, our projects may not be selected for construction. The development and construction of projects selected for construction involves numerous significant risks including scheduling delays, increased costs, tax strategies and changes to federal tax laws, federal, state and local permitting and regulatory approval processes, specifically BOEM’s approval processes, new legislation impacting the industry, future legislative or regulatory actions that could result in these projects not being probable of entering the construction phase, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent utilities and other entities, actions of our strategic partners, and capacity factors once projects are placed in operation. Also, supply constraints in New England are leading to historic increases in fuel and commodity costs which may impact our ability to accomplish our strategic objectives.

Our offshore wind partnership’s ability to generate returns from its offshore wind projects will depend on meeting construction schedules, controlling project costs, 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. Additionally, scheduling or permitting delays in offshore wind projects, increases in cost estimates, higher interest rates, changes to tax laws impacting the offshore wind partnership’s ability to monetize tax attributes, or the cancellation of any projects, as well as the other risk factors described above, could result in lower investment returns and, if significant enough, an impairment of the carrying value of our



investment. Such an impairment could have a material adverse effect on our financial position, results of operations, and cash flows, or our future growth opportunities may not be realized as anticipated.

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.

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. We also continue to pursue enhancements to standardize our systems and processes. The global supply chain of goods and services is currently being negatively impacted by several factors, including the geopolitical climate, labor shortages, domestic and international shipping constraints, increased demand, and shortages of raw materials. As a result, we are seeing delivery delays of certain goods. Additionally, the prices for equipment, materials, and contractor services have increased, and may continue to increase. If significant difficulties in the global supply chain cycle or inflationary impacts were to continue or worsen, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.

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 such as fires, explosions, 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, 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.

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.



## 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, such as ice and snow storms, tornadoes, micro-bursts, hurricanes, floods, droughts, 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 or man-made substances. 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.

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.

## 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 and by the FERC. These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters. The FERC also 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 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 prudence 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.

The federal, state and local political and economic environment has had, and may in the future have, an adverse effect on regulatory decisions with negative consequences for 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 their methodologies 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 all electric companies under the jurisdiction of 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.

FERC's policy has encouraged competition for transmission projects, even within existing service territories of electric companies. 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, including the Inflation Reduction Act (IRA) of 2022, as well as the potential tax effects of business decisions could negatively impact our business, results of operations (including our expected project returns from our planned offshore wind facilities), 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, conflict in Russia and Ukraine, and increased customer energy demand, the cost of energy supply in New England has significantly increased. We also may be required to implement rolling blackouts by ISO-New England, 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 bill, 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, and there can be no assurance that we will be able to respond adequately or sufficiently quickly to such actions. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on our financial position, results of operations and cash flows.

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

Our subsidiaries' operations are subject to extensive and increasing federal, state and local environmental statutes, rules and regulations that govern, among other things, water quality, 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.

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.

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.

Our goodwill is recorded at an amount that, 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, 2022, totaled $4.52 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.

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

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



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

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

## Item 1B. Unresolved Staff Comments

We do not have any unresolved SEC staff comments.

## Item 2. Properties

## Transmission and Distribution System

As of December 31, 2022, Eversource and our electric operating subsidiaries owned the following:

<table><tr><td>Eversource</td><td>Electric Distribution</td><td>Electric Transmission</td></tr><tr><td>Number of substations owned</td><td>474</td><td>73</td></tr><tr><td>Transformer capacity (in kVa)</td><td>44,614,960</td><td>19,129,000</td></tr><tr><td>Overhead lines (in circuit miles)</td><td>40,502</td><td>3,984</td></tr><tr><td>Underground lines (in circuit miles)</td><td>18,085</td><td>423</td></tr><tr><td>Capacity range of overhead transmission lines (in kV)</td><td>N/A</td><td>69 to 345</td></tr><tr><td>Capacity range of underground transmission lines (in kV)</td><td>N/A</td><td>69 to 345</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="2">CL&amp;P</td><td colspan="2">NSTAR Electric</td><td colspan="2">PSNH</td></tr><tr><td>Distribution</td><td>Transmission</td><td>Distribution</td><td>Transmission</td><td>Distribution</td><td>Transmission</td></tr><tr><td>Number of substations owned</td><td>175</td><td>20</td><td>176</td><td>31</td><td>123</td><td>22</td></tr><tr><td>Transformer capacity (in kVa)</td><td>21,967,000</td><td>3,184,000</td><td>18,151,360</td><td>11,595,000</td><td>4,496,600</td><td>4,350,000</td></tr><tr><td>Overhead lines (in circuit miles)</td><td>16,717</td><td>1,678</td><td>11,489</td><td>1,252</td><td>12,296</td><td>1,054</td></tr><tr><td>Underground lines (in circuit miles)</td><td>6,839</td><td>143</td><td>9,167</td><td>277</td><td>2,079</td><td>3</td></tr><tr><td>Capacity range of overhead transmission lines (in kV)</td><td>N/A</td><td>69 to 345</td><td>N/A</td><td>69 to 345</td><td>N/A</td><td>115 to 345</td></tr><tr><td>Capacity range of underground transmission lines (in kV)</td><td>N/A</td><td>69 to 345</td><td>N/A</td><td>115 to 345</td><td>N/A</td><td>115</td></tr></table>

<table><tr><td>Underground and overhead line transformers in service</td><td>680,739</td><td>293,512</td><td>217,089</td><td>170,138</td></tr><tr><td>Aggregate capacity (in kVa)</td><td>41,162,476</td><td>16,574,834</td><td>17,389,978</td><td>7,197,664</td></tr></table>

## Electric Generating Plants

As of December 31, 2022, NSTAR Electric owned the following solar power facilities:

<table><tr><td>Type of Plant</td><td>Number of Sites</td><td>Year Installed</td><td>Capacity (kilowatts, dc)</td></tr><tr><td>Solar Fixed Tilt, Photovoltaic</td><td>22</td><td>2010 - 2019</td><td>70,000</td></tr></table>

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

## Natural Gas Distribution System

As of December 31, 2022, NSTAR Gas owned 22 active gate stations, 147 district regulator stations, and approximately 3,324 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, 2022, EGMA owned 14 active gate stations, 191 district regulator stations, and approximately 5,011 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns liquefaction and vaporization plants and above ground storage tanks at four locations throughout Massachusetts with an aggregate storage capacity equivalent to 1.8 Bcf of natural gas. In addition, Hopkinton owns three propane peak shaving plants at three locations throughout Massachusetts with an aggregate storage capacity equivalent to 0.1 Bcf. Combined, these seven plants have an aggregate storage capacity equivalent to 1.9 Bcf of natural gas that is provided to EGMA under contract.



As of December 31, 2022, Yankee Gas owned 28 active gate stations, 200 district regulator stations, and approximately 3,519 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, 2022, NSTAR Gas and EGMA owned 1.0 and 0.5 miles of intrastate transmission natural gas pipeline, respectively.

## 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, 2022, Aquarion owned and operated sources of water supply with a combined yield of approximately 133 million gallons per day; 3,746 miles of transmission and distribution mains; 10 surface water treatment plants; 36 dams; and 116 wellfields.

## Franchises

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

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

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

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

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

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

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

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



Eversource Gas Company of Massachusetts Eversource Gas Company of Massachusetts holds valid franchises to sell natural gas in the areas in which it supplies natural gas service. Generally, Eversource Gas Company of Massachusetts holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Massachusetts 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 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'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's franchises extend to the boundaries of the water systems in the towns of Belmont, Bow, Carroll, and Gilford. Subject to NHPUC's regulations, AWC-NH and Abenaki have the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same.

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

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

## Item 3. Legal Proceedings

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

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

## Item 4. Mine Safety Disclosures

Not applicable.



## INFORMATION ABOUT OUR EXECUTIVE OFFICERS

The following sets forth the executive officers of Eversource Energy as of February 15, 2023. All of Eversource Energy’s officers serve terms of one year and until their successors elected and qualified.

<table><tr><td>Name</td><td>Age</td><td>Title</td></tr><tr><td>Joseph R. Nolan, Jr.</td><td>59</td><td>Chairman of the Board, President, Chief Executive Officer and a Trustee</td></tr><tr><td>John M. Moreira</td><td>61</td><td>Executive Vice President, Chief Financial Officer and Treasurer</td></tr><tr><td>Gregory B. Butler</td><td>65</td><td>Executive Vice President and General Counsel</td></tr><tr><td>Christine M. Carmody</td><td>60</td><td>Executive Vice President-Human Resources and Information Technology</td></tr><tr><td>Penelope M. Conner</td><td>59</td><td>Executive Vice President-Customer Experience and Energy Strategy</td></tr><tr><td>James W. Hunt, III</td><td>51</td><td>Executive Vice President-Corporate Relations and Sustainability and Secretary</td></tr><tr><td>Werner J. Schweiger</td><td>63</td><td>Executive Vice President and Chief Operating Officer</td></tr><tr><td>Jay S. Buth</td><td>53</td><td>Vice President, Controller and Chief Accounting Officer</td></tr></table>

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.

Christine M. Carmody. Ms. Carmody has served as Executive Vice President-Human Resources and Information Technology of Eversource Energy since August 8, 2016.

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.

Werner J. Schweiger: Mr. Schweiger has served as Executive Vice President and Chief Operating Officer of Eversource Energy since September 2, 2014.

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

## 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, 2023, there were 30,115 registered common shareholders of our company on record. As of the same date, there were a total of 348,483,425 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 2017 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2017 through 2022, assuming all dividends are reinvested.

Total Shareholder Return



<table><tr><td rowspan="2"></td><td rowspan="2">2017</td><td rowspan="2">2018</td><td rowspan="2">2019</td><td rowspan="2">2020</td><td rowspan="2">2021</td><td rowspan="2">2022</td></tr><tr></tr><tr><td>Eversource Energy</td><td>$100</td><td>$106</td><td>$143</td><td>$149</td><td>$162</td><td>$154</td></tr><tr><td>EEI Index</td><td>$100</td><td>$104</td><td>$130</td><td>$129</td><td>$151</td><td>$153</td></tr><tr><td>S&amp;P 500</td><td>$100</td><td>$96</td><td>$126</td><td>$149</td><td>$192</td><td>$157</td></tr></table>

## 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.

<table><tr><td>Period</td><td>Total Number of Shares Purchased</td><td>Average Price Paid per Share</td><td>Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs</td><td>Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)</td></tr><tr><td>October 1 - October 31, 2022</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>November 1 - November 30, 2022</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>December 1 - December 31, 2022</td><td>2,214</td><td>84.21</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>2,214</td><td>84.21</td><td>—</td><td>—</td></tr></table>

## Item 6. Removed and Reserved



## 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 2022 compared to fiscal year 2021 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2020 items and of fiscal year 2021 compared to fiscal year 2020, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2021 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. 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. EPS by business is a financial measure that is not recognized under GAAP (non-GAAP) 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. Our earnings discussion also includes non-GAAP financial measures referencing our earnings and EPS excluding certain transaction and transition costs, and our 2021 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.

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 transaction and transition costs, 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 earned $1.40 billion, or $4.05 per share, in 2022, compared with $1.22 billion, or $3.54 per share, in 2021.

- Our results include after-tax transaction and transition costs recorded at Eversource parent of $15.0 million, or $0.04 per share, in 2022, compared with $23.6 million, or $0.07 per share, in 2021. Our 2021 results also include after-tax charges of $86.1 million, or $0.25 per share, resulting from a PURA-approved CL&P settlement agreement and a PURA assessment as a result of CL&P's preparation for, and response to, Tropical Storm Isaias in August 2020, which were recorded within the electric distribution segment. Excluding these costs, our non-GAAP earnings were $1.42 billion, or $4.09 per share, in 2022, compared with $1.33 billion, or $3.86 per share, in 2021.

- We project that we will earn within a 2023 non-GAAP earning guidance range of between $4.25 per share and $4.43 per share, which excludes the potential impact of the strategic review of our offshore wind investment portfolio. We also project that our long-term EPS growth rate through 2027 from our regulated utility businesses will be in the upper half of a 5 to 7 percent range.

## Liquidity:

- Cash flows provided by operating activities totaled $2.40 billion in 2022, compared with $1.96 billion in 2021. Investments in property, plant and equipment totaled $3.44 billion in 2022 and $3.18 billion in 2021.

- Cash and Cash Equivalents totaled $374.6 million as of December 31, 2022, compared with $66.8 million as of December 31, 2021. Our available borrowing capacity under our commercial paper programs totaled $1.21 billion as of December 31, 2022.



• In 2022, we issued $4.05 billion of new long-term debt and we repaid $1.18 billion of long-term debt.

• In 2022, we issued 2,165,671 common shares, which resulted in proceeds of $197.1 million, net of issuance costs.

- In 2022, we paid dividends totaling $2.55 per common share, compared with dividends of $2.41 per common share in 2021. Our quarterly common share dividend payment was $0.6375 per share in 2022, as compared to $0.6025 per share in 2021. On February 1, 2023, our Board of Trustees approved a common share dividend payment of $0.675 per share, payable on March 31, 2023 to shareholders of record as of March 2, 2023.

• We project to make capital expenditures of $21.52 billion from 2023 through 2027, of which we expect $8.86 billion to be in our electric distribution segment, $5.25 billion to be in our natural gas distribution segment, $5.29 billion to be in our electric transmission segment, and $1.02 billion to be in our water distribution segment. We also project to invest $1.10 billion in information technology and facilities upgrades and enhancements. Additionally, we currently expect to make investments in our offshore wind business between $1.9 billion and $2.1 billion in 2023 and expect to make investments for our three projects in total between $1.6 billion and $1.9 billion from 2024 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned. These projected investments could be impacted by the strategic review of our offshore wind investment.

## Strategic and Regulatory Transactions and Developments:

- On May 4, 2022, we announced that we had initiated a strategic review of our offshore wind investment portfolio. As part of that review, we are exploring strategic alternatives that could result in a potential sale of all, or part, of our 50 percent interest in our offshore wind partnership with Orsted. We continue to work with interested parties through this ongoing process and expect to complete this review in the second quarter of 2023.

- 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. The DPU approved a renewal of the performance-based ratemaking (PBR) plan originally authorized in its previous 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 and exogenous events. The DPU also allowed for adjustments to the PBR mechanism for the recovery of future capital additions based on a historical five-year average of total capital additions, beginning with the January 1, 2024 PBR adjustment. The decision allows an authorized regulatory ROE of 9.80 percent on a capital structure including 53.2 percent equity.

## Earnings Overview

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

<table><tr><td rowspan="2">(Millions of Dollars, Except Per Share Amounts)</td><td colspan="8">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net Income Attributable to Common Shareholders (GAAP)</td><td>$ 1,404.9</td><td>$ 4.05</td><td>$ 1,220.5</td><td>$ 3.54</td><td>$ 1,205.2</td><td>$ 3.55</td><td></td><td></td></tr><tr><td>Regulated Companies (Non-GAAP)</td><td>$ 1,460.4</td><td>$ 4.21</td><td>$ 1,342.4</td><td>$ 3.89</td><td>$ 1,223.3</td><td>$ 3.60</td><td></td><td></td></tr><tr><td>Eversource Parent and Other Companies (Non-GAAP)</td><td>(40.5)</td><td>(0.12)</td><td>(12.2)</td><td>(0.03)</td><td>14.0</td><td>0.04</td><td></td><td></td></tr><tr><td>Non-GAAP Earnings</td><td>$ 1,419.9</td><td>$ 4.09</td><td>$ 1,330.2</td><td>$ 3.86</td><td>$ 1,237.3</td><td>$ 3.64</td><td></td><td></td></tr><tr><td>CL&amp;P Settlement Impacts (after-tax) (1)</td><td>—</td><td>—</td><td>(86.1)</td><td>(0.25)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Transaction and Transition Costs (after-tax) (2)</td><td>(15.0)</td><td>(0.04)</td><td>(23.6)</td><td>(0.07)</td><td>(32.1)</td><td>(0.09)</td><td></td><td></td></tr><tr><td>Net Income Attributable to Common Shareholders (GAAP)</td><td>$ 1,404.9</td><td>$ 4.05</td><td>$ 1,220.5</td><td>$ 3.54</td><td>$ 1,205.2</td><td>$ 3.55</td><td></td><td></td></tr></table>

(1) The 2021 after-tax costs are associated with the October 1, 2021 CL&P settlement agreement approved by PURA on October 27, 2021, which included a pre-tax $65 million charge to earnings for customer credits provided to customers over a two-month billing period from December 1, 2021 to January 31, 2022 and a $10 million pre-tax charge to earnings to establish a fund that provided bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages. The 2021 after-tax costs also include a charge recorded at CL&P as a result of PURA's April 28, 2021 and July 14, 2021 decisions, which included a pre-tax $28.4 million penalty for storm performance results provided as credits to customer bills over a one-year period that began September 1, 2021 and a pre-tax $0.2 million fine to the State of Connecticut's general fund. As a result of the October 1, 2021 settlement agreement, CL&P agreed to withdraw its pending appeals related to the storm performance penalty imposed in PURA's April 28, 2021 and July 14, 2021 decisions. Management views these collective charges as not directly related to the ongoing operations of the business and therefore not an indicator of baseline operating performance.

(2) The after-tax costs are for 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. The after-tax costs also include costs associated with our water business acquisitions and the strategic review of our offshore wind investment portfolio. We expect transaction costs in 2023 as a result of the wind strategic review.



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:

<table><tr><td rowspan="2">(Millions of Dollars, Except Per Share Amounts)</td><td colspan="8">For the Years Ended December 31,</td></tr><tr><td colspan="2">2022</td><td colspan="2">2021</td><td colspan="2">2020</td><td colspan="2"></td></tr><tr><td>Net Income - Regulated Companies (GAAP)</td><td>$ 1,460.4</td><td>$ 4.21</td><td>$ 1,256.3</td><td>$ 3.64</td><td>$ 1,221.8</td><td>$ 3.60</td><td></td><td></td></tr><tr><td>Electric Distribution, excluding CL&amp;P Settlement Impacts (Non-GAAP)</td><td>$ 592.8</td><td>$ 1.71</td><td>$ 556.2</td><td>$ 1.61</td><td>$ 544.0</td><td>$ 1.60</td><td></td><td></td></tr><tr><td>Electric Transmission</td><td>596.6</td><td>1.72</td><td>544.6</td><td>1.58</td><td>502.5</td><td>1.48</td><td></td><td></td></tr><tr><td>Natural Gas Distribution, excluding Transaction-Related Costs (Non-GAAP)</td><td>234.2</td><td>0.67</td><td>204.8</td><td>0.59</td><td>135.6</td><td>0.40</td><td></td><td></td></tr><tr><td>Water Distribution</td><td>36.8</td><td>0.11</td><td>36.8</td><td>0.11</td><td>41.2</td><td>0.12</td><td></td><td></td></tr><tr><td>Net Income - Regulated Companies (Non-GAAP)</td><td>$ 1,460.4</td><td>$ 4.21</td><td>$ 1,342.4</td><td>$ 3.89</td><td>$ 1,223.3</td><td>$ 3.60</td><td></td><td></td></tr><tr><td>CL&amp;P Settlement Impacts (after-tax)</td><td>—</td><td>—</td><td>(86.1)</td><td>(0.25)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Transaction and Transition Costs (after-tax)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1.5)</td><td>—</td><td></td><td></td></tr><tr><td>Net Income - Regulated Companies (GAAP)</td><td>$ 1,460.4</td><td>$ 4.21</td><td>$ 1,256.3</td><td>$ 3.64</td><td>$ 1,221.8</td><td>$ 3.60</td><td></td><td></td></tr></table>

Our electric distribution segment earnings increased $122.7 million in 2022, as compared to 2021, due primarily to the absence in 2022 of CL&P's October 1, 2021 settlement agreement that resulted in a $75 million pre-tax charge to earnings and a $28.6 million pre-tax charge to earnings at CL&P for a 2021 storm performance penalty imposed by PURA as a result of CL&P's preparation for, and response to, Tropical Storm Isaias. The after-tax impact of the CL&P settlement agreement and CL&P storm performance penalty imposed by PURA was $86.1 million, or $0.25 per share. Excluding those 2021 charges, electric distribution segment earnings increased $36.6 million due primarily to a base distribution rate increase at NSTAR Electric effective January 1, 2022, higher earnings from CL&P's capital tracking mechanism due to increased electric system improvements, lower pension plan expense in Connecticut and New Hampshire, and an increase in interest income primarily on regulatory deferrals. Those earnings increases were partially offset by higher operations and maintenance expense driven primarily by higher shared corporate costs resulting from the implementation of new information technology systems, higher storm costs, a $10 million pre-tax charge to earnings as a result of CL&P's commitment to contribute to an energy assistance program as part of its 2022 rate relief plan, and higher insurance reserves. Earnings were also unfavorably impacted by higher depreciation expense, higher property and other tax expense, and higher interest expense.

Our electric transmission segment earnings increased $52.0 million in 2022, as compared to 2021, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure, partially offset by a higher effective income tax rate and higher interest expense on short-term debt.

Our natural gas distribution segment earnings increased $29.4 million in 2022, as compared to 2021, due primarily to base distribution rate increases effective November 1, 2021 and November 1, 2022 at each of EGMA and NSTAR Gas, higher earnings from capital tracking mechanisms due to continued investments in natural gas infrastructure, and lower pension plan expense at Yankee Gas. Those earnings increases were partially offset by higher operations and maintenance expense, higher property tax expense, higher interest expense, and higher depreciation expense.

Our water distribution segment earnings were flat in 2022, as compared to 2021.

Eversource Parent and Other Companies: Eversource parent and other companies’ losses increased $19.7 million in 2022, as compared to 2021, due primarily to higher interest expense and a higher effective tax rate, partially offset by higher unrealized gains associated with our equity method investment in a renewable energy fund and an after-tax decrease of $8.6 million in transition costs associated with EGMA integration and transaction costs in 2022, as compared to 2021.

## 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, 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 $2.58 billion, $168.6 million, and $330.0 million at Eversource, CL&P, and PSNH, respectively, as of December 31, 2022.



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, 2022, $2.01 billion of Eversource's long-term debt, including $1.20 billion at Eversource parent, $400.0 million at CL&P, $80.0 million at NSTAR Electric, and $325.0 million at PSNH, matures within the next 12 months. CL&P repaid this long-term debt at maturity in January 2023. Eversource, with its strong 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 $374.6 million as of December 31, 2022, compared with $66.8 million as of December 31, 2021.

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 15, 2027. This revolving credit facility serves to backstop Eversource parent's $2.00 billion commercial paper program.

NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility, which terminates on October 15, 2027. This revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program.

The amount of borrowings outstanding and available under the commercial paper programs were as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Borrowings Outstanding as of December 31,</td><td colspan="3">Available Borrowing Capacity as of December 31,</td><td colspan="2">Weighted-Average Interest Rate as of December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td></td></tr><tr><td>Eversource Parent Commercial Paper Program</td><td>$ 1,442.2</td><td>$ 1,343.0</td><td>$ 557.8</td><td>$ 657.0</td><td>4.63%</td><td>0.31%</td><td></td><td></td></tr><tr><td>NSTAR Electric Commercial Paper Program</td><td>—</td><td>162.5</td><td>650.0</td><td>487.5</td><td>—%</td><td>0.14%</td><td></td><td></td></tr></table>

There were no borrowings outstanding on the revolving credit facilities as of December 31, 2022 or 2021.

CL&P and PSNH have uncommitted line of credit agreements totaling $450 million and $300 million, respectively, which will expire on May 12, 2023. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2022.

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.

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, 2022, there were intercompany loans from Eversource parent to PSNH of $173.3 million. As of December 31, 2021, there were intercompany loans from Eversource parent to PSNH of $110.6 million. 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.

Availability under Long-Term Debt Issuance Authorizations: On December 14, 2022, the NHPUC approved PSNH’s request for authorization to issue up to $600 million in long-term debt through December 31, 2023. 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. 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. The remaining Eversource operating companies, including NSTAR Electric, have utilized the long-term debt authorizations in place with the respective regulatory commissions.

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

<table><tr><td>(Millions of Dollars)</td><td>Interest Rate</td><td>Issuance/ (Repayment)</td><td>Issuance Repayment Date</td><td>Maturity Date</td><td>Use of Proceeds for Issuance/ Repayment Information</td></tr><tr><td>CL&amp;P 2023 Series A First Mortgage Bonds</td><td>5.25 %</td><td>$ 500.0</td><td>January 2023</td><td>January 2035</td><td>Repaid 2013 Series A Bonds at maturity and short-term debt, and paid capital expenditures and working capital</td></tr><tr><td>CL&amp;P 2013 Series A First Mortgage Bonds</td><td>2.50 %</td><td>(400.0)</td><td>January 2023</td><td>January 2023</td><td>Paid at maturity</td></tr><tr><td>NSTAR Electric 2022 Debentures</td><td>4.55 %</td><td>450.0</td><td>May 2022</td><td>June 2052</td><td>Repaid short-term debt, paid capital expenditures and working capital</td></tr><tr><td>NSTAR Electric 2022 Debentures</td><td>4.95 %</td><td>400.0</td><td>September 2022</td><td>September 2052</td><td>Refinanced investments in eligible green expenditures, which were previously financed using short-term debt from October 1, 2020 through June 30, 2022</td></tr><tr><td>NSTAR Electric 2012 Debentures</td><td>2.375 %</td><td>(400.0)</td><td>October 2022</td><td>October 2022</td><td>Paid at maturity</td></tr><tr><td>PSNH Series W First Mortgage Bonds</td><td>5.15 %</td><td>300.0</td><td>January 2023</td><td>January 2053</td><td>Repaid short-term debt, paid capital expenditures and working capital</td></tr></table>



<table><tr><td>(Millions of Dollars)</td><td>Interest Rate</td><td>Issuance/ (Repayment)</td><td>Issue Date or Repayment Date</td><td>Maturity Date</td><td>Use of Proceeds for Issuance/ Repayment Information</td></tr><tr><td>Eversource Parent Series V Senior Notes</td><td>2.90 %</td><td>650.0</td><td>February 2022</td><td>March 2027</td><td>Repaid Series K Senior Notes at maturity and short-term debt</td></tr><tr><td>Eversource Parent Series W Senior Notes</td><td>3.375 %</td><td>650.0</td><td>February 2022</td><td>March 2032</td><td>Repaid Series K Senior Notes at maturity and short-term debt</td></tr><tr><td>Eversource Parent Series X Senior Notes</td><td>4.20 %</td><td>900.0</td><td>June 2022</td><td>June 2024</td><td>Repaid short-term debt and paid working capital</td></tr><tr><td>Eversource Parent Series Y Senior Notes</td><td>4.60 %</td><td>600.0</td><td>June 2022</td><td>July 2027</td><td>Repaid short-term debt and paid working capital</td></tr><tr><td>Eversource Parent Series K Senior Notes</td><td>2.75 %</td><td>(750.0)</td><td>March 2022</td><td>March 2022</td><td>Paid at maturity</td></tr><tr><td>Yankee Gas Series B First Mortgage Bonds</td><td>8.48 %</td><td>(20.0)</td><td>March 2022</td><td>March 2022</td><td>Paid at maturity</td></tr><tr><td>Yankee Gas Series U First Mortgage Bonds</td><td>4.31 %</td><td>100.0</td><td>September 2022</td><td>September 2032</td><td>Repaid short-term debt, paid capital expenditures and for general corporate purposes</td></tr><tr><td>EGMA Series C First Mortgage Bonds</td><td>4.70 %</td><td>100.0</td><td>June 2022</td><td>June 2052</td><td>Repaid short-term debt, paid capital expenditures and for general corporate purposes</td></tr><tr><td>NSTAR Gas Series V First Mortgage Bonds</td><td>4.40 %</td><td>125.0</td><td>July 2022</td><td>August 2032</td><td>Repaid short-term debt, paid capital expenditures and for general corporate purposes</td></tr><tr><td>Aquarion Water Company of New Hampshire General Mortgage Bonds</td><td>4.45 %</td><td>(5.0)</td><td>July 2022</td><td>July 2022</td><td>Paid at maturity</td></tr><tr><td>Aquarion Water Company of Connecticut Senior Notes</td><td>4.69 %</td><td>70.0</td><td>August 2022</td><td>September 2052</td><td>Repaid short-term debt</td></tr></table>

As a result of the CL&P and PSNH long-term debt issuances in January 2023, $400 million and $295.3 million, respectively, of current portion of long-term debt were reclassified as Long-Term Debt on CL&P's and PSNH's balance sheets as of December 31, 2022.

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 and $17.6 million of interest payments in 2022, and paid $43.2 million of RRB principal payments and $18.9 million of interest payments in 2021.

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. Eversource may issue and sell its common shares through its sales agents during the term of this agreement. Shares may be offered in transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise. Sales may be made at either market prices prevailing at the time of sale, at prices related to such prevailing market prices or at negotiated prices. 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 $2.40 billion in 2022, compared with $1.96 billion in 2021. Changes in Eversource's cash flows from operations were generally consistent with changes in its results of operations, after adjustment for non-cash items and as adjusted by changes in working capital in the normal course of business. Operating cash flows were favorably impacted by the timing of cash payments made on our accounts payable, an increase in regulatory over-recoveries driven by the timing of collections for the non-bypassable FMCC at CL&P and other regulatory tracking mechanisms, a decrease of $99.2 million in pension and PBOP contributions made in 2022, as compared to 2021, and a $43.7 million decrease in income tax payments made in 2022, as compared to 2021. The impact of regulatory collections are included in both Regulatory Over/Under Recoveries and Amortization on the statements of cash flows. These favorable impacts were partially offset by the timing of cash collections on our accounts receivable, $78.4 million of payments in 2022 related to withheld property taxes at our Massachusetts companies, primarily at NSTAR Electric, $72.0 million of customer credits distributed to CL&P's customers 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 $61.6 million increase in cost of removal expenditures, and an increase of $34.0 million in cash payments for storm costs at NSTAR Electric.

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. In 2021, we paid cash dividends of $805.4 million and issued non-cash dividends of $22.9 million in the form of treasury shares, totaling dividends of $828.3 million, or $2.41 per common share. Our quarterly common share dividend payment was $0.6375 per share in 2022, as compared to $0.6025 per share in 2021. On February 1, 2023, our Board of Trustees approved a common share dividend payment of $0.675 per share, payable on March 31, 2023 to shareholders of record as of March 2, 2023.

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 2022, CL&P, NSTAR Electric and PSNH paid $292.4 million, $287.6 million and $104.0 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 2022, investments for Eversource, CL&P, NSTAR Electric, and PSNH were $3.44 billion, $876.7 million, $954.3 million and $485.6 million, respectively. Capital expenditures were primarily for continuing projects to maintain and improve infrastructure and operations, including enhancing reliability to the transmission and distribution systems.



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

Estimated interest payments on existing long-term fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement as of December 31, 2022 and are as follows:

<table><tr><td>(Millions of Dollars)</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>Thereafter</td><td>Total</td></tr><tr><td>Eversource</td><td>$ 722.6</td><td>$ 654.7</td><td>$ 589.6</td><td>$ 559.7</td><td>$ 517.3</td><td>$ 5,864.4</td><td>$ 8,908.3</td></tr><tr><td>CL&amp;P</td><td>154.7</td><td>149.7</td><td>138.6</td><td>135.6</td><td>127.6</td><td>1,657.2</td><td>2,363.4</td></tr></table>

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 investment, and guarantees of certain obligations primarily associated with our offshore wind investment. The future funding and guarantee obligations associated with our offshore wind investment could be impacted by the strategic review of our offshore wind investment.

For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures - Projected Capital Expenditures" and for projected investments in our offshore wind business, 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 corporate credit ratings and outlooks by S&P, Moody's, and Fitch is as follows:

<table><tr><td rowspan="2"></td><td colspan="2">S&amp;P</td><td colspan="2">Moody&#x27;s</td><td colspan="2">Fitch</td></tr><tr><td>Current</td><td>Outlook</td><td>Current</td><td>Outlook</td><td>Current</td><td>Outlook</td></tr><tr><td>Eversource Parent</td><td>A-</td><td>Positive</td><td>Baa1</td><td>Negative</td><td>BBB+</td><td>Stable</td></tr><tr><td>CL&amp;P</td><td>A</td><td>Positive</td><td>A3</td><td>Stable</td><td>A-</td><td>Stable</td></tr><tr><td>NSTAR Electric</td><td>A</td><td>Positive</td><td>A1</td><td>Negative</td><td>A</td><td>Stable</td></tr><tr><td>PSNH</td><td>A</td><td>Stable</td><td>A3</td><td>Stable</td><td>A-</td><td>Stable</td></tr></table>

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:

<table><tr><td rowspan="2"></td><td colspan="2">S&amp;P</td><td colspan="2">Moody&#x27;s</td><td colspan="2">Fitch</td></tr><tr><td>Current</td><td>Outlook</td><td>Current</td><td>Outlook</td><td>Current</td><td>Outlook</td></tr><tr><td>Eversource Parent</td><td>BBB+</td><td>Positive</td><td>Baa1</td><td>Negative</td><td>BBB+</td><td>Stable</td></tr><tr><td>CL&amp;P</td><td>A+</td><td>Positive</td><td>A1</td><td>Stable</td><td>A+</td><td>Stable</td></tr><tr><td>NSTAR Electric</td><td>A</td><td>Positive</td><td>A1</td><td>Negative</td><td>A+</td><td>Stable</td></tr><tr><td>PSNH</td><td>A+</td><td>Stable</td><td>A1</td><td>Stable</td><td>A+</td><td>Stable</td></tr></table>

## Impact of COVID-19

The financial impacts of COVID-19 as it relates to our businesses primarily relate to collectability of customer receivables and the outcome of future proceedings before our state regulatory commissions to recover our incremental uncollectible customer receivable costs associated with COVID-19.

As of December 31, 2022, our allowance for uncollectible customer receivable balance of $486.3 million, of which $284.4 million relates to hardship accounts that are specifically recovered in rates charged to customers, adequately reflected the collection risk and net realizable value for our receivables. As of December 31, 2022 and 2021, the total amount incurred as a result of COVID-19 included in the allowance for uncollectible accounts was $50.9 million and $55.3 million at Eversource, $16.0 million and $23.9 million at CL&P, and $4.1 million and $9.0 million at NSTAR Electric, respectively. At our Connecticut and Massachusetts utilities, the COVID-19 related uncollectible amounts were deferred either as incremental regulatory costs or deferred through existing regulatory tracking mechanisms that recover uncollectible energy supply costs, as management believes it is probable that these costs will ultimately be recovered from customers in future rates. No COVID-19 related uncollectible amounts were deferred at PSNH as a result of a July 2021 NHPUC order. Based on the status of our COVID-19 regulatory dockets, policies and practices in the jurisdictions in which we operate, we believe the state regulatory commissions in Connecticut and Massachusetts will allow us to recover our incremental uncollectible customer receivable costs associated with COVID-19.

## 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 $3.79 billion in 2022, $3.54 billion in 2021, and $3.06 billion in 2020. These amounts included $266.5 million in 2022, $238.0 million in 2021, and $239.1 million in 2020 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 $91.7 million in 2022, as compared to 2021. A summary of electric transmission capital expenditures by company is as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>CL&amp;P</td><td>$ 416.8</td><td>$ 400.0</td><td>$ 402.9</td><td></td></tr><tr><td>NSTAR Electric</td><td>438.4</td><td>480.3</td><td>366.8</td><td></td></tr><tr><td>PSNH</td><td>351.8</td><td>235.0</td><td>193.9</td><td></td></tr><tr><td>Total Electric Transmission Segment</td><td>$ 1,207.0</td><td>$ 1,115.3</td><td>$ 963.6</td><td></td></tr></table>

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.

Our transmission projects in Massachusetts include electric transmission upgrades in the greater Boston metropolitan area. Two of these upgrades, the Mystic-Woburn and the Wakefield-Woburn reliability projects, are under construction and are expected to be placed in service by the fourth quarter of 2023. Construction on the last remaining upgrade, the Sudbury-Hudson Reliability Project, commenced in the fourth quarter of 2022. We spent $71.9 million during 2022 and we expect to make additional capital expenditures of approximately $115 million on these remaining transmission upgrades. There are also several transmission projects underway in southeastern Massachusetts, including Cape Cod, required to reinforce the Southeastern Massachusetts transmission system and bring the system into compliance with applicable national and regional reliability standards. We spent $23.2 million during 2022 and we expect to make additional capital expenditures of approximately $110 million on these transmission upgrades.

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

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="9">For the Years Ended December 31,</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Total Electric</td><td>Natural Gas</td><td>Water</td><td>Total</td><td></td><td></td></tr><tr><td>2022</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic Business</td><td>$ 267.8</td><td>$ 202.4</td><td>$ 68.6</td><td>$ 538.8</td><td>$ 175.2</td><td>$ 16.8</td><td>$ 730.8</td><td></td><td></td></tr><tr><td>Aging Infrastructure</td><td>199.9</td><td>245.1</td><td>70.8</td><td>515.8</td><td>562.3</td><td>137.6</td><td>1,215.7</td><td></td><td></td></tr><tr><td>Load Growth and Other</td><td>90.7</td><td>177.0</td><td>31.3</td><td>299.0</td><td>66.4</td><td>0.9</td><td>366.3</td><td></td><td></td></tr><tr><td>Total Distribution</td><td>$ 558.4</td><td>$ 624.5</td><td>$ 170.7</td><td>$ 1,353.6</td><td>$ 803.9</td><td>$ 155.3</td><td>$ 2,312.8</td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic Business</td><td>$ 256.2</td><td>$ 179.9</td><td>$ 56.0</td><td>$ 492.1</td><td>$ 206.1</td><td>$ 16.5</td><td>$ 714.7</td><td></td><td></td></tr><tr><td>Aging Infrastructure</td><td>178.0</td><td>219.1</td><td>67.7</td><td>464.8</td><td>509.6</td><td>127.1</td><td>1,101.5</td><td></td><td></td></tr><tr><td>Load Growth and Other</td><td>80.2</td><td>169.9</td><td>37.1</td><td>287.2</td><td>83.3</td><td>0.6</td><td>371.1</td><td></td><td></td></tr><tr><td>Total Distribution</td><td>$ 514.4</td><td>$ 568.9</td><td>$ 160.8</td><td>$ 1,244.1</td><td>$ 799.0</td><td>$ 144.2</td><td>$ 2,187.3</td><td></td><td></td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Basic Business</td><td>$ 233.4</td><td>$ 195.1</td><td>$ 52.4</td><td>$ 480.9</td><td>$ 88.2</td><td>$ 10.9</td><td>$ 580.0</td><td></td><td></td></tr><tr><td>Aging Infrastructure</td><td>179.9</td><td>237.1</td><td>80.2</td><td>497.2</td><td>391.3</td><td>115.5</td><td>1,004.0</td><td></td><td></td></tr><tr><td>Load Growth and Other</td><td>77.8</td><td>112.2</td><td>21.3</td><td>211.3</td><td>65.6</td><td>0.8</td><td>277.7</td><td></td><td></td></tr><tr><td>Total Distribution</td><td>$ 491.1</td><td>$ 544.4</td><td>$ 153.9</td><td>$ 1,189.4</td><td>$ 545.1</td><td>$ 127.2</td><td>$ 1,861.7</td><td></td><td></td></tr></table>

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

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

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



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 2023 through 2027, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="9">Years</td></tr><tr><td>2023</td><td colspan="2">2024</td><td>2025</td><td colspan="2">2026</td><td colspan="2">2027</td><td>2023 - 2027 Total</td></tr><tr><td>CL&amp;P Transmission</td><td>$     406</td><td>$     312</td><td>$     324</td><td>$     263</td><td>$     136</td><td>$     136</td><td>$     136</td><td>$     136</td><td>1,441</td></tr><tr><td>NSTAR Electric Transmission</td><td>461</td><td colspan="2">527</td><td>436</td><td colspan="2">575</td><td>748</td><td colspan="2">2,747</td></tr><tr><td>PSNH Transmission</td><td>329</td><td colspan="2">270</td><td>252</td><td colspan="2">174</td><td>72</td><td colspan="2">1,097</td></tr><tr><td>Total Electric Transmission</td><td>$     1,196</td><td>$     1,109</td><td>$     1,012</td><td>$     1,012</td><td>$     1,012</td><td>$     956</td><td>$     956</td><td>$     956</td><td>5,285</td></tr><tr><td>Electric Distribution</td><td>$     1,847</td><td>$     1,750</td><td>$     1,768</td><td>$     1,870</td><td>$     1,870</td><td>$     1,628</td><td>$     1,628</td><td>$     1,628</td><td>8,863</td></tr><tr><td>Natural Gas Distribution</td><td>1,035</td><td colspan="2">1,038</td><td>1,146</td><td colspan="2">1,115</td><td>918</td><td colspan="2">5,252</td></tr><tr><td>Total Electric and Natural Gas Distribution</td><td>$     2,882</td><td>$     2,788</td><td>$     2,914</td><td>$     2,985</td><td>$     2,985</td><td>$     2,546</td><td>$     2,546</td><td>$     2,546</td><td>14,115</td></tr><tr><td>Water Distribution</td><td>$     170</td><td>$     194</td><td>$     203</td><td>$     218</td><td>$     218</td><td>$     235</td><td>$     235</td><td>$     235</td><td>1,020</td></tr><tr><td>Information Technology and All Other</td><td>$     215</td><td>$     213</td><td>$     244</td><td>$     219</td><td>$     219</td><td>$     208</td><td>$     208</td><td>$     208</td><td>1,099</td></tr><tr><td>Total</td><td>$     4,463</td><td>$     4,304</td><td>$     4,373</td><td>$     4,434</td><td>$     4,434</td><td>$     3,945</td><td>$     3,945</td><td>$     3,945</td><td>21,519</td></tr></table>

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.

Acquisition of The Torrington Water Company: On October 3, 2022, Aquarion acquired The Torrington Water Company (TWC) following the receipt of all required approvals. The acquisition was structured as a stock-for-stock exchange, and Eversource issued 925,264 treasury shares at closing for a purchase price of $72.1 million. TWC provides regulated water service to approximately 10,100 customers in Connecticut.

Offshore Wind Business: Our offshore wind business includes a 50 percent ownership interest in North East Offshore, which holds PPAs and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as an undeveloped offshore lease area. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted.

The offshore leases include a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode Island and a separate, adjacent 300-square-mile ocean lease located approximately 25 miles south of the coast of Massachusetts. In aggregate, these ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy.

As of December 31, 2022 and 2021, Eversource's total equity investment balance in its offshore wind business was $1.95 billion and $1.21 billion, respectively. This equity investment includes capital expenditures for the three projects, as well as capitalized costs related to future development, acquisition costs of offshore lease areas, and capitalized interest.

Strategic Review of Offshore Wind Investments: On May 4, 2022, we announced that we had initiated a strategic review of our offshore wind investment portfolio. As part of that review, we are exploring strategic alternatives that could result in a potential sale of all, or part, of our 50 percent interest in our offshore wind partnership with Ørsted. In late July, we started preliminary and targeted outreach to interested parties. We continue to work with interested parties through this ongoing process and expect to complete this review in the second quarter of 2023. If the recommended path forward following the strategic review is a sale of all, or part, of our interest in the partnership, we expect potential proceeds from such transaction would likely be used to support our regulated investments in strengthening, modernizing and decarbonizing our regulated energy and water delivery systems. We currently believe that the fair market value of our offshore wind investment is greater than the carrying value; however, there could be changes in market conditions that would impact our ability to sell this investment or realize a value in excess of our carrying value. As the strategic review proceeds, we remain committed to continue providing oversight of the siting and construction of onshore elements of our South Fork Wind, Revolution Wind and Sunrise Wind offshore wind projects.

Contracts, Permitting and Construction of Offshore Wind Projects: The following table provides a summary of the Eversource and Ørsted major projects with announced contracts:

<table><tr><td>Wind Project</td><td>State Servicing</td><td>Size (MW)</td><td>Term (Years)</td><td>Price per MWh</td><td>Pricing Terms</td><td>Contract Status</td></tr><tr><td>Revolution Wind</td><td>Rhode Island</td><td>400</td><td>20</td><td>$98.43</td><td>Fixed price contract; no price escalation</td><td>Approved</td></tr><tr><td>Revolution Wind</td><td>Connecticut</td><td>304</td><td>20</td><td>$98.43 - $99.50</td><td>Fixed price contracts; no price escalation</td><td>Approved</td></tr><tr><td>South Fork Wind</td><td>New York (LIPA)</td><td>90</td><td>20</td><td>$160.33</td><td>2 percent average price escalation</td><td>Approved</td></tr><tr><td>South Fork Wind</td><td>New York (LIPA)</td><td>40</td><td>20</td><td>$86.25</td><td>2 percent average price escalation</td><td>Approved</td></tr><tr><td>Sunrise Wind</td><td>New York (NYSERDA)</td><td>924</td><td>25</td><td>$110.37  \(^{(1)}</td><td>Fixed price contract; no price escalation</td><td>Approved</td></tr></table>

(1) Index Offshore Wind Renewable Energy Certificate (OREC) strike price.

Revolution Wind and Sunrise Wind projects are subject to 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. 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 these projects' in-service dates.

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. The first major milestone in the BOEM review process is an issuance of a Notice of Intent (NOI) to complete an Environmental Impact Statement (EIS). BOEM then provides a final review schedule for the project’s COP



approval. BOEM conducts environmental and technical reviews of the COP. The EIS 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. BOEM released its Draft EIS on September 2, 2022 for the Revolution Wind project and on December 16, 2022 for the Sunrise Wind project. The Draft EIS analyzes the potential environmental impacts of the project and the alternatives to the project to be evaluated as part of the process. Each of the identified alternative configurations in the Draft EISs had a similar level of environmental impacts, and if an alternative configuration was selected, the Revolution Wind project and the Sunrise Wind project would each still meet their respective contractual output requirements. For Revolution Wind, a final EIS is expected in the second quarter of 2023, the Record of Decision in the third quarter of 2023, and final approval is expected in the fourth quarter of 2023. For Sunrise Wind, a final EIS and Record of Decision are expected in the third quarter of 2023, and final approval is expected in the fourth quarter of 2023.

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 September 23, 2022, Sunrise Wind filed a Joint Proposal to the New York State Public Service Commission. Among other things, the Joint Proposal includes proposed mitigation for certain environmental, community and construction impacts associated with constructing the project. The Joint Proposal was signed by the New York Departments of Public Service, Environmental Conservation, Transportation and State as well as the Office of Agriculture and Markets and the Long Island Commercial Fisheries Association. On November 17, 2022, the New York Public Service Commission approved an order adopting the Joint Proposal and granting a Certificate of Environmental Compatibility and Public Need. On November 18, 2022, Sunrise Wind filed its Environmental Management and Construction Plan (EM&CP) with the New York Public Service Commission, which details the plans on how the project will be constructed in accordance with the conditions of the approved Joint Proposal. Comments from several of the reviewing agencies and parties have been received and Sunrise Wind is in the process of reviewing and addressing those comments in the plan.

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. Onshore activities for the project's underground onshore transmission line and construction of the onshore interconnection facility located in East Hampton, New York are underway. Offshore activities began in the fourth quarter of 2022 with construction of the sea-to-shore conduit system. Other marine construction activities, including the project's monople foundation, 11-megawatt wind turbines, cable installation, and offshore substation, are expected to occur in 2023. Construction-related purchase agreements with third-party contractors and materials contracts have largely been secured. South Fork Wind faces several challenges and appeals of New York State and federal agency approvals, however it believes it is probable it will be able to overcome these challenges.

For Revolution Wind and Sunrise Wind, construction is expected to begin in the second half of 2023 once all necessary federal, state and local approvals are received.

Projected In-Service Dates: We expect the South Fork Wind project to be in-service by the end of 2023. For Revolution Wind and Sunrise Wind, based on the BOEM permit schedule included in each respective NOI outlining when BOEM will complete its review of the COP, we currently expect in-service dates in 2025 for both projects.

Projected Investments: For Revolution Wind and Sunrise Wind, we are preparing our final project designs and advancing the appropriate federal, state, and local siting and permitting processes along with our offshore wind partner, Ørsted. Construction of South Fork Wind is underway. Construction-related purchase agreements with third-party contractors and materials contracts have largely been secured. Subject to advancing our final project designs and federal, state and local permitting processes and construction schedules, we currently expect to make investments in our offshore wind business between $1.9 billion and $2.1 billion in 2023 and expect to make investments for our three projects in total between $1.6 billion and $1.9 billion from 2024 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned. These projected investments could be impacted by the strategic review of our offshore wind investment.

## 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, 2022 and 2021. 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, 2022 and 2021.

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.

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 2022 rate base, a change of 10 basis points to the base ROE would impact Eversource’s future annual after-tax earnings by approximately $5 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

FERC Notice of Inquiry on ROE: On March 21, 2019, FERC issued a Notice of Inquiry (NOI) seeking comments from all stakeholders on FERC's policies for evaluating ROEs for electric public utilities, and interstate natural gas and oil pipelines. On June 26, 2019, the NETOs jointly filed comments supporting the methodology established in the FERC's October 16, 2018 order with minor enhancements going forward. The NETOs jointly filed reply comments in the FERC ROE NOI on July 26, 2019. On May 12, 2020, the NETOs filed supplemental comments in the NOI ROE docket. At this time, Eversource cannot predict how this proceeding will affect its transmission ROEs.

FERC Notice of Inquiry and Proposed Rulemaking on Transmission Incentives: On March 21, 2019, FERC issued an NOI seeking comments on FERC's policies for implementing electric transmission incentives. On June 26, 2019, Eversource filed comments requesting that FERC retain policies that have been effective in encouraging new transmission investment and remain flexible enough to attract investment in new and emerging transmission technologies. Eversource filed reply comments on August 26, 2019. 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 2022 estimated rate base) on Eversource’s after-tax earnings is approximately $18 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 and natural gas utilities are required to file a distribution rate case within four years of the last rate case. 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 at CL&P that included a current base distribution rate freeze until no earlier than January 1, 2024. The approval of the settlement agreement satisfies 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. Aquarion is not required to initiate a rate review with PURA on a set schedule. On August 29, 2022, Aquarion filed an application with PURA to amend its existing rate schedules and a final decision is expected March 15, 2023.

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 are 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. The natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply procurement costs are recovered from customers in energy supply rates that are approved by the respective state regulatory commission. The rates are reset periodically and are fully reconciled to their costs. 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.

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 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 Amended EDC Advanced Metering Infrastructure Proposal. CL&P submitted an Amended Proposal in response to this request on November 8, 2021 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. The procedural schedule includes briefs that were filed on April 29, 2022, written comments that were filed July 20, 2022, and a technical session on September 14, 2022.

CL&P Rate Relief Plan: On November 28, 2022, Governor Lamont, DEEP, Office of Consumer Counsel, and CL&P jointly developed a rate relief plan for electric customers for the winter peak season of January 1, 2023 through April 30, 2023. On December 16, 2022, PURA approved the rate relief plan. As part of the rate relief plan, CL&P reduced the Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate effective January 1, 2023 to provide customers with an average $10 monthly bill credit from January through April 2023. This rate reduction accelerates the return to customers of net revenues generated by long-term state-approved energy contracts with the Millstone and Seabrook nuclear power plants of approximately $90 million. The rate relief plan also included instituting a temporary, flat monthly discount for qualifying low-income hardship customers effective January 1, 2023. This flat-rate credit will continue until a new low-income discount rate that was approved by PURA in an October 19, 2022 decision is implemented in 2024. These aspects of the rate relief plan do not impact CL&P's earnings but do impact its future



cash flows. Also as part of the rate relief plan, CL&P committed to contribute $10 million to an energy assistance program for qualifying hardship customers, which is expected to be distributed as a bill credit to those customers by the end of the first quarter of 2023. CL&P recorded a current liability of $10 million on the balance sheet and a charge to expense on the statement of income for the year ended December 31, 2022 associated with the customer assistance program.

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 for electric distribution companies. PURA will conduct the proceeding in two phases, with a draft decision on the first phase expected in March 2023 and then a procedural schedule established for the second phase. On January 25, 2023, PURA staff issued a proposal outlining a suggested portfolio of performance based regulation elements for further exploration and implementation in the second phase of the proceeding. At this time, we cannot predict the ultimate outcome of this proceeding and the resulting impact to CL&P.

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. A final decision from PURA is expected March 15, 2023.

## Massachusetts:

NSTAR Electric Distribution Rates: As part of an inflation-based mechanism, NSTAR Electric submitted its fourth annual Performance Based Rate (PBR) Adjustment filing on November 10, 2021 and on December 22, 2021, the DPU approved a $36.8 million increase to base distribution rates effective January 1, 2022.

NSTAR Electric Distribution Rate Case: 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. The DPU approved a renewal of the performance-based ratemaking (PBR) plan originally authorized in its previous 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 and exogenous events. The DPU also allowed for adjustments to the PBR mechanism for the recovery of future capital additions based on a historical five-year average of total capital additions, beginning with the January 1, 2024 PBR adjustment. The decision allows an authorized regulatory ROE of 9.80 percent on a capital structure including 53.2 percent equity.

Among other items, the DPU approved an increase to the annual storm fund contribution collected through base distribution rates from $10 million to $31 million, and allowed for the recovery of storm threshold costs of $1.3 million per storm event subsequent to the eighth storm in a calendar year (six recovered in base rates plus two additional storms). The DPU approved cost recovery of a portion of NSTAR Electric’s outstanding storm costs beginning on January 1, 2023 and January 1, 2024, subject to reconciliation from future prudency reviews. In a subsequent compliance filing, the DPU allowed recovery to commence for outstanding storm costs occurring between 2018 and 2022 and interest in a total of $162.1 million over a five-year period starting January 1, 2023. In addition, NSTAR Electric will begin to recover 2021 exogenous storms and interest in a total of $220.9 million over a five-year period beginning January 1, 2024. The DPU also approved the recovery of historical exogenous property taxes of $30.8 million incurred from 2020 through 2022 over a two-year period and $8.3 million incurred from 2012 through 2015 over a five-year period effective January 1, 2023. NSTAR Electric’s AMI Implementation Plan and a new Advanced Metering Infrastructure tariff (AMIF) reconciling mechanism effective January 1, 2023 were also approved and NSTAR Electric will recover all meter-related capital now through the AMIF as opposed to base distribution rates.

NSTAR Electric Grid Modernization Plan: On October 7, 2022, the DPU issued an order approving continuing investments from the initial 2018 to 2021 Grid Modernization Plan that were included in the 2022 to 2025 Grid Modernization Plan. The DPU established a preauthorized total budget cap of $162.6 million over the four-year plan period for these continuing investments. On November 30, 2022, the DPU issued an order that preauthorized a four-year $43.0 million budget for new grid-facing investments. All of the ongoing and new investments will have targeted cost recovery through NSTAR Electric’s annual grid modernization factor filings.

NSTAR Electric Advanced Metering Infrastructure Plan: On November 30, 2022, the DPU approved NSTAR Electric’s proposed Advanced Metering Infrastructure customer-facing investment and implementation plan (including program operating costs), including a full deployment of advanced metering functionality, for the years 2022 through 2028. The DPU established preauthorized total budget caps of $534.8 million for core AMI investments and corresponding operating costs and $133.1 million for supporting AMI investments and corresponding operating costs over the seven-year plan period. The DPU approved a new AMIF tariff reconciling mechanism effective January 1, 2023 to recover eligible costs associated with both AMI customer-facing investments and implementation costs. Investments above these budget caps can be recovered in a future base distribution rate proceeding.

NSTAR Electric Transmission Support Agreement: On June 17, 2022, FERC approved a transmission support agreement between NSTAR Electric and Park City Wind LLC (PCW). The agreement commits NSTAR Electric to construct certain transmission facilities required to interconnect PCW's future 800 MW offshore wind generation facility to NSTAR Electric's transmission system. Of the total estimated $196 million project, NSTAR Electric will finance an estimated $152 million and earn a return on those specific investments over a ten-year period once the facility is in operation based on the authorized return that is in effect at the applicable time for regional transmission service under the ISO-NE Open Access Transmission Tariff. The interconnection transmission facilities are currently expected to be in-service in 2026.

NSTAR Electric CIP Filing: On December 30, 2022, the DPU approved a provisional system planning tariff for the recovery of costs associated with a capital investment project (CIP) proposal submitted by NSTAR Electric for one of six geographic study areas in its service territory in accordance with DPU’s directives. The DPU established a new, provisional framework for planning and funding upgrades to the electric power system to foster development and interconnection of distributed energy facilities. Under the DPU program, NSTAR Electric has filed



infrastructure upgrade proposals to be built within a four-year construction timeframe that allocate the costs of interconnection upgrades between the interconnecting distributed generation facility and distribution customers. Payments made by the distributed generation facility will be applied against the total capital investment made by NSTAR Electric and NSTAR Electric will earn a return on the net investment. The amount allocated to distribution customers will be recovered through a reconciling mechanism, the Provisional System Planning Tariff. The DPU approved the first of these provisional system planning projects, the Marion-Fairhaven group study area, which will enable 141 MW of distributed energy to be interconnected at a total estimated cost of $119.7 million. Of the total $119.7 million, $65.8 million will be allocated to distribution customers, once the enabled distributed energy facilities capacity is fully subscribed by distributed energy facilities interconnecting customers. Additionally, NSTAR Electric will proceed with construction of $54 million of transmission upgrades necessary to improve local reliability and integrate distribution energy resources in the Marion-Fairhaven area and recover the amount through local transmission rates.

NSTAR Electric Electric Vehicles Program: On December 30, 2022, NSTAR Electric received DPU approval for a new Phase 2 electric vehicle (EV) charging infrastructure program (including operating costs) totaling $188 million over a four-year period, which includes make-ready costs and other EV expenditures to support the deployment of charging ports and provides incentives for charging infrastructure installed at commercial and residential sites in Massachusetts. NSTAR Electric will recover the cost of this program through an Electric Vehicle Program tariff.

NSTAR Gas Distribution Rates: As part of an inflation-based mechanism, NSTAR Gas submitted its second annual Performance Based Rate Adjustment filing on September 15, 2022 and on October 31, 2022, the DPU approved a $21.7 million increase to base distribution rates for effect on November 1, 2022. The increase is inclusive of a $4.5 million permanent increase related to exogenous property taxes and a $5.4 million increase related to an October 6, 2021 mitigation plan filing that delayed recovery of a portion of a base distribution rate increase originally scheduled to take effect November 1, 2021. The DPU also approved the recovery of historical exogenous property taxes incurred from November 1, 2020 through October 31, 2022 of $8.2 million over a two-year period through a separate reconciling mechanism effective November 1, 2022.

EGMA Distribution Rates: As established in an October 7, 2020 EGMA Rate Settlement Agreement approved by the DPU, on September 16, 2022 EGMA filed for its second base distribution rate increase and on October 31, 2022, the DPU approved a $6.7 million increase to base distribution rates and a $3.3 million increase to the Tax Act Credit Factor for effect on November 1, 2022. The DPU also approved the recovery of historical exogenous property taxes incurred from November 1, 2020 through October 31, 2022 of $8.6 million over a two-year period through a separate reconciling mechanism effective November 1, 2022. EGMA will request recovery of incremental property taxes incurred after October 31, 2022 in future exogenous filings.

## New Hampshire:

PSNH Distribution Rates: In connection with an October 9, 2020 settlement agreement, PSNH was permitted three step increases to reflect qualifying plant additions in calendar years 2019, 2020 and 2021. The first two step adjustments had effective dates of January 1, 2021 and August 1, 2021, respectively. 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 is being collected over the remainder of the rate year (November 1, 2022 – July 31, 2023).

PSNH Pole Acquisition Approval: On November 18, 2022, the NHPUC issued a decision that approved a proposed purchase agreement between PSNH and Consolidated Communications, in which PSNH would acquire approximately 343,000 jointly-owned utility poles and approximately 3,800 solely-owned poles and pole assets. The NHPUC also authorized PSNH to recover certain expenses associated with the operation and maintenance of the transferred poles, pole inspections, and vegetation management expenses through a new cost recovery mechanism, the Pole Plant Adjustment Mechanism (PPAM), subject to consummation of the purchase agreement. On December 16, 2022, a motion for rehearing of NHPUC’s approval was filed by an intervenor, which was denied by the NHPUC on February 8, 2023. PSNH cannot predict the timing of consummation of the proposed purchase agreement.

PSNH Energy Efficiency Plan: On November 12, 2021, the NHPUC issued an order rejecting the proposed 2021 through 2023 energy efficiency plan and significantly reduced funding and operational functions of the program. The order eliminated the recovery of performance incentives and made other key changes to the energy efficiency plan beginning in 2022. PSNH sought a rehearing of the order and was denied, which resulted in PSNH filing a formal appeal to the New Hampshire Supreme Court.

On February 10, 2022, the NHPUC issued an order that restored the 2022 energy efficiency rate to be consistent with the 2021 rate, which PSNH implemented effective March 1, 2022. On February 24, 2022, state legislation was signed into law that undid the most impactful effects of the November 12, 2021 NHPUC order. The legislation 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 legislation 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. As a result of the new legislation passed specific to this order, PSNH withdrew its appeal to the New Hampshire Supreme Court. PSNH made the required filing for the remainder of the 2022 through 2023 triennial plan on March 1, 2022, which was approved as filed by the NHPUC on April 29, 2022.

## Legislative and Policy Matters

Massachusetts: On August 11, 2022, Governor Baker signed into law climate-related legislation which, among other things, affirms the state’s commitment to contract for 5,600 MW of offshore wind by June 30, 2027, modifies the bidding process to encourage more competition among offshore wind developers, and provides incentives to increase the manufacturing and assembly of offshore wind components in Massachusetts. The law also provides incentives to encourage the sale and leasing of electric vehicles, promotes energy storage and electrification technologies, directs electric companies to develop grid modernization plans to upgrade distribution and transmission facilities, and initiates a pilot program that would allow up to ten communities in the state to restrict fossil fuel use in new buildings. Additionally, for long-term contracts that are approved by the DPU between developers of offshore wind generation and the contracting electric distribution company, the law provides for an annual



remuneration for the distribution company equal to 2.25 percent of the annual payments under the contract to compensate the distribution company for accepting the financial obligation of the long-term contract.

Federal: On August 16, 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law. This is a broad package of legislation that includes incentives and support for clean energy resource development. Most notable for Eversource, the investment tax credit (ITC) on offshore wind projects increases from 30 percent to 40 percent if certain requirements for labor and domestic content are met. The act also re-establishes the production tax credit for solar and wind energy projects, gives increased credit for projects in certain communities, and sets credits for qualifying clean energy generation and energy storage projects. The tax provisions of the IRA provide additional incentives for offshore wind projects and could reduce retail electricity costs for our customers related to those clean energy investments. The IRA includes other tax provisions focused on implementing a 15 percent minimum tax on adjusted financial statement income and a one percent excise tax on corporate share repurchases. The Department of Treasury and the Internal Revenue Service issued limited guidance in the fourth quarter; however, they are expected to issue additional needed guidance with respect to the application of the newly enacted IRA provisions in the future. We will continue to monitor and evaluate impacts on our consolidated financial statements. We currently do not expect the alternative minimum tax change to have a material impact on our earnings, financial condition or cash flows.

## 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.

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 prudence 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 prudence reviews from our regulators. We have approximately $1.4 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 prudence review as of December 31, 2022. Tropical Storm Isaias resulted in deferred storm restoration costs of approximately $235 million at CL&P as of December 31, 2022. While it is possible that some amount of the Tropical Storm Isaias costs may be disallowed by PURA in a future proceeding, any such amount cannot be estimated at this time. We believe that our storm restoration costs were prudently incurred, meet the criteria for cost recovery and are probable of recovery.

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

Pension, SERP and PBOP: We sponsor Pension, SERP and PBOP Plans to provide retirement benefits to our employees. Plan assets and the benefit obligation are presented on a net basis and we recognize the overfunded or underfunded status of the plans as an asset or liability on the balance sheet. These amounts are remeasured annually using a December 31st measurement date. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit expense/income. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate 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, 2022, our expected long-term rate-of-return assumption used to determine our pension and PBOP expense was 8.25 percent for the Eversource Service plans and 7 percent for the Aquarion plans. For the forecasted 2023 pension and PBOP expense, an expected long-term rate of return of 8.25 percent for the Eversource Service plans and 7 percent for the Aquarion 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, 2022, the discount rates used to determine the funded status 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. As of December 31, 2021, the discount rates used were within a range of 2.8 percent to 3.0 percent for the Pension and SERP Plans, and within a range of 2.91 percent to 2.92 percent for the PBOP Plans. The increase in the discount rates used to calculate the funded status resulted in a decrease to the Pension and SERP Plans' projected benefit obligation and the PBOP Plans' projected benefit obligation of $1.48 billion and $180.1 million, respectively, as of December 31, 2022.

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 2022 expense were within a range of 2.2 percent to 3.2 percent for the Pension and SERP Plans, and within a range of 2.3 percent to 3.3 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 2022, 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, 2022 and 2021, 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, 2022, for the Aquarion PBOP Plan, the health care trend rate used to determine the funded status for pre-65 retirees is 7 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 2022.

An increase in the discount rate used to determine our pension funded status would decrease our projected benefit obligation at December 31st, resulting in a lower unamortized actuarial loss to be recognized in future years' pension expense, subject to exceeding the 10 percent corridor. An increase in the discount rate at December 31st would also result in an increase in the interest cost component and a decrease 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 $181.6 million for the year ended December 31, 2022, and there was pre-tax net periodic benefit expense of $23.6 million and $56.9 million for the years ended December 31, 2021 and 2020,



respectively. For the PBOP Plans, pre-tax net periodic benefit income was $79.8 million, $60.5 million and $51.6 million for the years ended December 31, 2022, 2021 and 2020, 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 and PBOP expenses, therefore the change in their pension and PBOP expense does not impact earnings. 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 2023 for the Pension and SERP Plans will be approximately $114 million and for the PBOP Plans will be approximately $57 million. The change in pension income from 2022 to 2023 is driven primarily by an increase in the interest cost component due to a higher discount rate and lower expected return on assets due to a lower asset balance, partially offset by lower amortization of actuarial losses due to unrecognized actuarial gains arising in 2022. The change in PBOP income from 2022 to 2023 is driven primarily by an increase in the interest cost component due to a higher discount rate and lower expected return on assets due to a lower asset balance. For the PBOP Plans, there is no amortization of actuarial losses in 2023. 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. We contributed $80.0 million to the Pension Plans in 2022. 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 2023 and we do not expect to make pension contributions in 2023. 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 2023. We contributed $3.1 million to the Aquarion PBOP Plan in 2022. We currently estimate contributing $5.0 million and $2.9 million to the Aquarion Pension and PBOP Plans, respectively in 2023.

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:

<table><tr><td rowspan="2"></td><td colspan="2">Pension Plans (excluding SERP Plans)</td><td colspan="2">PBOP Plans</td></tr><tr><td>Decrease in Plan Income</td><td>Increase in Plan Expense</td><td colspan="2">Decrease in Plan Income</td></tr><tr><td>(Millions of Dollars)</td><td colspan="2">For the Years Ended December 31,</td><td colspan="2">For the Years Ended December 31,</td></tr><tr><td>Eversource</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td></tr><tr><td>Lower expected long-term rate of return</td><td>32.5</td><td>26.5</td><td>5.6</td><td>4.8</td></tr><tr><td>Lower discount rate</td><td>32.6</td><td>27.0</td><td>1.7</td><td>2.6</td></tr><tr><td>Higher compensation rate</td><td>7.6</td><td>9.9</td><td>N/A</td><td>N/A</td></tr></table>

Goodwill: We recorded goodwill on our balance sheet associated with previous mergers and acquisitions, all of which totaled $4.52 billion as of December 31, 2022. 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, 2022, 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 $951 million to Water Distribution.

Goodwill recorded and allocated to the Water Distribution reporting unit included $44.8 million in 2022 arising from the acquisition of The Torrington Water Company on October 3, 2022 and $22.2 million arising from the acquisition of NESC on December 1, 2021, which included measurement period increases in 2022 totaling $0.5 million.

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.

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, 2022 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 2022 goodwill impairment assessment resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment. 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 2022.

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. For our offshore wind equity method investment, basis differences are related to intangible assets for PPAs that will be amortized over the term of the PPAs, and equity method goodwill that is not amortized. Capitalized interest associated with our offshore wind equity method investment is included in the investment balance.

Equity method investments are assessed for impairment when conditions exist that indicate that the fair value of the investment is less than book value. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations 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. No impairments occurred during 2022. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment.

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

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

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

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

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

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. Significant unobservable inputs utilized in the models include energy-related product prices for future years for long-dated derivative contracts and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk-adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

## RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the years ended December 31, 2022 and 2021 included in this Annual Report on Form 10-K:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>Increase</td><td></td></tr><tr><td>Operating Revenues</td><td>$ 12,289.3</td><td>$ 9,863.1</td><td>$ 2,426.2</td><td></td></tr><tr><td>Operating Expenses:</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased Power, Purchased Natural Gas and Transmission</td><td>5,014.1</td><td>3,372.3</td><td>1,641.8</td><td></td></tr><tr><td>Operations and Maintenance</td><td>1,865.3</td><td>1,739.7</td><td>125.6</td><td></td></tr><tr><td>Depreciation</td><td>1,194.2</td><td>1,103.0</td><td>91.2</td><td></td></tr><tr><td>Amortization</td><td>448.9</td><td>232.0</td><td>216.9</td><td></td></tr><tr><td>Energy Efficiency Programs</td><td>658.0</td><td>592.8</td><td>65.2</td><td></td></tr><tr><td>Taxes Other Than Income Taxes</td><td>910.6</td><td>830.0</td><td>80.6</td><td></td></tr><tr><td>Total Operating Expenses</td><td>10,091.1</td><td>7,869.8</td><td>2,221.3</td><td></td></tr><tr><td>Operating Income</td><td>2,198.2</td><td>1,993.3</td><td>204.9</td><td></td></tr><tr><td>Interest Expense</td><td>678.3</td><td>582.4</td><td>95.9</td><td></td></tr><tr><td>Other Income, Net</td><td>346.1</td><td>161.3</td><td>184.8</td><td></td></tr><tr><td>Income Before Income Tax Expense</td><td>1,866.0</td><td>1,572.2</td><td>293.8</td><td></td></tr><tr><td>Income Tax Expense</td><td>453.6</td><td>344.2</td><td>109.4</td><td></td></tr><tr><td>Net Income</td><td>1,412.4</td><td>1,228.0</td><td>184.4</td><td></td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>7.5</td><td>7.5</td><td>—</td><td></td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 1,404.9</td><td>$ 1,220.5</td><td>$ 184.4</td><td></td></tr></table>

## 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:

<table><tr><td rowspan="3"></td><td colspan="4">Electric</td><td colspan="4">Firm Natural Gas</td><td colspan="4">Water</td></tr><tr><td colspan="2">Sales Volumes (GWh)</td><td rowspan="2">Percentage (Decrease)/ Increase</td><td colspan="2">Sales Volumes (MMcf)</td><td rowspan="2">Percentage Increase</td><td colspan="2">Sales Volumes (MG)</td><td rowspan="2">Percentage Increase</td><td></td><td></td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td></td></tr><tr><td>Traditional</td><td>7,764</td><td>7,782</td><td>(0.2)%</td><td>—</td><td>—</td><td>—</td><td>%</td><td>1,857</td><td>1,256</td><td>47.9 %</td><td></td></tr><tr><td>Decoupled and Special Contracts (1)</td><td>43,493</td><td>43,228</td><td>0.6 %</td><td>152,291</td><td>150,145</td><td>1.4 %</td><td>23,154</td><td>22,099</td><td>4.8 %</td><td></td><td></td></tr><tr><td>Total Sales Volumes</td><td>51,257</td><td>51,010</td><td>0.5 %</td><td>152,291</td><td>150,145</td><td>1.4 %</td><td>25,011</td><td>23,355</td><td>7.1 %</td><td></td><td></td></tr></table>

(1) Special contracts are unique to Yankee Gas natural gas distribution customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.

Weather, fluctuations in energy supply costs, 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: Operating Revenues by segment increased in 2022, as compared to 2021, as follows:

<table><tr><td>(Millions of Dollars)</td><td>Increase/(Decrease)</td></tr><tr><td>Electric Distribution</td><td>$ 1,981.7</td></tr><tr><td>Natural Gas Distribution</td><td>426.0</td></tr><tr><td>Electric Transmission</td><td>174.1</td></tr><tr><td>Water Distribution</td><td>11.2</td></tr><tr><td>Other</td><td>81.5</td></tr><tr><td>Eliminations</td><td>(248.3)</td></tr><tr><td>Total Operating Revenues</td><td>$ 2,426.2</td></tr></table>

Electric and Natural Gas (excluding EGMA) Distribution Revenues:

Base Distribution Revenues:

- Base electric distribution revenues increased $43.4 million in 2022, as compared to 2021, due primarily to the impact of base distribution rate increases at NSTAR Electric effective January 1, 2022 resulting from its annual Performance Based Rate Adjustment filing and at PSNH effective August 1, 2021 and November 1, 2022.

- Base natural gas distribution revenues (excluding EGMA) increased $21.4 million in 2022, as compared to 2021, due primarily to base distribution rate increases at NSTAR Gas effective November 1, 2021 and November 1, 2022.

Electric distribution revenues at CL&P also increased $93.4 million in 2022, as compared to 2021, due to the absence of a 2021 reserve established to provide bill credits to customers as a result of CL&P's settlement agreement on October 1, 2021 and a storm performance penalty assessed by PURA. In the 2021 settlement agreement, CL&P agreed to provide a total of $65 million of customer credits, which were distributed based on customer sales over a two-month period from December 1, 2021 to January 31, 2022. Additionally, CL&P recorded a $28.4 million reserve in 2021 for a civil penalty for non-compliance with storm performance standards that was provided as credits to customers on electric bills beginning on September 1, 2021 over a one-year period.

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 and amortization expense 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.

Tracked distribution revenues increased/(decreased) in 2022, as compared to 2021, due primarily to the following:

<table><tr><td>(Millions of Dollars)</td><td>Electric Distribution</td><td>Natural Gas Distribution</td></tr><tr><td>Retail Tariff Tracked Revenues:</td><td></td><td></td></tr><tr><td>Energy supply procurement</td><td>$ 1,032.9</td><td>$ 144.1</td></tr><tr><td>Retail transmission</td><td>246.8</td><td>—</td></tr><tr><td>CL&amp;P FMCC</td><td>(87.8)</td><td>—</td></tr><tr><td>Energy efficiency</td><td>52.9</td><td>(1.4)</td></tr><tr><td>Stranded costs</td><td>(72.5)</td><td>—</td></tr><tr><td>Other distribution tracking mechanisms</td><td>49.8</td><td>31.7</td></tr><tr><td>Wholesale Market Sales Revenue</td><td>615.1</td><td>33.3</td></tr></table>

The increase in energy supply procurement within electric distribution and natural gas distribution in 2022, as compared to 2021, was driven by higher average prices and higher 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 increase in electric distribution wholesale market sales revenue in 2022, as compared to 2021, was due primarily to higher 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 increased approximately 90 percent in 2022, as compared to 2021, driven primarily by higher natural gas prices in New England. The increase was also due to higher wholesale sales volumes at CL&P resulting from the sale of output generated by the Seabrook PPA beginning in the first quarter of 2022. 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. The increase in electric distribution wholesale market sales revenues was also driven by higher proceeds from the sale of transmission rights over a one-year period under CL&P's, NSTAR Electric's and PSNH's Hydro-Quebec transmission support agreements. Proceeds from these sales are credited back to customers.

The decrease in CL&P’s FMCC revenues and PSNH’s stranded cost revenues was driven by decreases in the retail rate, which reflect the net benefit of higher wholesale market sales received in the ISO-NE market for long-term state approved energy contracts at CL&P and PSNH, which are then credited back to customers through these retail rates. The decrease in PSNH’s stranded cost revenues was also due to lower stranded costs to be recovered due to higher Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are credited back to customers.

EGMA Natural Gas Distribution Revenues: EGMA total operating revenues at the natural gas distribution segment increased by $193.8 million in 2022, as compared to 2021. Included in the total operating revenues increase was EGMA's base natural gas distribution revenues increase of $26.3 million in 2022, as compared to 2021, due primarily to base distribution rate increases effective November 1, 2021 and November 1, 2022.

Electric Transmission Revenues: Electric transmission revenues increased $174.1 million in 2022, as compared to 2021, 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 purchasing electricity and natural gas on behalf of our customers and the cost of energy purchase contracts, as required by regulation. These electric and natural gas supply costs and other energy-related costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Purchased Natural Gas and Transmission expense increased in 2022, as compared to 2021, due primarily to the following:

<table><tr><td>(Millions of Dollars)</td><td>Increase</td></tr><tr><td>Purchased Power Costs</td><td>$ 1,217.5</td></tr><tr><td>Natural Gas Costs</td><td>307.7</td></tr><tr><td>Transmission Costs</td><td>277.1</td></tr><tr><td>Eliminations</td><td>(160.5)</td></tr><tr><td>Total Purchased Power, Purchased Natural Gas and Transmission</td><td>$ 1,641.8</td></tr></table>

The increase in purchased power expense at the electric distribution business in 2022, as compared to 2021, was driven primarily by higher energy supply procurement costs resulting from higher average prices and higher average supply-related sales volumes, as well as higher long-term contractual energy-related costs that are recovered in the non-bypassable component of the FMCC mechanism at CL&P, and higher net metering costs at NSTAR Electric and CL&P.

The increase in costs at the natural gas distribution segment in 2022, as compared to 2021, was due primarily to higher average prices and higher average supply-related sales volumes.

The increase in transmission costs in 2022, as compared to 2021, was primarily the result of an increase resulting from the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers. This was partially offset by a decrease in Local Network Service charges, which reflects the cost of transmission service provided by Eversource over our local transmission network, and a decrease in costs billed by ISO-NE that support regional grid investments.



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). Operations and Maintenance expense increased in 2022, as compared to 2021, due primarily to the following:

<table><tr><td>(Millions of Dollars)</td><td>Increase/(Decrease)</td></tr><tr><td>Base Electric Distribution (Non-Tracked Costs):</td><td></td></tr><tr><td>General costs (including vendor services in corporate areas, insurance, fees and assessments)</td><td>$ 26.8</td></tr><tr><td>Shared corporate costs (including computer software depreciation at Eversource Service)</td><td>25.0</td></tr><tr><td>Storm costs</td><td>22.0</td></tr><tr><td>Commitment to energy assistance program as part of CL&amp;P rate relief plan</td><td>10.0</td></tr><tr><td>Operations-related expenses (including vegetation management, vendor services and vehicles)</td><td>4.4</td></tr><tr><td>Employee-related expenses, including labor and benefits</td><td>(20.5)</td></tr><tr><td>Absence in 2022 of CL&amp;P charge to fund various customer assistance initiatives associated with the settlement agreement on October 1, 2021</td><td>(10.0)</td></tr><tr><td>Other non-tracked operations and maintenance</td><td>20.3</td></tr><tr><td>Total Base Electric Distribution (Non-Tracked Costs)</td><td>78.0</td></tr><tr><td>Tracked Electric Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher transmission expenses of $35.1 million and increase of $34.7 million due to higher pension tracking mechanism at NSTAR Electric</td><td>72.4</td></tr><tr><td>Total Electric Distribution and Electric Transmission</td><td>150.4</td></tr><tr><td>Natural Gas Distribution:</td><td></td></tr><tr><td>Base (Non-Tracked Costs) - Increase due primarily to higher employee-related expenses and higher shared corporate costs</td><td>12.6</td></tr><tr><td>Tracked Costs</td><td>18.6</td></tr><tr><td>Total Natural Gas Distribution</td><td>31.2</td></tr><tr><td>Water Distribution</td><td>8.3</td></tr><tr><td>Parent and Other Companies and Eliminations:</td><td></td></tr><tr><td>Eversource Parent and Other Companies - other operations and maintenance</td><td>30.5</td></tr><tr><td>Transaction and Transition Costs</td><td>(11.8)</td></tr><tr><td>Eliminations</td><td>(83.0)</td></tr><tr><td>Total Operations and Maintenance</td><td>$ 125.6</td></tr></table>

Depreciation expense increased in 2022, as compared to 2021, due to higher utility plant in service balances.

Amortization expense includes the deferral of energy supply, 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. Energy supply and energy-related 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 increased in 2022, as compared to 2021, due primarily to the deferral adjustment of energy supply, energy-related and other tracked costs at CL&P (included in the non-bypassable component of the FMCC mechanism), and NSTAR Electric, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The increase in the FMCC mechanism at CL&P was driven primarily by the net costs and benefits of the long-term state approved contracts that Eversource has executed with Millstone and Seabrook, among others. The increase was partially offset by a decrease in storm amortization expense at CL&P related to the completion of the amortization period of certain storm cost deferred assets.

Energy Efficiency Programs expense increased in 2022, as compared to 2021, due primarily 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 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 in 2022, as compared to 2021, due primarily to an increase in property taxes as a result of higher utility plant balances and higher Connecticut gross earnings taxes.

Interest Expense increased in 2022, as compared to 2021, due primarily to an increase in interest on long-term debt as a result of new debt issuances ($101.3 million), an increase in interest on short-term notes payable ($10.9 million), an increase in interest expense on regulatory deferrals ($6.7 million), and higher amortization of debt discounts and premiums, net ($3.3 million), partially offset by an increase in capitalized AFUDC related to debt funds and other capitalized interest ($20.0 million), lower interest resulting from the 2022 payment of withheld property taxes at NSTAR Electric ($5.0 million), and a decrease in RRB interest expense ($1.4 million).

Other Income, Net increased in 2022, as compared to 2021, due primarily to an increase related to pension, SERP and PBOP non-service income components ($135.4 million), an increase in interest income primarily from regulatory deferrals ($24.9 million), an increase in capitalized AFUDC related to equity funds ($10.0 million), an increase in equity in earnings related to Eversource's equity method investments ($8.7 million), a gain on the sale of property in 2022 ($2.5 million) and investment income in 2022 compared to investment losses in 2021 driven by market volatility ($2.1 million).

Income Tax Expense increased in 2022, as compared to 2021, due primarily to higher pre-tax earnings ($61.7 million), higher state taxes ($5.9 million), lower share-based payment excess tax benefits ($1.9 million), an increase in return to provision adjustments ($11.2 million), a decrease in



amortization of EDIT ($20.0 million), an increase in valuation allowances ($8.5 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.2 million).

Results of Operations for the years ended December 31, 2022 and 2021 for each of CL&P, NSTAR Electric and PSNH have been omitted from this report but are set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

## 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: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As of December 31, 2022, approximately 98 percent of our long-term debt was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rates, annual interest expense would have increased by a pre-tax amount of $3.5 million.

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, 2022, our regulated companies held collateral (letters of credit or cash) of $32 million from counterparties related to our standard service contracts. As of December 31, 2022, Eversource had $35.7 million of cash posted with ISO-NE related to energy transactions. For further information on cash collateral deposited and posted with counterparties, see Note 1M, "Summary of Significant Accounting Policies - Supplemental Cash Flow Information," to the financial statements.

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



## Item 8. Financial Statements and Supplementary Data
Eversource

Management’s Report on Internal Controls Over Financial Reporting
Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Consolidated Financial Statements

## 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, 2022.

February 15, 2023



## 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, 2022, 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, 2022, 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, 2022, of the Company and our report dated February 15, 2023, 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 15, 2023



## 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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 15, 2023, 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 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’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.

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.

## /s/ Deloitte & Touche LLP

Hartford, Connecticut
February 15, 2023

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



<table><tr><td rowspan="2">(Thousands of Dollars)</td><td colspan="2">As of December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Current Assets:</td><td></td><td></td></tr><tr><td>Cash</td><td>$ 47,597</td><td>$ 66,773</td></tr><tr><td>Cash Equivalents</td><td>327,006</td><td>—</td></tr><tr><td>Receivables, Net (net of allowance for uncollectible accounts of $486,297 and $417,406 as of December 31, 2022 and 2021, respectively)</td><td>1,517,138</td><td>1,226,069</td></tr><tr><td>Unbilled Revenues</td><td>238,968</td><td>210,879</td></tr><tr><td>Materials, Supplies, Natural Gas and REC Inventory</td><td>374,395</td><td>267,547</td></tr><tr><td>Regulatory Assets</td><td>1,335,491</td><td>1,129,093</td></tr><tr><td>Prepayments and Other Current Assets</td><td>382,603</td><td>369,759</td></tr><tr><td>Total Current Assets</td><td>4,223,198</td><td>3,270,120</td></tr><tr><td>Property, Plant and Equipment, Net</td><td>36,112,820</td><td>33,377,650</td></tr><tr><td>Deferred Debits and Other Assets:</td><td></td><td></td></tr><tr><td>Regulatory Assets</td><td>4,242,794</td><td>4,586,709</td></tr><tr><td>Goodwill</td><td>4,522,632</td><td>4,477,269</td></tr><tr><td>Investments in Unconsolidated Affiliates</td><td>2,176,080</td><td>1,436,293</td></tr><tr><td>Prepaid Pension and PBOP</td><td>1,045,524</td><td>271,987</td></tr><tr><td>Marketable Securities</td><td>366,508</td><td>460,347</td></tr><tr><td>Other Long-Term Assets</td><td>541,344</td><td>611,769</td></tr><tr><td>Total Deferred Debits and Other Assets</td><td>12,894,882</td><td>11,844,374</td></tr><tr><td>Total Assets</td><td>$ 53,230,900</td><td>$ 48,492,144</td></tr><tr><td>LIABILITIES AND CAPITALIZATION</td><td></td><td></td></tr><tr><td>Current Liabilities:</td><td></td><td></td></tr><tr><td>Notes Payable</td><td>$ 1,442,200</td><td>$ 1,505,450</td></tr><tr><td>Long-Term Debt - Current Portion</td><td>1,320,129</td><td>1,193,097</td></tr><tr><td>Rate Reduction Bonds - Current Portion</td><td>43,210</td><td>43,210</td></tr><tr><td>Accounts Payable</td><td>2,113,905</td><td>1,672,230</td></tr><tr><td>Regulatory Liabilities</td><td>890,786</td><td>602,432</td></tr><tr><td>Other Current Liabilities</td><td>989,053</td><td>830,620</td></tr><tr><td>Total Current Liabilities</td><td>6,799,283</td><td>5,847,039</td></tr><tr><td>Deferred Credits and Other Liabilities:</td><td></td><td></td></tr><tr><td>Accumulated Deferred Income Taxes</td><td>5,067,902</td><td>4,597,120</td></tr><tr><td>Regulatory Liabilities</td><td>3,930,305</td><td>3,866,251</td></tr><tr><td>Derivative Liabilities</td><td>143,929</td><td>235,387</td></tr><tr><td>Asset Retirement Obligations</td><td>502,713</td><td>500,111</td></tr><tr><td>Accrued Pension, SERP and PBOP</td><td>135,473</td><td>242,463</td></tr><tr><td>Other Long-Term Liabilities</td><td>888,081</td><td>971,080</td></tr><tr><td>Total Deferred Credits and Other Liabilities</td><td>10,668,403</td><td>10,412,412</td></tr><tr><td>Long-Term Debt</td><td>19,723,994</td><td>17,023,577</td></tr><tr><td>Rate Reduction Bonds</td><td>410,492</td><td>453,702</td></tr><tr><td>Noncontrolling Interest - Preferred Stock of Subsidiaries</td><td>155,570</td><td>155,570</td></tr><tr><td>Common Shareholders&#x27; Equity:</td><td></td><td></td></tr><tr><td>Common Shares</td><td>1,799,920</td><td>1,789,092</td></tr><tr><td>Capital Surplus, Paid In</td><td>8,401,731</td><td>8,098,514</td></tr><tr><td>Retained Earnings</td><td>5,527,153</td><td>5,005,391</td></tr><tr><td>Accumulated Other Comprehensive Loss</td><td>(39,421)</td><td>(42,275)</td></tr><tr><td>Treasury Stock</td><td>(216,225)</td><td>(250,878)</td></tr><tr><td>Common Shareholders&#x27; Equity</td><td>15,473,158</td><td>14,599,844</td></tr><tr><td>Commitments and Contingencies (Note 13)</td><td></td><td></td></tr><tr><td>Total Liabilities and Capitalization</td><td>$ 53,230,900</td><td>$ 48,492,144</td></tr></table>

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



<table><tr><td rowspan="2">(Thousands of Dollars, Except Share Information)</td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Operating Revenues</td><td>$ 12,289,336</td><td>$ 9,863,085</td><td>$ 8,904,430</td></tr><tr><td>Operating Expenses:</td><td></td><td></td><td></td></tr><tr><td>Purchased Power, Purchased Natural Gas and Transmission</td><td>5,014,074</td><td>3,372,344</td><td>2,987,840</td></tr><tr><td>Operations and Maintenance</td><td>1,865,328</td><td>1,739,685</td><td>1,480,252</td></tr><tr><td>Depreciation</td><td>1,194,246</td><td>1,103,008</td><td>981,380</td></tr><tr><td>Amortization</td><td>448,892</td><td>231,965</td><td>177,679</td></tr><tr><td>Energy Efficiency Programs</td><td>658,051</td><td>592,775</td><td>535,760</td></tr><tr><td>Taxes Other Than Income Taxes</td><td>910,591</td><td>829,987</td><td>752,785</td></tr><tr><td>Total Operating Expenses</td><td>10,091,182</td><td>7,869,764</td><td>6,915,696</td></tr><tr><td>Operating Income</td><td>2,198,154</td><td>1,993,321</td><td>1,988,734</td></tr><tr><td>Interest Expense</td><td>678,274</td><td>582,334</td><td>538,452</td></tr><tr><td>Other Income, Net</td><td>346,088</td><td>161,282</td><td>108,590</td></tr><tr><td>Income Before Income Tax Expense</td><td>1,865,968</td><td>1,572,269</td><td>1,558,872</td></tr><tr><td>Income Tax Expense</td><td>453,574</td><td>344,223</td><td>346,186</td></tr><tr><td>Net Income</td><td>1,412,394</td><td>1,228,046</td><td>1,212,686</td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>7,519</td><td>7,519</td><td>7,519</td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 1,404,875</td><td>$ 1,220,527</td><td>$ 1,205,167</td></tr><tr><td>Basic Earnings Per Common Share</td><td>$ 4.05</td><td>$ 3.55</td><td>$ 3.56</td></tr><tr><td>Diluted Earnings Per Common Share</td><td>$ 4.05</td><td>$ 3.54</td><td>$ 3.55</td></tr><tr><td>Weighted Average Common Shares Outstanding:</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>346,783,444</td><td>343,972,926</td><td>338,836,147</td></tr><tr><td>Diluted</td><td>347,246,768</td><td>344,631,056</td><td>339,847,062</td></tr></table>

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

## CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

<table><tr><td rowspan="2">(Thousands of Dollars)</td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Net Income</td><td>$ 1,412,394</td><td>$ 1,228,046</td><td>$ 1,212,686</td></tr><tr><td>Other Comprehensive Income/(Loss), Net of Tax:</td><td></td><td></td><td></td></tr><tr><td>Qualified Cash Flow Hedging Instruments</td><td>20</td><td>972</td><td>1,596</td></tr><tr><td>Changes in Unrealized (Losses)/Gains on Marketable Securities</td><td>(1,636)</td><td>(671)</td><td>342</td></tr><tr><td>Changes in Funded Status of Pension, SERP and PBOP Benefit Plans</td><td>4,470</td><td>33,835</td><td>(13,290)</td></tr><tr><td>Other Comprehensive Income/(Loss), Net of Tax</td><td>2,854</td><td>34,136</td><td>(11,352)</td></tr><tr><td>Comprehensive Income Attributable to Noncontrolling Interests</td><td>(7,519)</td><td>(7,519)</td><td>(7,519)</td></tr><tr><td>Comprehensive Income Attributable to Common Shareholders</td><td>$ 1,407,729</td><td>$ 1,254,663</td><td>$ 1,193,815</td></tr></table>

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



<table><tr><td></td><td colspan="2">Common Shares</td><td>Capital Surplus, Paid In</td><td>Retained Earnings</td><td>Accumulated Other Comprehensive Loss</td><td>Treasury Stock</td><td>Total Common Shareholders&#x27; Equity</td></tr><tr><td>(Thousands of Dollars, Except Share Information)</td><td>Shares</td><td>Amount</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance as of January 1, 2020</td><td>329,880,645</td><td>$ 1,729,292</td><td>$ 7,087,768</td><td>$ 4,177,048</td><td>$ (65,059)</td><td>$ (299,055)</td><td>$ 12,629,994</td></tr><tr><td>Net Income</td><td></td><td></td><td></td><td>1,212,686</td><td></td><td></td><td>1,212,686</td></tr><tr><td>Dividends on Common Shares - $2.27 Per Share</td><td></td><td></td><td></td><td>(767,500)</td><td></td><td></td><td>(767,500)</td></tr><tr><td>Dividends on Preferred Stock</td><td></td><td></td><td></td><td>(7,519)</td><td></td><td></td><td>(7,519)</td></tr><tr><td>Issuance of Common Shares - $5 par value</td><td>11,960,000</td><td>59,800</td><td>889,860</td><td></td><td></td><td></td><td>949,660</td></tr><tr><td>Long-Term Incentive Plan Activity</td><td></td><td></td><td>7,890</td><td></td><td></td><td></td><td>7,890</td></tr><tr><td>Issuance of Treasury Shares</td><td>1,113,378</td><td></td><td>50,812</td><td></td><td></td><td>21,076</td><td>71,888</td></tr><tr><td>Capital Stock Expense</td><td></td><td></td><td>(20,667)</td><td></td><td></td><td></td><td>(20,667)</td></tr><tr><td>Adoption of Accounting Standards Update 2016-13</td><td></td><td></td><td></td><td>(1,514)</td><td></td><td></td><td>(1,514)</td></tr><tr><td>Other Comprehensive Loss</td><td></td><td></td><td></td><td></td><td>(11,352)</td><td></td><td>(11,352)</td></tr><tr><td>Balance as of December 31, 2020</td><td>342,954,023</td><td>1,789,092</td><td>8,015,663</td><td>4,613,201</td><td>(76,411)</td><td>(277,979)</td><td>14,063,566</td></tr><tr><td>Net Income</td><td></td><td></td><td></td><td>1,228,046</td><td></td><td></td><td>1,228,046</td></tr><tr><td>Dividends on Common Shares - $2.41 Per Share</td><td></td><td></td><td></td><td>(828,337)</td><td></td><td></td><td>(828,337)</td></tr><tr><td>Dividends on Preferred Stock</td><td></td><td></td><td></td><td>(7,519)</td><td></td><td></td><td>(7,519)</td></tr><tr><td>Long-Term Incentive Plan Activity</td><td></td><td></td><td>3,537</td><td></td><td></td><td></td><td>3,537</td></tr><tr><td>Issuance of Treasury Shares</td><td>986,656</td><td></td><td>49,913</td><td></td><td></td><td>18,451</td><td>68,364</td></tr><tr><td>Issuance of Treasury Shares for Acquisition of New England Service Company</td><td>462,517</td><td></td><td>29,401</td><td></td><td></td><td>8,650</td><td>38,051</td></tr><tr><td>Other Comprehensive Income</td><td></td><td></td><td></td><td></td><td>34,136</td><td></td><td>34,136</td></tr><tr><td>Balance as of December 31, 2021</td><td>344,403,196</td><td>1,789,092</td><td>8,098,514</td><td>5,005,391</td><td>(42,275)</td><td>(250,878)</td><td>14,599,844</td></tr><tr><td>Net Income</td><td></td><td></td><td></td><td>1,412,394</td><td></td><td></td><td>1,412,394</td></tr><tr><td>Dividends on Common Shares - $2.55 Per Share</td><td></td><td></td><td></td><td>(883,113)</td><td></td><td></td><td>(883,113)</td></tr><tr><td>Dividends on Preferred Stock</td><td></td><td></td><td></td><td>(7,519)</td><td></td><td></td><td>(7,519)</td></tr><tr><td>Issuance of Common Shares - $5 par value</td><td>2,165,671</td><td>10,828</td><td>189,077</td><td></td><td></td><td></td><td>199,905</td></tr><tr><td>Long-Term Incentive Plan Activity</td><td></td><td></td><td>8,335</td><td></td><td></td><td></td><td>8,335</td></tr><tr><td>Issuance of Treasury Shares</td><td>949,724</td><td></td><td>53,822</td><td></td><td></td><td>17,350</td><td>71,172</td></tr><tr><td>Capital Stock Expense</td><td></td><td></td><td>(2,847)</td><td></td><td></td><td></td><td>(2,847)</td></tr><tr><td>Issuance of Treasury Shares for Acquisition of The Torrington Water Company</td><td>925,264</td><td></td><td>54,830</td><td></td><td></td><td>17,303</td><td>72,133</td></tr><tr><td>Other Comprehensive Income</td><td></td><td></td><td></td><td></td><td>2,854</td><td></td><td>2,854</td></tr><tr><td>Balance as of December 31, 2022</td><td>348,443,855</td><td>$ 1,799,920</td><td>$ 8,401,731</td><td>$ 5,527,153</td><td>$</td><td>(39,421)</td><td>$ (216,225)</td><td>$ 15,473,158</td></tr></table>

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



<table><tr><td rowspan="2">(Thousands of Dollars)</td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Operating Activities:</td><td></td><td></td><td></td></tr><tr><td>Net Income</td><td>$ 1,412,394</td><td>$ 1,228,046</td><td>$ 1,212,686</td></tr><tr><td>Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:</td><td></td><td></td><td></td></tr><tr><td>Depreciation</td><td>1,194,246</td><td>1,103,008</td><td>981,380</td></tr><tr><td>Deferred Income Taxes</td><td>346,779</td><td>347,056</td><td>257,154</td></tr><tr><td>Uncollectible Expense</td><td>61,876</td><td>60,886</td><td>53,461</td></tr><tr><td>Pension, SERP and PBOP (Income)/Expense, Net</td><td>(160,857)</td><td>(14,693)</td><td>12,888</td></tr><tr><td>Pension and PBOP Contributions</td><td>(83,148)</td><td>(182,344)</td><td>(111,524)</td></tr><tr><td>Regulatory Under Recoveries, Net</td><td>(205,294)</td><td>(314,211)</td><td>(516,411)</td></tr><tr><td>(Customer Credits)/Reserve at CL&amp;P related to PURA Settlement Agreement and Storm Performance Penalty</td><td>(72,041)</td><td>81,274</td><td>—</td></tr><tr><td>Amortization</td><td>448,892</td><td>231,965</td><td>177,679</td></tr><tr><td>Cost of Removal Expenditures</td><td>(303,755)</td><td>(242,130)</td><td>(148,332)</td></tr><tr><td>Payment of Withheld Property Taxes</td><td>(78,446)</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>(39,192)</td><td>(64,640)</td><td>(25,957)</td></tr><tr><td>Changes in Current Assets and Liabilities:</td><td></td><td></td><td></td></tr><tr><td>Receivables and Unbilled Revenues, Net</td><td>(470,593)</td><td>(135,505)</td><td>(351,843)</td></tr><tr><td>Taxes Receivable/Accrued, Net</td><td>18,358</td><td>(110,621)</td><td>43,819</td></tr><tr><td>Accounts Payable</td><td>377,657</td><td>(29,201)</td><td>122,567</td></tr><tr><td>Other Current Assets and Liabilities, Net</td><td>(45,583)</td><td>3,710</td><td>(24,995)</td></tr><tr><td>Net Cash Flows Provided by Operating Activities</td><td>2,401,293</td><td>1,962,600</td><td>1,682,572</td></tr><tr><td>Investing Activities:</td><td></td><td></td><td></td></tr><tr><td>Investments in Property, Plant and Equipment</td><td>(3,441,852)</td><td>(3,175,080)</td><td>(2,942,996)</td></tr><tr><td>Proceeds from Sales of Marketable Securities</td><td>457,612</td><td>447,893</td><td>434,124</td></tr><tr><td>Purchases of Marketable Securities</td><td>(424,174)</td><td>(414,980)</td><td>(401,823)</td></tr><tr><td>Acquisition of Assets of Columbia Gas of Massachusetts, Net of Restricted Cash</td><td>—</td><td>—</td><td>(1,113,252)</td></tr><tr><td>Investments in Unconsolidated Affiliates</td><td>(742,496)</td><td>(327,385)</td><td>(239,673)</td></tr><tr><td>Proceeds from the Sale of Hingham Water System</td><td>—</td><td>—</td><td>110,536</td></tr><tr><td>Other Investing Activities</td><td>20,420</td><td>22,178</td><td>23,809</td></tr><tr><td>Net Cash Flows Used in Investing Activities</td><td>(4,130,490)</td><td>(3,447,374)</td><td>(4,129,275)</td></tr><tr><td>Financing Activities:</td><td></td><td></td><td></td></tr><tr><td>Issuance of Common Shares, Net of Issuance Costs</td><td>197,058</td><td>—</td><td>928,992</td></tr><tr><td>Cash Dividends on Common Shares</td><td>(860,033)</td><td>(805,439)</td><td>(744,665)</td></tr><tr><td>Cash Dividends on Preferred Stock</td><td>(7,519)</td><td>(7,519)</td><td>(7,519)</td></tr><tr><td>(Decrease)/Increase in Notes Payable</td><td>(78,170)</td><td>256,125</td><td>13,955</td></tr><tr><td>Repayment of Rate Reduction Bonds</td><td>(43,210)</td><td>(43,210)</td><td>(43,210)</td></tr><tr><td>Issuance of Long-Term Debt</td><td>4,045,000</td><td>3,230,000</td><td>2,760,000</td></tr><tr><td>Retirement of Long-Term Debt</td><td>(1,175,000)</td><td>(1,142,500)</td><td>(327,236)</td></tr><tr><td>Other Financing Activities</td><td>(48,185)</td><td>(46,625)</td><td>14,273</td></tr><tr><td>Net Cash Flows Provided by Financing Activities</td><td>2,029,941</td><td>1,440,832</td><td>2,594,590</td></tr><tr><td>Net Increase/(Decrease) in Cash, Cash Equivalents and Restricted Cash</td><td>300,744</td><td>(43,942)</td><td>147,887</td></tr><tr><td>Cash, Cash Equivalents and Restricted Cash - Beginning of Year</td><td>221,008</td><td>264,950</td><td>117,063</td></tr><tr><td>Cash, Cash Equivalents and Restricted Cash - End of Year</td><td>$ 521,752</td><td>$ 221,008</td><td>$ 264,950</td></tr></table>

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

The 2022 financial statements for CL&P, NSTAR Electric and PSNH have been omitted from this report but are set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.



# EVERSOURCE ENERGY AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

## COMBINED NOTES TO FINANCIAL STATEMENTS

Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the financial statements.

## 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

## A. About Eversource, CL&P, NSTAR Electric and PSNH

Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business. Eversource Energy's wholly-owned regulated utility subsidiaries consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR Gas and EGMA (natural gas utilities), and Aquarion (water utilities). Eversource provides energy delivery and/or water service to approximately 4.4 million electric, natural gas and water customers through twelve regulated utilities in Connecticut, Massachusetts and New Hampshire.

Eversource, CL&P, NSTAR Electric and PSNH are reporting companies under the Securities Exchange Act of 1934. Eversource Energy is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other Eversource companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. Eversource's regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P, Yankee Gas and Aquarion, the DPU for NSTAR Electric, NSTAR Gas, EGMA and Aquarion, and the NHPUC for PSNH and Aquarion).

CL&P, NSTAR Electric and PSNH furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire, respectively. NSTAR Gas and EGMA are engaged in the distribution and sale of natural gas to customers within Massachusetts and Yankee Gas is engaged in the distribution and sale of natural gas to customers within Connecticut. Aquarion is engaged in the collection, treatment and distribution of water in Connecticut, Massachusetts and New Hampshire. CL&P, NSTAR Electric and PSNH's results include the operations of their respective distribution and transmission businesses. The distribution business also includes the results of NSTAR Electric's solar power facilities.

Eversource Service, Eversource's service company, and several wholly-owned real estate subsidiaries of Eversource, provide support services to Eversource, including its regulated companies.

## B. Basis of Presentation

The consolidated financial statements of Eversource, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements."

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

CYAPC and YAEC are inactive regional nuclear power companies engaged in the long-term storage of their spent nuclear fuel. Eversource consolidates the operations of CYAPC and YAEC because CL&P's, NSTAR Electric's and PSNH's combined ownership and voting interests in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and the CYAPC and YAEC companies have been eliminated in consolidation of the Eversource financial statements.

Eversource holds several equity ownership interests that are not consolidated and are accounted for under the equity method.

In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by Eversource or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the financial statements of Eversource. The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the balance sheets of Eversource, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric Boards of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time. The Net Income reported in the statements of income and cash flows represents net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.

Eversource's utility subsidiaries' electric, natural gas and water distribution and transmission businesses are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations, which considers the effect of regulation on the differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. See Note 2, "Regulatory Accounting," for further information.

As of December 31, 2022 and 2021, Eversource's carrying amount of goodwill was $4.52 billion and $4.48 billion, respectively. Eversource performs an assessment for possible impairment of its goodwill at least annually. Eversource completed its annual goodwill impairment



assessment for each of its reporting units as of October 1, 2022 and determined that no impairment exists. See Note 25, "Goodwill," for further information.

For the year ended December 31, 2022, no impairments to goodwill, long-lived assets, available-for-sale debt securities, or equity method investment carrying values were identified.

Certain reclassifications of prior year data were made in the accompanying financial statements to conform to the current year presentation.

## C. Cash and Cash Equivalents

Cash includes cash on hand. At the end of each reporting period, any overdraft amounts are reclassified from Cash to Accounts Payable on the balance sheets. Cash Equivalents include short-term cash investments that are highly liquid in nature and have original maturities of three months or less.

## D. Allowance for Uncollectible Accounts

Receivables, Net on the balance sheets primarily includes trade receivables from retail customers and customers related to wholesale transmission contracts, wholesale market sales, sales of RECs, and property rentals. Receivables, Net also includes customer receivables for the purchase of electricity from a competitive third party supplier, the current portion of customer energy efficiency loans, property damage receivables and other miscellaneous receivables. There is no material concentration of receivables.

Receivables are recorded at amortized cost, net of a credit loss provision (or allowance for uncollectible accounts). The current expected credit loss (CECL) model, which was implemented on January 1, 2020 (ASU 2016-13), is applied to receivables for purposes of calculating the allowance for uncollectible accounts. This model is based on expected losses and results in the recognition of estimated expected credit losses, including uncollectible amounts for both billed and unbilled revenues, over the life of the receivable at the time a receivable is recorded.

The allowance for uncollectible accounts is determined based upon a variety of judgments and factors, including an aging-based quantitative assessment that applies an estimated uncollectible percentage to each receivable aging category. Factors in determining credit loss include historical collection, write-off experience, analysis of delinquency statistics, and management's assessment of collectability from customers, including current economic conditions, customer payment trends, the impact on customer bills because of energy usage trends and changes in rates, flexible payment plans and financial hardship arrearage management programs being offered to customers, reasonable forecasts, and expectations of future collectability and collection efforts. Management continuously assesses the collectability of receivables and adjusts estimates based on actual experience and future expectations based on economic conditions, collection efforts and other factors. Management also monitors the aging analysis of receivables to determine if there are changes in the collections of accounts receivable. Receivable balances are written off against the allowance for uncollectible accounts when the customer accounts are no longer in service and these balances are deemed to be uncollectible. Management concluded that the reserve balance as of December 31, 2022 adequately reflected the collection risk and net realizable value for its receivables.

As of December 31, 2022 and 2021, the total amount incurred as a result of COVID-19 included in the allowance for uncollectible accounts was $50.9 million and $55.3 million at Eversource, $16.0 million and $23.9 million at CL&P, and $4.1 million and $9.0 million at NSTAR Electric, respectively. At our Connecticut and Massachusetts utilities, the COVID-19 related uncollectible amounts were deferred either as incremental regulatory costs or deferred through existing regulatory tracking mechanisms that recover uncollectible energy supply costs, as management believes it is probable that these costs will ultimately be recovered from customers in future rates. No COVID-19 related uncollectible amounts were deferred at PSNH as a result of a July 2021 NHPUC order. Based on the status of our COVID-19 regulatory dockets, policies and practices in the jurisdictions in which we operate, we believe the state regulatory commissions in Connecticut and Massachusetts will allow us to recover our incremental uncollectible customer receivable costs associated with COVID-19.

The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 180 days and 90 days, respectively. The DPU allows NSTAR Electric, NSTAR Gas and EGMA to recover in rates amounts associated with certain uncollectible hardship accounts receivable. These uncollectible hardship customer account balances are included in Regulatory Assets or Other Long-Term Assets on the balance sheets. Hardship customers are protected from shut-off in certain circumstances, and historical collection experience has reflected a higher default risk as compared to the rest of the receivable population. Management uses a higher credit risk profile for this pool of trade receivables as compared to non-hardship receivables. The allowance for uncollectible hardship accounts is included in the total uncollectible allowance balance.



The total allowance for uncollectible accounts is included in Receivables, Net on the balance sheets. The activity in the allowance for uncollectible accounts by portfolio segment is as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">Eversource</td><td colspan="4">CL&amp;P</td><td colspan="4">NSTAR Electric</td><td colspan="2">PSNH</td></tr><tr><td>Hardship Accounts</td><td>Retail (Non-Hardship), Wholesale, and Other</td><td>Total Allowance</td><td>Hardship Accounts</td><td>Retail (Non-Hardship), Wholesale, and Other</td><td>Hardship Accounts</td><td>Total Allowance</td><td>Hardship Accounts</td><td>Retail (Non-Hardship), Whole sale, and Other</td><td>Hardship Accounts</td><td>Total Allowance</td><td>Total Allowance</td><td>Total Allowance</td><td></td></tr><tr><td>Balance as of January 1, 2020</td><td>$ 143.3</td><td>$ 81.5</td><td>$ 224.8</td><td>$ 80.1</td><td>$ 17.2</td><td>$ 97.3</td><td>$ 43.9</td><td>$ 31.5</td><td>$ 75.4</td><td>$ 10.5</td><td></td><td></td><td></td><td></td></tr><tr><td>ASU 2016-13 Implementation Impact on January 1, 2020</td><td>21.6</td><td>2.2</td><td>23.8</td><td>21.3</td><td>0.9</td><td>22.2</td><td>(1.6)</td><td>0.3</td><td>(1.3)</td><td>0.3</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase due to CMA acquisition</td><td>—</td><td>24.2</td><td>24.2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Uncollectible Expense</td><td>—</td><td>53.5</td><td>53.5</td><td>—</td><td>12.9</td><td>12.9</td><td>—</td><td>15.3</td><td>15.3</td><td>5.2</td><td></td><td></td><td></td><td></td></tr><tr><td>Uncollectible Costs Deferred (1)</td><td>43.1</td><td>53.9</td><td>97.0</td><td>38.2</td><td>10.8</td><td>49.0</td><td>(1.7)</td><td>26.4</td><td>24.7</td><td>7.4</td><td></td><td></td><td></td><td></td></tr><tr><td>Write-Offs</td><td>(14.7)</td><td>(63.3)</td><td>(78.0)</td><td>(11.9)</td><td>(17.8)</td><td>(29.7)</td><td>(0.9)</td><td>(26.3)</td><td>(27.2)</td><td>(6.9)</td><td></td><td></td><td></td><td></td></tr><tr><td>Recoveries Collected</td><td>1.5</td><td>12.1</td><td>13.6</td><td>14.4</td><td>4.3</td><td>5.7</td><td>—</td><td>4.7</td><td>4.7</td><td>0.7</td><td></td><td></td><td></td><td></td></tr><tr><td>Balance as of December 31, 2020</td><td>$ 194.8</td><td>$ 164.1</td><td>$ 358.9</td><td>$ 129.1</td><td>$ 28.3</td><td>$ 157.4</td><td>$ 39.7</td><td>$ 51.9</td><td>$ 91.6</td><td>$ 17.2</td><td></td><td></td><td></td><td></td></tr><tr><td>Uncollectible Expense</td><td>—</td><td>60.9</td><td>60.9</td><td>—</td><td>13.5</td><td>13.5</td><td>—</td><td>16.6</td><td>16.6</td><td>13.1</td><td></td><td></td><td></td><td></td></tr><tr><td>Uncollectible Costs Deferred (1)</td><td>51.9</td><td>58.7</td><td>110.6</td><td>32.3</td><td>25.5</td><td>57.8</td><td>4.3</td><td>15.8</td><td>20.1</td><td>3.1</td><td></td><td></td><td></td><td></td></tr><tr><td>Write-Offs</td><td>(22.0)</td><td>(107.7)</td><td>(129.7)</td><td>(18.0)</td><td>(36.2)</td><td>(54.2)</td><td>(0.7)</td><td>(36.3)</td><td>(37.0)</td><td>(10.0)</td><td></td><td></td><td></td><td></td></tr><tr><td>Recoveries Collected</td><td>1.4</td><td>15.3</td><td>16.7</td><td>1.2</td><td>5.6</td><td>6.8</td><td>—</td><td>5.7</td><td>5.7</td><td>0.9</td><td></td><td></td><td></td><td></td></tr><tr><td>Balance as of December 31, 2021</td><td>$ 226.1</td><td>$ 191.3</td><td>$ 417.4</td><td>$ 144.6</td><td>$ 36.7</td><td>$ 181.3</td><td>$ 43.3</td><td>$ 53.7</td><td>$ 97.0</td><td>$ 24.3</td><td></td><td></td><td></td><td></td></tr><tr><td>Uncollectible Expense</td><td>—</td><td>61.9</td><td>61.9</td><td>—</td><td>15.6</td><td>15.6</td><td>—</td><td>21.6</td><td>21.6</td><td>9.2</td><td></td><td></td><td></td><td></td></tr><tr><td>Uncollectible Costs Deferred (1)</td><td>77.8</td><td>34.7</td><td>112.5</td><td>58.3</td><td>1.2</td><td>59.5</td><td>1.5</td><td>10.9</td><td>12.4</td><td>2.5</td><td></td><td></td><td></td><td></td></tr><tr><td>Write-Offs</td><td>(21.3)</td><td>(102.7)</td><td>(124.0)</td><td>(15.3)</td><td>(23.0)</td><td>(38.3)</td><td>(1.1)</td><td>(41.2)</td><td>(42.3)</td><td>(7.7)</td><td></td><td></td><td></td><td></td></tr><tr><td>Recoveries Collected</td><td>1.8</td><td>16.7</td><td>18.5</td><td>1.3</td><td>5.9</td><td>7.2</td><td>—</td><td>6.3</td><td>6.3</td><td>0.9</td><td></td><td></td><td></td><td></td></tr><tr><td>Balance as of December 31, 2022</td><td>$ 284.4</td><td>$ 201.9</td><td>$ 486.3</td><td>$ 188.9</td><td>$ 36.4</td><td>$ 225.3</td><td>$ 43.7</td><td>$ 51.3</td><td>$ 95.0</td><td>$ 29.2</td><td></td><td></td><td></td><td></td></tr></table>

(1) These expected credit losses are deferred as regulatory costs on the balance sheets, as these amounts are ultimately recovered in rates. Amounts include uncollectible costs for hardship accounts and other customer receivables, including uncollectible amounts related to uncollectible energy supply costs and COVID-19. The increase in the allowance for uncollectible hardship accounts in 2022 at Eversource and CL&P primarily relates to increased customer enrollment in disconnection prevention programs in Connecticut.

## E. Transfer of Energy Efficiency Loans

CL&P transferred a portion of its energy efficiency customer loan portfolio to outside lenders in order to make additional loans to customers. CL&P remains the servicer of the loans and will transmit customer payments to the lenders, with a maximum amount outstanding under this program of $55 million. The amounts of the loans are included in Accounts Receivable, Net and Other Long-Term Assets, and are offset by Other Current Liabilities and Other Long-Term Liabilities on CL&P's balance sheet. The current and long-term portions totaled $9.1 million and $13.0 million, respectively, as of December 31, 2022, and $10.5 million and $8.3 million, respectively, as of December 31, 2021.

## F. Materials, Supplies, Natural Gas and REC Inventory

Materials, Supplies, Natural Gas and REC Inventory include materials and supplies purchased primarily for construction or operation and maintenance purposes, natural gas purchased for delivery to customers, and RECs. Inventory is valued at the lower of cost or net realizable value. RECs are purchased from suppliers of renewable sources of generation and are used to meet state mandated Renewable Portfolio Standards requirements. The carrying amounts of materials and supplies, natural gas inventory, and RECs, which are included in Current Assets on the balance sheets, were as follows:

As of December 31,

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="6">2022</td><td colspan="6">2021</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td></td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PS NH</td><td></td><td></td><td></td></tr><tr><td>Materials and Supplies</td><td>$ 221.0</td><td>$ 88.2</td><td>$ 81.0</td><td>$ 34.4</td><td>$ 148.9</td><td>$ 60.3</td><td>$ 55.0</td><td>$ 25.2</td><td></td><td></td><td></td><td></td></tr><tr><td>Natural Gas</td><td>95.9</td><td>—</td><td>—</td><td>—</td><td>56.2</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>RECs</td><td>57.5</td><td>—</td><td>57.4</td><td>0.1</td><td>62.4</td><td>—</td><td>61.7</td><td>0.7</td><td></td><td></td><td></td><td></td></tr><tr><td>Total</td><td>$ 374.4</td><td>$ 88.2</td><td>$ 138.4</td><td>$ 34.5</td><td>$ 267.5</td><td>$ 60.3</td><td>$ 116.7</td><td>$ 25.9</td><td></td><td></td><td></td><td></td></tr></table>

## G. Fair Value Measurements

Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases" or "normal sales" (normal) and to marketable securities held in trusts. Fair value measurement guidance is also applied to valuations of the investments used to calculate the funded status of pension and PBOP plans, the nonrecurring fair value measurements of nonfinancial assets such as goodwill, long-lived assets, equity method investments, AROs, and in the valuation of business combinations and asset acquisitions. The fair value measurement guidance was also applied in estimating the fair value of preferred stock, long-term debt and RRBs.

Fair Value Hierarchy: In measuring fair value, Eversource uses observable market data when available in order to minimize the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. Eversource evaluates the classification of assets and liabilities measured at fair value on a quarterly basis.



The levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.

Uncategorized - Investments that are measured at net asset value are not categorized within the fair value hierarchy.

Determination of Fair Value: The valuation techniques and inputs used in Eversource's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," Note 6, "Investments in Unconsolidated Affiliates," Note 7, "Asset Retirement Obligations," Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," Note 15, "Fair Value of Financial Instruments," and Note 25, "Goodwill," to the financial statements.

## H. Derivative Accounting

Many of the electric and natural gas companies' contracts for the purchase and sale of energy or energy-related products are derivatives. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.

The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of a contract as normal, and determination of the fair value of derivative contracts. All of these judgments can have a significant impact on the financial statements. The judgment applied in the election of a contract as normal (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then a contract cannot be considered normal, accrual accounting is terminated, and fair value accounting is applied prospectively.

The fair value of derivative contracts is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the balance sheets.

Regulatory assets or regulatory liabilities are recorded to offset the fair values of these derivative contracts related to energy and energy-related products, as contract settlements are recovered from, or refunded to, customers in future rates. All changes in the fair value of these derivative contracts are recorded as regulatory assets or liabilities and do not impact net income.

For further information regarding derivative contracts, see Note 4, "Derivative Instruments," to the financial statements.

## I. Operating Expenses

The cost of natural gas included in Purchased Power, Purchased Natural Gas and Transmission on the statements of income were as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Eversource - Cost of Natural Gas</td><td>$ 1,010.2</td><td>$ 718.6</td><td>$ 464.2</td><td></td></tr></table>

## J. Allowance for Funds Used During Construction

AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the electric, natural gas and water companies' utility plant on the balance sheet. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.

The average AFUDC rate is based on a FERC-prescribed formula using the cost of a company's short-term financings and capitalization (preferred stock, long-term debt and common equity), as appropriate. The average rate is applied to average eligible CWIP amounts to calculate AFUDC.

AFUDC costs and the weighted-average AFUDC rates were as follows:

<table><tr><td rowspan="2">Eversource (Millions of Dollars, except percentages)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Borrowed Funds</td><td>$ 21.8</td><td>$ 18.4</td><td>$ 23.7</td><td></td></tr><tr><td>Equity Funds</td><td>47.3</td><td>37.3</td><td>42.0</td><td></td></tr><tr><td>Total AFUDC</td><td>$ 69.1</td><td>$ 55.7</td><td>$ 65.7</td><td></td></tr><tr><td>Average AFUDC Rate</td><td>4.7%</td><td>4.2%</td><td>5.0%</td><td></td></tr></table>



For the Years Ended December 31,

<table><tr><td rowspan="2"></td><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Borrowed Funds</td><td>$ 4.8</td><td>$ 10.7</td><td>$ 1.4</td><td>$ 2.9</td><td>$ 9.0</td><td>$ 0.8</td><td>$ 6.6</td><td>$ 9.1</td><td>$ 2.1</td><td></td><td></td><td></td></tr><tr><td>Equity Funds</td><td>13.6</td><td>24.6</td><td>2.5</td><td>7.7</td><td>20.4</td><td>1.6</td><td>13.8</td><td>21.5</td><td>4.2</td><td></td><td></td><td></td></tr><tr><td>Total AFUDC</td><td>$ 18.4</td><td>$ 35.3</td><td>$ 3.9</td><td>$ 10.6</td><td>$ 29.4</td><td>$ 2.4</td><td>$ 20.4</td><td>$ 30.6</td><td>$ 6.3</td><td></td><td></td><td></td></tr><tr><td>Average AFUDC Rate</td><td>6.6%</td><td>5.4%</td><td>2.6%</td><td>5.0%</td><td>4.9%</td><td>2.5%</td><td>5.9%</td><td>5.7%</td><td>4.7%</td><td></td><td></td><td></td></tr></table>

## K. Other Income, Net

The components of Other Income, Net on the statements of income were as follows:

<table><tr><td rowspan="2"></td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Pension, SERP and PBOP Non-Service Income Components, Net of Deferred Portion (1)</td><td>$ 219.8</td><td>$ 84.4</td><td>$ 44.4</td><td></td></tr><tr><td>AFUDC Equity</td><td>47.3</td><td>37.3</td><td>42.0</td><td></td></tr><tr><td>Equity in Earnings of Unconsolidated Affiliates (2)</td><td>22.9</td><td>14.2</td><td>14.2</td><td></td></tr><tr><td>Investment Income/(Loss)</td><td>1.9</td><td>(0.2)</td><td>1.1</td><td></td></tr><tr><td>Interest Income</td><td>50.5</td><td>25.6</td><td>4.8</td><td></td></tr><tr><td>Gain on Sale of Property</td><td>2.6</td><td>0.1</td><td>1.8</td><td></td></tr><tr><td>Other</td><td>1.1</td><td>(0.1)</td><td>0.3</td><td></td></tr><tr><td>Total Other Income, Net</td><td>$ 346.1</td><td>$ 161.3</td><td>$ 108.6</td><td></td></tr></table>

For the Years Ended December 31,

<table><tr><td rowspan="2"></td><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Pension, SERP and PBOP Non-Service Income Components, Net of Deferred Portion (1)</td><td>$ 64.4</td><td>$ 85.5</td><td>$ 26.8</td><td>$ 15.2</td><td>$ 40.2</td><td>$ 10.3</td><td>$ 3.8</td><td>$ 29.3</td><td>$ 7.0</td><td></td><td></td><td></td></tr><tr><td>AFUDC Equity</td><td>13.6</td><td>24.6</td><td>2.5</td><td>7.7</td><td>20.4</td><td>1.6</td><td>13.8</td><td>21.5</td><td>4.2</td><td></td><td></td><td></td></tr><tr><td>Investment (Loss)/Income</td><td>(1.3)</td><td>1.2</td><td>0.2</td><td>1.3</td><td>0.1</td><td>0.1</td><td>1.1</td><td>(0.8)</td><td>0.1</td><td></td><td></td><td></td></tr><tr><td>Interest Income</td><td>6.5</td><td>30.7</td><td>3.1</td><td>5.9</td><td>13.4</td><td>2.4</td><td>2.0</td><td>0.9</td><td>2.4</td><td></td><td></td><td></td></tr><tr><td>Other</td><td>0.1</td><td>0.7</td><td>0.1</td><td>0.1</td><td>0.7</td><td>0.2</td><td>0.1</td><td>1.1</td><td>0.1</td><td></td><td></td><td></td></tr><tr><td>Total Other Income, Net</td><td>$ 83.3</td><td>$ 142.7</td><td>$ 32.7</td><td>$ 30.2</td><td>$ 74.8</td><td>$ 14.6</td><td>$ 20.8</td><td>$ 52.0</td><td>$ 13.8</td><td></td><td></td><td></td></tr></table>

(1) See Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for the components of net periodic benefit income/expense for the Pension, SERP and PBOP Plans. The non-service related components of pension, SERP and PBOP benefit income/expense, after capitalization or deferral, are presented as non-operating income and recorded in Other Income, Net on the statements of income.

(2) Equity in earnings of unconsolidated affiliates includes $12.2 million and $2.1 million of pre-tax unrealized gains for the years ended December 31, 2022 and 2021, respectively, and $2.4 million of primarily realized gains for the year ended December 31, 2020, associated with an equity method investment in a renewable energy fund. Equity in earnings of unconsolidated affiliates for the year ended December 31, 2020 includes an other-than-temporary impairment of $2.8 million related to a write-off of an investment within a renewable energy fund. See Note 6, “Investments in Unconsolidated Affiliates,” for Eversource’s equity method investments.

## L. Other Taxes

Eversource's companies that serve customers in Connecticut collect gross receipts taxes levied by the state of Connecticut from their customers. These gross receipts taxes are recorded separately with collections in Operating Revenues and with payments in Taxes Other Than Income Taxes on the statements of income as follows:

<table><tr><td rowspan="2"></td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Eversource</td><td>$ 194.7</td><td>$ 181.9</td><td>$ 170.6</td><td></td></tr><tr><td>CL&amp;P</td><td>166.1</td><td>158.1</td><td>149.9</td><td></td></tr></table>

As agents for state and local governments, Eversource's companies that serve customers in Connecticut and Massachusetts collect certain sales taxes that are recorded on a net basis with no impact on the statements of income.



## M. Supplemental Cash Flow Information

<table><tr><td rowspan="2">Eversource(Millions of Dollars)</td><td colspan="4">As of and For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Cash Paid During the Year for:</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest, Net of Amounts Capitalized</td><td>$     636.2</td><td>$     568.7</td><td>$     518.0</td><td></td></tr><tr><td>Income Taxes</td><td>77.9</td><td>121.6</td><td>48.9</td><td></td></tr><tr><td>Non-Cash Investing Activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Plant Additions Included in Accounts Payable (As of)</td><td>586.9</td><td>467.9</td><td>367.2</td><td></td></tr></table>

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;&amp; P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Cash Paid During the Year for:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest, Net of Amounts Capitalized</td><td>$   167.2</td><td>$   152.8</td><td>$   58.3</td><td>$   161.5</td><td>$   141.6</td><td>$   56.5</td><td>$   149.0</td><td>$   129.4</td><td>$   54.5</td><td></td><td></td><td></td></tr><tr><td>Income Taxes</td><td>117.6</td><td>23.8</td><td>58.3</td><td>38.4</td><td>74.2</td><td>51.1</td><td>10.9</td><td>110.7</td><td>34.2</td><td></td><td></td><td></td></tr><tr><td>Non-Cash Investing Activities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Plant Additions Included in Accounts Payable (As of)</td><td>131.8</td><td>184.3</td><td>76.2</td><td>110.6</td><td>120.0</td><td>68.7</td><td>101.8</td><td>103.2</td><td>33.3</td><td></td><td></td><td></td></tr></table>

The following table reconciles cash and cash equivalents as reported on the balance sheets to the cash, cash equivalents and restricted cash balance as reported on the statements of cash flows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="8">2022</td><td colspan="4">2021</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSN</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Cash and Cash Equivalents as reported on the Balance Sheets</td><td>$ 374.6</td><td>$ 11.3</td><td>$ 327.7</td><td>$ 0.1</td><td>$ 66.8</td><td>$ 55.8</td><td>$ 0.7</td><td>$ —</td><td></td><td></td><td></td></tr><tr><td>Restricted cash included in:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Special Deposits</td><td>102.2</td><td>8.8</td><td>17.5</td><td>33.1</td><td>78.2</td><td>18.7</td><td>17.4</td><td>31.4</td><td></td><td></td><td></td></tr><tr><td>Marketable Securities</td><td>25.4</td><td>0.2</td><td>0.1</td><td>0.4</td><td>31.3</td><td>0.3</td><td>0.1</td><td>0.5</td><td></td><td></td><td></td></tr><tr><td>Other Long-Term Assets</td><td>19.6</td><td>—</td><td>—</td><td>3.2</td><td>44.7</td><td>—</td><td>—</td><td>3.2</td><td></td><td></td><td></td></tr><tr><td>Cash, Cash Equivalents and Restricted Cash as reported on the Statements of Cash Flows</td><td>$ 521.8</td><td>$ 20.3</td><td>$ 345.3</td><td>$ 36.8</td><td>$ 221.0</td><td>$ 74.8</td><td>$ 18.2</td><td>$ 35.1</td><td></td><td></td><td></td></tr></table>

Special Deposits represent cash collections related to the PSNH RRB customer charges that are held in trust, required ISO-NE cash deposits, cash held in escrow accounts, and CYAPC and YAEC cash balances. The December 31, 2021 balance also included a $10 million customer assistance fund to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages at CL&P established under the terms of the PURA-approved October 2021 settlement agreement. Those customers were provided with $10 million of bill forgiveness in the first quarter of 2022, which represented a non-cash transaction. Special Deposits are included in Current Assets on the balance sheets. Restricted cash included in Marketable Securities represents money market funds held in trusts to fund certain non-qualified executive benefits and restricted trusts to fund CYAPC and YAEC's spent nuclear fuel storage obligations.

Restricted cash also includes an Energy Relief Fund for energy efficiency and clean energy measures in the Merrimack Valley and an additional energy efficiency program established under the terms of the EGMA 2020 settlement agreement. As of December 31, 2022, $20.0 million of this restricted cash was recorded as short-term in Special Deposits and $15.9 million was recorded in Other Long-Term Assets. As of December 31, 2021, this restricted cash totaled $41.5 million and was recorded in Other Long-Term Assets on the balance sheet.

Cash Equivalents at NSTAR Electric of $327.0 million related to a cash infusion by Eversource parent received in December 2022 recorded in a money market account.

## N. Related Parties

Eversource Service, Eversource's service company, provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, tax, and other services to Eversource's companies. The Rocky River Realty Company and Properties, Inc., two other Eversource subsidiaries, construct, acquire or lease some of the property and facilities used by Eversource's companies.

As of both December 31, 2022 and 2021, CL&P, NSTAR Electric and PSNH had long-term receivables from Eversource Service in the amounts of $25.0 million, $5.5 million and $3.8 million, respectively, which were included in Other Long-Term Assets on the balance sheets. These amounts related to the funding of investments held in trust by Eversource Service in connection with certain postretirement benefits for CL&P, NSTAR Electric and PSNH employees and have been eliminated in consolidation on the Eversource financial statements.

Included in the CL&P, NSTAR Electric and PSNH balance sheets as of December 31, 2022 and 2021 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric and PSNH and other subsidiaries that are wholly-owned by Eversource. These amounts have been eliminated in consolidation on the Eversource financial statements.



The Eversource Energy Foundation is an independent not-for-profit charitable entity and is not included in the consolidated financial statements of Eversource as the Company does not have title to, and cannot receive contributions back from, the Eversource Energy Foundation's assets. Eversource made contributions to the Eversource Energy Foundation of $8.0 million in 2022 and $6.4 million in 2020 and did not make any contributions in 2021.

## 2. REGULATORY ACCOUNTING

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

The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

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

Regulatory Assets: The components of regulatory assets were as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="9">As of December 31,</td></tr><tr><td colspan="4">2022</td><td colspan="5">2021</td></tr><tr><td></td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td></td><td>PSNH</td></tr><tr><td>Benefit Costs</td><td>$ 921.7</td><td>$ 156.7</td><td>$ 299.5</td><td>$ 56.6</td><td>$ 1,481.0</td><td>$ 272.4</td><td>$ 395.5</td><td>$ 118.9</td><td></td></tr><tr><td>Storm Costs, Net</td><td>1,379.1</td><td>799.3</td><td>484.4</td><td>95.4</td><td>1,102.7</td><td>695.6</td><td>341.3</td><td>65.8</td><td></td></tr><tr><td>Regulatory Tracking Mechanisms</td><td>1,075.3</td><td>216.8</td><td>391.5</td><td>73.7</td><td>1,050.5</td><td>333.6</td><td>376.6</td><td>85.4</td><td></td></tr><tr><td>Income Taxes, Net</td><td>853.3</td><td>491.1</td><td>115.6</td><td>16.0</td><td>790.7</td><td>470.5</td><td>112.6</td><td>17.5</td><td></td></tr><tr><td>Securitized Stranded Costs</td><td>435.7</td><td>—</td><td>—</td><td>435.7</td><td>478.9</td><td>—</td><td>—</td><td>478.9</td><td></td></tr><tr><td>Goodwill-related</td><td>281.0</td><td>—</td><td>241.2</td><td>—</td><td>297.8</td><td>—</td><td>255.7</td><td>—</td><td></td></tr><tr><td>Derivative Liabilities</td><td>181.8</td><td>181.8</td><td>—</td><td>—</td><td>249.2</td><td>249.2</td><td>—</td><td>—</td><td></td></tr><tr><td>Asset Retirement Obligations</td><td>127.9</td><td>35.9</td><td>68.2</td><td>4.4</td><td>115.0</td><td>33.6</td><td>59.8</td><td>4.1</td><td></td></tr><tr><td>Other Regulatory Assets</td><td>322.5</td><td>26.2</td><td>114.0</td><td>14.4</td><td>150.0</td><td>29.9</td><td>37.7</td><td>15.8</td><td></td></tr><tr><td>Total Regulatory Assets</td><td>5,578.3</td><td>1,907.8</td><td>1,714.4</td><td>696.2</td><td>5,715.8</td><td>2,084.8</td><td>1,579.2</td><td>786.4</td><td></td></tr><tr><td>Less: Current Portion</td><td>1,335.5</td><td>314.1</td><td>492.8</td><td>102.2</td><td>1,129.1</td><td>371.6</td><td>444.0</td><td>107.2</td><td></td></tr><tr><td>Total Long-Term Regulatory Assets</td><td>$ 4,242.8</td><td>$ 1,593.7</td><td>$ 1,221.6</td><td>$ 594.0</td><td>$ 4,586.7</td><td>$ 1,713.2</td><td>$ 1,135.2</td><td>$ 679.2</td><td></td></tr></table>

Benefit Costs: Deferred benefit costs represent unrecognized actuarial losses and gains and unrecognized prior service costs and credits attributable to Eversource's Pension, SERP and PBOP Plans. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. The regulatory asset or regulatory liability is amortized with the recognition of actuarial losses and gains and prior service costs and credits to net periodic benefit expense/income over the estimated average future employee service period using the corridor approach. Regulatory accounting is also applied to the portions of Eversource's service company costs that support the regulated companies, as these amounts are also recoverable. As these regulatory assets or regulatory liabilities do not represent a cash outlay for the regulated companies, no carrying charge is recovered from customers. See Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," for further information on regulatory benefit plan amounts arising and amortized during the year.

Eversource, CL&P, NSTAR Electric, and PSNH recover benefit costs related to their distribution and transmission operations from customers in rates as allowed by their applicable regulatory commissions. NSTAR Electric, NSTAR Gas and EGMA recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year. The electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension and PBOP expenses.

Storm Costs, Net: The storm cost deferrals relate to costs incurred for storm events at CL&P, NSTAR Electric and PSNH that each company expects to recover from customers. A storm must meet certain criteria to qualify for deferral and recovery with the criteria specific to each state jurisdiction and utility company. Once a storm qualifies for recovery, all qualifying expenses incurred during storm restoration efforts are deferred and recovered from customers. Costs for storms that do not meet the specific criteria are expensed as incurred. In addition to storm restoration costs, CL&P and PSNH are each allowed to recover pre-staging storm costs. Management believes all storm costs deferred were prudently incurred and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery processes. Each electric utility company either recovers a carrying charge on its deferred storm cost regulatory asset balance or the regulatory asset balance is included in rate base.



Multiple tropical and severe storms over the past several years have caused extensive damage to Eversource's electric distribution systems resulting in significant numbers and durations of customer outages, along with significant pre-staging costs. Storms in 2022 that qualified for future recovery resulted in deferred storm restoration costs and pre-staging costs totaling $399 million at Eversource, including $163 million at CL&P, $181 million at NSTAR Electric, and $55 million at PSNH. Management believes that all of these storm costs were prudently incurred and meet the criteria for specific cost recovery. Of Eversource's total deferred storm costs, $1.40 billion either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudence review (including $807 million at CL&P, $492 million at NSTAR Electric and $98 million at PSNH) as of December 31, 2022. These storm cost totals exclude storm funding amounts that are collected in rates, which are recorded as a reduction to the deferred storm cost regulatory asset balance. NSTAR Electric and PSNH are seeking approval of their deferred storm restoration costs through the applicable regulatory recovery process. As part of CL&P's October 1, 2021 settlement agreement, CL&P agreed to freeze its current base distribution rates (including storm costs) until no earlier than January 1, 2024. As a result, CL&P has not yet filed for approval of its storm costs in a regulatory proceeding.

CL&P Tropical Storm Isaias Costs: On August 4, 2020, Tropical Storm Isaias caused catastrophic damage to our electric distribution system, which resulted in significant numbers and durations of customer outages, primarily in Connecticut. In terms of customer outages, this storm was one of the worst in CL&P's history. PURA will investigate the prudence of costs incurred by CL&P to restore service in response to Tropical Storm Isaias. That investigation is expected to occur either in a separate proceeding not yet initiated or as part of CL&P's next rate review proceeding. Tropical Storm Isaias resulted in deferred storm restoration costs of approximately $235 million at CL&P as of December 31, 2022. Although PURA found that CL&P's performance in its preparation for, and response to, Tropical Storm Isaias fell below applicable performance standards in certain instances, CL&P believes it will be able to present credible evidence in a future proceeding demonstrating there is no reasonably close causal connection between the alleged sub-standard performance and the storm costs incurred. While it is possible that some amount of storm costs may be disallowed by PURA in a future proceeding, any such amount cannot be estimated at this time. Eversource and CL&P continue to believe that these storm restoration costs associated with Tropical Storm Isaias were prudently incurred and meet the criteria for cost recovery; and as a result, management does not expect the storm cost review by PURA to have a material impact on the financial position or results of operations of Eversource or CL&P.

Regulatory Tracking Mechanisms: The regulated companies' approved rates are designed to recover costs incurred to provide service to customers. The regulated companies recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms. The differences between the costs incurred (or the rate recovery allowed) and the actual revenues are recorded as regulatory assets (for undercollections) or as regulatory liabilities (for overcollections) to be included in future customer rates each year. Carrying charges are recovered in rates on all material regulatory tracking mechanisms.

The electric and natural gas distribution companies recover, on a fully reconciling basis, the costs associated with the procurement of energy and natural gas supply, electric transmission related costs from FERC-approved transmission tariffs, energy efficiency programs, low income assistance programs, certain uncollectible accounts receivable for hardship customers, restructuring and stranded costs as a result of deregulation (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

CL&P, NSTAR Electric, Yankee Gas, NSTAR Gas, EGMA and the Aquarion Water Company of Connecticut each have a regulatory commission approved revenue decoupling mechanism. Distribution revenues are decoupled from customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues. Each company reconciles its annual base distribution rate recovery amount to the pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period.

Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. The amortization period of these assets varies depending on the nature and/or remaining life of the underlying assets and liabilities. For further information regarding income taxes, see Note 12, "Income Taxes," to the financial statements.

Securitized Stranded Costs: In 2018, a subsidiary of PSNH issued $635.7 million of securitized RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. Securitized regulatory assets, which are not earning an equity return, are being recovered over the amortization period of the associated RRBs. The PSNH RRBs are expected to be repaid by February 1, 2033. For further information, see Note 10, "Rate Reduction Bonds and Variable Interest Entities," to the financial statements.

Goodwill-related: The goodwill regulatory asset originated from a 1999 transaction, and the DPU allowed its recovery in NSTAR Electric and NSTAR Gas rates. This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40-year period, and as of December 31, 2022, there were 17 years of amortization remaining.

Derivative Liabilities: Regulatory assets are recorded as an offset to derivative liabilities and relate to the fair value of contracts used to purchase energy and energy-related products that will be recovered from customers in future rates. These assets are excluded from rate base and are being recovered as the actual settlements occur over the duration of the contracts. See Note 4, "Derivative Instruments," to the financial statements for further information on these contracts.

Asset Retirement Obligations: The costs associated with the depreciation of the regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. The regulated companies' ARO assets,



regulatory assets, and ARO liabilities offset and are excluded from rate base. These costs are being recovered over the life of the underlying property, plant and equipment.

Other Regulatory Assets: Other Regulatory Assets primarily include environmental remediation costs, certain uncollectible accounts receivable for hardship customers, certain exogenous property taxes and merger-related costs allowed for recovery, contractual obligations associated with the spent nuclear fuel storage costs of the CYAPC, YAEC and MYAPC decommissioned nuclear power facilities, water tank painting costs, losses associated with the reacquisition or redemption of long-term debt, and various other items.

Regulatory Costs in Long-Term Assets: Eversource's regulated companies had $210.8 million (including $135.9 million for CL&P, $19.8 million for NSTAR Electric and $1.0 million for PSNH) and $252.5 million (including $114.9 million for CL&P, $85.0 million for NSTAR Electric and $3.4 million for PSNH) of additional regulatory costs as of December 31, 2022 and 2021, respectively, that were included in long-term assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates. As of December 31, 2022 and 2021, these regulatory costs included incremental COVID-19 related non-tracked uncollectible expense deferred of $29.8 million and $33.0 million at Eversource, $11.8 million and $18.0 million at CL&P, and $2.2 million and $6.1 million at NSTAR Electric, respectively.

Equity Return on Regulatory Assets: For rate-making purposes, the regulated companies recover the carrying costs related to their regulatory assets. For certain regulatory assets, the carrying cost recovered includes an equity return component. This equity return is not recorded on the balance sheets. The equity return for PSNH was $4.1 million and $5.0 million as of December 31, 2022 and 2021, respectively. These carrying costs will be recovered from customers in future rates.

Regulatory Liabilities: The components of regulatory liabilities were as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="2">2022</td><td colspan="2">2021</td></tr></table>

EDIT due to Tax Cuts and Jobs Act of 2017: Pursuant to the Tax Cuts and Jobs Act of 2017, Eversource had remeasured its existing deferred federal income tax balances to reflect the decrease in the U.S. federal corporate income tax rate from 35 percent to 21 percent. The remeasurement resulted in provisional regulated excess accumulated deferred income tax (excess ADIT or EDIT) liabilities that will benefit customers in future periods and were recognized as regulatory liabilities on the balance sheet. EDIT liabilities related to property, plant, and equipment are subject to IRS normalization rules and will be returned to customers using the same timing as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities. Eversource's regulated companies (except for the Connecticut water business) are in the process of refunding the EDIT liabilities to customers based on orders issued by applicable state and federal regulatory commissions.

Cost of Removal: Eversource's regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense, and the cumulative amount collected from customers but not yet expended is recognized as a regulatory liability.

Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP: Regulatory liabilities were recorded for the deferred portion of the non-service related components of net periodic benefit expense/(income) for the Pension, SERP and PBOP Plans. These regulatory liabilities will be amortized over the remaining useful lives of the various classes of utility property, plant and equipment.

AFUDC - Transmission: Regulatory liabilities were recorded by CL&P and NSTAR Electric for AFUDC accrued on certain reliability-related transmission projects to reflect local rate base recovery. These regulatory liabilities will be amortized over the depreciable life of the related transmission assets.

CL&P Settlement Agreement and Storm Performance Penalty: On April 28, 2021, PURA issued a final decision on CL&P's compliance with its emergency response plan that concluded CL&P failed to comply with certain storm performance standards and was imprudent in certain instances. A $28.4 million performance penalty assessed by PURA was recorded within current regulatory liabilities on CL&P's balance sheet and was credited to customers on electric bills beginning on September 1, 2021 over a one-year period. On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel, Office of the Attorney General and the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory proceedings initiated by PURA. PURA approved the settlement



agreement on October 27, 2021. CL&P recorded a current regulatory liability of $75 million on the balance sheet associated with the provisions of the settlement agreement. Customer credits of $65 million were distributed based on customer sales over a two-month billing period from December 1, 2021 to January 31, 2022. CL&P also irrevocably set aside $10 million in a customer assistance fund to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages. Those customers were provided with $10 million of bill forgiveness in the first quarter of 2022. The balance as of December 31, 2021 represented the reserve for customer credits not yet issued and bill payment assistance not yet provided. See Note 13G, "Commitments and Contingencies - CL&P Regulatory Matters," for further information.

Other Regulatory Liabilities: Other Regulatory Liabilities primarily include EGMA’s acquired regulatory liability as a result of the 2020 DPU-approved rate settlement agreement and the CMA asset acquisition on October 9, 2020, and various other items.

FERC ROE Complaints: As of December 31, 2022, Eversource has a reserve established for the second ROE complaint period in the pending FERC ROE complaint proceedings, which was recorded as a regulatory liability and is reflected within Regulatory Tracking Mechanisms in the table above. The cumulative pre-tax reserve (excluding interest) as of December 31, 2022 totaled $39.1 million for Eversource (including $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH). See Note 13E, "Commitments and Contingencies – FERC ROE Complaints," for further information on developments in the pending ROE complaint proceedings.

## Recent Regulatory Developments:

CL&P Rate Relief Plan: On November 28, 2022, Governor Lamont, DEEP, Office of Consumer Counsel, and CL&P jointly developed a rate relief plan for electric customers for the winter peak season of January 1, 2023 through April 30, 2023. On December 16, 2022, PURA approved the rate relief plan. As part of the rate relief plan, CL&P reduced the Non-Bypassable Federally Mandated Congestion Charge (NBPCMC) rate effective January 1, 2023 to provide customers with an average $10 monthly bill credit from January through April 2023. This rate reduction accelerates the return to customers of net revenues generated by long-term state-approved energy contracts with the Millstone and Seabrook nuclear power plants of approximately $90 million. The rate relief plan also included instituting a temporary, flat monthly discount for qualifying low-income hardship customers effective January 1, 2023. This flat-rate credit will continue until a new low-income discount rate that was approved by PURA in an October 19, 2022 decision is implemented in 2024. These aspects of the rate relief plan do not impact CL&P's earnings but do impact its future cash flows. Also as part of the rate relief plan, CL&P committed to contribute $10 million to an energy assistance program for qualifying hardship customers, which is expected to be distributed as a bill credit to those customers by the end of the first quarter of 2023. CL&P recorded a current liability of $10 million on the balance sheet and a charge to expense on the statement of income for the year ended December 31, 2022 associated with the customer assistance program.

NSTAR Electric Distribution Rate Case: 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. The DPU approved a renewal of the performance-based ratemaking (PBR) plan originally authorized in its previous 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 and exogenous events. The DPU also allowed for adjustments to the PBR mechanism for the recovery of future capital additions based on a historical five-year average of total capital additions, beginning with the January 1, 2024 PBR adjustment. The decision allows an authorized regulatory ROE of 9.80 percent on a capital structure including 53.2 percent equity.

Among other items, the DPU approved an increase to the annual storm fund contribution collected through base distribution rates from $10 million to $31 million, and allowed for the recovery of storm threshold costs of $1.3 million per storm event subsequent to the eighth storm in a calendar year (six recovered in base rates plus two additional storms). The DPU approved cost recovery of a portion of NSTAR Electric's outstanding storm costs beginning on January 1, 2023 and January 1, 2024, subject to reconciliation from future prudence reviews. In a subsequent compliance filing, the DPU allowed recovery to commence for outstanding storm costs occurring between 2018 and 2022 and interest in a total of $162.1 million over a five-year period starting January 1, 2023. In addition, NSTAR Electric will begin to recover 2021 exogenous storms and interest in a total of $220.9 million over a five-year period beginning January 1, 2024. The DPU also approved the recovery of historical exogenous property taxes of $30.8 million incurred from 2020 through 2022 over a two-year period and $8.3 million incurred from 2012 through 2015 over a five-year period effective January 1, 2023. As a result of this decision, these deferred property taxes were reclassified from Other Long-Term Assets to Regulatory Assets on the NSTAR Electric balance sheet.

NSTAR Gas Distribution Rates: As part of an inflation-based mechanism, NSTAR Gas submitted its second annual Performance Based Rate Adjustment filing on September 15, 2022 and on October 31, 2022, the DPU approved a $21.7 million increase to base distribution rates for effect on November 1, 2022. The increase is inclusive of a $4.5 million permanent increase related to exogenous property taxes and a $5.4 million increase related to an October 6, 2021 mitigation plan filing that delayed recovery of a portion of a base distribution rate increase originally scheduled to take effect November 1, 2021. The DPU also approved the recovery of historical exogenous property taxes incurred from November 1, 2020 through October 31, 2022 of $8.2 million over a two-year period through a separate reconciling mechanism effective November 1, 2022. As a result of this decision, these deferred property taxes were reclassified from Other Long-Term Assets to Regulatory Balance sheet.

EGMA Distribution Rates: As established in an October 7, 2020 EGMA Rate Settlement Agreement approved by the DPU, on September 16, 2022 EGMA filed for its second base distribution rate increase and on October 31, 2022, the DPU approved a $6.7 million increase to base distribution rates and a $3.3 million increase to the Tax Act Credit Factor for effect on November 1, 2022. The DPU also approved the recovery of historical exogenous property taxes incurred from November 1, 2020 through October 31, 2022 of $8.6 million over a two-year period through a separate reconciling mechanism effective November 1, 2022. EGMA will request recovery of incremental property taxes incurred after October 31, 2022 in future exogenous filings. As a result of this decision, these deferred property taxes were reclassified from Other Long-Term Assets to Regulatory Assets on the Eversource balance sheet.



## 3. PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overheads and AFUDC for regulated property. The cost of repairs and maintenance is charged to Operations and Maintenance expense as incurred.

The following tables summarize property, plant and equipment by asset category:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="3">As of December 31,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Distribution - Electric</td><td>$ 18,326.2</td><td>$ 17,679.1</td><td></td></tr><tr><td>Distribution - Natural Gas</td><td>7,443.8</td><td>6,694.8</td><td></td></tr><tr><td>Transmission - Electric</td><td>13,709.3</td><td>12,882.4</td><td></td></tr><tr><td>Distribution - Water</td><td>2,112.6</td><td>1,900.9</td><td></td></tr><tr><td>Solar</td><td>200.8</td><td>200.9</td><td></td></tr><tr><td>Utility</td><td>41,792.7</td><td>39,358.1</td><td></td></tr><tr><td>Other \( ^{(1)} \)</td><td>1,738.1</td><td>1,469.5</td><td></td></tr><tr><td>Property, Plant and Equipment, Gross</td><td>43,530.8</td><td>40,827.6</td><td></td></tr><tr><td>Less: Accumulated Depreciation</td><td></td><td></td><td></td></tr><tr><td>Utility</td><td>(9,167.4)</td><td>(8,885.2)</td><td></td></tr><tr><td>Other</td><td>(706.1)</td><td>(580.1)</td><td></td></tr><tr><td>Total Accumulated Depreciation</td><td>(9,873.5)</td><td>(9,465.3)</td><td></td></tr><tr><td>Property, Plant and Equipment, Net</td><td>33,657.3</td><td>31,362.3</td><td></td></tr><tr><td>Construction Work in Progress</td><td>2,455.5</td><td>2,015.4</td><td></td></tr><tr><td>Total Property, Plant and Equipment, Net</td><td>$ 36,112.8</td><td>$ 33,377.7</td><td></td></tr></table>

As of December 31,

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="3">2022</td><td colspan="3">2021</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Distribution - Electric</td><td>$ 7,370.1</td><td>$ 8,410.0</td><td>$ 2,586.4</td><td>$ 7,117.6</td><td>$ 8,105.5</td><td>$ 2,496.2</td></tr><tr><td>Transmission - Electric</td><td>6,165.1</td><td>5,333.8</td><td>2,212.0</td><td>5,859.0</td><td>5,090.5</td><td>1,934.6</td></tr><tr><td>Solar</td><td>—</td><td>200.8</td><td>—</td><td>—</td><td>200.9</td><td>—</td></tr><tr><td>Property, Plant and Equipment, Gross</td><td>13,535.2</td><td>13,944.6</td><td>4,798.4</td><td>12,976.6</td><td>13,396.9</td><td>4,430.8</td></tr><tr><td>Less: Accumulated Depreciation</td><td>(2,567.1)</td><td>(3,381.2)</td><td>(912.3)</td><td>(2,572.1)</td><td>(3,227.3)</td><td>(908.4)</td></tr><tr><td>Property, Plant and Equipment, Net</td><td>10,968.1</td><td>10,563.4</td><td>3,886.1</td><td>10,404.5</td><td>10,169.6</td><td>3,522.4</td></tr><tr><td>Construction Work in Progress</td><td>498.9</td><td>1,063.6</td><td>174.1</td><td>399.0</td><td>707.0</td><td>134.1</td></tr><tr><td>Total Property, Plant and Equipment, Net</td><td>$ 11,467.0</td><td>$ 11,627.0</td><td>$ 4,060.2</td><td>$ 10,803.5</td><td>$ 10,876.6</td><td>$ 3,656.5</td></tr></table>

(1) These assets are primarily comprised of computer software, hardware and equipment at Eversource Service and buildings at The Rocky River Realty Company.

Depreciation: Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution and the water utilities). The composite rates, which are subject to approval by the appropriate state regulatory agency, include a cost of removal component, which is collected from customers over the lives of the plant assets and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service.

Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.

The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:

<table><tr><td>(Percent)</td><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Eversource</td><td>3.0 %</td><td>3.1 %</td><td>3.0 %</td></tr><tr><td>CL&amp;P</td><td>2.8 %</td><td>2.8 %</td><td>2.8 %</td></tr><tr><td>NSTAR Electric</td><td>2.7 %</td><td>2.8 %</td><td>2.8 %</td></tr><tr><td>PSNH</td><td>3.0 %</td><td>3.1 %</td><td>2.8 %</td></tr></table>

The following table summarizes average remaining useful lives of depreciable assets:

As of December 31, 2022

<table><tr><td>(Years)</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Distribution - Electric</td><td>34.2</td><td>35.0</td><td>34.6</td><td>30.8</td></tr><tr><td>Distribution - Natural Gas</td><td>37.4</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Transmission - Electric</td><td>39.8</td><td>36.3</td><td>45.2</td><td>39.3</td></tr><tr><td>Distribution - Water</td><td>39.0</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Solar</td><td>22.9</td><td>—</td><td>22.9</td><td>—</td></tr><tr><td>Other \( ^{(1)} \)</td><td>11.0</td><td>—</td><td>—</td><td>—</td></tr></table>

(1) The estimated useful life of computer software, hardware and equipment primarily ranges from 5 to 15 years and of buildings is 40 years.



## 4. DERIVATIVE INSTRUMENTS

The electric and natural gas companies purchase and procure energy and energy-related products, which are subject to price volatility, for their customers. The costs associated with supplying energy to customers are recoverable from customers in future rates. These regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and non-derivative contracts.

Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses on the statements of income as electricity or natural gas is delivered.

Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the electric and natural gas companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as contract settlement amounts are recovered from, or refunded to, customers in their respective energy supply rates.

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, on the balance sheets. The following table presents the gross fair values of contracts, categorized by risk type, and the net amounts recorded as current or long-term derivative assets or liabilities:

<table><tr><td rowspan="2"></td><td colspan="2">2022</td><td colspan="2">2021</td></tr><tr><td>Fair Value Hierarchy</td><td>Commodity Supply and Price Risk Management</td><td>Net Amount Recorded as a Derivative</td><td>Commodity Supply and Price Risk Management</td><td>Net Amount Recorded as a Derivutive</td></tr><tr><td>Current Derivative Assets</td><td>Level 3</td><td>$ 16.3</td><td>$ (0.5)</td><td>$ 15.8</td><td>$ 14.7</td></tr><tr><td>Long-Term Derivative Assets</td><td>Level 3</td><td>28.8</td><td>(0.9)</td><td>27.9</td><td>46.9</td></tr><tr><td>Current Derivative Liabilities</td><td>Level 3</td><td>(81.6)</td><td>—</td><td>(81.6)</td><td>(73.5)</td></tr><tr><td>Long-Term Derivative Liabilities</td><td>Level 3</td><td>(143.9)</td><td>—</td><td>(143.9)</td><td>(235.4)</td></tr></table>

(1) Amounts represent derivative assets and liabilities that Eversource elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.

The business activities that result in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2022, CL&P's derivative assets were exposed to counterparty credit risk and contracted with investment grade entities.

## Derivative Contracts at Fair Value with Offsetting Regulatory Amounts

Commodity Supply and Price Risk Management: As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. CL&P has a sharing agreement with UI, with 80 percent of the costs or benefits of each contract borne by or allocated to CL&P and 20 percent borne by or allocated to UI. The combined capacities of these contracts as of December 31, 2022 and 2021 were 674 MW and 675 MW, respectively. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the capacity market price received in the ISO-NE capacity markets.

For the years ended December 31, 2022, 2021 and 2020, there were gains of $10.1 million and losses of $7.1 million and $21.2 million, respectively, deferred as regulatory costs, which reflect the change in fair value associated with Eversource's derivative contracts.

## Fair Value Measurements of Derivative Instruments

The fair value of derivative contracts classified as Level 3 utilizes both significant observable and unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations adjusted for assumptions related to exit price. Valuations of derivative contracts using a discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the Company's credit rating for liabilities. Significant observable inputs for valuations of these contracts include energy-related product prices in future years for which quoted prices in an active market exist. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy-related products, and accounting requirements.

The following is a summary of the significant unobservable inputs utilized in the valuations of the derivative contracts classified as Level 3:

<table><tr><td rowspan="3">CL&amp;P</td><td colspan="12">As of December 31,</td></tr><tr><td colspan="6">2022</td><td colspan="6">2021</td></tr><tr><td colspan="3">Range</td><td colspan="3">Average</td><td colspan="2">Period Covered</td><td colspan="2">Range</td><td colspan="2">Average</td><td>Period Covered</td></tr><tr><td>Forward Reserve Prices</td><td>$0.44</td><td>—</td><td>$0.5</td><td>$</td><td>0.47</td><td>per kW-Month</td><td>2023 - 2024</td><td>$0.50</td><td>—</td><td>$1.1</td><td>$</td><td>0.82</td><td>per kW-Month</td></tr></table>

Exit price premiums of 2.9 percent through 7.1 percent, or a weighted average of 6.1 percent, are also Level 3 significant unobservable inputs applied to these contracts and reflect the uncertainty and illiquidity premiums that would be required based on the most recent market activity available for similar type contracts. The risk premium was weighted by the relative fair value of the net derivative instruments.



As of December 31, 2021, Level 3 unobservable inputs also utilized in the valuation of CL&P's capacity-related contracts included capacity prices of $2.61 per kW-Month over the period 2025 through 2026. Beginning in the first quarter of 2022, these capacity price inputs are now observable.

Significant increases or decreases in future capacity or forward reserve prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in risk premiums would increase the fair value of the derivative liability. Changes in these fair values are recorded as a regulatory asset or liability and do not impact net income.

The following table presents changes in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis.

<table><tr><td rowspan="2">CL&amp;P (Millions of Dollars)</td><td colspan="3">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td></td></tr><tr><td>Derivatives, Net:</td><td></td><td></td><td></td></tr><tr><td>Fair Value as of Beginning of Period</td><td>$ (249.2)</td><td>$ (293.1)</td><td></td></tr><tr><td>Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets</td><td>10.1</td><td>(8.5)</td><td></td></tr><tr><td>Settlements</td><td>57.3</td><td>52.4</td><td></td></tr><tr><td>Fair Value as of End of Period</td><td>$ (181.8)</td><td>$ (249.2)</td><td></td></tr></table>

## 5. MARKETABLE SECURITIES

Eversource holds marketable securities that are primarily used to fund certain non-qualified executive benefits. The trusts that hold these marketable securities are not subject to regulatory oversight by state or federal agencies. Eversource’s marketable securities also include the CYAPC and YAEC legally restricted trusts that each hold equity and available-for-sale debt securities to fund the spent nuclear fuel removal obligations of their nuclear fuel storage facilities. Equity and available-for-sale debt marketable securities are recorded at fair value, with the current portion recorded in Prepayments and Other Current Assets and the long-term portion recorded in Marketable Securities on the balance sheets.

Equity Securities: Unrealized gains and losses on equity securities held in Eversource's non-qualified executive benefit trust are recorded in Other Income, Net on the statements of income. The fair value of these equity securities as of December 31, 2022 and 2021 was $20.0 million and $40.2 million, respectively. For the years ended December 31, 2022, 2021 and 2020, there were unrealized losses of $9.7 million and unrealized gains of $4.4 million and $3.7 million recorded in Other Income, Net related to these equity securities, respectively.

Eversource's equity securities also include CYAPC's and YAEC's marketable securities held in spent nuclear fuel trusts, which had fair values of $170.1 million and $214.0 million as of December 31, 2022 and 2021, respectively. Unrealized gains and losses for these spent nuclear fuel trusts are subject to regulatory accounting treatment and are recorded in Marketable Securities with the corresponding offset to long-term liabilities on the balance sheets, with no impact on the statements of income.

Available-for-Sale Debt Securities: The following is a summary of the available-for-sale debt securities:

<table><tr><td rowspan="3">Eversource (Millions of Dollars)</td><td colspan="12">As of December 31,</td></tr><tr><td colspan="6">2022</td><td colspan="6">2021</td></tr><tr><td>Amortized Cost</td><td>Pre-Tax Unrealized Gains</td><td>Pre-Tax Unrealized Losses</td><td>Fair Value</td><td>Amortized Cost</td><td>Pre-Tax Unrealized Gains</td><td>Pre-Tax Losses</td><td>Fair Value</td><td></td><td></td><td></td><td></td></tr><tr><td>Debt Securities</td><td>$ 201.6</td><td>$ 0.1</td><td>$ (16.2)</td><td>$ 185.5</td><td>$ 214.5</td><td>$ 5.1</td><td>$ (0.2)</td><td>$ 219.4</td><td></td><td></td><td></td><td></td></tr></table>

Unrealized gains and losses on available-for-sale debt securities held in Eversource's non-qualified executive benefit trust are recorded in Accumulated Other Comprehensive Income, excluding amounts related to credit losses or losses on securities intended to be sold, which are recorded in Other Income, Net. There have been no credit losses for the years ended December 31, 2022 and 2021, and no allowance for credit losses as of December 31, 2022. Factors considered in determining whether a credit loss exists include adverse conditions specifically affecting the issuer, the payment history, ratings and rating changes of the security, and the severity of the impairment. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated. Debt securities included in Eversource's non-qualified benefit trust portfolio are investment-grade bonds with a lower default risk based on their credit quality.

Eversource's debt securities also include CYAPC's and YAEC's marketable securities held in spent nuclear fuel trusts in the amounts of $163.2 million and $189.9 million as of December 31, 2022 and 2021, respectively. Unrealized gains and losses for available-for-sale debt securities included in the CYAPC and YAEC spent nuclear fuel trusts are subject to regulatory accounting treatment and are recorded in Marketable Securities with the corresponding offset to long-term liabilities on the balance sheets, with no impact on the statements of income. Pre-tax unrealized gains and losses as of December 31, 2022 and 2021 primarily relate to the debt securities included in CYAPC's and YAEC's spent nuclear fuel trusts.



As of December 31, 2022, the contractual maturities of available-for-sale debt securities were as follows:

<table><tr><td>Eversource (Millions of Dollars)</td><td>Amortized Cost</td><td>Fair Value</td></tr><tr><td>Less than one year (1)</td><td>$ 28.5</td><td>$ 28.3</td></tr><tr><td>One to five years</td><td>43.8</td><td>42.4</td></tr><tr><td>Six to ten years</td><td>35.6</td><td>32.3</td></tr><tr><td>Greater than ten years</td><td>93.7</td><td>82.5</td></tr><tr><td>Total Debt Securities</td><td>$ 201.6</td><td>$ 185.5</td></tr></table>

(1) Amounts in the Less than one year category include securities in the CYAPC and YAEC spent nuclear fuel trusts, which are restricted and are classified in long-term Marketable Securities on the balance sheets.

Realized Gains and Losses: Realized gains and losses are recorded in Other Income, Net for Eversource's benefit trust and are offset in long-term liabilities for CYAPC and YAEC. Eversource utilizes the specific identification basis method for the Eversource non-qualified benefit trust, and the average cost basis method for the CYAPC and YAEC spent nuclear fuel trusts to compute the realized gains and losses on the sale of marketable securities.

Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

<table><tr><td rowspan="2">Eversource (Millions of Dollars)</td><td colspan="2">As of December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Level 1:</td><td></td><td></td></tr><tr><td>Mutual Funds and Equities</td><td>$ 190.1</td><td>$ 254.2</td></tr><tr><td>Money Market Funds</td><td>25.4</td><td>31.3</td></tr><tr><td>Total Level 1</td><td>$ 215.5</td><td>$ 285.5</td></tr><tr><td>Level 2:</td><td></td><td></td></tr><tr><td>U.S. Government Issued Debt Securities (Agency and Treasury)</td><td>$ 82.3</td><td>$ 81.3</td></tr><tr><td>Corporate Debt Securities</td><td>46.1</td><td>65.3</td></tr><tr><td>Asset-Backed Debt Securities</td><td>8.6</td><td>12.6</td></tr><tr><td>Municipal Bonds</td><td>12.7</td><td>12.3</td></tr><tr><td>Other Fixed Income Securities</td><td>10.4</td><td>16.6</td></tr><tr><td>Total Level 2</td><td>$ 160.1</td><td>$ 188.1</td></tr><tr><td>Total Marketable Securities</td><td>$ 375.6</td><td>$ 473.6</td></tr></table>

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instruments and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates, and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

## 6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

Investments in entities that are not consolidated are included in long-term assets on the balance sheets and earnings impacts from these equity investments are included in Other Income, Net on the statements of income. Eversource's investments included the following:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="3">Investment Balance as of December 31,</td></tr><tr><td>Ownership Interest</td><td>2022</td><td>2021</td></tr><tr><td>Offshore Wind Business - North East Offshore</td><td>50 %</td><td>$ 1,947.1</td><td>$ 1,213.6</td></tr><tr><td>Natural Gas Pipeline - Algonquin Gas Transmission, LLC</td><td>15 %</td><td>118.8</td><td>121.9</td></tr><tr><td>Renewable Energy Investment Fund</td><td>90 %</td><td>84.1</td><td>76.5</td></tr><tr><td>Other</td><td>various</td><td>26.1</td><td>24.3</td></tr><tr><td>Total Investments in Unconsolidated Affiliates</td><td></td><td>$ 2,176.1</td><td>$ 1,436.3</td></tr></table>

For the years ended December 31, 2022, 2021 and 2020, Eversource had equity in earnings of unconsolidated affiliates of $22.9 million, $14.2 million, and $14.2 million, respectively. Eversource received dividends from its equity method investees of $26.2 million, $21.6 million, and $21.8 million, respectively, for the years ended December 31, 2022, 2021 and 2020.

Investments in affiliates where Eversource has the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost. 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. The carrying amount of Eversource's offshore wind investments exceeded its share of underlying equity in net assets by $343.1 million and $300.4 million, respectively, as of December 31, 2022 and 2021. As of December 31, 2022, these basis differences are



primarily comprised of $168.9 million of equity method goodwill that is not being amortized, intangible assets for PPAs, and capitalized interest.

Offshore Wind Business: Eversource's offshore wind business includes a 50 percent ownership interest in North East Offshore, which holds PPAs and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as an undeveloped offshore lease area. The offshore wind investment includes capital expenditures for the three offshore wind projects, as well as capitalized costs related to future development, acquisition costs of offshore lease areas, and capitalized interest. Cash flows used in investing activities presented in Investments in Unconsolidated Affiliates on the statements of cash flows primarily relates to capital contributions in the offshore wind investment.

On May 4, 2022, Eversource announced that it had initiated a strategic review of its offshore wind investment portfolio. As part of that review, Eversource is exploring strategic alternatives that could result in a potential sale of all, or part, of its 50 percent interest in its offshore wind partnership with Ørsted. In late July, Eversource started preliminary and targeted outreach to interested parties. Eversource continues to work with interested parties through this ongoing process and expects to complete this review in the second quarter of 2023. Eversource's strategic review of its offshore wind investment does not impact the presentation of the December 31, 2022 financial statements.

NSTAR Electric: As of December 31, 2022 and 2021, NSTAR Electric's investments included a 14.5 percent ownership interest in two companies that transmit hydro-electricity imported from the Hydro-Quebec system in Canada of $9.3 million and $9.0 million, respectively.

Impairment of Equity Method Investments: Equity method investments are assessed for impairment when conditions exist that indicate that the fair value of the investment is less than book value. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations 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. No impairments occurred during the year 2022. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment.

Eversource believes that the fair market value of its offshore wind investment is greater than the carrying value based upon management’s expectation for future cash flows arising from the sale of all, or part, of its investment. There are uncertainties in a sale process, and there could be changes in market conditions that would impact Eversource’s ability to sell this investment or the value it would receive for these assets. In the event that the strategic review does not result in the sale of the offshore wind business or that a sale of the offshore wind business is significantly delayed or at lower than expected value from these changes in market conditions driven by unfavorable developments, such as scheduling or permitting delays, increases in cost estimates, changes to tax laws impacting the project’s ability to monetize tax attributes, higher interest rates, and increases in the discount rate, it could result in Eversource having to evaluate whether or not its investment is impaired. Any resulting impairment charge could have a material adverse effect on the financial position and results of operations.

During the year ended December 31, 2020, Eversource recorded an other-than-temporary impairment of $2.8 million within Other Income, Net on the statement of income, related to a write-off of an investment within a renewable energy fund.

## 7. ASSET RETIREMENT OBLIGATIONS

Eversource, including CL&P, NSTAR Electric and PSNH, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated, even if it is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily CYAPC's and YAEC's obligation to dispose of spent nuclear fuel and high level waste, and also certain assets containing asbestos and hazardous contamination. Management has performed fair value calculations reflecting expected probabilities for settlement scenarios.

The fair value of an ARO is recorded as a long-term liability with a corresponding amount included in Property, Plant and Equipment, Net on the balance sheets. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation and the corresponding credits are recorded as accumulated depreciation and ARO liabilities, respectively. As the electric and natural gas companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and both the depreciation and accretion costs associated with these companies' AROs are recorded as increases to Regulatory Assets on the balance sheets.

A reconciliation of the beginning and ending carrying amounts of ARO liabilities is as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="5">2022</td><td colspan="5">2021</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNN</td><td></td></tr><tr><td>Balance as of Beginning of Year</td><td>$ 500.1</td><td>$ 35.0</td><td>$ 97.5</td><td>$ 4.7</td><td>$ 499.7</td><td>$ 33.4</td><td>$ 91.8</td><td>$ 4.4</td><td></td><td></td></tr><tr><td>Liabilities Settled During the Year</td><td>(22.3)</td><td>—</td><td>—</td><td>—</td><td>(23.9)</td><td>(0.6)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Accretion</td><td>28.9</td><td>2.4</td><td>4.1</td><td>0.2</td><td>29.4</td><td>2.2</td><td>4.0</td><td>0.3</td><td></td><td></td></tr><tr><td>Revisions in Estimated Cash Flows</td><td>(4.0)</td><td>—</td><td>(0.3)</td><td>—</td><td>(5.1)</td><td>—</td><td>1.7</td><td>—</td><td></td><td></td></tr><tr><td>Balance as of End of Year</td><td>$ 502.7</td><td>$ 37.4</td><td>$ 101.3</td><td>$ 4.9</td><td>$ 500.1</td><td>$ 35.0</td><td>$ 97.5</td><td>$ 4.7</td><td></td><td></td></tr></table>

Eversource's amounts include CYAPC and YAEC's AROs of $320.5 million and $325.9 million as of December 31, 2022 and 2021, respectively. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE's timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste and other assumptions, including discount rates. The incremental asset recorded as an offset to the ARO liability was fully depreciated since the plants have no remaining useful life. Any changes in



the ARO liability are recorded with a corresponding offset to the related regulatory asset. The assets held in the CYAPC and YAEC spent nuclear fuel trusts are restricted for settling the ARO and all other nuclear fuel storage obligations. For further information on the assets held in the spent nuclear fuel trusts, see Note 5, "Marketable Securities," to the financial statements.

## 8. SHORT-TERM DEBT

Short-Term Debt - Borrowing Limits: The amount of short-term borrowings that may be incurred by CL&P and NSTAR Electric is subject to periodic approval by the FERC. Because the NHPUC has jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. On December 3, 2021, the FERC granted authorization that allows CL&P to issue total short-term borrowings in an aggregate principal amount not to exceed $600 million outstanding at any one time, through December 31, 2023. On December 3, 2021, the FERC granted authorization that allows NSTAR Electric to issue total short-term borrowings in an aggregate principal amount not to exceed $655 million outstanding at any one time, through December 31, 2023.

PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2022, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled $443.5 million.

CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. As of December 31, 2022, CL&P had $1.01 billion of unsecured debt capacity available under this authorization.

Yankee Gas, NSTAR Gas and EGMA are not required to obtain approval from any state or federal authority to incur short-term debt.

Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource parent has a $2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are parties to a five-year $2.00 billion revolving credit facility, which terminates on October 15, 2027. This revolving credit facility serves to backstop Eversource parent's $2.00 billion commercial paper program.

NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility, which terminates on October 15, 2027. This revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program.

The amount of borrowings outstanding and available under the commercial paper programs were as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Borrowings Outstanding as of December 31,</td><td colspan="2">Available Borrowing Capacity as of December 31,</td><td colspan="2">Weighted-Average Interest Rate as of December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td></tr><tr><td>(Earnings of Dollars)</td><td>1,442.2</td><td>1,343.0</td><td>557.8</td><td>657.0</td><td>4.63%</td><td>0.31%</td><td></td></tr><tr><td>Eversource Parent Commercial Paper Program</td><td>1,442.2</td><td>1,343.0</td><td>557.8</td><td>657.0</td><td>4.63%</td><td>0.31%</td><td></td></tr><tr><td>NSTAR Electric Commercial Paper Program</td><td>—</td><td>162.5</td><td>650.0</td><td>487.5</td><td>—%</td><td>0.14%</td><td></td></tr></table>

There were no borrowings outstanding on the revolving credit facilities as of December 31, 2022 or 2021.

CL&P and PSNH have uncommitted line of credit agreements totaling $450 million and $300 million, respectively, which will expire on May 12, 2023. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2022.

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.

Under the credit facilities described above, Eversource and its subsidiaries, including CL&P, NSTAR Electric, PSNH, NSTAR Gas, EGMA, Yankee Gas, and Aquarion Water Company of Connecticut, must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. As of December 31, 2022 and 2021, Eversource and its subsidiaries were in compliance with these covenants. If Eversource or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid, and additional borrowings by such borrower would not be permitted under its respective credit facility.

Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of December 31, 2022, there were intercompany loans from Eversource parent to PSNH of $173.3 million. As of December 31, 2021, there were intercompany loans from Eversource parent to PSNH of $110.6 million. 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.

Sources and Uses of Cash: The Company expects the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities.



## 9. LONG-TERM DEBT

Details of long-term debt outstanding are as follows:

<table><tr><td rowspan="2">CL&amp;P
(Millions of Dollars)</td><td rowspan="2">Interest Rate</td><td colspan="2">As of December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>First Mortgage Bonds:</td><td></td><td></td><td></td></tr><tr><td>1994 Series D due 2024</td><td>7.875 %</td><td>139.8</td><td>139.8</td></tr><tr><td>2004 Series B due 2034</td><td>5.750 %</td><td>130.0</td><td>130.0</td></tr><tr><td>2005 Series B due 2035</td><td>5.625 %</td><td>100.0</td><td>100.0</td></tr><tr><td>2006 Series A due 2036</td><td>6.350 %</td><td>250.0</td><td>250.0</td></tr><tr><td>2007 Series B due 2037</td><td>5.750 %</td><td>150.0</td><td>150.0</td></tr><tr><td>2007 Series D due 2037</td><td>6.375 %</td><td>100.0</td><td>100.0</td></tr><tr><td>2013 Series A due 2023</td><td>2.500 %</td><td>400.0</td><td>400.0</td></tr><tr><td>2014 Series A due 2044</td><td>4.300 %</td><td>475.0</td><td>475.0</td></tr><tr><td>2015 Series A due 2045</td><td>4.150 %</td><td>350.0</td><td>350.0</td></tr><tr><td>2017 Series A due 2027</td><td>3.200 %</td><td>500.0</td><td>500.0</td></tr><tr><td>2018 Series A due 2048</td><td>4.000 %</td><td>800.0</td><td>800.0</td></tr><tr><td>2020 Series A due 2025</td><td>0.750 %</td><td>400.0</td><td>400.0</td></tr><tr><td>2021 Series A due 2031</td><td>2.050 %</td><td>425.0</td><td>425.0</td></tr><tr><td>Total First Mortgage Bonds</td><td></td><td>4,219.8</td><td>4,219.8</td></tr><tr><td>Less Amounts due Within One Year</td><td></td><td>(400.0)</td><td>—</td></tr><tr><td>Current Portion Classified as Long-Term Debt (1)</td><td></td><td>400.0</td><td>—</td></tr><tr><td>Unamortized Premiums and Discounts, Net</td><td></td><td>21.5</td><td>23.1</td></tr><tr><td>Unamortized Debt Issuance Costs</td><td></td><td>(24.8)</td><td>(27.5)</td></tr><tr><td>CL&amp;P Long-Term Debt</td><td></td><td>4,216.5</td><td>4,215.4</td></tr><tr><td>NSTAR Electric
(Millions of Dollars)</td><td>Interest Rate</td><td colspan="2">As of December 31,</td></tr><tr><td>Debentures:</td><td></td><td>2022</td><td>2021</td></tr><tr><td>2006 Debentures due 2036</td><td>5.750 %</td><td>200.0</td><td>200.0</td></tr><tr><td>2010 Debentures due 2040</td><td>5.500 %</td><td>300.0</td><td>300.0</td></tr><tr><td>2012 Debentures due 2022</td><td>2.375 %</td><td>—</td><td>400.0</td></tr><tr><td>2014 Debentures due 2044</td><td>4.400 %</td><td>300.0</td><td>300.0</td></tr><tr><td>2015 Debentures due 2025</td><td>3.250 %</td><td>250.0</td><td>250.0</td></tr><tr><td>2016 Debentures due 2026</td><td>2.700 %</td><td>250.0</td><td>250.0</td></tr><tr><td>2017 Debentures due 2027</td><td>3.200 %</td><td>700.0</td><td>700.0</td></tr><tr><td>2019 Debentures due 2029</td><td>3.250 %</td><td>400.0</td><td>400.0</td></tr><tr><td>2020 Debentures due 2030</td><td>3.950 %</td><td>400.0</td><td>400.0</td></tr><tr><td>2021 Debentures due 2051</td><td>3.100 %</td><td>300.0</td><td>300.0</td></tr><tr><td>2021 Debentures due 2031</td><td>1.950 %</td><td>300.0</td><td>300.0</td></tr><tr><td>2022 Debentures due 2052</td><td>4.550 %</td><td>450.0</td><td>—</td></tr><tr><td>2022 Debentures due 2052</td><td>4.950 %</td><td>400.0</td><td>—</td></tr><tr><td>Total Debentures</td><td></td><td>4,250.0</td><td>3,800.0</td></tr><tr><td>Notes:</td><td></td><td></td><td></td></tr><tr><td>2004 Senior Notes Series B due 2034</td><td>5.900 %</td><td>50.0</td><td>50.0</td></tr><tr><td>2007 Senior Notes Series D due 2037</td><td>6.700 %</td><td>40.0</td><td>40.0</td></tr><tr><td>2013 Senior Notes Series G due 2023</td><td>3.880 %</td><td>80.0</td><td>80.0</td></tr><tr><td>2016 Senior Notes Series H due 2026</td><td>2.750 %</td><td>50.0</td><td>50.0</td></tr><tr><td>Total Notes</td><td></td><td>220.0</td><td>220.0</td></tr><tr><td>Less Amounts due Within One Year</td><td></td><td>(80.0)</td><td>(400.0)</td></tr><tr><td>Unamortized Premiums and Discounts, Net</td><td></td><td>(14.8)</td><td>(11.2)</td></tr><tr><td>Unamortized Debt Issuance Costs</td><td></td><td>(30.1)</td><td>(23.4)</td></tr><tr><td>NSTAR Electric Long-Term Debt</td><td></td><td>4,345.1</td><td>3,585.4</td></tr></table>



<table><tr><td rowspan="2">(Millions of Dollars)</td><td rowspan="2">Interest Rate</td><td colspan="2">As of December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>First Mortgage Bonds:</td><td></td><td></td><td></td></tr><tr><td>2005 Series M due 2035</td><td>5.600 %</td><td>50.0</td><td>50.0</td></tr><tr><td>2013 Series S due 2023</td><td>3.500 %</td><td>325.0</td><td>325.0</td></tr><tr><td>2019 Series T due 2049</td><td>3.600 %</td><td>300.0</td><td>300.0</td></tr><tr><td>2020 Series U due 2050</td><td>2.400 %</td><td>150.0</td><td>150.0</td></tr><tr><td>2021 Series V due 2031</td><td>2.200 %</td><td>350.0</td><td>350.0</td></tr><tr><td>Total First Mortgage Bonds</td><td></td><td>1,175.0</td><td>1,175.0</td></tr><tr><td>Less Amounts due Within One Year</td><td></td><td>(325.0)</td><td>—</td></tr><tr><td>Current Portion Classified as Long-Term Debt (1)</td><td></td><td>295.3</td><td>—</td></tr><tr><td>Unamortized Premiums and Discounts, Net</td><td></td><td>(2.5)</td><td>(2.6)</td></tr><tr><td>Unamortized Debt Issuance Costs</td><td></td><td>(7.9)</td><td>(8.6)</td></tr><tr><td>PSNH Long-Term Debt</td><td></td><td>1,134.9</td><td>1,163.8</td></tr></table>

<table><tr><td rowspan="2">(Millions of Dollars)</td><td rowspan="2">Interest Rate</td><td colspan="2">As of December 31,</td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Yankee Gas - First Mortgage Bonds due 2024 - 2051</td><td>1.380 % - 5.350%</td><td>845.0</td><td>765.0</td></tr><tr><td>NSTAR Gas - First Mortgage Bonds due 2025 - 2051</td><td>2.250 % - 7.110%</td><td>705.0</td><td>580.0</td></tr><tr><td>EGMA - First Mortgage Bonds due 2031 - 2052</td><td>2.110 % - 4.700%</td><td>650.0</td><td>550.0</td></tr><tr><td>Aquarion - Senior Notes due 2024</td><td>4.000%</td><td>360.0</td><td>360.0</td></tr><tr><td>Aquarion - Unsecured Notes due 2023 - 2052</td><td>— % - 6.430%</td><td>464.7</td><td>394.9</td></tr><tr><td>Aquarion - Secured Debt due 2023 - 2044</td><td>2.864 % - 9.290%</td><td>34.4</td><td>39.6</td></tr><tr><td>Eversource Parent - Senior Notes due 2023 - 2050</td><td>0.800 % - 4.600%</td><td>8,150.0</td><td>6,100.0</td></tr><tr><td>Pre-1983 Spent Nuclear Fuel Obligation (CYAPC)</td><td></td><td>11.9</td><td>11.7</td></tr><tr><td>Fair Value Adjustment (2)</td><td></td><td>26.2</td><td>43.8</td></tr><tr><td>Less Fair Value Adjustment - Current Portion (2)</td><td></td><td>(7.0)</td><td>(17.7)</td></tr><tr><td>Less Amounts due in One Year</td><td></td><td>(1,203.4)</td><td>(775.4)</td></tr><tr><td>Unamortized Premiums and Discounts, Net</td><td></td><td>40.1</td><td>43.4</td></tr><tr><td>Unamortized Debt Issuance Costs</td><td></td><td>(49.4)</td><td>(36.3)</td></tr><tr><td>Total Other Long-Term Debt</td><td></td><td>10,027.5</td><td>8,059.0</td></tr><tr><td>Total Eversource Long-Term Debt</td><td></td><td>19,724.0</td><td>17,023.6</td></tr></table>

(1) As a result of the CL&P and PSNH long-term debt issuances in January 2023, $400 million and $295.3 million, respectively, of current portion of long-term debt were reclassified as Long-Term Debt on CL&P's and PSNH's balance sheets as of December 31, 2022.

(2) The fair value adjustment amount is the purchase price adjustments, net of amortization, required to record long-term debt at fair value on the dates of the 2012 merger with NSTAR and the 2017 acquisition of Aquarion.

Availability under Long-Term Debt Issuance Authorizations: On December 14, 2022, the NHPUC approved PSNH's request for authorization to issue up to $600 million in long-term debt through December 31, 2023. 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. 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. The remaining Eversource operating companies, including NSTAR Electric, have utilized the long-term debt authorizations in place with the respective regulatory commissions.

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

<table><tr><td>(Millions of Dollars)</td><td>Interest Rate</td><td>Issuance/ (Repayment)</td><td>Issue Repayment Date</td><td>Maturity Date</td><td>Use of Proceeds for Issuance/ Repayment Information</td></tr><tr><td>CL&amp;P 2023 Series A First Mortgage Bonds</td><td>5.25 %</td><td>500.0</td><td>January 2023</td><td>January 2053</td><td>Repaid 2013 Series A Bonds at maturity and short-term debt, and paid capital expenditures and working capital</td></tr><tr><td>CL&amp;P 2013 Series A First Mortgage Bonds</td><td>2.50 %</td><td>(400.0)</td><td>January 2023</td><td>January 2023</td><td>Paid at maturity</td></tr><tr><td>NSTAR Electric 2022 Debentures</td><td>4.55 %</td><td>450.0</td><td>May 2022</td><td>June 2052</td><td>Repaid short-term debt, paid capital expenditures and working capital</td></tr><tr><td>NSTAR Electric 2022 Debentures</td><td>4.95 %</td><td>400.0</td><td>September 2022</td><td>September 2052</td><td>Refinanced investments in eligible green expenditures, which were previously financed using short-term debt from October 1, 2020 through June 30, 2022</td></tr><tr><td>NSTAR Electric 2012 Debentures</td><td>2.375 %</td><td>(400.0)</td><td>October 2022</td><td>October 2022</td><td>Paid at maturity</td></tr><tr><td>PSNH Series W First Mortgage Bonds</td><td>5.15 %</td><td>300.0</td><td>January 2023</td><td>January 2053</td><td>Repaid short-term debt, paid capital expenditures and working capital</td></tr><tr><td>Eversource Parent Series V Senior Notes</td><td>2.90 %</td><td>650.0</td><td>February 2022</td><td>March 2027</td><td>Repaid Series K Senior Notes at maturity and short-term debt</td></tr></table>



<table><tr><td>(Millions of Dollars)</td><td>Interest Rate</td><td>Issuance/ (Repayment)</td><td>Issue Date or Repayment Date</td><td>Maturity Date</td><td>Use of Proceeds for Issuance/ Repayment Information</td></tr><tr><td>Eversource Parent Series W Senior Notes</td><td>3.375 %</td><td>650.0</td><td>February 2022</td><td>March 2032</td><td>Repaid Series K Senior Notes at maturity and short-term debt</td></tr><tr><td>Eversource Parent Series X Senior Notes</td><td>4.20 %</td><td>900.0</td><td>June 2022</td><td>June 2024</td><td>Repaid short-term debt and paid working capital</td></tr><tr><td>Eversource Parent Series Y Senior Notes</td><td>4.60 %</td><td>600.0</td><td>June 2022</td><td>July 2027</td><td>Repaid short-term debt and paid working capital</td></tr><tr><td>Eversource Parent Series K Senior Notes</td><td>2.75 %</td><td>(750.0)</td><td>March 2022</td><td>March 2022</td><td>Paid at maturity</td></tr><tr><td>Yankee Gas Series B First Mortgage Bonds</td><td>8.48 %</td><td>(20.0)</td><td>March 2022</td><td>March 2022</td><td>Paid at maturity</td></tr><tr><td>Yankee Gas Series U First Mortgage Bonds</td><td>4.31 %</td><td>100.0</td><td>September 2022</td><td>September 2032</td><td>Repaid short-term debt, paid capital expenditures and for general corporate purposes</td></tr><tr><td>EGMA Series C First Mortgage Bonds</td><td>4.70 %</td><td>100.0</td><td>June 2022</td><td>June 2052</td><td>Repaid short-term debt, paid capital expenditures and for general corporate purposes</td></tr><tr><td>NSTAR Gas Series V First Mortgage Bonds</td><td>4.40 %</td><td>125.0</td><td>July 2022</td><td>August 2032</td><td>Repaid short-term debt, paid capital expenditures and for general corporate purposes</td></tr><tr><td>Aquarion Water Company of New Hampshire General Mortgage Bonds</td><td>4.45 %</td><td>(5.0)</td><td>July 2022</td><td>July 2022</td><td>Paid at maturity</td></tr><tr><td>Aquarion Water Company of Connecticut Senior Notes</td><td>4.69 %</td><td>70.0</td><td>August 2022</td><td>September 2052</td><td>Repaid short-term debt</td></tr></table>

Long-Term Debt Provisions: The utility plant of CL&P, PSNH, Yankee Gas, NSTAR Gas, EGMA and a portion of Aquarion is subject to the lien of each company's respective first mortgage bond indenture. The Eversource parent, NSTAR Electric and a portion of Aquarion debt is unsecured. Additionally, the long-term debt agreements provide that Eversource and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including equity requirements for NSTAR Electric, NSTAR Gas and Aquarion. Under the equity requirements, NSTAR Electric's and Aquarion's senior notes must maintain a certain consolidated indebtedness to capitalization ratio as of the end of any fiscal quarter and NSTAR Gas' outstanding long-term debt must not exceed equity.

Certain secured and unsecured long-term debt securities are callable at redemption price or are subject to make-whole provisions.

No long-term debt defaults have occurred as of December 31, 2022.

CYAPC's Pre-1983 Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. CYAPC is obligated to pay the DOE for the costs to dispose of spent nuclear fuel and high-level radioactive waste generated prior to April 7, 1983 (pre-1983 Spent Nuclear Fuel). CYAPC has partially paid this obligation and recorded an accrual for its remaining liability to the DOE. This liability accrues interest costs at the 3-month Treasury bill yield rate. For nuclear fuel used to generate electricity prior to April 7, 1983, payment may be made any time prior to the first delivery of spent fuel to the DOE. As of December 31, 2022 and 2021, as a result of consolidating CYAPC, Eversource has consolidated $11.9 million and $11.7 million, respectively, in pre-1983 spent nuclear fuel obligations to the DOE. The obligation includes accumulated interest costs of $8.8 million and $8.7 million as of December 31, 2022 and 2021, respectively. CYAPC maintains a trust to fund amounts due to the DOE for the disposal of pre-1983 spent nuclear fuel. For further information, see Note 5, "Marketable Securities," to the financial statements. Fees for disposal of nuclear fuel burned on or after April 7, 1983 were billed to member companies and paid to the DOE.

Long-Term Debt Maturities: Long-term debt maturities on debt outstanding for the years 2023 through 2027 and thereafter are shown below. These amounts exclude PSNH rate reduction bonds, CYAPC pre-1983 spent nuclear fuel obligation, net unamortized premiums, discounts and debt issuance costs, and other fair value adjustments as of December 31, 2022:

<table><tr><td>(Millions of Dollars)</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>2023</td><td>$ 2,008.4</td><td>$ 400.0</td><td>$ 80.0</td><td>$ 325.0</td></tr><tr><td>2024</td><td>1,950.0</td><td>139.8</td><td>—</td><td>—</td></tr><tr><td>2025</td><td>1,400.2</td><td>400.0</td><td>250.0</td><td>—</td></tr><tr><td>2026</td><td>940.2</td><td>—</td><td>300.0</td><td>—</td></tr><tr><td>2027</td><td>2,539.2</td><td>500.0</td><td>700.0</td><td>—</td></tr><tr><td>Thereafter</td><td>12,236.0</td><td>2,780.0</td><td>3,140.0</td><td>850.0</td></tr><tr><td>Total</td><td>$ 21,074.0</td><td>$ 4,219.8</td><td>$ 4,470.0</td><td>$ 1,175.0</td></tr></table>

## 10. RATE REDUCTION BONDS AND VARIABLE INTEREST ENTITIES

Rate Reduction Bonds: In May 2018, PSNH Funding, a wholly-owned subsidiary of PSNH, issued $635.7 million of securitized RRBs in multiple tranches with a weighted average interest rate of 3.66 percent, and final maturity dates ranging from 2026 to 2035. The RRBs are expected to be repaid by February 1, 2033. RRB payments consist of principal and interest and are paid semi-annually, beginning on February 1, 2019. The RRBs were issued pursuant to a finance order issued by the NHPUC in January 2018 to recover remaining costs resulting from the divestiture of PSNH’s generation assets.

The proceeds were used by PSNH Funding to purchase PSNH’s stranded cost asset-recovery property, including its vested property right to bill, collect and adjust a non-bypassable stranded cost recovery charge from PSNH’s retail customers. The collections are used to pay principal, interest and other costs in connection with the RRBs. The RRBs are secured by the stranded cost asset-recovery property. Cash collections



from the stranded cost recovery charges and funds on deposit in trust accounts are the sole source of funds to satisfy the debt obligation. PSNH is not the owner of the RRBs, and PSNH Funding’s assets and revenues are not available to pay PSNH’s creditors. The RRBs are non-recourse senior secured obligations of PSNH Funding and are not insured or guaranteed by PSNH or Eversource Energy.

PSNH Funding was formed solely to issue RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. PSNH Funding is considered a VIE primarily because the equity capitalization is insufficient to support its operations. PSNH has the power to direct the significant activities of the VIE and is most closely associated with the VIE as compared to other interest holders. Therefore, PSNH is considered the primary beneficiary and consolidates PSNH Funding in its consolidated financial statements. The following tables summarize the impact of PSNH Funding on PSNH's balance sheets and income statements:

<table><tr><td colspan="2">(Millions of Dollars)</td><td colspan="2">As of December 31,</td></tr><tr><td>PSNH Balance Sheets:</td><td>2022</td><td>2021</td><td></td></tr><tr><td>Restricted Cash - Current Portion (included in Current Assets)</td><td>$     32.4</td><td>$     31.1</td><td></td></tr><tr><td>Restricted Cash - Long-Term Portion (included in Other Long-Term Assets)</td><td>3.2</td><td>3.2</td><td></td></tr><tr><td>Securitized Stranded Cost (included in Regulatory Assets)</td><td>435.7</td><td>478.9</td><td></td></tr><tr><td>Other Regulatory Liabilities (included in Regulatory Liabilities)</td><td>6.0</td><td>5.4</td><td></td></tr><tr><td>Accrued Interest (included in Other Current Liabilities)</td><td>6.9</td><td>7.5</td><td></td></tr><tr><td>Rate Reduction Bonds - Current Portion</td><td>43.2</td><td>43.2</td><td></td></tr><tr><td>Rate Reduction Bonds - Long-Term Portion</td><td>410.5</td><td>453.7</td><td></td></tr></table>

<table><tr><td colspan="2">(Millions of Dollars)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td colspan="2">PSNH Income Statements:</td><td>2022</td><td>2021</td><td>2020</td><td></td><td></td><td></td></tr><tr><td colspan="2">Amortization of RRB Principal (included in Amortization of Regulatory Assets, Net)</td><td>$     43.2</td><td>$     43.2</td><td>$     43.2</td><td>$     43.2</td><td>$     43</td><td></td></tr><tr><td colspan="2">Interest Expense on RRB Principal (included in Interest Expense)</td><td>17.0</td><td>18.4</td><td>19.7</td><td></td><td></td><td></td></tr></table>

Estimated principal payments on RRBs as of December 31, 2022, is summarized annually through 2027 and thereafter as follows:

<table><tr><td>(Millions of Dollars)</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>Thereafter</td><td>Total</td></tr><tr><td>PSNH</td><td>$     43.2</td><td>$     43.2</td><td>$     43.2</td><td>$     43.2</td><td>$     43</td><td>$     237.7</td><td>$     453.7</td></tr></table>

Variable Interest Entities - Other: The Company's variable interests outside of the consolidated group include contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. Eversource, CL&P and NSTAR Electric hold variable interests in VIEs through agreements with certain entities that own single renewable energy or peaking generation power plants, with other independent power producers and with transmission businesses. Eversource, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, Eversource, CL&P and NSTAR Electric do not consolidate these VIEs.

## 11. EMPLOYEE BENEFITS

## A. Pension Benefits and Postretirement Benefits Other Than Pension

Eversource provides defined benefit retirement plans (Pension Plans) that cover eligible employees and are subject to the provisions of ERISA, as amended by the Pension Protection Act of 2006. Eversource's policy is to annually fund the Pension Plans in an amount at least equal to an amount that will satisfy all federal funding requirements. In addition to the Pension Plans, Eversource maintains non-qualified defined benefit retirement plans (SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible participants consisting of current and retired employees.

Eversource also provides defined benefit postretirement plans (PBOP Plans) that provide life insurance and a health reimbursement arrangement created for the purpose of reimbursing retirees and dependents for health insurance premiums and certain medical expenses to eligible employees that meet certain age and service eligibility requirements. The benefits provided under the PBOP Plans are not vested, and the Company has the right to modify any benefit provision subject to applicable laws at that time. Eversource annually funds postretirement costs through tax deductible contributions to external trusts.



Actuarial Gains and Losses: For the year ended December 31, 2022, actuarial gains were primarily attributable to an increase in the discount rate, which resulted in a decrease to the Eversource PBOP projected benefit obligation of $180.1 million. For the year ended December 31, 2021, actuarial gains were primarily attributable to an increase in the discount rate, which resulted in a decrease to the Eversource PBOP liability of $29.8 million, and by changes in our retirement assumptions.

A reconciliation of the prepaid assets and liabilities within the Eversource Pension, SERP and PBOP Plans’ funded status to the balance sheets is as follows:

<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="12">As of December 31,</td></tr><tr><td colspan="6">2022</td><td colspan="6">2021</td></tr><tr><td>Eversource</td><td colspan="2">CL&amp;P</td><td>NSTAR Electric</td><td colspan="2">PSNH</td><td>Eversource</td><td colspan="2">CL&amp;P</td><td>NSTAR Electricity</td><td colspan="2">PSNH</td></tr><tr><td>Prepaid Pension</td><td>$     756.7</td><td>$     147.9</td><td>$     310.2</td><td>$     66.4</td><td>$     272.0</td><td>$     0.4</td><td>$     149.8</td><td>$     0.4</td><td>$     149.8</td><td>$     0</td><td>$     149.8</td><td>$     0</td><td>$     149.8</td></tr><tr><td>Prepaid PBOP</td><td>288.8</td><td>—</td><td>266.6</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>291.6</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Prepaid Pension and PBOP</td><td>$     1,045.5</td><td>$     147.9</td><td>$     576.8</td><td>$     66.4</td><td>$     272.0</td><td>$     0.4</td><td>$     441.4</td><td>$     0.4</td><td>$     441.4</td><td>$     0</td><td>$     441.4</td><td>$     0</td><td>$     441.4</td></tr><tr><td>Accrued Pension</td><td>$     3.7</td><td>$     5.9</td><td>$     1.8</td><td>$     4.6</td><td>$     176.1</td><td>$     7.5</td><td>$     2.2</td><td>$     5.8</td><td>$     2.2</td><td>$     5.8</td><td>$     2</td><td>$     5.8</td><td>$     2</td></tr><tr><td>Accrued SERP</td><td>166.7</td><td>7.3</td><td>—</td><td>2.3</td><td>18.0</td><td>19.8</td><td>—</td><td>4.3</td><td>—</td><td>4.3</td><td>—</td><td>4.3</td><td>—</td></tr><tr><td>Accrued PBOP</td><td>12.4</td><td>7.3</td><td>—</td><td>(0.2)</td><td>(0.4)</td><td>(9.7)</td><td>(0.5)</td><td>(0.2)</td><td>(0.5)</td><td>(0.2)</td><td>(0</td><td>(0.5)</td></tr><tr><td>Less: Accrued SERP - current portion</td><td>(47.3)</td><td>(0.3)</td><td>(0.2)</td><td>(0.4)</td><td>(9.7)</td><td>(0.5)</td><td>(0.2)</td><td>(0.5)</td><td>(0.2)</td><td>(0</td><td>(0.5)</td><td>(0.2)</td></tr><tr><td>Accrued Pension, SERP and PBOP</td><td>$     135.5</td><td>$     12.9</td><td>$     1.6</td><td>$     6.5</td><td>$     242.5</td><td>$     26.8</td><td>$     2.0</td><td>$     30.2</td><td>$     2.0</td><td>$     30.2</td><td>$     2</td><td>$     30.2</td></tr></table>

The following actuarial assumptions were used in calculating the Pension, SERP and PBOP Plans' year end funded status:

<table><tr><td rowspan="3"></td><td colspan="4">Pension and SERP</td><td colspan="4">PBOP</td></tr><tr><td colspan="4">As of December 31,</td><td colspan="4">As of December 31,</td></tr><tr><td colspan="2">2022</td><td colspan="2">2021</td><td colspan="2">2022</td><td colspan="2">2021</td></tr><tr><td>Discount Rate</td><td>5.1%</td><td>—</td><td>5.2%</td><td>2.8%</td><td>3.0%</td><td>5.2%</td><td>2.91%</td><td>—</td></tr><tr><td>Compensation/Progression Rate</td><td>3.5%</td><td>—</td><td>4.0%</td><td>3.5%</td><td>—</td><td>4.0%</td><td colspan="3">N/A</td></tr></table>

For the Eversource Service PBOP Plan, the health care cost trend rate is not applicable. For the Aquarion PBOP Plan, the health care cost trend rate for pre-65 retirees is 7 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.

Expense: Eversource charges net periodic benefit plan expense/(income) for the Pension, SERP and PBOP Plans to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. The Company utilizes the spot rate methodology to estimate the discount rate for the service and interest cost components of benefit expense, which provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve.

The components of net periodic benefit plan expense/(income) for the Pension, SERP and PBOP Plans, prior to amounts capitalized as Property, Plant and Equipment or deferred as regulatory assets/(liabilities) for future recovery or refund, are shown below. The service cost component of net periodic benefit plan expense/(income), less the capitalized portion, is included in Operations and Maintenance expense on the statements of income. The remaining components of net periodic benefit plan expense/(income), less the deferred portion, are included in Other Income, Net on the statements of income. Pension, SERP and PBOP expense reflected in the statements of cash flows for CL&P, NSTAR Electric and PSNH does not include intercompany allocations of net periodic benefit plan expense/(income), as these amounts are cash settled on a short-term basis.

<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="6">Pension and SERP</td><td colspan="4">PBOP</td></tr><tr><td colspan="4">For the Year Ended December 31, 2022</td><td colspan="4">For the Year Ended December 31, 2022</td><td></td></tr><tr><td>Eversource</td><td colspan="2">CL&amp;P</td><td>NSTAR Electric</td><td colspan="2">PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>Service Cost</td><td>$     70.1</td><td>$     18.7</td><td>$     13.8</td><td>$     6.9</td><td>$     11.6</td><td>$     2.0</td><td>$     2.0</td><td>$     2.0</td><td>$     1.1</td><td>$     1.1</td></tr><tr><td>Interest Cost</td><td>154.5</td><td>31.3</td><td>32.8</td><td>16.9</td><td>20.2</td><td>3.7</td><td>5.3</td><td>2.2</td><td>2.2</td><td>2.2</td></tr><tr><td>Expected Return on Plan Assets</td><td>(523.6)</td><td>(106.3)</td><td>(128.4)</td><td>(56.1)</td><td>(89.9)</td><td>(11.4)</td><td>(42.4)</td><td>(6.7)</td><td>(6.7)</td><td>(6.7)</td></tr><tr><td>Actuarial Loss</td><td>116.0</td><td>16.2</td><td>32.8</td><td>7.9</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Prior Service Cost/(Credit)</td><td>1.4</td><td>—</td><td>0.3</td><td>—</td><td>(21.7)</td><td>1.1</td><td>(17.0)</td><td>0.4</td><td>0.4</td><td>0.4</td></tr><tr><td>Total Net Periodic Benefit Plan Income</td><td>$ (181.6)</td><td>$ (40.1)</td><td>$ (48.7)</td><td>$ (24.4)</td><td>$ (79.8)</td><td>$ (4.6)</td><td>$ (52.1)</td><td>$ (3.0)</td><td>$ (3.0)</td><td>$ (3.0)</td></tr><tr><td>Intercompany Income Allocations</td><td>N/A</td><td>$ (16.0)</td><td>$ (12.4)</td><td>$ (3.6)</td><td>N/A</td><td>$ (3.7)</td><td>$ (3.6)</td><td>$ (1.2)</td><td>$ (1.2)</td><td>$ (1.2)</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="6">Pension and SERP</td><td colspan="6">PBOP</td></tr><tr><td colspan="6">For the Year Ended December 31, 2021</td><td colspan="6">For the Year Ended December 31, 2021</td></tr><tr><td>(Millions of Dollars)</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>P</td><td>NSTAR Electric</td><td>P</td><td>NSTAR Electric</td><td>P</td></tr><tr><td>Service Cost</td><td>$ 85.8</td><td>$ 23.0</td><td>$ 15.8</td><td>$ 8.9</td><td>$ 13.5</td><td>$ 2.3</td><td>$ 2.4</td><td>$ 1.2</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest Cost</td><td>130.0</td><td>27.3</td><td>26.8</td><td>14.5</td><td>17.4</td><td>3.2</td><td>4.4</td><td>1.8</td><td></td><td></td><td></td><td></td></tr><tr><td>Expected Return on Plan Assets</td><td>(437.5)</td><td>(86.8)</td><td>(108.1)</td><td>(47.5)</td><td>(79.1)</td><td>(10.3)</td><td>(36.9)</td><td>(6.1)</td><td></td><td></td><td></td><td></td></tr><tr><td>Actuarial Loss</td><td>243.9</td><td>45.5</td><td>61.6</td><td>20.7</td><td>8.9</td><td>1.8</td><td>2.4</td><td>0.7</td><td></td><td></td><td></td><td></td></tr><tr><td>Prior Service Cost/(Credit)</td><td>1.4</td><td>—</td><td>0.3</td><td>—</td><td>(21.2)</td><td>1.1</td><td>(17.0)</td><td>0.4</td><td></td><td></td><td></td><td></td></tr><tr><td>Total Net Periodic Benefit Plan Expense/(Income)</td><td>$ 23.6</td><td>$ 9.0</td><td>$ (3.6)</td><td>$ (3.4)</td><td>$ (60.5)</td><td>$ (1.9)</td><td>$ (44.7)</td><td>$ (2.0)</td><td></td><td></td><td></td><td></td></tr><tr><td>Intercompany Expense/(Income) Allocations</td><td>N/A</td><td>$ 8.0</td><td>$ 8.8</td><td>$ 2.7</td><td>N/A</td><td>$ (1.6)</td><td>$ (1.9)</td><td>$ (0.6)</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td colspan="6">Pension and SERP</td><td colspan="6">PBOP</td></tr><tr><td></td><td colspan="6">For the Year Ended December 31, 2020</td><td colspan="6">For the Year Ended December 31, 2020</td></tr><tr><td>(Millions of Dollars)</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>P</td><td>NSTAR Electric</td><td>P</td><td>NSTAR Electric</td><td>P</td></tr><tr><td>Service Cost</td><td>$ 76.2</td><td>$ 21.8</td><td>$ 15.4</td><td>$ 8.2</td><td>$ 10.2</td><td>$ 1.7</td><td>$ 2.1</td><td>$ 0.9</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest Cost</td><td>177.8</td><td>37.3</td><td>38.6</td><td>19.4</td><td>24.6</td><td>4.4</td><td>6.6</td><td>2.8</td><td></td><td></td><td></td><td></td></tr><tr><td>Expected Return on Plan Assets</td><td>(400.3)</td><td>(79.2)</td><td>(103.0)</td><td>(44.7)</td><td>(73.6)</td><td>(9.9)</td><td>(34.0)</td><td>(5.7)</td><td></td><td></td><td></td><td></td></tr><tr><td>Actuarial Loss</td><td>202.0</td><td>39.2</td><td>55.2</td><td>15.6</td><td>8.4</td><td>1.1</td><td>2.5</td><td>0.8</td><td></td><td></td><td></td><td></td></tr><tr><td>Prior Service Cost/(Credit)</td><td>1.2</td><td>—</td><td>0.3</td><td>—</td><td>(21.2)</td><td>1.1</td><td>(17.0)</td><td>0.4</td><td></td><td></td><td></td><td></td></tr><tr><td>Total Net Periodic Benefit Plan Expense/(Income)</td><td>$ 56.9</td><td>$ 19.1</td><td>$ 6.5</td><td>$ (1.5)</td><td>$ (51.6)</td><td>$ (1.6)</td><td>$ (39.8)</td><td>$ (0.8)</td><td></td><td></td><td></td><td></td></tr><tr><td>Intercompany Expense/(Income) Allocations</td><td>N/A</td><td>$ 9.1</td><td>$ 8.9</td><td>$ 2.9</td><td>N/A</td><td>$ (1.1)</td><td>$ (1.4)</td><td>$ (0.5)</td><td></td><td></td><td></td><td></td></tr></table>

The following actuarial assumptions were used to calculate Pension, SERP and PBOP expense amounts:

<table><tr><td rowspan="3"></td><td colspan="6">Pension and SERP</td><td colspan="6">PBOP</td></tr><tr><td colspan="6">For the Years Ended December 31,</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td colspan="2">2022</td><td colspan="2">2021</td><td colspan="2">2020</td><td colspan="2">2022</td><td colspan="2">2021</td><td colspan="3">2020</td></tr><tr><td>Discount Rate</td><td>2.2%</td><td>-</td><td>3.2%</td><td>1.5%</td><td>-</td><td>3.0%</td><td>2.6%</td><td>-</td><td>3.5%</td><td>2.3%</td><td>-</td><td>3.3%</td></tr><tr><td>Expected Long-Term Rate of Return</td><td colspan="2">8.25%</td><td colspan="2">8.25%</td><td colspan="2">8.25</td><td colspan="2">8.25%</td><td colspan="2">8.25</td><td>8.25</td><td>8.25</td></tr><tr><td>Compensation/Progression Rate</td><td>3.5%</td><td>-</td><td>4.0%</td><td>3.5%</td><td>-</td><td>4.0%</td><td>3.3%</td><td>-</td><td>4.0%</td><td>N/A</td><td>N/A</td><td>N/A</td></tr></table>

For the Aquarion Pension and PBOP Plans, the expected long-term rate of return was 7 percent for the years ended December 31, 2022 and 2021. For the Aquarion PBOP Plan, the health care cost trend rate was a range of 3.5 percent to 6.5 percent for the year ended December 31, 2022 and 3.5 percent to 6.2 percent for the year ended December 31, 2021.

Regulatory Assets and Accumulated Other Comprehensive Income/(Loss) Amounts: The Pension, SERP and PBOP Plans cover eligible employees, including, among others, employees of the regulated companies. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. Regulatory accounting is also applied to the portions of the Eversource Service retiree benefit costs that support the regulated companies, as these costs are also recovered from customers. Adjustments to the Pension, SERP and PBOP Plans' funded status for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note 2, "Regulatory Accounting," and Note 16, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements.

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and Other Comprehensive Income (OCI) as well as amounts in Regulatory Assets and OCI that were reclassified as net periodic benefit expense during the years presented:

<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="6">Pension and SERP</td><td colspan="4">PBOP</td></tr><tr><td colspan="3">Regulatory Assets</td><td colspan="3">OCI</td><td colspan="2">Regulatory Assets</td><td colspan="2">OCI</td></tr><tr><td colspan="3">For the Years Ended December 31,</td><td colspan="3">For the Years Ended December 31,</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>Actuarial (Gains)/Losses Arising During the Year</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td>2021</td><td>2022</td><td>2021</td></tr><tr><td>Actuarial Losses Reclassified as Net Periodic Benefit Expense</td><td>(107.0)</td><td>(231.2)</td><td>(9.0)</td><td>(12.7)</td><td>—</td><td>(8.5)</td><td>—</td><td>(0.4)</td><td></td></tr><tr><td>Prior Service (Cost)/Credit Reclassified as Net Periodic Benefit (Expense)/Income</td><td>(1.2)</td><td>(1.3)</td><td>(0.2)</td><td>(0.1)</td><td>21.8</td><td>21.1</td><td>(0.1)</td><td>0.1</td><td></td></tr></table>



The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Income amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2022 and 2021:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="3">Regulatory Assets as of December 31,</td><td colspan="3">AOCI as of December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2022</td><td>2021</td><td></td><td></td></tr><tr><td>Pension and SERP</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Actuarial Loss</td><td>$     888.7</td><td>$     1,427.3</td><td>$     61.9</td><td>$     66.3</td><td></td><td></td></tr><tr><td>Prior Service Cost</td><td>4.1</td><td>5.3</td><td>0.4</td><td>0.6</td><td></td><td></td></tr><tr><td>PBOP</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Actuarial Loss</td><td>$     81.8</td><td>$     45.0</td><td>$     2.7</td><td>$     3.5</td><td></td><td></td></tr><tr><td>Prior Service (Credit)/Cost</td><td>(108.3)</td><td>(130.1)</td><td>0.9</td><td>1.0</td><td></td><td></td></tr></table>

The difference between the actual return and calculated expected return on plan assets for the Pension and PBOP Plans, as well as changes in actuarial assumptions impacting the projected benefit obligation, are recorded as unamortized actuarial gains or losses arising during the year in Regulatory Assets or Accumulated Other Comprehensive Income/(Loss). Unamortized actuarial gains or losses are amortized as a component of pension and PBOP expense over the estimated average future employee service period using the corridor approach.

Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans:

<table><tr><td>(Millions of Dollars)</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>2028 - 2032</td></tr><tr><td>Pension and SERP</td><td>$     401.4</td><td>$     374.4</td><td>$     380.1</td><td>$     383.0</td><td>$     384.1</td><td>$     1,901.7</td></tr><tr><td>PBOP</td><td>57.9</td><td>57.3</td><td>56.6</td><td>55.5</td><td>54.4</td><td>253.7</td></tr></table>

Eversource Contributions: 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 2023 and we do not expect to make pension contributions in 2023. We do not expect to make any contributions to the Eversource Service PBOP Plan in 2023. Eversource currently estimates contributing $5.0 million and $2.9 million to the Aquarion Pension and PBOP Plans, respectively, in 2023.

Fair Value of Pension and PBOP Plan Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. Eversource's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk. The investment strategy for each asset category includes a diversification of asset types, fund strategies and fund managers and it establishes target asset allocations that are routinely reviewed and periodically rebalanced. PBOP assets are comprised of assets held in the PBOP Plan trust, as well as specific assets within the Pension Plan trust (401(h) assets). The investment policy and strategy of the 401(h) assets is consistent with that of the defined benefit pension plan. Eversource's expected long-term rates of return on Pension and PBOP Plan assets are based on target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, Eversource evaluated input from consultants, as well as long-term inflation assumptions and historical returns. Management has assumed long-term rates of return of 8.25 percent for the Eversource Service Pension and PBOP Plan assets and a 7 percent long-term rate of return for the Aquarion Plans to estimate its 2023 Pension and PBOP costs.

These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:

<table><tr><td rowspan="3"></td><td colspan="4">As of December 31,</td></tr><tr><td colspan="2">2022</td><td colspan="2">2021</td></tr><tr><td colspan="2">Eversource Pension Plan and PBOP Plan</td><td colspan="2">Eversource Pension Plan and PBOP Plan</td></tr><tr><td></td><td>Target Asset Allocation</td><td>Assumed Rate of Return</td><td>Target Asset Allocation</td><td>Assumed Rate of Return</td></tr><tr><td>Equity Securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>United States</td><td>15.0 %</td><td>8.5 %</td><td>15.0 %</td><td>8.5 %</td></tr><tr><td>Global</td><td>10.0 %</td><td>8.75 %</td><td>10.0 %</td><td>8.75 %</td></tr><tr><td>Non-United States</td><td>8.0 %</td><td>8.5 %</td><td>8.0 %</td><td>8.5 %</td></tr><tr><td>Emerging Markets</td><td>4.0 %</td><td>10.0 %</td><td>4.0 %</td><td>10.0 %</td></tr><tr><td>Debt Securities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed Income</td><td>13.0 %</td><td>4.0 %</td><td>13.0 %</td><td>4.0 %</td></tr><tr><td>Public High Yield Fixed Income</td><td>4.0 %</td><td>6.5 %</td><td>4.0 %</td><td>6.5 %</td></tr><tr><td>Private Debt</td><td>13.0 %</td><td>9.0 %</td><td>13.0 %</td><td>9.0 %</td></tr><tr><td>Private Equity</td><td>18.0 %</td><td>12.0 %</td><td>18.0 %</td><td>12.0 %</td></tr><tr><td>Real Assets</td><td>15.0 %</td><td>7.5 %</td><td>15.0 %</td><td>7.5 %</td></tr></table>



The following table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="10">Fair Value Measurements as of December 31,</td></tr><tr><td colspan="5">2022</td><td colspan="5">2021</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Uncategorized</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Uncategorized</td><td>Total</td><td></td><td></td></tr><tr><td>Asset Category:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity Securities</td><td>$ 407.7</td><td>$ —</td><td>$ 1,102.2</td><td>$ 1,509.9</td><td>$ 722.5</td><td>$ —</td><td>$ 1,385.2</td><td>$ 2,107.7</td><td></td><td></td></tr><tr><td>Fixed Income (1)</td><td>277.1</td><td>78.5</td><td>1,598.8</td><td>1,954.4</td><td>139.6</td><td>233.8</td><td>1,689.1</td><td>2,062.5</td><td></td><td></td></tr><tr><td>Private Equity</td><td>—</td><td>—</td><td>1,684.9</td><td>1,684.9</td><td>—</td><td>—</td><td>1,702.7</td><td>1,702.7</td><td></td><td></td></tr><tr><td>Real Assets</td><td>181.8</td><td>—</td><td>731.0</td><td>912.8</td><td>218.3</td><td>—</td><td>702.8</td><td>921.1</td><td></td><td></td></tr><tr><td>Total</td><td>$ 866.6</td><td>$ 78.5</td><td>$ 5,116.9</td><td>$ 6,062.0</td><td>$ 1,080.4</td><td>$ 233.8</td><td>$ 5,479.8</td><td>$ 6,794.0</td><td></td><td></td></tr><tr><td>Less: 401(h) PBOP Assets (2)</td><td></td><td></td><td></td><td>(255.6)</td><td></td><td></td><td></td><td></td><td></td><td>(298.5)</td></tr><tr><td>Total Pension Assets</td><td></td><td></td><td></td><td>$ 5,806.4</td><td></td><td></td><td></td><td>$ 6,495.5</td><td></td><td></td></tr><tr><td colspan="11">PBOP Plan</td></tr><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="10">Fair Value Measurements as of December 31,</td></tr><tr><td colspan="5">2022</td><td colspan="5">2021</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Uncategorized</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Uncategorized</td><td>Total</td><td></td><td></td></tr><tr><td>Asset Category:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity Securities</td><td>$ 153.2</td><td>$ —</td><td>$ 183.5</td><td>$ 336.7</td><td>$ 191.4</td><td>$ —</td><td>$ 248.3</td><td>$ 439.7</td><td></td><td></td></tr><tr><td>Fixed Income</td><td>18.2</td><td>40.2</td><td>141.1</td><td>199.5</td><td>49.7</td><td>45.2</td><td>125.5</td><td>220.4</td><td></td><td></td></tr><tr><td>Private Equity</td><td>—</td><td>—</td><td>70.9</td><td>70.9</td><td>—</td><td>—</td><td>58.7</td><td>58.7</td><td></td><td></td></tr><tr><td>Real Assets</td><td>71.2</td><td>—</td><td>36.2</td><td>107.4</td><td>90.0</td><td>—</td><td>31.0</td><td>121.0</td><td></td><td></td></tr><tr><td>Total</td><td>$ 242.6</td><td>$ 40.2</td><td>$ 431.7</td><td>$ 714.5</td><td>$ 331.1</td><td>$ 45.2</td><td>$ 463.5</td><td>$ 839.8</td><td></td><td></td></tr><tr><td>Add: 401(h) PBOP Assets (2)</td><td></td><td></td><td></td><td>255.6</td><td></td><td></td><td></td><td></td><td>298.5</td><td></td></tr><tr><td>Total PBOP Assets</td><td></td><td></td><td></td><td>$ 970.1</td><td></td><td></td><td></td><td>$ 1,138.3</td><td></td><td></td></tr></table>

(1) Fixed Income investments classified as Level 1 as of December 31, 2022 include pending redemption settlements of $138 million.

(2) The assets of the Pension Plan include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plan.

The Company values assets based on observable inputs when available. Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date.

Fixed income securities, such as government issued securities and corporate bonds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows.

Certain investments, such as commingled funds, private equity investments, fixed income funds, real asset funds and hedge funds are valued using the net asset value (NAV) as a practical expedient. Assets valued at NAV are uncategorized in the fair value hierarchy. These investments are structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. Commingled funds are recorded at NAV provided by the asset manager, which is based on the market prices of the underlying equity securities. Private Equity investments, Fixed Income partnership funds and Real Assets are valued using the NAV provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments, or the NAV of underlying assets held in hedge funds. Equity Securities investments in United States, Global, Non-United States and Emerging Markets that are uncategorized include investments in commingled funds and hedge funds that are overlaid with equity index swaps and futures contracts. Fixed Income investments that are uncategorized include investments in commingled funds, fixed income funds that invest in a variety of opportunistic credit and private debt strategies, and hedge funds that are overlaid with fixed income futures.

## B. Defined Contribution Plans

Eversource maintains defined contribution plans on behalf of eligible participants. The Eversource 401k Plan provides for employee and employer contributions up to statutory limits. For eligible employees, the Eversource 401k Plan provides employer matching contributions of either 100 percent up to a maximum of three percent of eligible compensation or 50 percent up to a maximum of eight percent of eligible compensation. The Eversource 401k Plan also contains a K-Vantage feature for the benefit of eligible participants, which provides an additional annual employer contribution based on age and years of service. K-Vantage participants are not eligible to actively participate in the Eversource Pension Plan.

The total Eversource 401k Plan employer matching contributions, including the K-Vantage contributions, were as follows:

<table><tr><td>(Millions of Dollars)</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>2022</td><td>$ 59.9</td><td>$ 7.7</td><td>$ 12.8</td><td>$ 4.8</td></tr><tr><td>2021</td><td>55.5</td><td>7.0</td><td>12.2</td><td>4.3</td></tr><tr><td>2020</td><td>49.4</td><td>6.6</td><td>11.8</td><td>4.1</td></tr></table>



## C. Share-Based Payments

Share-based compensation awards are recorded using a fair-value based method at the date of grant. Eversource, CL&P, NSTAR Electric and PSNH record compensation expense related to these awards, as applicable, for shares issued to their respective employees and officers, as well as for the allocation of costs associated with shares issued to Eversource's service company employees and officers that support CL&P, NSTAR Electric and PSNH.

Eversource Incentive Plans: Eversource maintains long-term equity-based incentive plans in which Eversource, CL&P, NSTAR Electric and PSNH employees, officers and board members are eligible to participate. The incentive plans authorize Eversource to grant up to 3,200,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2022 and 2021, Eversource had 903,183 and 2,430,716 common shares, respectively, available for issuance under these plans.

Eversource accounts for its various share-based plans as follows:

- RSUs - Eversource records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of Eversource's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from Capital Surplus, Paid In as RSUs become issued as common shares.

- Performance Shares - Eversource records compensation expense, net of estimated forfeitures, over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. Vesting of outstanding performance shares is based upon the Company's EPS growth over the requisite service period and level of payout is determined based on the total shareholder return as compared to the Edison Electric Institute (EEI) Index during the requisite service period. The fair value of performance shares is determined at the date of grant using a lattice model. Compensation expense is subject to volatility until payout is established.

RSUs: Eversource granted RSUs under the annual long-term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules, or immediate vesting, for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows:

<table><tr><td></td><td>RSUs (Units)</td><td>Weighted Average Grant-Date Fair Value</td></tr><tr><td>Outstanding as of December 31, 2021</td><td>594,623</td><td>$ 65.70</td></tr><tr><td>Granted</td><td>218,005</td><td>$ 85.96</td></tr><tr><td>Shares Issued</td><td>(174,633)</td><td>$ 79.89</td></tr><tr><td>Forfeited</td><td>(8,261)</td><td>$ 85.87</td></tr><tr><td>Outstanding as of December 31, 2022</td><td>629,734</td><td>$ 68.52</td></tr></table>

The weighted average grant-date fair value of RSUs granted for the years ended December 31, 2022, 2021 and 2020 was $85.96, $81.89 and $88.23, respectively. As of December 31, 2022 and 2021, the number and weighted average grant-date fair value of unvested RSUs was 300,592 and $87.21 per share, and 297,270 and $83.39 per share, respectively. During 2022, there were 184,540 RSUs at a weighted average grant-date fair value of $81.07 per share that vested during the year and were either paid or deferred. As of December 31, 2022, 329,142 RSUs were fully vested and deferred and an additional 285,562 are expected to vest.

Performance Shares: Eversource granted performance shares under the annual long-term incentive programs that vest based upon the extent to which Company goals are achieved at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:

<table><tr><td></td><td>Performance Shares (Units)</td><td>Weighted Average Grant-Date Fair Value</td></tr><tr><td>Outstanding as of December 31, 2021</td><td>464,507</td><td>$ 80.54</td></tr><tr><td>Granted</td><td>337,406</td><td>$ 83.34</td></tr><tr><td>Shares Issued</td><td>(248,981)</td><td>$ 68.96</td></tr><tr><td>Forfeited</td><td>(5,642)</td><td>$ 85.28</td></tr><tr><td>Outstanding as of December 31, 2022</td><td>547,290</td><td>$ 87.49</td></tr></table>

The weighted average grant-date fair value of performance shares granted for the years ended December 31, 2022, 2021 and 2020 was $83.34, $76.08 and $75.36, respectively. As of December 31, 2022 and 2021, the number and weighted average grant-date fair value of unvested performance shares was 457,069 and $88.43 per share, and 436,957 and $81.41 per share, respectively. During 2022, there were 311,553 performance shares at a weighted average grant-date fair value of $73.15 per share that vested during the year and were either paid or deferred. As of December 31, 2022, 90,221 performance shares were fully vested and deferred.

Compensation Expense: The total compensation expense and associated future income tax benefits recognized by Eversource, CL&P, NSTAR Electric and PSNH for share-based compensation awards were as follows:

<table><tr><td rowspan="2">Eversource (Millions of Dollars)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Compensation Expense</td><td>$ 33.4</td><td>$ 28.2</td><td>$ 33.9</td><td></td></tr><tr><td>Future Income Tax Benefit</td><td>8.7</td><td>7.3</td><td>8.9</td><td></td></tr></table>



<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="12">For the Years Ended December 31,</td></tr><tr><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td></td><td></td><td></td></tr><tr><td>Compensation Expense</td><td>$ 10.0</td><td>$ 10.7</td><td>$ 3.6</td><td>$ 8.8</td><td>$ 9.0</td><td>$ 3.0</td><td>$ 10.9</td><td>$ 11.3</td><td>$ 3.6</td><td></td><td></td><td></td></tr><tr><td>Future Income Tax Benefit</td><td>2.6</td><td>2.8</td><td>0.9</td><td>2.3</td><td>2.3</td><td>0.8</td><td>2.9</td><td>3.0</td><td>1.0</td><td></td><td></td><td></td></tr></table>

As of December 31, 2022, there was $24.5 million of total unrecognized compensation expense related to nonvested share-based awards for Eversource, including $4.0 million for CL&P, $6.9 million for NSTAR Electric, and $1.4 million for PSNH. This cost is expected to be recognized ratably over a weighted-average period of 1.77 years for Eversource and 1.78 years for CL&P, NSTAR Electric and PSNH.

An income tax rate of 26 percent was used to estimate the tax effect on total share-based payments determined under the fair-value based method for all awards. The Company issues treasury shares to settle fully vested RSUs and performance shares under the Company's incentive plans.

For the years ended December 31, 2022, 2021 and 2020, excess tax benefits associated with the distribution of stock compensation awards reduced income tax expense by $2.1 million, $4.0 million, and $6.6 million, respectively, which increased cash flows from operating activities on the statements of cash flows.

## D. Other Retirement Benefits

Eversource provides retirement and other benefits for certain current and past company officers. These benefits are accounted for on an accrual basis and expensed over a period equal to the service lives of the employees. The actuarially-determined liability for these benefits is included in Other Current and Long-Term Liabilities on the balance sheets. The related expense, which includes the allocation of expense associated with Eversource's service company officers that support CL&P, NSTAR Electric and PSNH, is included in Operations and Maintenance Expense on the income statements. The liability and expense amounts are as follows:

<table><tr><td rowspan="2">Eversource (Millions of Dollars)</td><td colspan="4">As of and For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td></tr><tr><td>Actuarially-Determined Liability</td><td>$ 43.4</td><td>$ 42.8</td><td>$ 45.7</td></tr><tr><td>Other Retirement Benefits Expense  \( {}^{(1)} \)</td><td>10.9</td><td>2.2</td><td>3.3</td></tr></table>

<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="12">As of and For the Years Ended December 31,</td></tr><tr><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td></td><td></td><td></td></tr><tr><td>Actuarially-Determined Liability</td><td>$ 0.2</td><td>$ 0.1</td><td>$ 1.3</td><td>$ 0.2</td><td>$ 0.1</td><td>$ 1.5</td><td>$ 0.2</td><td>$ 0.1</td><td>$ 1.7</td><td></td><td></td><td></td></tr><tr><td>Other Retirement Benefits Expense  \( {}^{(1)} \)</td><td>4.0</td><td>3.7</td><td>1.3</td><td>0.7</td><td>0.7</td><td>0.3</td><td>1.2</td><td>1.1</td><td>0.5</td><td></td><td></td><td></td></tr></table>

(1) Other Retirement Benefits Expense in 2022 includes a one-time special retirement benefit payable of $9.2 million.

## 12. INCOME TAXES

The components of income tax expense are as follows:

<table><tr><td rowspan="2">Eversource (Millions of Dollars)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Current Income Taxes:</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$ 95.8</td><td>$ 21.5</td><td>$ 73.6</td><td></td></tr><tr><td>State</td><td>13.6</td><td>(21.6)</td><td>19.1</td><td></td></tr><tr><td>Total Current</td><td>109.4</td><td>(0.1)</td><td>92.7</td><td></td></tr><tr><td>Deferred Income Taxes, Net:</td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>198.8</td><td>199.7</td><td>173.5</td><td></td></tr><tr><td>State</td><td>148.0</td><td>147.4</td><td>83.7</td><td></td></tr><tr><td>Total Deferred</td><td>346.8</td><td>347.1</td><td>257.2</td><td></td></tr><tr><td>Investment Tax Credits, Net</td><td>(2.6)</td><td>(2.8)</td><td>(3.7)</td><td></td></tr><tr><td>Income Tax Expense</td><td>$ 453.6</td><td>$ 344.2</td><td>$ 346.2</td><td></td></tr></table>



For the Years Ended December 31,

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&ampamp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&ampamp;P</td><td>PSNH</td><td>CL&ampamp;P</td></tr><tr><td>Current Income Taxes:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>$ 106.2</td><td>$ 55.0</td><td>$ 29.6</td><td>$ 15.0</td><td>$ 52.3</td><td>$ 43.1</td><td>$ 12.0</td><td>$ 53.9</td><td>$ 20.6</td><td></td><td></td><td></td></tr><tr><td>State</td><td>20.1</td><td>8.7</td><td>5.9</td><td>(7.0)</td><td>6.2</td><td>10.8</td><td>(6.1)</td><td>6.9</td><td>3.8</td><td></td><td></td><td></td></tr><tr><td>Total Current</td><td>126.3</td><td>63.7</td><td>35.5</td><td>8.0</td><td>58.5</td><td>53.9</td><td>5.9</td><td>60.8</td><td>24.4</td><td></td><td></td><td></td></tr><tr><td>Deferred Income Taxes, Net:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal</td><td>17.2</td><td>35.6</td><td>5.9</td><td>76.3</td><td>16.3</td><td>(14.9)</td><td>101.1</td><td>33.8</td><td>(1.3)</td><td></td><td></td><td></td></tr><tr><td>State</td><td>28.2</td><td>42.4</td><td>9.9</td><td>47.6</td><td>41.2</td><td>0.4</td><td>43.4</td><td>38.8</td><td>8.6</td><td></td><td></td><td></td></tr><tr><td>Total Deferred</td><td>45.4</td><td>78.0</td><td>15.8</td><td>123.9</td><td>57.5</td><td>(14.5)</td><td>144.5</td><td>72.6</td><td>7.3</td><td></td><td></td><td></td></tr><tr><td>Investment Tax Credits, Net</td><td>(0.5)</td><td>(1.7)</td><td>—</td><td>(0.6)</td><td>(1.7)</td><td>—</td><td>(0.7)</td><td>(2.6)</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Income Tax Expense</td><td>$ 171.2</td><td>$ 140.0</td><td>$ 51.3</td><td>$ 131.3</td><td>$ 114.3</td><td>$ 39.4</td><td>$ 149.7</td><td>$ 130.8</td><td>$ 31.7</td><td></td><td></td><td></td></tr></table>

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

<table><tr><td rowspan="2">(Millions of Dollars, except percentages)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Income Before Income Tax Expense</td><td>$ 1,866.0</td><td>$ 1,572.3</td><td>$ 1,558.9</td><td></td></tr><tr><td>Statutory Federal Income Tax Expense at 21%</td><td>391.9</td><td>330.2</td><td>327.4</td><td></td></tr><tr><td>Tax Effect of Differences:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation</td><td>(17.1)</td><td>(18.1)</td><td>(11.1)</td><td></td></tr><tr><td>Investment Tax Credit Amortization</td><td>(2.6)</td><td>(2.8)</td><td>(3.7)</td><td></td></tr><tr><td>State Income Taxes, Net of Federal Impact</td><td>75.9</td><td>54.4</td><td>44.9</td><td></td></tr><tr><td>Dividends on ESOP</td><td>(5.1)</td><td>(5.1)</td><td>(5.1)</td><td></td></tr><tr><td>Tax Asset Valuation Allowance/Reserve Adjustments</td><td>51.6</td><td>44.6</td><td>33.4</td><td></td></tr><tr><td>Excess Stock Benefit</td><td>(2.1)</td><td>(4.0)</td><td>(6.6)</td><td></td></tr><tr><td>EDIT Amortization</td><td>(49.1)</td><td>(69.1)</td><td>(48.7)</td><td></td></tr><tr><td>Other, Net</td><td>10.2</td><td>14.1</td><td>15.7</td><td></td></tr><tr><td>Income Tax Expense</td><td>$ 453.6</td><td>$ 344.2</td><td>$ 346.2</td><td></td></tr><tr><td>Effective Tax Rate</td><td>24.3%</td><td>21.9%</td><td>22.2%</td><td></td></tr></table>

<table><tr><td rowspan="2">(Millions of Dollars, except percentages)</td><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="4">2020</td></tr><tr><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&ampamp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&ampamp;P</td><td>PSNH</td><td>CL&ampamp;P</td></tr><tr><td>Income Before Income Tax Expense</td><td>$ 704.1</td><td>$ 632.4</td><td>$ 222.9</td><td>$ 533.0</td><td>$ 590.9</td><td>$ 189.8</td><td>$ 607.6</td><td>$ 575.8</td><td>$ 179.0</td><td></td><td></td><td></td></tr><tr><td>Statutory Federal Income Tax Expense at 21%</td><td>147.9</td><td>132.8</td><td>46.8</td><td>111.9</td><td>124.1</td><td>39.9</td><td>127.6</td><td>120.9</td><td>37.6</td><td></td><td></td><td></td></tr><tr><td>Tax Effect of Differences:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation</td><td>(3.7)</td><td>(4.2)</td><td>0.9</td><td>(6.4)</td><td>(3.4)</td><td>(0.2)</td><td>0.4</td><td>(3.7)</td><td>(1.4)</td><td></td><td></td><td></td></tr><tr><td>Investment Tax Credit Amortization</td><td>(0.5)</td><td>(1.7)</td><td>—</td><td>(0.6)</td><td>(1.7)</td><td>—</td><td>(0.7)</td><td>(2.6)</td><td>—</td><td></td><td></td><td></td></tr><tr><td>State Income Taxes, Net of Federal Impact</td><td>(6.6)</td><td>40.3</td><td>12.5</td><td>(4.6)</td><td>37.5</td><td>8.9</td><td>(1.2)</td><td>36.0</td><td>9.8</td><td></td><td></td><td></td></tr><tr><td>Tax Asset Valuation Allowance/Reserve Adjustments</td><td>44.7</td><td>—</td><td>—</td><td>36.7</td><td>—</td><td>—</td><td>30.7</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Excess Stock Benefit</td><td>(0.7)</td><td>(0.8)</td><td>(0.3)</td><td>(1.5)</td><td>(1.4)</td><td>(0.5)</td><td>(2.3)</td><td>(2.3)</td><td>(0.8)</td><td></td><td></td><td></td></tr><tr><td>EDIT Amortization</td><td>(9.2)</td><td>(29.2)</td><td>(7.7)</td><td>(9.8)</td><td>(43.2)</td><td>(10.5)</td><td>(9.0)</td><td>(20.4)</td><td>(15.4)</td><td></td><td></td><td></td></tr><tr><td>Other, Net</td><td>(0.7)</td><td>2.8</td><td>(0.9)</td><td>5.6</td><td>2.4</td><td>1.8</td><td>4.2</td><td>2.9</td><td>1.9</td><td></td><td></td><td></td></tr><tr><td>Income Tax Expense</td><td>$ 171.2</td><td>$ 140.0</td><td>$ 51.3</td><td>$ 131.3</td><td>$ 114.3</td><td>$ 39.4</td><td>$ 149.7</td><td>$ 130.8</td><td>$ 31.7</td><td></td><td></td><td></td></tr><tr><td>Effective Tax Rate</td><td>24.3%</td><td>22.1%</td><td>23.0%</td><td>24.6%</td><td>19.3%</td><td>20.8%</td><td>24.6%</td><td>22.7%</td><td>17.7%</td><td></td><td></td><td></td></tr></table>

Eversource, CL&P, NSTAR Electric and PSNH file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature. The tax effects of temporary differences that give rise to the net accumulated deferred income tax obligations are as follows:



<table><tr><td rowspan="3">(Millions of Dollars)</td><td colspan="12">2022</td></tr><tr><td rowspan="2">Eversource</td><td rowspan="2">CL&amp;P</td><td colspan="3">NSTAR Electric</td><td rowspan="2">PSNH</td><td rowspan="2">Eversource</td><td rowspan="2">CL&amp;P</td><td colspan="4">2021</td></tr><tr><td>Electric</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred Tax Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Employee Benefits</td><td>$ 228.9</td><td>$ 25.3</td><td>$ 57.4</td><td>$ 11.6</td><td>$ 270.8</td><td>$ 23.9</td><td>$ 40.3</td><td>$ 14.1</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative Liabilities</td><td>53.8</td><td>53.8</td><td>—</td><td>—</td><td>76.8</td><td>76.8</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory Deferrals - Liabilities</td><td>529.5</td><td>146.6</td><td>285.7</td><td>42.1</td><td>390.7</td><td>90.9</td><td>215.4</td><td>24.3</td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for Uncollectible Accounts</td><td>125.5</td><td>60.5</td><td>20.7</td><td>7.9</td><td>104.1</td><td>48.8</td><td>21.5</td><td>6.2</td><td></td><td></td><td></td><td></td></tr><tr><td>Tax Effect - Tax Regulatory Liabilities</td><td>762.9</td><td>324.6</td><td>241.8</td><td>97.8</td><td>783.4</td><td>328.2</td><td>254.3</td><td>100.9</td><td></td><td></td><td></td><td></td></tr><tr><td>Net Operating Loss Carryforwards</td><td>16.7</td><td>—</td><td>—</td><td>—</td><td>7.5</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchase Accounting Adjustment</td><td>62.0</td><td>—</td><td>—</td><td>—</td><td>67.2</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>176.6</td><td>109.5</td><td>20.5</td><td>21.3</td><td>196.6</td><td>103.9</td><td>21.7</td><td>22.9</td><td></td><td></td><td></td><td></td></tr><tr><td>Total Deferred Tax Assets</td><td>1,955.9</td><td>720.3</td><td>626.1</td><td>180.7</td><td>1,897.1</td><td>672.5</td><td>553.2</td><td>168.4</td><td></td><td></td><td></td><td></td></tr><tr><td>Less: Valuation Allowance</td><td>82.8</td><td>63.3</td><td>—</td><td>—</td><td>61.5</td><td>44.5</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Net Deferred Tax Assets</td><td>$ 1,873.1</td><td>$ 657.0</td><td>$ 626.1</td><td>$ 180.7</td><td>$ 1,835.6</td><td>$ 628.0</td><td>$ 553.2</td><td>$ 168.4</td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred Tax Liabilities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Accelerated Depreciation and Other Plant-Related Differences</td><td>$ 4,793.7</td><td>$ 1,602.0</td><td>$ 1,643.7</td><td>$ 523.8</td><td>$ 4,426.0</td><td>$ 1,509.5</td><td>$ 1,553.7</td><td>$ 482.9</td><td></td><td></td><td></td><td></td></tr><tr><td>Property Tax Accruals</td><td>95.3</td><td>40.7</td><td>41.3</td><td>6.7</td><td>88.1</td><td>40.5</td><td>33.7</td><td>6.3</td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory Amounts:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory Deferrals - Assets</td><td>1,251.9</td><td>406.4</td><td>407.9</td><td>165.2</td><td>1,260.3</td><td>438.3</td><td>337.6</td><td>198.4</td><td></td><td></td><td></td><td></td></tr><tr><td>Tax Effect - Tax Regulatory Assets</td><td>271.7</td><td>185.6</td><td>10.7</td><td>7.9</td><td>257.8</td><td>181.4</td><td>10.9</td><td>8.3</td><td></td><td></td><td></td><td></td></tr><tr><td>Goodwill-related Regulatory Asset - 1999 Merger</td><td>76.8</td><td>—</td><td>65.9</td><td>—</td><td>81.4</td><td>—</td><td>69.9</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Employee Benefits</td><td>305.5</td><td>45.0</td><td>140.8</td><td>18.7</td><td>174.7</td><td>3.5</td><td>107.1</td><td>0.7</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivative Assets</td><td>10.5</td><td>10.5</td><td>—</td><td>—</td><td>14.9</td><td>14.9</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Other</td><td>135.6</td><td>6.8</td><td>16.7</td><td>21.2</td><td>129.5</td><td>2.0</td><td>19.8</td><td>9.8</td><td></td><td></td><td></td><td></td></tr><tr><td>Total Deferred Tax Liabilities</td><td>$ 6,941.0</td><td>$ 2,297.0</td><td>$ 2,327.0</td><td>$ 743.5</td><td>$ 6,432.7</td><td>$ 2,190.1</td><td>$ 2,132.7</td><td>$ 706.4</td><td></td><td></td><td></td><td></td></tr></table>

2022 Federal Legislation: On August 16, 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law. This is a broad package of legislation that includes incentives and support for clean energy resource development. Most notable for Eversource, the investment tax credit (ITC) on offshore wind projects increases from 30 percent to 40 percent if certain requirements for labor and domestic content are met. The act also re-establishes the production tax credit for solar and wind energy projects, gives increased credit for projects in certain communities, and sets credits for qualifying clean energy generation and energy storage projects. The tax provisions of the IRA provide additional incentives for offshore wind projects and could reduce retail electricity costs for our customers related to those clean energy investments. The IRA includes other tax provisions focused on implementing a 15 percent minimum tax on adjusted financial statement income and a one percent excise tax on corporate share repurchases. The Department of Treasury and the Internal Revenue Service issued limited guidance in the fourth quarter; however, they are expected to issue additional needed guidance with respect to the application of the newly enacted IRA provisions in the future. We will continue to monitor and evaluate impacts on our consolidated financial statements. We currently do not expect the alternative minimum tax change to have a material impact on our earnings, financial condition or cash flows.

2021 Federal Legislation: On November 5, 2021, Congress passed the Infrastructure Investment and Jobs Act. The Act provided spending of more than $500 billion on roads, highways, bridges, public transit, and utilities. For water and sewer utilities, the Act restored the exclusion from a corporation’s income for contributions in aid of construction where the corporation is a water or sewer utility eliminated by the Tax Cuts and Jobs Act of 2017. Under the Act, a regulated public utility that provides water or sewage disposal services can treat money or property received from any person as a tax-free contribution to capital if it meets certain criteria for contributions made after 2020. The Act did not have a material impact on Eversource in 2021.

Carryforwards: The following table provides the amounts and expiration dates of state tax credit and loss carryforwards and federal tax credit and net operating loss carryforwards:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="12">2022</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Expiration Range</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNN</td><td>Expiration Range</td><td></td><td></td></tr><tr><td>State Net Operating Loss</td><td>$ 288.1</td><td>$ —</td><td>$ —</td><td>$ —</td><td>2022 - 2041</td><td>$ 138.3</td><td>$ —</td><td>$ —</td><td>$ —</td><td>2021 - 2040</td><td></td><td></td></tr><tr><td>State Tax Credit</td><td>204.5</td><td>137.7</td><td>—</td><td>—</td><td>2022 - 2027</td><td>197.7</td><td>137.0</td><td>—</td><td>—</td><td>2021 - 2026</td><td></td><td></td></tr><tr><td>State Charitable Contribution</td><td>20.1</td><td>—</td><td>—</td><td>—</td><td>2022 - 2026</td><td>23.7</td><td>—</td><td>—</td><td>—</td><td>2021 - 2025</td><td></td><td></td></tr></table>

In 2022, the Company increased its valuation allowance reserve for state credits by $21.3 million ($18.8 million for CL&P), net of tax, to reflect an update for expiring tax credits. In 2021, the Company increased its valuation allowance reserve for state credits by $13.0 million ($10.8 million for CL&P), net of tax, to reflect an update for expiring tax credits.



For 2022 and 2021, state credit and state loss carryforwards have been partially reserved by a valuation allowance of $82.8 million and $61.5 million (net of tax), respectively.

Unrecognized Tax Benefits: A reconciliation of the activity in unrecognized tax benefits, all of which would impact the effective tax rate if recognized, is as follows:

<table><tr><td>(Millions of Dollars)</td><td>Eversource</td><td>CL&amp;P</td></tr><tr><td>Balance as of January 1, 2020</td><td>$ 55.0</td><td>$ 23.1</td></tr><tr><td>Gross Increases - Current Year</td><td>11.9</td><td>4.6</td></tr><tr><td>Gross Increases - Prior Year</td><td>1.4</td><td>0.7</td></tr><tr><td>Lapse of Statute of Limitations</td><td>(6.5)</td><td>(2.6)</td></tr><tr><td>Balance as of December 31, 2020</td><td>61.8</td><td>25.8</td></tr><tr><td>Gross Increases - Current Year</td><td>11.3</td><td>3.8</td></tr><tr><td>Gross Decreases - Prior Year</td><td>(0.3)</td><td>(0.6)</td></tr><tr><td>Lapse of Statute of Limitations</td><td>(7.0)</td><td>(2.8)</td></tr><tr><td>Balance as of December 31, 2021</td><td>65.8</td><td>26.2</td></tr><tr><td>Gross Increases - Current Year</td><td>11.5</td><td>3.5</td></tr><tr><td>Gross Decreases - Prior Year</td><td>(2.4)</td><td>(0.9)</td></tr><tr><td>Lapse of Statute of Limitations</td><td>(7.8)</td><td>(3.3)</td></tr><tr><td>Balance as of December 31, 2022</td><td>$ 67.1</td><td>$ 25.5</td></tr></table>

Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense on the statements of income. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the statements of income. No penalties have been recorded. There has been no interest expense or income recognized on uncertain tax positions for the years ended December 31, 2022, 2021 or 2020. The accrued interest payable was $0.1 million as of both December 31, 2022 and 2021.

Tax Positions: During 2022 and 2021, Eversource did not resolve any of its uncertain tax positions.

Open Tax Years: The following table summarizes Eversource, CL&P, NSTAR Electric, and PSNH's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2022:

<table><tr><td>Description</td><td>Tax Years</td></tr><tr><td>Federal</td><td>2022</td></tr><tr><td>Connecticut</td><td>2019 - 2022</td></tr><tr><td>Massachusetts</td><td>2019 - 2022</td></tr><tr><td>New Hampshire</td><td>2019 - 2022</td></tr></table>

Eversource does not estimate to have an earnings impact related to unrecognized tax benefits during the next twelve months.

## 13. COMMITMENTS AND CONTINGENCIES

## A. Environmental Matters

Eversource, CL&P, NSTAR Electric and PSNH are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. Eversource, CL&P, NSTAR Electric and PSNH have an active environmental auditing and training program and each believes it is substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring. These liabilities are estimated on an undiscounted basis and do not assume that the amounts are recoverable from insurance companies or other third parties. The environmental reserves include sites at different stages of discovery and remediation and do not include any unasserted claims.

These reserve estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of Eversource's, CL&P's, NSTAR Electric's and PSNH's responsibility for remediation or the extent of remediation required, recently enacted laws and regulations or changes in cost estimates due to certain economic factors. It is possible that new information or future developments could require a reassessment of the potential exposure to required environmental remediation. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

The amounts recorded as environmental reserves are included in Other Current Liabilities and Other Long-Term Liabilities on the balance sheets and represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs. The environmental reserves also take into account recurring costs of managing hazardous substances and



pollutants, mandated expenditures to remediate contaminated sites and any other infrequent and non-recurring clean-up costs. A reconciliation of the activity in the environmental reserves is as follows:

<table><tr><td>(Millions of Dollars)</td><td colspan="2">Eversource</td><td>CL&amp;P</td><td colspan="2">NSTAR Electric</td><td>PSNH</td></tr><tr><td>Balance as of January 1, 2021</td><td>$</td><td>102.4</td><td>$</td><td>12.3</td><td>$</td><td>7.1</td></tr><tr><td>Additions</td><td></td><td>23.4</td><td></td><td>4.4</td><td></td><td>—</td></tr><tr><td>Payments/Reductions</td><td></td><td>(10.4)</td><td></td><td>(2.8)</td><td></td><td>(0.8)</td></tr><tr><td>Balance as of December 31, 2021</td><td></td><td>115.4</td><td></td><td>13.9</td><td></td><td>6.3</td></tr><tr><td>Additions</td><td></td><td>12.6</td><td></td><td>0.9</td><td></td><td>0.5</td></tr><tr><td>Payments/Reductions</td><td></td><td>(5.4)</td><td></td><td>(0.9)</td><td></td><td>(0.7)</td></tr><tr><td>Balance as of December 31, 2022</td><td>$</td><td>122.6</td><td>$</td><td>13.9</td><td>$</td><td>6.1</td></tr></table>

The number of environmental sites for which remediation or long-term monitoring, preliminary site work or site assessment is being performed are as follows:

<table><tr><td></td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>2022</td><td>59</td><td>13</td><td>10</td><td>8</td></tr><tr><td>2021</td><td>61</td><td>14</td><td>11</td><td>9</td></tr></table>

The increase in the reserve balance was due primarily to changes in cost estimates at certain MGP sites at our natural gas business segment, which we now know will require additional remediation.

Included in the number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which Eversource may have potential liability. The reserve balances related to these former MGP sites were $112.6 million and $105.6 million as of December 31, 2022 and 2021, respectively, and related primarily to the natural gas business segment.

As of December 31, 2022, for 15 environmental sites (7 for CL&P and 1 for NSTAR Electric) that are included in the Company's reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake. As of December 31, 2022, $25.8 million (including $4.4 million for CL&P and $0.1 million for NSTAR Electric) had been accrued as a liability for these sites.

As of December 31, 2022, for 7 environmental sites (1 for CL&P) that are included in the Company's reserve for environmental costs, the information known and the nature of the remediation options allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2022, $29.9 million (including $0.6 million for CL&P) has been accrued as a liability for these sites, which represents the low end of the range of the liabilities for environmental costs. Management believes that additional losses of up to approximately $17 million ($0.3 million at CL&P) may be incurred in executing current remediation plans for these sites.

As of December 31, 2022, for the remaining 37 environmental sites (including 5 for CL&P, 9 for NSTAR Electric and 8 for PSNH) that are included in the Company's reserve for environmental costs, the $66.9 million accrual (including $8.9 million for CL&P, $3.3 million for NSTAR Electric and $6.1 million for PSNH) represents management's best estimate of the probable liability and no additional loss is estimable at this time.

PSNH, NSTAR Gas, EGMA and Yankee Gas have rate recovery mechanisms for MGP related environmental costs, therefore, changes in their respective environmental reserves do not impact Net Income. CL&P is allowed to defer certain environmental costs for future recovery. NSTAR Electric does not have a separate environmental cost recovery regulatory mechanism.

## B. Long-Term Contractual Arrangements

Estimated Future Annual Costs: The estimated future annual costs of significant executed, non-cancelable, long-term contractual arrangements in effect as of December 31, 2022 are as follows:

<table><tr><td>Eversource (Millions of Dollars)</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>Thereafter</td><td>Total</td></tr><tr><td>Renewable Energy Purchase Contracts</td><td>$ 751.8</td><td>$ 952.6</td><td>$ 954.8</td><td>$ 983.0</td><td>$ 998.5</td><td>$ 8,141.1</td><td>$ 12,781.8</td></tr><tr><td>Natural Gas Procurement</td><td>447.1</td><td>419.4</td><td>340.9</td><td>298.5</td><td>269.4</td><td>1,450.6</td><td>3,225.9</td></tr><tr><td>Purchased Power and Capacity</td><td>87.6</td><td>86.8</td><td>75.2</td><td>2.9</td><td>2.7</td><td>7.2</td><td>262.4</td></tr><tr><td>Speaker CfdS</td><td>20.3</td><td>21.1</td><td>17.9</td><td>16.0</td><td>11.4</td><td>64.4</td><td>151.1</td></tr><tr><td>Transmission Support Commitments</td><td>17.8</td><td>20.7</td><td>22.6</td><td>22.6</td><td>22.6</td><td>22.6</td><td>128.9</td></tr><tr><td>Total</td><td>$ 1,324.6</td><td>$ 1,500.6</td><td>$ 1,411.4</td><td>$ 1,323.0</td><td>$ 1,304.6</td><td>$ 9,685.9</td><td>$ 16,550.1</td></tr></table>



<table><tr><td colspan="10">CL&amp;P</td></tr><tr><td colspan="10">(Millions of Dollars)</td></tr><tr><td>Renewable Energy Purchase Contracts</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>Thereafter</td><td>Total</td><td></td><td></td></tr><tr><td>Purchased Power and Capacity</td><td>594.8</td><td>609.1</td><td>610.2</td><td>607.6</td><td>609.0</td><td>2,253.1</td><td>5,283.8</td><td></td><td></td></tr><tr><td>Speaker CIDs</td><td>83.5</td><td>83.9</td><td>72.4</td><td>0.1</td><td>—</td><td>—</td><td>239.9</td><td></td><td></td></tr><tr><td>Transmission Support Commitments</td><td>20.3</td><td>21.1</td><td>17.9</td><td>16.0</td><td>11.4</td><td>64.4</td><td>151.1</td><td></td><td></td></tr><tr><td>Total</td><td>7.0</td><td>8.2</td><td>8.9</td><td>8.9</td><td>8.9</td><td>8.9</td><td>50.8</td><td></td><td></td></tr></table>

<table><tr><td colspan="10">NSTAR Electric</td></tr><tr><td>(Millions of Dollars)</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>Thereafter</td><td>Total</td><td></td><td></td></tr><tr><td>Renewable Energy Purchase Contracts</td><td>$ 79.2</td><td>$ 270.0</td><td>$ 316.5</td><td>$ 322.9</td><td>$ 328.6</td><td>$ 5,519.8</td><td>$ 6,837.0</td><td></td><td></td></tr><tr><td>Purchased Power and Capacity</td><td>2.9</td><td>2.9</td><td>2.8</td><td>2.8</td><td>2.7</td><td>7.2</td><td>21.3</td><td></td><td></td></tr><tr><td>Transmission Support Commitments</td><td>7.0</td><td>8.1</td><td>8.9</td><td>8.9</td><td>8.9</td><td>8.9</td><td>50.7</td><td></td><td></td></tr><tr><td>Total</td><td>$ 89.1</td><td>$ 281.0</td><td>$ 328.2</td><td>$ 334.6</td><td>$ 340.2</td><td>$ 5,535.9</td><td>$ 6,909.0</td><td></td><td></td></tr></table>

<table><tr><td colspan="10">PSNH</td></tr><tr><td>(Millions of Dollars)</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>2027</td><td>Thereafter</td><td>Total</td><td></td><td></td></tr><tr><td>Renewable Energy Purchase Contracts</td><td>$ 77.8</td><td>$ 73.5</td><td>$ 28.1</td><td>$ 52.5</td><td>$ 60.9</td><td>$ 368.2</td><td>$ 661.0</td><td></td><td></td></tr><tr><td>Purchased Power and Capacity</td><td>1.2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1.2</td><td></td><td></td></tr><tr><td>Transmission Support Commitments</td><td>3.8</td><td>4.4</td><td>4.8</td><td>4.8</td><td>4.8</td><td>4.8</td><td>27.4</td><td></td><td></td></tr><tr><td>Total</td><td>$ 82.8</td><td>$ 77.9</td><td>$ 32.9</td><td>$ 57.3</td><td>$ 65.7</td><td>$ 373.0</td><td>$ 689.6</td><td></td><td></td></tr></table>

Renewable Energy Purchase Contracts: Renewable energy purchase contracts include non-cancellable commitments under contracts of CL&P, NSTAR Electric and PSNH for the purchase of energy and capacity from renewable energy facilities. Such contracts extend through 2043 for CL&P, 2044 for NSTAR Electric and 2033 for PSNH.

Renewable Energy and Purchase Contracts includes long-term commitments of NSTAR Electric pertaining to the Vineyard Wind LLC contract awarded under the Massachusetts Clean Energy 83C procurement solicitation. NSTAR Electric, along with other Massachusetts distribution companies, entered into 20-year contracts to purchase electricity generated by this 800 megawatt offshore wind project. Construction on the Vineyard Wind project commenced in 2022. Estimated energy costs under this contract are expected to begin when the facilities are in service in 2024 and range between $240 million and $375 million per year under NSTAR Electric’s 20-year contract, totaling approximately $6.0 billion.

As required by 2018 regulation, CL&P and UI each entered into PURA-approved ten-year contracts in 2019 to purchase a combined total of approximately 9 million MWh annually from the Millstone Nuclear Power Station generation facility, which represents a combined amount of approximately 50 percent of the facility's output (approximately 40 percent by CL&P). The Millstone Nuclear Power Station has a 2,112 MW nameplate capacity. Energy deliveries and payments under these contracts began in 2019. Also as required by 2018 regulation, CL&P and UI each entered into PURA-approved eight-year contracts in 2019 to purchase a combined amount of approximately 18 percent of the Seabrook Nuclear Power Plant's output (approximately 15 percent by CL&P) beginning January 1, 2022. The Seabrook Nuclear Power Plant has an approximate 1,250 MW nameplate capacity. The total estimated remaining future cost of the Millstone Nuclear Power Station and Seabrook Nuclear Power Plant energy purchase contracts are $2.9 billion and are reflected in the table above. CL&P sells the energy purchased under these contracts into the market and uses the proceeds from these energy sales to offset the contract costs. As the net costs under these contracts are recovered from customers in future rates, the contracts do not have an impact on the net income of CL&P. These contracts do not meet the definition of a derivative, and accordingly, the costs of these contracts are being accounted for as incurred.

Excluded from the table above are long-term commitments of NSTAR Electric pertaining to the Massachusetts Clean Energy 83D contract, for which construction was suspended prior to December 31, 2021. Should the project attain feasibility and construction recommence, the estimated costs under the contract may potentially begin in 2023 and range between $150 million and $415 million per year under a 20-year contract, totaling approximately $6.7 billion.

The contractual obligations table above does not include long-term commitments signed by CL&P and NSTAR Electric, as required by the PURA and DPU, respectively, for the purchase of renewable energy and related products that are contingent on the future construction of energy facilities.

Natural Gas Procurement: Eversource's natural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas as part of its portfolio of supplies, which extend through 2045.

Purchased Power and Capacity: These contracts include capacity CfDs of CL&P through 2026, and various IPP contracts or purchase obligations for electricity which extend through 2024 for CL&P, 2031 for NSTAR Electric and 2023 for PSNH.

As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. CL&P has a sharing agreement with UI, with 80 percent of the costs or benefits of each contract borne by or allocated to CL&P and 20 percent borne by or allocated to UI. The combined capacities of these contracts as of December 31, 2022 and 2021 were 674 MW and 675 MW, respectively. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the capacity market price received in the ISO-NE capacity markets. CL&P's portion of the costs and benefits of these contracts will be paid by, or refunded to, CL&P's customers.



The contractual obligations table above does not include CL&P's, NSTAR Electric's or PSNH's standard/basic service contracts for the purchase of energy supply, the amounts of which vary with customers' energy needs.

Peaker CfDs: CL&P, along with UI, has three peaker CfDs for a total of approximately 500 MW of peaking capacity through 2042. CL&P has a sharing agreement with UI, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The Peaker CfDs pay the generation facility owner the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the Peaker CfDs are recovered from, or refunded to, CL&P's customers.

Transmission Support Commitments: Along with other New England utilities, CL&P, NSTAR Electric and PSNH entered into a series of agreements in the 1980's to support the costs of, and receive rights to use, transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada. CL&P, NSTAR Electric and PSNH were obligated to pay, over a 30-year period that ended in 2020, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities. On December 18, 2020, the parties to these agreements submitted to FERC an offer of settlement and amendments to these agreements implementing the terms of an extension for an additional 20-year period ending in 2040. On May 20, 2021, FERC approved this settlement, effective January 1, 2021.

The total costs incurred under these agreements were as follows:

<table><tr><td rowspan="2">Eversource (Millions of Dollars)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Renewable Energy Purchase Contracts</td><td>$     678.1</td><td>$     609.2</td><td>$     584.2</td><td></td></tr><tr><td>Natural Gas Procurement</td><td>1,042.8</td><td>712.7</td><td>453.4</td><td></td></tr><tr><td>Purchased Power and Capacity</td><td>61.6</td><td>56.4</td><td>62.7</td><td></td></tr><tr><td>Peaker CfDs</td><td>13.4</td><td>24.3</td><td>22.7</td><td></td></tr><tr><td>Transmission Support Commitments</td><td>12.7</td><td>15.4</td><td>22.1</td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="10">For the Years Ended December 31,</td></tr><tr><td colspan="4">2022</td><td colspan="4">2021</td><td colspan="3">2020</td></tr><tr><td></td><td colspan="2">NSTAR Electric</td><td colspan="2">PSNH</td><td colspan="2">NSTAR Electric</td><td colspan="2">PSNH</td><td>NSTAR Electric</td><td colspan="2">PSNH</td></tr><tr><td>(Millions of Dollars)</td><td>CL&amp;P</td><td>Electric</td><td>PSNH</td><td>CL&amp;P</td><td>Electric</td><td>PSNH</td><td>CL&amp;P</td><td></td><td>Electric</td><td>PSNH</td><td></td></tr><tr><td>Renewable Energy Purchase Contracts</td><td>$ 513.2</td><td>$ 90.8</td><td>$ 74.1</td><td>$ 457.1</td><td>$ 84.7</td><td>$ 67.4</td><td>$ 426.3</td><td>$ 88.8</td><td>$ 69.1</td><td></td><td></td></tr><tr><td>Purchased Power and Capacity</td><td>57.7</td><td>3.0</td><td>0.9</td><td>53.1</td><td>3.0</td><td>0.3</td><td>59.3</td><td>3.1</td><td>0.3</td><td></td><td></td></tr><tr><td>Peaker CfDs</td><td>13.4</td><td>—</td><td>—</td><td>24.3</td><td>—</td><td>—</td><td>22.7</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Transmission Support Commitments</td><td>5.0</td><td>5.0</td><td>2.7</td><td>6.1</td><td>6.0</td><td>3.3</td><td>8.7</td><td>8.7</td><td>4.7</td><td></td><td></td></tr></table>

## C. Spent Nuclear Fuel Obligations - Yankee Companies

CL&P, NSTAR Electric and PSNH have plant closure and fuel storage cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear power facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies fund these costs through litigation proceeds received from the DOE and, to the extent necessary, through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric and PSNH. CL&P, NSTAR Electric and PSNH, in turn recover these costs from their customers through state regulatory commission-approved retail rates. The Yankee Companies collect amounts that management believes are adequate to recover the remaining plant closure and fuel storage cost estimates for the respective plants. Management believes CL&P and NSTAR Electric will recover their shares of these obligations from their customers. PSNH has recovered its total share of these costs from its customers.

## Spent Nuclear Fuel Litigation:

The Yankee Companies have filed complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to accept delivery of, and provide for a permanent facility to store, spent nuclear fuel pursuant to the terms of the 1983 spent fuel and high-level waste disposal contracts between the Yankee Companies and the DOE. The court previously awarded the Yankee Companies damages for Phases I, II, III and IV of litigation resulting from the DOE's failure to meet its contractual obligations. These Phases covered damages incurred in the years 1998 through 2016, and the awarded damages have been received by the Yankee Companies with certain amounts of the damages refunded to their customers.

DOE Phase V Damages - On March 25, 2021, each of the Yankee Companies filed a fifth set of lawsuits against the DOE in the Court of Federal Claims resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal covering the years from 2017 to 2020. The Yankee Companies filed claims seeking monetary damages totaling $120.4 million for CYAPC, YAEC and MYAPC. Pursuant to a June 2, 2022 court order, the Yankee Companies were subsequently permitted to include monetary damages relating to the year 2021 in the DOE Phase V complaint. The Yankee Companies submitted a supplemental filing to include these costs of $33.1 million on June 8, 2022. The DOE Phase V trial is expected to begin in the third quarter of 2023.

## D. Guarantees and Indemnifications

In the normal course of business, Eversource parent provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric and PSNH, in the form of guarantees. Management does not anticipate a material impact to net income or cash flows as a result of these various guarantees and indemnifications.

Guarantees issued on behalf of unconsolidated entities, including equity method offshore wind investments, for which Eversource parent is the guarantor, are recorded at fair value as a liability on the balance sheet at the inception of the guarantee. Eversource regularly reviews



performance risk under these guarantee arrangements, and in the event it becomes probable that Eversource parent will be required to perform under the guarantee, the amount of probable payment will be recorded. The fair value of guarantees issued on behalf of unconsolidated entities are recorded within Other Long-Term Liabilities on the balance sheet, and were $4.2 million and $7.3 million as of December 31, 2022 and 2021, respectively.

The following table summarizes Eversource parent's exposure to guarantees and indemnifications of its subsidiaries and affiliates to external parties, and primarily relates to its offshore wind business:

As of December 31, 2022

<table><tr><td>Company (Obligor)</td><td>Description</td><td>Maximum Exposure (in millions)</td><td>Expiration Dates</td></tr><tr><td>North East Offshore LLC</td><td>Construction-related purchase agreements with third-party contractors  \( {}^{(1)} \)</td><td>$ 717.6</td><td>(1)</td></tr><tr><td>Sunrise Wind LLC</td><td>Construction-related purchase agreements with third-party contractors  \( {}^{(2)} \)</td><td>311.5</td><td>2025 - 2026</td></tr><tr><td>Revolution Wind, LLC</td><td>Construction-related purchase agreements with third-party contractors  \( {}^{(3)} \)</td><td>419.1</td><td>2024 - 2027</td></tr><tr><td>South Fork Wind, LLC</td><td>Construction-related purchase agreements with third-party contractors  \( {}^{(4)} \)</td><td>142.1</td><td>2023 - 2026</td></tr><tr><td>Eversource Investment LLC</td><td>Funding and indemnification obligations of North East Offshore LLC  \( {}^{(5)} \)</td><td>77.0</td><td>(5)</td></tr><tr><td>South Fork Wind, LLC</td><td>Power Purchase Agreement Security  \( {}^{(6)} \)</td><td>7.1</td><td>(6)</td></tr><tr><td>Sunrise Wind LLC</td><td>OREC capacity production  \( {}^{(7)} \)</td><td>2.2</td><td>(7)</td></tr><tr><td>Bay State Wind LLC</td><td>Real estate purchase</td><td>2.5</td><td>2023</td></tr><tr><td>South Fork Wind, LLC</td><td>Transmission interconnection</td><td>1.2</td><td>—</td></tr><tr><td>Eversource Investment LLC</td><td>Letters of Credit  \( {}^{(8)} \)</td><td>4.3</td><td>—</td></tr><tr><td>Various</td><td>Surety bonds  \( {}^{(9)} \)</td><td>35.7</td><td>2023</td></tr><tr><td>Eversource Service</td><td>Lease payments for real estate</td><td>0.5</td><td>2024</td></tr></table>

(1) Eversource parent issued guarantees on behalf of its 50 percent-owned affiliate, North East Offshore LLC (NEO), under which Eversource parent agreed to guarantee 50 percent of NEO's performance of obligations under certain purchase agreements with third-party contractors, in an aggregate amount not to exceed $1.3 billion with an expiration date in 2025. Eversource parent also issued a separate guarantee to Ørsted on behalf of NEO, under which Eversource parent agreed to guarantee 50 percent of NEO's payment obligations under certain offshore wind project construction-related agreements with Ørsted in an aggregate amount not to exceed $62.5 million and expiring upon full performance of the guaranteed obligation. Any amounts paid under this guarantee to Ørsted will count toward, but not increase, the maximum amount of the Funding Guarantee described in Note 5, below.

(2) Eversource parent issued guarantees on behalf of its 50 percent-owned affiliate, Sunrise Wind LLC, whereby Eversource parent will guarantee Sunrise Wind LLC's performance of certain obligations, in an aggregate amount not to exceed $465.8 million, in connection with construction-related purchase agreements. Eversource parent's obligations under the guarantees expire upon the earlier of (i) dates ranging from March 2025 and April 2026 and (ii) full performance of the guaranteed obligations.

(3) Eversource parent issued guarantees on behalf of its 50 percent-owned affiliate, Revolution Wind, LLC, whereby Eversource parent will guarantee Revolution Wind, LLC's performance of certain obligations, in an aggregate amount not to exceed $546.7 million, in connection with construction-related purchase agreements. Eversource parent's obligations under the guarantees expire upon the earlier of (i) dates ranging from May 2024 and November 2027 and (ii) full performance of the guaranteed obligations.

(4) Eversource parent issued guarantees on behalf of its 50 percent-owned affiliate, South Fork Wind, LLC, whereby Eversource parent will guarantee South Fork Wind, LLC's performance of certain obligations in connection with construction-related purchase agreements. Under these guarantees, Eversource parent will guarantee South Fork Wind, LLC's performance of certain obligations, in a total aggregate amount not to exceed $207.7 million. Eversource parent's obligations under these guarantees expire upon the earlier of (i) dates ranging from June 2023 and August 2026 and (ii) full performance of the guaranteed obligations.

(5) Eversource parent issued a guarantee (Funding Guarantee) on behalf of Eversource Investment LLC (EI), its wholly-owned subsidiary that holds a 50 percent ownership interest in NEO, under which Eversource parent agreed to guarantee certain funding obligations and certain indemnification payments of EI under the operating agreement of NEO, in an amount not to exceed $910 million. The guaranteed obligations include payment of EI's funding obligations during the construction phase of NEO's underlying offshore wind projects and indemnification obligations associated with third party credit support for its investment in NEO. Eversource parent's obligations under the Funding Guarantee expire upon the full performance of the guaranteed obligations.

(6) Eversource parent issued a guarantee on behalf of its 50 percent-owned affiliate, South Fork Wind, LLC, whereby Eversource parent will guarantee South Fork Wind, LLC's performance of certain obligations, in an amount not to exceed $7.1 million, under a Power Purchase Agreement between the Long Island Power Authority and South Fork Wind, LLC (the Agreement). The guarantee expires upon the later of (i) the end of the Agreement term and (ii) full performance of the guarantee obligations.

(7) Eversource parent issued a guarantee on behalf of its 50 percent-owned affiliate, Sunrise Wind LLC, whereby Eversource parent will guarantee Sunrise Wind LLC's performance of certain obligations, in an amount not to exceed $15.4 million, under the Offshore Wind Renewable Energy Certificate Purchase and Sale Agreement (the Agreement). The Agreement was executed by and between the New York State Energy Research and Development Authority (NYSERDA) and Sunrise Wind LLC. The guarantee expires upon the full performance of the guaranteed obligations. Effective January 1, 2023, exposure under the guarantee increased from $2.2 million to $11.0 million.



(8) On September 16, 2020, Eversource parent entered into a guarantee on behalf of EI, which holds Eversource's investments in offshore wind-related equity method investments, under which Eversource parent would guarantee EI's obligations under a letter of credit facility with a financial institution that EI may request in an aggregate amount of up to approximately $25 million. In January 2022, Eversource parent issued two letters of credit on behalf of South Fork Wind, LLC related to future decommissioning obligations of certain onshore transmission assets totaling $4.3 million.

(9) Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended. Certain surety bonds contain credit ratings triggers that would require Eversource parent to post collateral in the event that the unsecured debt credit ratings of Eversource parent are downgraded.

2023 Guaranty: In the first quarter of 2023, Eversource parent issued an additional guaranty on behalf of Sunrise Wind LLC totaling $58.1 million, whereby Eversource parent will guarantee Sunrise Wind LLC's performance of certain contractual obligations.

## E. FERC ROE Complaints

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

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

All amounts associated with the first complaint period have been refunded, which totaled $38.9 million (pre-tax and excluding interest) at Eversource and reflected both the base ROE and incentive cap prescribed by the FERC order. The refund consisted of $22.4 million for CL&P, $13.7 million for NSTAR Electric and $2.8 million for PSNH.

Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 2022 and 2021. 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, 2022 and 2021.

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.

A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource’s after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods.

## F. Eversource and NSTAR Electric Boston Harbor Civil Action

In 2016, the United States Attorney on behalf of the United States Army Corps of Engineers filed a civil action in the United States District Court for the District of Massachusetts against NSTAR Electric, HEEC, and the Massachusetts Water Resources Authority (together with NSTAR Electric and HEEC, the "Defendants"). The action alleged that the Defendants failed to comply with certain permitting requirements related to the placement of the HEEC-owned electric distribution cable beneath Boston Harbor. The parties reached a settlement pursuant to which HEEC agreed to install a new 115kV distribution cable across Boston Harbor to Deer Island, utilizing a different route, and remove portions of the existing cable. Construction of the new distribution cable was completed in August 2019 and removal of the portions of the existing cable was completed in January 2020.

On February 9, 2023, the parties filed a Voluntary Stipulation of Dismissal with Prejudice with the United States District Court for the District of Massachusetts whereby the parties agreed to dismiss all remaining claims, crossclaims and counterclaims with prejudice.

## G. CL&P Regulatory Matters

CL&P Tropical Storm Isaias Response Investigation: On April 28, 2021, PURA issued a final decision on CL&P's compliance with its emergency response plan that concluded CL&P failed to comply with certain storm performance standards and was imprudent in certain instances regarding its preparation for, and response to, Tropical Storm Isaias. Based on its findings, PURA ordered CL&P to adjust its future rates in a pending or future rate proceeding to reflect a monetary penalty in the form of a downward adjustment of 90 basis points in its allowed rate of return on equity (ROE), which is currently 9.25 percent. On July 14, 2021, PURA issued a final decision in a penalty proceeding that included an assessment of $28.6 million, consisting of a $28.4 million civil penalty for non-compliance with storm performance standards to be provided as credits on customer bills and a $0.2 million fine for violations of accident reporting requirements to be paid to the State of Connecticut's general fund. The $28.4 million performance penalty was credited to customers on electric bills beginning on September 1, 2021 over a one-year period. The $28.4 million is the maximum statutory penalty amount under applicable Connecticut law in effect at the time of Tropical Storm Isaias, which is 2.5 percent of CL&P's annual distribution revenues. The liability for the performance penalty was recorded as a current regulatory liability on CL&P's balance sheet and as a reduction to Operating Revenues on the year ended December 31, 2021 statement of income.

CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel, Office of the Attorney General and the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory proceedings initiated by PURA. PURA approved the settlement agreement on October 27, 2021. In the settlement agreement, CL&P agreed to provide a total of $65 million of customer credits, which were distributed based on customer sales over a two-month billing period from December 1, 2021 to January 31, 2022. CL&P also agreed to irrevocably set aside $10 million in a customer assistance fund to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages, as approved by PURA, with the objective of disbursing the funds prior to April 30, 2022. Those customers were provided with $10 million of bill forgiveness in the first quarter of 2022. CL&P recorded a current regulatory liability of $75 million on the balance sheet associated with the provisions of the settlement agreement, with a $65 million pre-tax charge as a reduction to Operating Revenues associated with the customer credits and a $10 million charge to Operations and Maintenance expense associated with the customer assistance fund on the year ended December 31, 2021 statement of income.

In exchange for the $75 million of customer credits and assistance, PURA's interim rate reduction docket was resolved without findings. As a result of the settlement agreement, neither the 90 basis point reduction to CL&P's return on equity introduced in PURA's storm-related decision issued April 28, 2021, nor the 45 basis point reduction to CL&P's return on equity included in PURA's decision issued September 14, 2021 in the interim rate reduction docket, will be implemented. CL&P has also agreed to freeze its current base distribution rates, subject to the customer credits described above, until no earlier than January 1, 2024. The rate freeze applies 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 does not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings, either currently pending or that may be initiated during the rate freeze period, that may place additional obligations on CL&P. The approval of the settlement agreement satisfies 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.

As part of the settlement agreement, CL&P agreed to withdraw with prejudice its pending appeals of PURA's decisions dated April 28, 2021 and July 14, 2021 related to Storm Isaias and agreed to waive its right to file an appeal and seek a judicial stay of the September 14, 2021 decision in the interim rate reduction docket. The settlement agreement assures that CL&P will have the opportunity to petition for and demonstrate the prudence of the storm costs incurred to respond to customer outages associated with Storm Isaias in a future ratemaking proceeding.

The cumulative pre-tax impact of the settlement agreement and the Storm Isaias assessment imposed in PURA’s April 28, 2021 and July 14, 2021 decisions totaled $103.6 million, and the after-tax earnings impact was $86.1 million, or $0.25 per share, for the year ended December 31, 2021.



## H. Litigation and Legal Proceedings

Eversource, including CL&P, NSTAR Electric and PSNH, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss. The Company records and discloses losses when these losses are probable and reasonably estimable, and discloses matters when losses are probable but not estimable or when losses are reasonably possible. Legal costs related to the defense of loss contingencies are expensed as incurred.

## 14. LEASES

Eversource, including CL&P, NSTAR Electric and PSNH, has entered into lease agreements as a lessee for the use of land, office space, service centers, vehicles, information technology, and equipment. These lease agreements are classified as either finance or operating leases and the liability and right-of-use asset are recognized on the balance sheet at lease commencement. Leases with an initial term of 12 months or less are not recorded on the balance sheet and are recognized as lease expense on a straight-line basis over the lease term.

Eversource determines whether or not a contract contains a lease based on whether or not it provides Eversource with the use of a specifically identified asset for a period of time, as well as both the right to direct the use of that asset and receive the significant economic benefits of the asset. Eversource has elected the practical expedient to not separate non-lease components from lease components and instead to account for both as a single lease component, with the exception of the information technology asset class where the lease and non-lease components are separated.

The provisions of Eversource, CL&P, NSTAR Electric and PSNH lease agreements contain renewal options. The renewal options range from one year to twenty years. The renewal period is included in the measurement of the lease liability if it is reasonably certain that Eversource will exercise these renewal options.

For leases entered into or modified after the January 1, 2019 implementation date of the leases standard under Topic 842, the discount rate utilized for classification and measurement purposes as of the inception date of the lease is based on each company's collateralized incremental interest rate to borrow over a comparable term for an individual lease because the rate implicit in the lease is not determinable.

CL&P and PSNH entered into certain contracts for the purchase of energy that qualify as leases. These contracts do not have minimum lease payments and therefore are not recognized as a lease liability on the balance sheet and are not reflected in the future minimum lease payments table below. Expense related to these contracts is included as variable lease cost in the table below. The expense and long-term obligation for these contracts are also included in Note 13B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the financial statements.

The components of lease cost, prior to amounts capitalized, are as follows:

<table><tr><td rowspan="2">Eversource (Millions of Dollars)</td><td colspan="5">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td><td></td></tr><tr><td>Finance Lease Cost:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of Right-of-use-Assets</td><td>$ 8.3</td><td>$ 4.6</td><td>$ 2.6</td><td></td><td></td></tr><tr><td>Interest on Lease Liabilities</td><td>2.0</td><td>3.9</td><td>1.4</td><td></td><td></td></tr><tr><td>Total Finance Lease Cost</td><td>10.3</td><td>8.5</td><td>4.0</td><td></td><td></td></tr><tr><td>Operating Lease Cost</td><td>11.6</td><td>12.2</td><td>11.1</td><td></td><td></td></tr><tr><td>Variable Lease Cost</td><td>78.1</td><td>61.0</td><td>57.8</td><td></td><td></td></tr><tr><td>Total Lease Cost</td><td>$ 100.0</td><td>$ 81.7</td><td>$ 72.9</td><td></td><td></td></tr></table>

For the Years Ended December 31,

<table><tr><td rowspan="2"></td><td colspan="5">2022</td><td colspan="5">2021</td><td colspan="5">2020</td></tr><tr><td colspan="2">CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td colspan="2">NSTAR Electric</td><td>PSNH</td><td>CL&amp;P</td><td colspan="2" rowspan="2">NSTAR Electric</td><td colspan="2">PSNH</td><td></td></tr><tr><td>(Millions of Dollars)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Finance Lease Cost:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of Right-of-use-Assets</td><td>$</td><td>—</td><td>0.2</td><td>$</td><td>0.1</td><td>$</td><td>0.5</td><td>$</td><td>0.2</td><td>$</td><td>0.1</td><td>$</td><td>0.7</td><td>$</td><td>0.2</td></tr><tr><td>Interest on Lease Liabilities</td><td></td><td>—</td><td>0.6</td><td></td><td>—</td><td></td><td>0.1</td><td></td><td>0.6</td><td></td><td>—</td><td></td><td>0.3</td><td></td><td>0.6</td></tr><tr><td>Total Finance Lease Cost</td><td></td><td>—</td><td>0.8</td><td></td><td>0.1</td><td></td><td>0.6</td><td></td><td>0.8</td><td></td><td>0.1</td><td></td><td>1.0</td><td></td><td>0.8</td></tr><tr><td>Operating Lease Cost</td><td></td><td>0.3</td><td>2.3</td><td></td><td>0.1</td><td></td><td>0.3</td><td></td><td>2.3</td><td></td><td>0.1</td><td></td><td>0.6</td><td></td><td>2.1</td></tr><tr><td>Variable Lease Cost</td><td></td><td>25.6</td><td></td><td>—</td><td></td><td>52.5</td><td></td><td>16.2</td><td></td><td>—</td><td></td><td>44.8</td><td></td><td>12.2</td><td></td></tr><tr><td>Total Lease Cost</td><td>$</td><td>25.9</td><td>$</td><td>3.1</td><td>$</td><td>52.7</td><td>$</td><td>17.1</td><td>$</td><td>3.1</td><td>$</td><td>45.0</td><td>$</td><td>13.8</td><td>$</td></tr></table>



Operating lease cost, net of the capitalized portion, is included in Operations and Maintenance (or Purchased Power, Purchased Natural Gas and Transmission expense for transmission leases) on the statements of income. Amortization of finance lease assets is included in Depreciation on the statements of income. Interest expense on finance leases is included in Interest Expense on the statements of income.

Supplemental balance sheet information related to leases is as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td rowspan="2">Balance Sheet Classification</td><td colspan="5">As of December 31, 2022</td><td colspan="5">As of December 31, 2021</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PS NH</td><td></td><td></td></tr><tr><td>Operating Leases:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets, Net</td><td>Other Long-Term Assets</td><td>$ 56.9</td><td>$ 2.2</td><td>$ 22.5</td><td>$ —</td><td>$ 47.2</td><td>$ 0.1</td><td>$ 24.3</td><td>$ 0.3</td><td></td><td></td></tr><tr><td>Operating Lease Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current Portion</td><td>Other Current Liabilities</td><td>$ 9.0</td><td>$ 0.6</td><td>$ 1.2</td><td>$ —</td><td>$ 10.0</td><td>$ 0.1</td><td>$ 1.1</td><td>$ —</td><td></td><td></td></tr><tr><td>Long-Term</td><td>Other Long-Term Liabilities</td><td>47.9</td><td>1.6</td><td>21.3</td><td>—</td><td>37.2</td><td>—</td><td>23.2</td><td>0.3</td><td></td><td></td></tr><tr><td>Total Operating Lease Liabilities</td><td></td><td>$ 56.9</td><td>$ 2.2</td><td>$ 22.5</td><td>$ —</td><td>$ 47.2</td><td>$ 0.1</td><td>$ 24.3</td><td>$ 0.3</td><td></td><td></td></tr><tr><td>Finance Leases:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets, Net</td><td>Property, Plant and Equipment, Net</td><td>$ 54.5</td><td>$ —</td><td>$ 3.2</td><td>$ —</td><td>$ 58.0</td><td>$ —</td><td>$ 3.3</td><td>$ 0.7</td><td></td><td></td></tr><tr><td>Finance Lease Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current Portion</td><td>Other Current Liabilities</td><td>$ 3.8</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 3.9</td><td>$ —</td><td>$ —</td><td>$ 0.1</td><td></td><td></td></tr><tr><td>Long-Term</td><td>Other Long-Term Liabilities</td><td>54.2</td><td>—</td><td>4.9</td><td>—</td><td>55.4</td><td>—</td><td>4.9</td><td>0.6</td><td></td><td></td></tr><tr><td>Total Finance Lease Liabilities</td><td></td><td>$ 58.0</td><td>$ —</td><td>$ 4.9</td><td>$ —</td><td>$ 59.3</td><td>$ —</td><td>$ 4.9</td><td>$ 0.7</td><td></td><td></td></tr></table>

The finance lease payments that NSTAR Electric will make over the next twelve months are entirely interest-related, due to escalating payments. As such, none of the finance lease payments over the next twelve months will reduce the finance lease liability.

Other information related to leases is as follows:

<table><tr><td rowspan="3"></td><td colspan="10">As of December 31,</td></tr><tr><td colspan="5">2022</td><td colspan="5">2021</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PS NH</td><td></td><td></td></tr><tr><td>Weighted-Average Remaining Lease Term (Years):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Leases</td><td>11</td><td>4</td><td>17</td><td>—</td><td>13</td><td>7</td><td>18</td><td>7</td><td></td><td></td></tr><tr><td>Finance Leases</td><td>15</td><td>—</td><td>19</td><td>—</td><td>16</td><td>—</td><td>20</td><td>7</td><td></td><td></td></tr><tr><td>Weighted-Average Discount Rate (Percentage):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Leases</td><td>3.2 %</td><td>3.8 %</td><td>4.0 %</td><td>— %</td><td>4.1 %</td><td>3.0 %</td><td>4.0 %</td><td>3.7 %</td><td></td><td></td></tr><tr><td>Finance Leases</td><td>2.7 %</td><td>— %</td><td>2.9 %</td><td>— %</td><td>2.7 %</td><td>— %</td><td>2.9 %</td><td>3.5 %</td><td></td><td></td></tr><tr><td>(Millions of Dollars)</td><td></td><td></td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td></td><td></td><td></td><td></td></tr><tr><td>For the Year Ended December 31, 2022</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash Paid for Amounts Included in the Measurement of Lease Liabilities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Cash Flows from Operating Leases</td><td></td><td>$ 11.3</td><td>$ 0.3</td><td>$ 2.1</td><td>$ 0.1</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Cash Flows from Finance Leases</td><td></td><td>2.0</td><td>—</td><td>0.6</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Financing Cash Flows from Finance Leases</td><td></td><td>3.9</td><td>—</td><td>—</td><td>0.1</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Supplemental Non-Cash Information on Lease Liabilities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities</td><td></td><td>18.9</td><td>2.4</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities</td><td></td><td>3.5</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>(Millions of Dollars)</td><td></td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>For the Year Ended December 31, 2021</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash Paid for Amounts Included in the Measurement of Lease Liabilities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Cash Flows from Operating Leases</td><td></td><td>$ 12.1</td><td>$ 0.3</td><td>$ 2.1</td><td>$ 0.1</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Cash Flows from Finance Leases</td><td></td><td>3.4</td><td>0.1</td><td>0.6</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Financing Cash Flows from Finance Leases</td><td></td><td>4.1</td><td>1.4</td><td>—</td><td>0.1</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Supplemental Non-Cash Information on Lease Liabilities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities</td><td></td><td>2.1</td><td>—</td><td>1.9</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities</td><td></td><td>2.3</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr></table>



<table><tr><td>(Millions of Dollars)</td><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>PSNH</td></tr><tr><td>For the Year Ended December 31, 2020</td><td></td><td></td><td></td><td></td></tr><tr><td>Cash Paid for Amounts Included in the Measurement of Lease Liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Cash Flows from Operating Leases</td><td>$ 10.9</td><td>$ 0.6</td><td>$ 1.8</td><td>$ 0.1</td></tr><tr><td>Operating Cash Flows from Finance Leases</td><td>1.7</td><td>0.3</td><td>0.6</td><td>—</td></tr><tr><td>Financing Cash Flows from Finance Leases</td><td>2.8</td><td>1.6</td><td>—</td><td>0.1</td></tr><tr><td>Supplemental Non-Cash Information on Lease Liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities</td><td>0.6</td><td>0.1</td><td>0.2</td><td>—</td></tr><tr><td>Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities</td><td>0.7</td><td>—</td><td>0.3</td><td>—</td></tr></table>

In 2020, Eversource also acquired $14.7 million of right-of-use assets in exchange for the assumption of new operating lease liabilities and $54.2 million of right-of-use assets in exchange for the assumption of new finance lease liabilities as a result of the CMA asset acquisition.

Future minimum lease payments, excluding variable costs, under long-term leases, as of December 31, 2022 are as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="4">Operating Leases</td><td colspan="4">Finance Leases</td></tr><tr><td>Eversource</td><td>CL&amp;P</td><td>NSTAR Electric</td><td>Eversource</td><td>NSTAR Electric</td><td></td><td></td><td></td></tr><tr><td>Year Ending December 31,</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2023</td><td>$ 10.3</td><td>$ 0.7</td><td>$ 2.1</td><td>$ 5.9</td><td>$ 0.6</td><td></td><td></td><td></td></tr><tr><td>2024</td><td>9.3</td><td>0.7</td><td>2.1</td><td>5.9</td><td>0.6</td><td></td><td></td><td></td></tr><tr><td>2025</td><td>6.4</td><td>0.7</td><td>1.7</td><td>5.9</td><td>0.6</td><td></td><td></td><td></td></tr><tr><td>2026</td><td>5.5</td><td>0.3</td><td>1.7</td><td>5.4</td><td>0.7</td><td></td><td></td><td></td></tr><tr><td>2027</td><td>5.2</td><td>—</td><td>1.7</td><td>5.4</td><td>0.7</td><td></td><td></td><td></td></tr><tr><td>Thereafter</td><td>31.2</td><td>—</td><td>23.6</td><td>50.9</td><td>11.8</td><td></td><td></td><td></td></tr><tr><td>Future lease payments</td><td>67.9</td><td>2.4</td><td>32.9</td><td>79.4</td><td>15.0</td><td></td><td></td><td></td></tr><tr><td>Less amount representing interest</td><td>11.0</td><td>0.2</td><td>10.4</td><td>21.4</td><td>10.1</td><td></td><td></td><td></td></tr><tr><td>Present value of future minimum lease payments</td><td>$ 56.9</td><td>$ 2.2</td><td>$ 22.5</td><td>$ 58.0</td><td>$ 4.9</td><td></td><td></td><td></td></tr></table>

## 15. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of long-term debt and RRB debt securities is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. The fair values provided in the table below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:

<table><tr><td rowspan="2">(Millions of Dollars)</td><td colspan="3">Eversource</td><td colspan="3">CL&amp;P</td><td colspan="3">NSTAR Electric</td><td colspan="3">PSNH</td></tr><tr><td>Carrying Amount</td><td>Fair Value</td><td>Carrying Amount</td><td>Fair Value</td><td>Carrying Amount</td><td>Fair Value</td><td></td><td>Carrying Amount</td><td>Fair Value</td><td></td><td>Carrying Amount</td><td>Fair value</td></tr><tr><td>As of December 31, 2022:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred Stock Not Subject to Mandatory Redemption</td><td>$ 155.6</td><td>$ 136.7</td><td>$ 116.2</td><td>$ 99.2</td><td>$ 43.0</td><td>$ 37.5</td><td>$</td><td>—</td><td>$</td><td>—</td><td></td><td></td></tr><tr><td>Long-Term Debt</td><td>21,044.1</td><td>18,891.3</td><td>4,216.5</td><td>3,828.3</td><td>4,425.1</td><td>4,091.8</td><td>1,164.6</td><td>970.5</td><td></td><td></td><td></td><td></td></tr><tr><td>Rate Reduction Bonds</td><td>453.7</td><td>424.7</td><td>—</td><td>—</td><td>—</td><td>—</td><td>453.7</td><td>424.7</td><td></td><td></td><td></td><td></td></tr><tr><td>As of December 31, 2021:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Preferred Stock Not Subject to Mandatory Redemption</td><td>$ 155.6</td><td>$ 166.3</td><td>$ 116.2</td><td>$ 122.3</td><td>$ 43.0</td><td>$ 44.0</td><td>$</td><td>—</td><td>$</td><td>—</td><td></td><td></td></tr><tr><td>Long-Term Debt</td><td>18,216.7</td><td>19,636.3</td><td>4,215.4</td><td>4,848.9</td><td>3,985.4</td><td>4,453.5</td><td>1,163.8</td><td>1,220.6</td><td></td><td></td><td></td><td></td></tr><tr><td>Rate Reduction Bonds</td><td>496.9</td><td>543.3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>496.9</td><td>543.3</td><td></td><td></td><td></td><td></td></tr></table>

Derivative Instruments and Marketable Securities: Derivative instruments and investments in marketable securities are carried at fair value. For further information, see Note 4, "Derivative Instruments," and Note 5, "Marketable Securities," to the financial statements.

See Note 1G, "Summary of Significant Accounting Policies – Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.



## 16. ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The changes in accumulated other comprehensive income/(loss) by component, net of tax, are as follows:

<table><tr><td rowspan="2"></td><td colspan="6">For the Year Ended December 31, 2022</td><td colspan="6">For the Year Ended December 31, 2021</td></tr><tr><td>Qualified Cash Flow Hedging Instruments</td><td>Unrealized Gains/(Losses) on Marketable Securities</td><td>Defined Benefit Plans</td><td>Total</td><td>Qualified Cash Flow Hedging Instruments</td><td>Unrealized Gains/(Losses) on Marketable Securities</td><td>Defined Benefit Plans</td><td>Total</td><td></td><td></td><td></td></tr><tr><td>Balance as of January 1st</td><td>$ (0.4)</td><td>$ 0.4</td><td>$ (42.3)</td><td>$ (42.3)</td><td>$ (1.4)</td><td>$ 1.1</td><td>$ (76.1)</td><td>$ (76.4)</td><td></td><td></td><td></td></tr><tr><td>OCI Before Reclassifications</td><td>—</td><td>(1.6)</td><td>(2.5)</td><td>(4.1)</td><td>—</td><td>(0.7)</td><td>24.1</td><td>23.4</td><td></td><td></td><td></td></tr><tr><td>Amounts Reclassified from AOCI</td><td>—</td><td>—</td><td>7.0</td><td>7.0</td><td>1.0</td><td>—</td><td>9.7</td><td>10.7</td><td></td><td></td><td></td></tr><tr><td>Net OCI</td><td>—</td><td>(1.6)</td><td>4.5</td><td>2.9</td><td>1.0</td><td>(0.7)</td><td>33.8</td><td>34.1</td><td></td><td></td><td></td></tr><tr><td>Balance as of December 31st</td><td>$ (0.4)</td><td>$ (1.2)</td><td>$ (37.8)</td><td>$ (39.4)</td><td>$ (0.4)</td><td>$ 0.4</td><td>$ (42.3)</td><td>$ (42.3)</td><td></td><td></td><td></td></tr></table>

Defined benefit plan OCI amounts before reclassifications relate to actuarial gains and losses that arose during the year and were recognized in AOCI. The unamortized actuarial gains and losses and prior service costs on the defined benefit plans are amortized from AOCI into Other Income, Net over the average future employee service period, and are reflected in amounts reclassified from AOCI. The related tax effects of the defined benefit plan OCI amounts before reclassifications recognized in AOCI were net deferred tax assets of $1.3 million and $6.0 million in 2022 and 2020, respectively and were net deferred tax liabilities of $8.3 million in 2021.

The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income:

<table><tr><td rowspan="3">Eversource (Millions of Dollars)</td><td colspan="4">Amounts Reclassified from AOCI</td><td rowspan="3">Statements of Income Line Item Impacted</td></tr><tr><td colspan="2">For the Years Ended December 31,</td><td rowspan="2">2020</td><td rowspan="2"></td></tr><tr><td>2022</td><td>2021</td></tr><tr><td>Qualified Cash Flow Hedging Instruments</td><td>$ —</td><td>$ (1.7)</td><td>$ (2.5)</td><td>Interest Expense</td><td></td></tr><tr><td>Tax Effect</td><td>—</td><td>0.7</td><td>0.9</td><td>Income Tax Expense</td><td></td></tr><tr><td>Qualified Cash Flow Hedging Instruments, Net of Tax</td><td>$ —</td><td>$ (1.0)</td><td>$ (1.6)</td><td></td><td></td></tr><tr><td>Defined Benefit Plan Costs:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of Actuarial Losses</td><td>$ (9.0)</td><td>$ (13.1)</td><td>$ (8.1)</td><td>Other Income, Net (1)</td><td></td></tr><tr><td>Amortization of Prior Service Cost</td><td>(0.3)</td><td>—</td><td>(0.3)</td><td>Other Income, Net (1)</td><td></td></tr><tr><td>Total Defined Benefit Plan Costs</td><td>(9.3)</td><td>(13.1)</td><td>(8.4)</td><td></td><td></td></tr><tr><td>Tax Effect</td><td>2.3</td><td>3.4</td><td>2.1</td><td>Income Tax Expense</td><td></td></tr><tr><td>Defined Benefit Plan Costs, Net of Tax</td><td>$ (7.0)</td><td>$ (9.7)</td><td>$ (6.3)</td><td></td><td></td></tr><tr><td>Total Amounts Reclassified from AOCI, Net of Tax</td><td>$ (7.0)</td><td>$ (10.7)</td><td>$ (7.9)</td><td></td><td></td></tr></table>

(1) These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 1K, "Summary of Significant Accounting Policies – Other Income, Net" and Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for further information.

## 17. DIVIDEND RESTRICTIONS

Eversource parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total indebtedness to total capitalization ratio requirement in its revolving credit agreements. Pursuant to the joint revolving credit agreement of Eversource, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut, and to the NSTAR Electric revolving credit agreement, each company is required to maintain consolidated total indebtedness to total capitalization ratio of no greater than 65 percent at the end of each fiscal quarter. As of December 31, 2022, all companies were in compliance with such covenant and in compliance with all such provisions of the revolving credit agreements that may restrict the payment of dividends as of December 31, 2022.

The Retained Earnings balances subject to dividend restrictions were $5.53 billion for Eversource, $2.46 billion for CL&P, $2.92 billion for NSTAR Electric and $572.1 million for PSNH as of December 31, 2022.

CL&P, NSTAR Electric and PSNH are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric and PSNH, would not be construed or applied by the FERC to prohibit the payment of dividends from retained earnings for lawful and legitimate business purposes. In addition, certain state statutes may impose additional limitations on such companies and, including but not limited to, on NSTAR Gas, Yankee Gas, EGMA, Aquarion Water Company of Connecticut, Aquarion Water Company of Massachusetts and Aquarion Water Company of New Hampshire. Such state law restrictions do not restrict the payment of dividends from retained earnings or net income.



## 18. COMMON SHARES

The following table sets forth the Eversource parent common shares and the shares of common stock of CL&P, NSTAR Electric and PSNH that were authorized and issued, as well as the respective per share par values:

<table><tr><td rowspan="2"></td><td colspan="4">Shares</td></tr><tr><td colspan="2">Authorized as of December 31, 2022 and 2021</td><td colspan="2">Issued as of December 31,</td></tr><tr><td>Par Value</td><td></td><td>2022</td><td>2021</td><td></td></tr><tr><td>Eversource</td><td>$ 5</td><td>380,000,000</td><td>359,984,073</td><td>357,818,402</td></tr><tr><td>CL&amp;P</td><td>$ 10</td><td>24,500,000</td><td>6,035,205</td><td>6,035,205</td></tr><tr><td>NSTAR Electric</td><td>$ 1</td><td>100,000,000</td><td>200</td><td>200</td></tr><tr><td>PSNH</td><td>$ 1</td><td>100,000,000</td><td>301</td><td>301</td></tr></table>

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. Eversource may issue and sell its common shares through its sales agents during the term of this agreement. Shares may be offered in transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise. Sales may be made at either market prices prevailing at the time of sale, at prices related to such prevailing market prices or at negotiated prices. 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.

Treasury Shares: As of December 31, 2022 and 2021, there were 11,540,218 and 13,415,206 Eversource common shares held as treasury shares, respectively. As of December 31, 2022 and 2021, there were 348,443,855 and 344,403,196 Eversource common shares outstanding, respectively.

Acquisition of The Torrington Water Company: On October 3, 2022, Aquarion acquired The Torrington Water Company (TWC) following the receipt of all required approvals. The acquisition was structured as a stock-for-stock exchange, and Eversource issued 925,264 treasury shares at closing for a purchase price of $72.1 million.

Acquisition of New England Service Company: On December 1, 2021, Aquarion acquired New England Service Company (NESC), pursuant to a definitive agreement entered into on April 8, 2021. The acquisition was structured as a stock-for-stock merger and Eversource issued 462,517 treasury shares at closing for a purchase price of $38.1 million.

Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan. Eversource also issued treasury shares for its December 2021 and October 2022 water business acquisitions. The issuance of treasury shares represents a non-cash transaction, as the treasury shares were used to fulfill Eversource's obligations that require the issuance of common shares.

## 19. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION

The CL&P and NSTAR Electric preferred stock is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in Eversource's financial statements.

CL&P is authorized to issue up to 9,000,000 shares of preferred stock, par value $50 per share, and NSTAR Electric is authorized to issue 2,890,000 shares of preferred stock, par value $100 per share. Holders of preferred stock of CL&P and NSTAR Electric are entitled to receive cumulative dividends in preference to any payment of dividends on the common stock. Upon liquidation, holders of preferred stock of CL&P and NSTAR Electric are entitled to receive a liquidation preference before any distribution to holders of common stock in an amount equal to the par value of the preferred stock plus accrued and unpaid dividends. If the net assets were to be insufficient to pay the liquidation preference in full, then the net assets would be distributed ratably to all holders of preferred stock. The preferred stock of CL&P and NSTAR Electric is subject to optional redemption by the CL&P and NSTAR Electric Boards of Directors at any time.



Details of preferred stock not subject to mandatory redemption are as follows (in millions, except in redemption price and shares):

<table><tr><td rowspan="2">Series</td><td rowspan="2"></td><td rowspan="2">Redemption Price Per Share</td><td colspan="3">Shares Outstanding as of December 31,</td><td colspan="3">As of December 31,</td></tr><tr><td>2022</td><td>2021</td><td></td><td>2022</td><td>2021</td><td></td></tr><tr><td>CL&amp;P</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>$1.90</td><td>Series of 1947</td><td>$</td><td>52.50</td><td>163,912</td><td>163,912</td><td>$</td><td>8.2</td><td>$</td></tr><tr><td>$2.00</td><td>Series of 1947</td><td>$</td><td>54.00</td><td>336,088</td><td>336,088</td><td></td><td>16.8</td><td>16.8</td></tr><tr><td>$2.04</td><td>Series of 1949</td><td>$</td><td>52.00</td><td>100,000</td><td>100,000</td><td></td><td>5.0</td><td>5.0</td></tr><tr><td>$2.20</td><td>Series of 1949</td><td>$</td><td>52.50</td><td>200,000</td><td>200,000</td><td></td><td>10.0</td><td>10.0</td></tr><tr><td>3.90%</td><td>Series of 1949</td><td>$</td><td>50.50</td><td>160,000</td><td>160,000</td><td></td><td>8.0</td><td>8.0</td></tr><tr><td>$2.06</td><td>Series E of 1954</td><td>$</td><td>51.00</td><td>200,000</td><td>200,000</td><td></td><td>10.0</td><td>10.0</td></tr><tr><td>$2.09</td><td>Series F of 1955</td><td>$</td><td>51.00</td><td>100,000</td><td>100,000</td><td></td><td>5.0</td><td>5.0</td></tr><tr><td>4.50%</td><td>Series of 1956</td><td>$</td><td>50.75</td><td>104,000</td><td>104,000</td><td></td><td>5.2</td><td>5.2</td></tr><tr><td>4.96%</td><td>Series of 1958</td><td>$</td><td>50.50</td><td>100,000</td><td>100,000</td><td></td><td>5.0</td><td>5.0</td></tr><tr><td>4.50%</td><td>Series of 1963</td><td>$</td><td>50.50</td><td>160,000</td><td>160,000</td><td></td><td>8.0</td><td>8.0</td></tr><tr><td>5.28%</td><td>Series of 1967</td><td>$</td><td>51.43</td><td>200,000</td><td>200,000</td><td></td><td>10.0</td><td>10.0</td></tr><tr><td>$3.24</td><td>Series G of 1968</td><td>$</td><td>51.84</td><td>300,000</td><td>300,000</td><td></td><td>15.0</td><td>15.0</td></tr><tr><td>6.56%</td><td>Series of 1968</td><td>$</td><td>51.44</td><td>200,000</td><td>200,000</td><td></td><td>10.0</td><td>10.0</td></tr><tr><td>Total CL&amp;P</td><td></td><td></td><td></td><td>2,324,000</td><td>2,324,000</td><td>$</td><td>116.2</td><td>$</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>NSTAR Electric</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>4.25%</td><td>Series of 1956</td><td>$</td><td>103.625</td><td>180,000</td><td>180,000</td><td>$</td><td>18.0</td><td>$</td></tr><tr><td>4.78%</td><td>Series of 1958</td><td>$</td><td>102.80</td><td>250,000</td><td>250,000</td><td></td><td>25.0</td><td>25.0</td></tr><tr><td>Total NSTAR Electric</td><td></td><td></td><td></td><td>430,000</td><td>430,000</td><td>$</td><td>43.0</td><td>$</td></tr><tr><td>Fair Value Adjustment due to Merger with NSTAR</td><td></td><td></td><td></td><td></td><td></td><td></td><td>(3.6)</td><td>(3.6)</td></tr><tr><td>Other</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>6.00%</td><td>Series of 1958</td><td>$</td><td>100.00</td><td>23</td><td>23</td><td>$</td><td>—</td><td>$</td></tr><tr><td colspan="5">Total Eversource - Noncontrolling Interest - Preferred Stock of Subsidiaries</td><td>$</td><td>155.6</td><td>$</td><td>155.6</td></tr></table>

## 20. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

Dividends on the preferred stock of CL&P and NSTAR Electric totaled $7.5 million for each of the years ended December 31, 2022, 2021 and 2020. These dividends were presented as Net Income Attributable to Noncontrolling Interests on the Eversource statements of income. Noncontrolling Interest – Preferred Stock of Subsidiaries on the Eversource balance sheets totaled $155.6 million as of December 31, 2022 and 2021. On the Eversource balance sheets, Common Shareholders' Equity was fully attributable to Eversource parent and Noncontrolling Interest – Preferred Stock of Subsidiaries was fully attributable to the noncontrolling interest.

For the years ended December 31, 2022, 2021 and 2020, there was no change in ownership of the common equity of CL&P and NSTAR Electric.

## 21. EARNINGS PER SHARE

Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards and the equity forward sale agreement, as if they were converted into outstanding common shares. The dilutive effect of unvested RSU and performance share awards, as well as the equity forward sale agreement, is calculated using the treasury stock method. RSU and performance share awards are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied.

Earnings per share dilution related to the equity forward sale agreement was determined under the treasury stock method until settlement of the forward sale agreement. Under this method, the number of Eversource common shares used in calculating diluted EPS was deemed to be increased by the excess, if any, of the number of shares that would be issued upon physical settlement of the forward sale agreement less the number of shares that would be purchased by Eversource in the market (based on the average market price during the same reporting period) using the proceeds receivable upon settlement (based on the adjusted forward sale price at the end of that reporting period). Share dilution occurred when the average market price of Eversource's common shares was higher than the adjusted forward sale price. Eversource physically settled all remaining shares under the forward sale agreement as of March 26, 2020.

For the years ended December 31, 2022 and 2021, there were no antidilutive share awards excluded from the computation. For the year ended December 31, 2020, 39,560 antidilutive share awards were excluded from the EPS computation, as their impact would have been antidilutive. Antidilutive shares pertained to a purchase option extended to underwriters in connection with Eversource's June 2020 common share issuance.



The following table sets forth the components of basic and diluted EPS:

<table><tr><td rowspan="2">Eversource(Millions of Dollars, except share information)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2022</td><td>2021</td><td>2020</td><td></td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 1,404.9</td><td>$ 1,220.5</td><td>$ 1,205.2</td><td></td></tr><tr><td>Weighted Average Common Shares Outstanding:</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>346,783,444</td><td>343,972,926</td><td>338,836,147</td><td></td></tr><tr><td>Dilutive Effect of:</td><td></td><td></td><td></td><td></td></tr><tr><td>Share-Based Compensation Awards and Other</td><td>463,324</td><td>658,130</td><td>738,994</td><td></td></tr><tr><td>Equity Forward Sale Agreement</td><td>—</td><td>—</td><td>271,921</td><td></td></tr><tr><td>Total Dilutive Effect</td><td>463,324</td><td>658,130</td><td>1,010,915</td><td></td></tr><tr><td>Diluted</td><td>347,246,768</td><td>344,631,056</td><td>339,847,062</td><td></td></tr><tr><td>Basic EPS</td><td>$ 4.05</td><td>$ 3.55</td><td>$ 3.56</td><td></td></tr><tr><td>Diluted EPS</td><td>$ 4.05</td><td>$ 3.54</td><td>$ 3.55</td><td></td></tr></table>

## 22. REVENUES

Revenue is recognized when promised goods or services (referred to as performance obligations) are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. A five-step model is used for recognizing and measuring revenue from contracts with customers, which includes identifying the contract with the customer, identifying the performance obligations promised within the contract, determining the transaction price (the amount of consideration to which the company expects to be entitled), allocating the transaction price to the performance obligations and recognizing revenue when (or as) the performance obligation is satisfied.

The following tables present operating revenues disaggregated by revenue source:

<table><tr><td rowspan="2">Eversource(Millions of Dollars)</td><td colspan="8">For the Year Ended December 31, 2022</td></tr><tr><td>Electric Distribution</td><td>Natural Gas Distribution</td><td>Electric Transmission</td><td>Water Distribution</td><td>Other</td><td>Eliminations</td><td>Total</td><td></td></tr><tr><td>Revenues from Contracts with Customers</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Retail Tariff Sales</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 4,796.1</td><td>$ 1,204.9</td><td>$ —</td><td>$ 141.7</td><td>$ —</td><td>$ —</td><td>$ 6,142.7</td><td></td></tr><tr><td>Commercial</td><td>2,903.3</td><td>648.5</td><td>—</td><td>66.5</td><td>—</td><td>(4.1)</td><td>3,614.2</td><td></td></tr><tr><td>Industrial</td><td>374.9</td><td>199.7</td><td>—</td><td>4.7</td><td>—</td><td>(20.1)</td><td>559.2</td><td></td></tr><tr><td>Total Retail Tariff Sales Revenues</td><td>8,074.3</td><td>2,053.1</td><td>—</td><td>212.9</td><td>—</td><td>(24.2)</td><td>10,316.1</td><td></td></tr><tr><td>Wholesale Transmission Revenues</td><td>—</td><td>—</td><td>1,700.5</td><td>—</td><td>—</td><td>(1,264.5)</td><td>436.0</td><td></td></tr><tr><td>Wholesale Market Sales Revenues</td><td>1,190.9</td><td>140.8</td><td>—</td><td>3.8</td><td>—</td><td>—</td><td>1,335.5</td><td></td></tr><tr><td>Other Revenues from Contracts with Customers</td><td>72.3</td><td>5.6</td><td>14.1</td><td>8.4</td><td>1,435.5</td><td>(1,425.3)</td><td>110.6</td><td></td></tr><tr><td>Amortization of/(Reserve for) Revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Subject to Refund</td><td>72.0</td><td>—</td><td>0.7</td><td>(0.7)</td><td>—</td><td>—</td><td>72.0</td><td></td></tr><tr><td>Total Revenues from Contracts with Customers</td><td>9,409.5</td><td>2,199.5</td><td>1,715.3</td><td>224.4</td><td>1,435.5</td><td>(2,714.0)</td><td>12,270.2</td><td></td></tr><tr><td>Alternative Revenue Programs</td><td>(15.4)</td><td>14.8</td><td>92.7</td><td>(2.5)</td><td>—</td><td>(84.3)</td><td>5.3</td><td></td></tr><tr><td>Other Revenues</td><td>11.2</td><td>1.3</td><td>0.7</td><td>0.6</td><td>—</td><td>—</td><td>13.8</td><td></td></tr><tr><td>Total Operating Revenues</td><td>$ 9,405.3</td><td>$ 2,215.6</td><td>$ 1,808.7</td><td>$ 222.5</td><td>$ 1,435.5</td><td>$ (2,798.3)</td><td>$ 12,289.3</td><td></td></tr></table>

<table><tr><td rowspan="2">Eversource(Millions of Dollars)</td><td colspan="8">For the Year Ended December 31, 2021</td></tr><tr><td>Electric Distribution</td><td>Natural Gas Distribution</td><td>Electric Transmission</td><td>Water Distribution</td><td>Other</td><td>Eliminations</td><td>Total</td><td></td></tr><tr><td>Revenues from Contracts with Customers</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Retail Tariff Sales</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 3,989.8</td><td>$ 1,000.3</td><td>$ —</td><td>$ 133.5</td><td>$ —</td><td>$ —</td><td>$ 5,123.6</td><td></td></tr><tr><td>Commercial</td><td>2,486.1</td><td>497.6</td><td>—</td><td>62.8</td><td>—</td><td>(5.1)</td><td>3,041.4</td><td></td></tr><tr><td>Industrial</td><td>345.3</td><td>167.2</td><td>—</td><td>4.3</td><td>—</td><td>(17.1)</td><td>499.7</td><td></td></tr><tr><td>Total Retail Tariff Sales Revenues</td><td>6,821.2</td><td>1,665.1</td><td>—</td><td>200.6</td><td>—</td><td>(22.2)</td><td>8,664.7</td><td></td></tr><tr><td>Wholesale Transmission Revenues</td><td>—</td><td>—</td><td>1,751.3</td><td>—</td><td>86.6</td><td>(1,384.7)</td><td>453.2</td><td></td></tr><tr><td>Wholesale Market Sales Revenues</td><td>575.8</td><td>82.1</td><td>—</td><td>3.9</td><td>—</td><td>—</td><td>661.8</td><td></td></tr><tr><td>Other Revenues from Contracts with Customers</td><td>78.1</td><td>5.1</td><td>13.6</td><td>7.5</td><td>1,267.4</td><td>(1,257.7)</td><td>114.0</td><td></td></tr><tr><td>Reserve for Revenues Subject to Refund</td><td>(71.1)</td><td>—</td><td>(5.0)</td><td>(2.6)</td><td>—</td><td>—</td><td>(78.7)</td><td></td></tr><tr><td>Total Revenues from Contracts with Customers</td><td>7,404.0</td><td>1,752.3</td><td>1,759.9</td><td>209.4</td><td>1,354.0</td><td>(2,664.6)</td><td>9,815.0</td><td></td></tr><tr><td>Alternative Revenue Programs</td><td>14.7</td><td>37.0</td><td>(126.1)</td><td>1.5</td><td>—</td><td>114.6</td><td>41.7</td><td></td></tr><tr><td>Other Revenues</td><td>4.9</td><td>0.3</td><td>0.8</td><td>0.4</td><td>—</td><td>—</td><td>6.4</td><td></td></tr><tr><td>Total Operating Revenues</td><td>$ 7,423.6</td><td>$ 1,789.6</td><td>$ 1,634.6</td><td>$ 211.3</td><td>$ 1,354.0</td><td>$ (2,550.0)</td><td>$ 9,863.1</td><td></td></tr></table>



Customers may elect to purchase electricity from each Eversource electric utility or may contract separately with a competitive third party supplier. Revenue is not recorded for the sale of the electricity commodity to customers who have contracted separately with these suppliers, only the delivery to a customer, as the utility is acting as an agent on behalf of the third party supplier.

Wholesale Transmission Revenues: The Eversource electric transmission-owning companies (CL&P, NSTAR Electric and PSNH) each own and maintain transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. CL&P, NSTAR Electric and PSNH, as well as most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. The Eversource electric transmission-owning companies have a combination of FERC-approved regional and local formula rates that work in tandem to recover all their transmission costs. These rates are part of the ISO-NE Tariff. Regional rates recover the costs of higher voltage transmission facilities that benefit the region and are collected from all New England transmission customers, including the Eversource distribution businesses. Eversource's local rates recover the costs of transmission facilities that do not provide a benefit to the region, and are collected from Eversource's distribution businesses and other transmission customers. The distribution businesses of Eversource, in turn, recover the FERC approved charges from retail customers through annual tracking mechanisms, which are retail tariff sales.

The utility’s performance obligation for regulated wholesale transmission sales is to provide transmission services to the customer as demanded. The promise to provide transmission service represents a single performance obligation. The transaction prices are the transmission rate formulas as defined by the ISO-NE Tariff and are regulated and established by FERC. Wholesale transmission revenue is recognized over time as the performance obligation is completed, which occurs as transmission services are provided to customers. The revenue is recognized based on the output method. Each Eversource utility is entitled to be compensated for performance completed to date (e.g., use of the transmission system by the customer).

Wholesale Market Sales Revenues: Wholesale market sales transactions include sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third party marketers, and also the sale of RECs to various counterparties. ISO-NE oversees the region's wholesale electricity market and administers the transactions and terms and conditions, including payment terms, which are established in the ISO-NE tariff, between the buyers and sellers in the market. Pricing is set by the wholesale market. The wholesale transactions in the ISO-NE market occur on a day-ahead basis or a real-time basis (daily) and are, therefore, short-term. Transactions are tracked and reported by ISO-NE net by the hour, which is the net hourly position of energy sales and purchases by each market participant. The performance obligation for ISO-NE energy transactions is defined to be the net by hour transaction. Revenue is recognized when the performance obligation for these energy sales transactions is satisfied, which is when the sale occurs and the energy is transferred to the customer. For sales of natural gas, transportation, and natural gas pipeline capacity to third party marketers, revenue is recognized when the performance obligation is satisfied at the point in time the sale occurs and the natural gas or related product is transferred to the marketer. RECs are sold to various counterparties, and revenue is recognized when the performance obligation is satisfied upon transfer of title to the customer through the New England Power Pool Generation Information System. Wholesale transactions also include the sale of CL&P's, NSTAR Electric's and PSNH's transmission rights associated with their proportionate equity ownership share in the transmission lines of the Hydro-Quebec system in Canada.

Other Revenues from Contracts with Customers: Other revenues from contracts with customers primarily include property rentals that are not deemed leases. These revenues are generally recognized on a straight-line basis over time as the service is provided to the customer. Other revenues also include revenues from Eversource's service company, which is eliminated in consolidation.

Amortization of/(Reserve for) Revenues Subject to Refund: A reserve is recorded as a reduction to revenues when future refunds to customers are deemed probable. The reserve is reversed as refunds are provided to customers in rates. Amortization of Revenues Subject to Refund within the Electric Distribution segment in 2022 represents the reversal of a 2021 reserve at CL&P established to provide bill credits to customers as a result of the settlement agreement on October 1, 2021 and a storm performance penalty assessed by PURA. The reserve was reversed as customer credits were distributed to CL&P's customers in retail electric rates. Total customer credits as a result of the 2021 settlement and civil penalty of $93.4 million were recorded as a reserve for revenues subject to refund within current regulatory liabilities and reflected as a reduction to Operating Revenues on the 2021 income statement. The settlement amount of $65 million was refunded over a two-month billing period from December 1, 2021 to January 31, 2022 and the civil penalty of $28.4 million was refunded over a one year billing period, which began September 1, 2021.

The Connecticut water business continues to record a regulatory liability and reduction to revenues to reflect the difference between the 35 percent federal corporate income tax rate included in base distribution rates charged to customers and the 21 percent federal corporate income tax rate currently effective. This reserve will continue until base distribution rates are updated to reflect the lower federal tax rate.

Alternative Revenue Programs: In accordance with accounting guidance for rate-regulated operations, certain of Eversource's utilities' rate making mechanisms qualify as alternative revenue programs (ARPs) if they meet specified criteria, in which case revenues may be recognized prior to billing based on allowed levels of collection in rates. Eversource's utility companies recognize revenue and record a regulatory asset or liability once the condition or event allowing for the automatic adjustment of future rates occurs. ARP revenues include both the recognition of the deferral adjustment to ARP revenues, when the regulator-specified condition or event allowing for additional billing or refund has occurred, and an equal and offsetting reversal of the ARP deferral to revenues as those amounts are reflected in the price of service in subsequent periods.

Eversource’s ARPs include the revenue decoupling mechanism, the annual reconciliation adjustment to transmission formula rates, and certain capital tracker mechanisms. Certain Eversource electric, natural gas and water companies, including CL&P and NSTAR Electric, have revenue decoupling mechanisms approved by a regulatory commission (decoupled companies). Decoupled companies’ distribution revenues are not directly based on sales volumes. The decoupled companies reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues, with any difference between the allowed level of distribution revenue and the actual amount realized adjusted through subsequent rates. The transmission formula rates provide for the annual reconciliation and recovery or refund of



estimated costs to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission customers. This transmission deferral reconciles billed transmission revenues to the revenue requirement for our transmission businesses.

Other Revenues: Other Revenues include certain fees charged to customers that are not considered revenue from contracts with customers. Other revenues also include lease revenues under lessor accounting guidance of $4.0 million ($0.8 million at CL&P and $2.5 million at NSTAR Electric), $4.8 million ($0.8 million at CL&P and $3.1 million at NSTAR Electric), and $4.3 million, ($0.8 million at CL&P and $2.7 million at NSTAR Electric) for the years ended December 31, 2022, 2021 and 2020, respectively.

Intercompany Eliminations: Intercompany eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business, and revenues from Eversource's service company. Intercompany revenues and expenses between the Eversource wholesale transmission businesses and the Eversource distribution businesses and from Eversource's service company are eliminated in consolidation and included in "Eliminations" in the tables above.

Receivables: Receivables, Net on the balance sheet primarily includes trade receivables from retail customers and customers related to wholesale transmission contracts, wholesale market sales, sales of RECs, and property rentals. In general, retail tariff customers and wholesale transmission customers are billed monthly and the payment terms are generally due and payable upon receipt of the bill.

Unbilled Revenues: Unbilled Revenues on the balance sheet represent estimated amounts due from retail customers for electricity, natural gas or water delivered to customers but not yet billed. The utility company has satisfied its performance obligation and the customer has received and consumed the commodity as of the balance sheet date, and therefore, the utility company records revenue for those services in the period the services were provided. Only the passage of time is required before the company is entitled to payment for the satisfaction of the performance obligation. Payment from customers is due monthly as services are rendered and amounts are billed. Actual amounts billed to customers when meter readings become available may vary from the estimated amount.

Unbilled revenues are recognized by allocating estimated unbilled sales volumes to the respective customer classes, and then applying an estimated rate by customer class to those sales volumes. Unbilled revenue estimates reflect seasonality, weather, customer usage patterns, customer rates in effect for customer classes, and the timing of customer billing. The companies that have a decoupling mechanism record a regulatory deferral to reflect the actual allowed amount of revenue associated with their respective decoupled distribution rate design.

Practical Expedients: Eversource has elected practical expedients in the accounting guidance that allow the company to record revenue in the amount that the company has a right to invoice, if that amount corresponds directly with the value to the customer of the company's performance to date, and not to disclose related unsatisfied performance obligations. Retail and wholesale transmission tariff sales fall into this category, as these sales are recognized as revenue in the period the utility provides the service and completes the performance obligation, which is the same as the monthly amount billed to customers. There are no other material revenue streams for which Eversource has unsatisfied performance obligations.

## 23. SEGMENT INFORMATION

Eversource is organized into the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segment's services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These reportable segments represent substantially all of Eversource's total consolidated revenues. Revenues from the sale of electricity, natural gas and water primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution reportable segment includes the results of NSTAR Electric's solar power facilities. Eversource's reportable segments are determined based upon the level at which Eversource's chief operating decision maker assesses performance and makes decisions about the allocation of company resources.

The remainder of Eversource's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of Eversource parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of Eversource parent, 2) the revenues and expenses of Eversource Service, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, 4) the results of other unregulated subsidiaries, which are not part of its core business, and 5) Eversource parent's equity ownership interests that are not consolidated, which primarily include the offshore wind business, a natural gas pipeline owned by Enbridge, Inc., and a renewable energy investment fund.

In the ordinary course of business, Yankee Gas, NSTAR Gas and EGMA purchase natural gas transmission services from the Enbridge, Inc. natural gas pipeline project described above. These affiliate transaction costs total $77.7 million annually and are classified as Purchased Power, Purchased Natural Gas and Transmission on the Eversource statements of income.

Each of Eversource's subsidiaries, including CL&P, NSTAR Electric and PSNH, has one reportable segment.

Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP income/expense.



Eversource's segment information is as follows:

For the Year Ended December 31, 2022

<table><tr><td>Eversource
(Millions of Dollars)</td><td>Electric
Distribution</td><td>Natural Gas
Distribution</td><td>Electric
Transmission</td><td>Water
Distribution</td><td>Other</td><td>Eliminations</td><td>Total</td></tr><tr><td>Operating Revenues</td><td>$ 9,405.3</td><td>$ 2,215.6</td><td>$ 1,808.7</td><td>$ 222.5</td><td>$ 1,435.5</td><td>$ (2,798.3)</td><td>$ 12,289.3</td></tr><tr><td>Depreciation and Amortization</td><td>(970.4)</td><td>(157.6)</td><td>(337.4)</td><td>(50.9)</td><td>(132.6)</td><td>5.8</td><td>(1,643.1)</td></tr><tr><td>Other Operating Expenses</td><td>(7,663.7)</td><td>(1,727.0)</td><td>(548.4)</td><td>(111.8)</td><td>(1,189.1)</td><td>2,792.0</td><td>(8,448.0)</td></tr><tr><td>Operating Income</td><td>771.2</td><td>331.0</td><td>922.9</td><td>59.8</td><td>113.8</td><td>(0.5)</td><td>2,198.2</td></tr><tr><td>Interest Expense</td><td>(253.1)</td><td>(71.4)</td><td>(145.5)</td><td>(34.7)</td><td>(247.8)</td><td>74.2</td><td>(678.3)</td></tr><tr><td>Interest Income</td><td>45.1</td><td>10.2</td><td>0.5</td><td>—</td><td>66.3</td><td>(71.6)</td><td>50.5</td></tr><tr><td>Other Income, Net</td><td>180.4</td><td>33.6</td><td>37.9</td><td>8.5</td><td>1,600.8</td><td>(1,565.6)</td><td>295.6</td></tr><tr><td>Income Tax (Expense)/Benefit</td><td>(146.2)</td><td>(69.2)</td><td>(216.3)</td><td>3.2</td><td>(25.1)</td><td>—</td><td>(453.6)</td></tr><tr><td>Net Income</td><td>597.4</td><td>234.2</td><td>599.5</td><td>36.8</td><td>1,508.0</td><td>(1,563.5)</td><td>1,412.4</td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>(4.6)</td><td>—</td><td>(2.9)</td><td>—</td><td>—</td><td>—</td><td>(7.5)</td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 592.8</td><td>$ 234.2</td><td>$ 596.6</td><td>$ 36.8</td><td>$ 1,508.0</td><td>$ (1,563.5)</td><td>$ 1,404.9</td></tr><tr><td>Total Assets (as of)</td><td>$ 27,365.0</td><td>$ 8,084.9</td><td>$ 13,369.5</td><td>$ 2,783.8</td><td>$ 26,365.2</td><td>$ (24,737.5)</td><td>$ 53,230.9</td></tr><tr><td>Cash Flows Used for Investments in Plant</td><td>$ 1,172.6</td><td>$ 710.3</td><td>$ 1,144.0</td><td>$ 154.4</td><td>$ 260.6</td><td>$ —</td><td>$ 3,441.9</td></tr></table>

For the Year Ended December 31, 2021

<table><tr><td>Eversource
(Millions of Dollars)</td><td>Electric
Distribution</td><td>Natural Gas
Distribution</td><td>Electric
Transmission</td><td>Water
Distribution</td><td>Other</td><td>Eliminations</td><td>Total</td></tr><tr><td>Operating Revenues</td><td>$ 7,423.6</td><td>$ 1,789.6</td><td>$ 1,634.6</td><td>$ 211.3</td><td>$ 1,354.0</td><td>$ (2,550.0)</td><td>$ 9,863.1</td></tr><tr><td>Depreciation and Amortization</td><td>(737.8)</td><td>(142.3)</td><td>(300.3)</td><td>(46.1)</td><td>(113.1)</td><td>4.6</td><td>(1,335.0)</td></tr><tr><td>Other Operating Expenses</td><td>(5,970.0)</td><td>(1,345.4)</td><td>(496.2)</td><td>(101.4)</td><td>(1,170.4)</td><td>2,548.6</td><td>(6,534.8)</td></tr><tr><td>Operating Income</td><td>715.8</td><td>301.9</td><td>838.1</td><td>63.8</td><td>70.5</td><td>3.2</td><td>1,993.3</td></tr><tr><td>Interest Expense</td><td>(236.4)</td><td>(58.6)</td><td>(133.2)</td><td>(32.0)</td><td>(168.8)</td><td>46.6</td><td>(582.4)</td></tr><tr><td>Interest Income</td><td>20.7</td><td>4.5</td><td>2.2</td><td>—</td><td>46.0</td><td>(47.8)</td><td>25.6</td></tr><tr><td>Other Income, Net</td><td>78.1</td><td>17.9</td><td>19.8</td><td>3.3</td><td>1,363.9</td><td>(1,347.3)</td><td>135.7</td></tr><tr><td>Income Tax (Expense)/Benefit</td><td>(103.5)</td><td>(60.9)</td><td>(179.4)</td><td>1.7</td><td>(2.1)</td><td>—</td><td>(344.2)</td></tr><tr><td>Net Income</td><td>474.7</td><td>204.8</td><td>547.5</td><td>36.8</td><td>1,309.5</td><td>(1,345.3)</td><td>1,228.0</td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>(4.6)</td><td>—</td><td>(2.9)</td><td>—</td><td>—</td><td>—</td><td>(7.5)</td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 470.1</td><td>$ 204.8</td><td>$ 544.6</td><td>$ 36.8</td><td>$ 1,309.5</td><td>$ (1,345.3)</td><td>$ 1,220.5</td></tr><tr><td>Total Assets (as of)</td><td>$ 25,411.2</td><td>$ 7,215.9</td><td>$ 12,377.8</td><td>$ 2,551.1</td><td>$ 22,674.7</td><td>$ (21,738.6)</td><td>$ 48,492.1</td></tr><tr><td>Cash Flows Used for Investments in Plant</td><td>$ 1,053.3</td><td>$ 721.1</td><td>$ 1,024.1</td><td>$ 137.2</td><td>$ 239.4</td><td>$ —</td><td>$ 3,175.1</td></tr></table>

For the Year Ended December 31, 2020

<table><tr><td>Eversource
(Millions of Dollars)</td><td>Electric
Distribution</td><td>Natural Gas
Distribution</td><td>Electric
Transmission</td><td>Water
Distribution</td><td>Other</td><td>Eliminations</td><td>Total</td></tr><tr><td>Operating Revenues</td><td>$ 7,132.3</td><td>$ 1,208.7</td><td>$ 1,536.1</td><td>$ 215.4</td><td>$ 1,235.9</td><td>$ (2,424.0)</td><td>$ 8,904.4</td></tr><tr><td>Depreciation and Amortization</td><td>(657.0)</td><td>(87.9)</td><td>(278.1)</td><td>(44.2)</td><td>(93.5)</td><td>1.6</td><td>(1,159.1)</td></tr><tr><td>Other Operating Expenses</td><td>(5,642.3)</td><td>(913.8)</td><td>(470.0)</td><td>(86.6)</td><td>(1,071.9)</td><td>2,428.0</td><td>(5,756.6)</td></tr><tr><td>Operating Income</td><td>833.0</td><td>207.0</td><td>788.0</td><td>84.6</td><td>70.5</td><td>5.6</td><td>1,988.7</td></tr><tr><td>Interest Expense</td><td>(216.0)</td><td>(40.0)</td><td>(126.8)</td><td>(32.9)</td><td>(161.0)</td><td>38.3</td><td>(538.4)</td></tr><tr><td>Interest Income</td><td>3.2</td><td>0.9</td><td>4.7</td><td>—</td><td>37.8</td><td>(41.8)</td><td>4.8</td></tr><tr><td>Other Income, Net</td><td>58.0</td><td>3.1</td><td>23.3</td><td>2.0</td><td>1,382.9</td><td>(1,365.5)</td><td>103.8</td></tr><tr><td>Income Tax (Expense)/Benefit</td><td>(129.6)</td><td>(36.9)</td><td>(183.8)</td><td>(12.5)</td><td>16.6</td><td>—</td><td>(346.2)</td></tr><tr><td>Net Income</td><td>548.6</td><td>134.1</td><td>505.4</td><td>41.2</td><td>1,346.8</td><td>(1,363.4)</td><td>1,212.7</td></tr><tr><td>Net Income Attributable to Noncontrolling Interests</td><td>(4.6)</td><td>—</td><td>(2.9)</td><td>—</td><td>—</td><td>—</td><td>(7.5)</td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 544.0</td><td>$ 134.1</td><td>$ 502.5</td><td>$ 41.2</td><td>$ 1,346.8</td><td>$ (1,363.4)</td><td>$ 1,205.2</td></tr><tr><td>Cash Flows Used for Investments in Plant</td><td>$ 1,079.0</td><td>$ 494.4</td><td>$ 1,004.6</td><td>$ 118.8</td><td>$ 246.2</td><td>$ —</td><td>$ 2,943.0</td></tr></table>

## 24. ACQUISITION OF ASSETS OF COLUMBIA GAS OF MASSACHUSETTS

On October 9, 2020, Eversource acquired certain assets and liabilities that comprised the NiSource Inc. (NiSource) natural gas distribution business in Massachusetts, which was previously doing business as Columbia Gas of Massachusetts (CMA), pursuant to an asset purchase agreement (the Agreement) entered into on February 26, 2020 between Eversource and NiSource. The cash purchase price was $1.1 billion, plus a working capital amount of $68.6 million, as finalized in 2021. Eversource financed the acquisition through a combination of debt and equity issuances in a ratio that was consistent with its consolidated capital structure.

Pro Forma Financial Information: The following unaudited pro forma financial information reflects the pro forma combined results of operations of Eversource and the CMA business acquired and reflects the amortization of purchase price adjustments assuming the acquisition had taken place on January 1, 2019. The unaudited pro forma financial information has been presented for illustrative purposes only and is not



necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of Eversource. Pro forma net income excludes the impact of assets and liabilities not assumed by Eversource and non-recurring costs associated with the transaction.

<table><tr><td>(Pro forma amounts in millions, except share amounts)</td><td>For the Year Ended December 31, 2020</td></tr><tr><td>Operating Revenues</td><td>$ 9,273</td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>1,265</td></tr><tr><td>Basic EPS</td><td>3.73</td></tr><tr><td>Diluted EPS</td><td>3.72</td></tr></table>

Revenues and Net Income: The impact of CMA on Eversource's accompanying consolidated statement of income included operating revenues of $154.8 million and net income attributable to common shareholders of $13.9 million for the year ended December 31, 2020.

Transactions recognized separately from the business combination: Eversource entered into Transition Services Agreements (TSAs) with NiSource, under which NiSource provided certain administrative functions. The TSAs were completed in 2022. Eversource recorded $7.9 million and $21.4 million in Operating Expenses on the statements of income related to TSA costs for the years ended December 31, 2022 and 2021, respectively, and $15.9 million of TSA and pre-TSA costs in Operating Expenses in 2020. In addition, Eversource recorded $2.0 million in Energy Efficiency expense related to the implementation of new energy efficiency programs as specified in a DPU-approved rate settlement agreement in the fourth quarter of 2020.

## 25. GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. The following table presents Eversource's goodwill by reportable segment:

<table><tr><td>(Millions of Dollars)</td><td>Electric Distribution</td><td>Electric Transmission</td><td>Natural Gas Distribution</td><td>Water Distribution</td><td>Total</td></tr><tr><td>Balance as of January 1, 2021</td><td>$ 2,543.6</td><td>$ 576.8</td><td>$ 441.4</td><td>$ 884.2</td><td>$ 4,446.0</td></tr><tr><td>CMA Measurement Period Adjustments</td><td>—</td><td>—</td><td>9.6</td><td>—</td><td>9.6</td></tr><tr><td>Acquisition of NESC</td><td>—</td><td>—</td><td>—</td><td>21.7</td><td>21.7</td></tr><tr><td>Balance as of December 31, 2021</td><td>$ 2,543.6</td><td>$ 576.8</td><td>$ 451.0</td><td>$ 905.9</td><td>$ 4,477.3</td></tr><tr><td>NESC Measurement Period Adjustments</td><td>—</td><td>—</td><td>—</td><td>0.5</td><td>0.5</td></tr><tr><td>Acquisition of TWC</td><td>—</td><td>—</td><td>—</td><td>44.8</td><td>44.8</td></tr><tr><td>Balance as of December 31, 2022</td><td>$ 2,543.6</td><td>$ 576.8</td><td>$ 451.0</td><td>$ 951.2</td><td>$ 4,522.6</td></tr></table>

Eversource completed the acquisition of TWC on October 3, 2022, resulting in the addition of $44.8 million of goodwill, all of which was allocated to the Water Distribution reporting unit. Eversource completed the acquisition of NESC on December 1, 2021, resulting in the addition of $22.2 million of goodwill, which included measurement period increases in 2022 totaling $0.5 million. The goodwill was allocated to the Water Distribution reporting unit. Eversource completed the CMA asset acquisition on October 9, 2020, resulting in the addition of $51.9 million of goodwill, which included measurement period adjustments in 2021 resulting in an additional $9.6 million of goodwill. The goodwill was allocated to the Natural Gas Distribution reporting unit. For further information on the acquisitions of TWC and NESC, see Note 18, "Common Shares," to the financial statements.

Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. Goodwill is not subject to amortization, however, is subject to a fair value based assessment for impairment at least annually and whenever facts or circumstances indicate that there may be an impairment. A resulting write-down, if any, would be charged to Operating Expenses.

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 it's carrying amount. The annual goodwill assessment included a qualitative evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings.

Eversource's reporting units for the purpose of testing goodwill are Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. These reporting units are consistent with the operating segments underlying the reportable segments identified in Note 23, "Segment Information," to the financial statements.

Eversource completed its annual goodwill impairment assessment for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units as of October 1, 2022 and determined that no impairment existed. There were no events subsequent to October 1, 2022 that indicated impairment of goodwill.



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

No events that would be described in response to this item have occurred with respect to Eversource, CL&P, NSTAR Electric or PSNH.

## Item 9A. Controls and Procedures

Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for the preparation, integrity, and fair presentation of the accompanying Financial Statements and other sections of this combined Annual Report on Form 10-K. Eversource's internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for establishing and maintaining adequate internal controls over financial reporting. The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at Eversource, CL&P, NSTAR Electric and PSNH were effective as of December 31, 2022.

Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, evaluated the design and operation of the disclosure controls and procedures as of December 31, 2022 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officer and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of Eversource, CL&P, NSTAR Electric and PSNH are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for Eversource, CL&P, NSTAR Electric and PSNH during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

## Item 9B. Other Information

No information is required to be disclosed under this item as of December 31, 2022, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2022.

## PART III

## Item 10. Directors, Executive Officers and Corporate Governance

The information in Item 10 is provided as of February 15, 2023, except where otherwise indicated.

Certain information required by this Item 10 is omitted for NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.

## Eversource Energy

In addition to the information provided below concerning the executive officers of Eversource Energy, incorporated herein by reference is the information to be contained in the sections captioned “Election of Trustees,” “Governance of Eversource Energy” and the related subsections, “Selection of Trustees,” and “Delinquent Section 16(a) Reports” of Eversource Energy’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 24, 2023.

## CL&P

The information required by this Item 10 for CL&P has been omitted from this report but is set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.



## Item 11. Executive Compensation

## Eversource Energy

The information required by this Item 11 for Eversource Energy is incorporated herein by reference to certain information contained in Eversource Energy's definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 24, 2023, under the sections captioned "Compensation Discussion and Analysis," plus related subsections, and "Compensation Committee Report," plus related subsections following such Report.

## NSTAR ELECTRIC and PSNH

Certain information required by this Item 11 has been omitted for NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

## CL&P

The information required by this Item 11 for CL&P has been omitted from this report but is set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

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

## Eversource Energy

In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 24, 2023.

## NSTAR ELECTRIC and PSNH

Certain information required by this Item 12 has been omitted for NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

## CL&P

The information required by this Item 12 for CL&P has been omitted from this report but is set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

## SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth the number of Eversource Energy common shares issuable under Eversource Energy equity compensation plans, as well as their weighted exercise price, as of December 31, 2022, in accordance with the rules of the SEC:

<table><tr><td>Plan Category</td><td>Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)</td><td>Weighted-average exercise price of outstanding options, warrants and rights (2)</td><td>Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (1))</td></tr><tr><td>Equity compensation plans approved by security holders</td><td>1,177,024</td><td>$—</td><td>903,183</td></tr><tr><td>Equity compensation plans not approved by security holders (3)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>1,177,024</td><td>$—</td><td>903,183</td></tr></table>

(1) Includes 629,734 common shares for distribution in respect of restricted share units, and 547,290 performance shares issuable at target, all pursuant to the terms of our Incentive Plan.

(2) The weighted-average exercise price does not take into account restricted share units or performance shares, which have no exercise price.

(3) Securities set forth in this table are authorized for issuance under compensation plans that have been approved by shareholders of Eversource Energy.



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

## Eversource Energy

Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Related Person Transactions" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 24, 2023.

## NSTAR ELECTRIC and PSNH

Certain information required by this Item 13 has been omitted for NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

## CL&P

The information required by this Item 13 for CL&P has been omitted from this report but is set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

## Item 14. Principal Accountant Fees and Services

## Eversource Energy

Incorporated herein by reference is the information contained in the section "Relationship with Independent Auditors" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 24, 2023.

## CL&P, NSTAR ELECTRIC and PSNH

The information required by this Item 14 for CL&P, NSTAR Electric and PSNH has been omitted from this report but is set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

## PART IV

## Item 15. Exhibits and Financial Statement Schedules

(a) 1. Financial Statements:

The financial statements filed as part of this Annual Report on Form 10-K are set forth under Item 8, "Financial Statements and Supplementary Data."

## 2. Schedules

I. Financial Information of Registrant:

Eversource Energy (Parent) Balance Sheets as of December 31, 2022 and 2021

Eversource Energy (Parent) Statements of Income for the Years Ended

December 31, 2022, 2021 and 2020

Eversource Energy (Parent) Statements of Comprehensive Income for the Years Ended December 31, 2022, 2021 and 2020

Eversource Energy (Parent) Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020

Valuation and Qualifying Accounts and Reserves for Eversource, CL&P, NSTAR Electric and PSNH II. for 2022, 2021 and 2020

All other schedules of the companies for which inclusion is required in the applicable regulations of the SEC are permitted to be omitted under the related instructions or are not applicable, and therefore have been omitted.

3. Exhibit Index

* The schedules have been omitted from this report because they are not required. They are set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

## Item 16. Form 10-K Summary

Not applicable.



## EXHIBIT INDEX

Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith. Management contracts and compensation plans or arrangements are designated with a (+).

The portion of the Exhibit Index listing exhibits of CL&P, NSTAR Electric and PSNH has been omitted from this report but is set forth in the Annual Report on Form 10-K for 2022 filed with the SEC on a combined basis with Eversource Energy on February 15, 2023. Such report is also available in the Investors section at www.eversource.com.

## Exhibit

Number ___ Description ___

3. Articles of Incorporation and By-Laws

3.1 Declaration of Trust of Eversource Energy, as amended through May 3, 2017 (Exhibit 3.1, Eversource Form 10-Q filed on May 5, 2017)

4. Instruments defining the rights of security holders, including indentures

4.1 Indenture between Eversource Energy and The Bank of New York as Trustee dated as of April 1, 2002 (Exhibit A-3, Eversource Energy 35-CERT filed April 16, 2002, File No. 070-09535)

4.1.1 Fifth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of May 1, 2013, relating to $450 million of Senior Notes, Series F, due 2023 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed May 16, 2013, File No. 001-05324)

4.1.2 Sixth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2015, relating to $300 million of Senior Notes, Series H, due 2025 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed January 21, 2015, File No. 001-05324)

4.1.3 Seventh Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 7, 2016, relating to $250 million of Senior Notes, Series J, due 2026 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed March 15, 2016, File No. 001-05324)

4.1.4 Ninth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of October 1, 2017, relating to $450 million of Senior Notes, Series K, due 2022 and $450 million of Senior Notes, Series L, due 2024 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed October 12, 2017, File No. 001-05324)

4.1.5 Tenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2018, relating to $450 million of Senior Notes, Series M, Due 2028 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed January 12, 2018, File No. 001-05324)

4.1.6 Eleventh Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of December 1, 2018, relating to $400 million of Senior Notes, Series N, Due 2023 and $500 million of Senior Notes, Series O, Due 2029 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed December 18, 2018, File No. 001-05324)

4.1.7 Twelfth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2020, relating to $650 million of Senior Notes, Series P, Due 2050 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed January 16, 2020, File No. 001-05324)

4.1.8 Thirteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of August 1, 2020, relating to $300 million aggregate principal amount of Senior Notes, Series Q, Due 2025 and $600 million aggregate principal amount of Senior Notes, Series R, Due 2030 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed August 20, 2020, File No. 001-05324)

4.1.9 Fourteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 1, 2021, relating to $350 million aggregate principal amount of Senior Notes, Series S, Due 2031 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed March 16, 2021, File No. 001-05324)



4.1.10 Fifteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of August 1, 2021, relating to $350 million aggregate principal amount of Floating Rate Senior Notes, Series T and $300 million aggregate principal amount of Senior Notes, Series U, Due 2026 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed August 13, 2021, File No. 001-05324)

4.1.11 Sixteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of February 1, 2022, relating to $650 million aggregate principal amount of Senior Notes, Series V, Due 2027 and $650 million aggregate principal amount of Senior Notes, Series W, Due 2032 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed February 25, 2022, File No. 001-05324)

4.1.12 Seventeenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of June 1, 2022, relating to $900 million aggregate principal amount of Senior Notes, Series X, Due 2024 and $600 million aggregate principal amount of Senior Notes, Series Y, Due 2027 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed June 27, 2022, File No. 001-05324)

4.2 Eversource Energy Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.3, Eversource Energy Annual Report on Form 10-K filed February 27, 2020, File No. 001-05324)

(A) Eversource Energy, The Connecticut Light and Power Company and Public Service Company of New Hampshire

4.1 Second Amended and Restated Credit Agreement, dated as of October 15, 2021, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 10.12, 2021 Eversource Form 10-K filed on February 17, 2022)

4.1.1 First Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated October 17, 2022, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 4, Eversource Form 10-Q filed on November 4, 2022)

10.1 Lease between The Rocky River Realty Company and Eversource Energy Service Company, dated as of July 1, 2008 (Exhibit 10.1, 2017 Eversource Form 10-K filed on February 26, 2018)

*+10.2 Eversource Energy Board of Trustees' Compensation Arrangement Summary

+10.3 Eversource Supplemental Executive Retirement Program effective as of January 1, 2015 (Exhibit 10.5, 2015 Eversource Energy Form 10-K filed February 26, 2016, File No. 001-05324)

+10.4 Eversource Energy Deferred Compensation Plan for Executives effective as of January 1, 2014 (Exhibit 10.6, 2015 Eversource Energy Form 10-K filed February 26, 2016, File No. 001-05324)

+10.4.1 Amendment No 1 to the Eversource Deferred Compensation Plan effective February 7, 2018 (Exhibit 10.6.1, Eversource Energy Annual Report on Form 10-K filed February 27, 2020, File No. 001-05324)

+10.5 NSTAR Excess Benefit Plan, effective August 25, 1999 (Exhibit 10.1 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)

+10.5.1 NSTAR Excess Benefit Plan, incorporating the NSTAR 409A Excess Benefit Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.1.1 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)

+10.6 Amended and Restated Change in Control Agreement by and between Joseph R. Nolan, Jr. and NSTAR, dated November 15, 2007 (Exhibit 10.13, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.7 Amended and Restated Change in Control Agreement by and between Werner J. Schweiger and NSTAR, dated November 15, 2007 (Exhibit 10.14, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.8 Amended and Restated Change in Control Agreement by and between Senior Vice President and NSTAR, dated November 15, 2007 (Exhibit 10.15, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.9 Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (Exhibit 10.5, NSTAR Form 10-Q for the Quarter Ended September 30, 2000 filed November 14, 2000, File No. 001-14768)



+10.10 Currently effective Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form) (Exhibit 10.17, 2009 NSTAR Form 10-K filed February 25, 2010, File No. 001-14768)

(A) Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company and Public Service Company of New Hampshire

10.1 Amended and Restated Form of Service Contract between each of Eversource Energy, CL&P, NSTAR Electric Company and Eversource Energy Service Company dated as of January 1, 2014. (Exhibit 10.1, Eversource Energy Form 10-K filed on February 25, 2014, File No. 001-05324)

10.2 Transmission Operating Agreement between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, 2004 Eversource Energy Form 10-K filed March 17, 2005, File No. 001-05324)

10.2.1 Rate Design and Funds Disbursement Agreement among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, 2006 Eversource Energy Form 10-K filed March 1, 2007, File No. 001-05324)

10.3 Eversource Energy's Third Amended and Restated Tax Allocation Agreement dated as of April 10, 2012, (Exhibit 10.1 Eversource Energy Form 10-Q for Quarter Ended June 30, 2012 filed August 7, 2012, File No. 001-05324)

+10.4 Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, Eversource Energy Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

+10.5 2018 Eversource Energy Incentive Plan (Exhibit 99.2, Eversource Energy Current Report on Form 8-K dated May 3, 2018)

+10.6 Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 Eversource Energy Form 10-K filed March 21, 2003, File No. 001-05324)

+10.6.1 First Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 Eversource Energy Form 10-K filed March 12, 2004, File No. 001-05324)

+10.6.2 Second Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of November 12, 2008 (Exhibit 10.12.2, 2008 Eversource Energy Form 10-K filed February 27, 2009, File No. 001-05324)

+10.7 Special Severance Program for Officers of Eversource Energy Companies as of January 1, 2009 (Exhibit 10.2 Eversource Energy Form 10-Q for Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

+10.8 Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, 2008 Eversource Energy 2010 Form 10-K filed February 27, 2009, File No. 001-05324)

(B) Eversource Energy, The Connecticut Light and Power Company, Public Service Company of New Hampshire and NSTAR Electric Company

10.1 Eversource Energy Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology among The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, Eversource Energy Form 10-Q for the Quarter Ended March 31, 2008 filed May 9, 2008, File No. 001-05324)

 \( ^{*} $ 21. Subsidiaries of the Registrant

 \( ^{*} $ 23. Consents of Independent Registered Public Accounting Firm

 \( ^{*} $ 31. Rule 13a - 14(a)/15 d - 14(a) Certifications

31 Certification by the Chief Executive Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.1 Certification by the Chief Financial Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 \( ^{*} $ 32 18 U.S.C. Section 1350 Certifications



32 Certification by the Chief Executive Officer and Chief Financial Officer of Eversource Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*101.INS Inline XBRL Instance Document - the instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document

*101.SCH Inline XBRL Taxonomy Extension Schema

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*104 The cover page from the Annual Report on Form 10-K for the year ended December 31, 2022, formatted in Inline XBRL



# EVERSOURCE ENERGY

# SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

## EVERSOURCE ENERGY

February 15, 2023

By: /s/ John M. Moreira

John M. Moreira

Executive Vice President, Chief Financial Officer and Treasurer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

## POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Gregory B. Butler and John M. Moreira and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

<table><tr><td>Signature</td><td>Title</td><td>Date</td></tr><tr><td>/s/ Joseph R. Nolan, Jr.</td><td>Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)</td><td>February 15, 2023</td></tr><tr><td>Joseph R. Nolan, Jr.</td><td>Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)</td><td>February 15, 2023</td></tr><tr><td>/s/ John M. Moreira</td><td>Trustee</td><td>February 15, 2023</td></tr><tr><td>John M. Moreira</td><td>Trustee</td><td>February 15, 2023</td></tr></table>



# CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Joseph R. Nolan, Jr., certify that:

1. I have reviewed this Annual Report on Form 10-K of Eversource Energy (the registrant);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 15, 2023

/s/ Joseph R. Nolan, Jr.

Joseph R. Nolan, Jr.

Chairman of the Board, President and Chief Executive Officer

(Principal Executive Officer)



# CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John M. Moreira, certify that:

1. I have reviewed this Annual Report on Form 10-K of Eversource Energy (the registrant);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 15, 2023

/s/ John M. Moreira

John M. Moreira

Executive Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)



# CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Annual Report on Form 10-K of Eversource Energy (the registrant) for the period ending December 31, 2022 as filed with the Securities and Exchange Commission (the Report), we, Joseph R. Nolan, Jr., Chairman of the Board, President and Chief Executive Officer of the registrant, and John M. Moreira, Executive Vice President, Chief Financial Officer and Treasurer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Joseph R. Nolan, Jr.

Joseph R. Nolan, Jr.

Chairman of the Board, President and Chief Executive Officer

/s/ John M. Moreira

John M. Moreira

Executive Vice President, Chief Financial Officer and Treasurer

Date: February 15, 2023



## Eversource Energy Trustees

Joseph R. Nolan, Jr.
Chairman of the Board,
President and Chief Executive Officer,
Eversource Energy

Cotton M. Cleveland
President, Mather Associates

James S. DiStasio
Retired Senior Vice Chairman and
Americas Chief Operating Officer,
Ernst & Young

Francis A. Doyle
Chairman and Chief Executive Officer,
Connell Limited Partnership

Linda Dorcena Forry
Vice President, Diversity, Inclusion & Community
Relations for the Northeast,
Suffolk Construction

Gregory M. Jones
Vice President, Community Health and Engagement,
Hartford Healthcare

Loretta D. Keane
Chief Financial Officer, Arcadia Solutions, LLC

John Y. Kim
Managing Partner, Brewer Lane Ventures, LLC

Kenneth R. Leibler
Chairman,
The Putnam Mutual Funds

David H. Long
Chairman, President and Chief Executive Officer,
Liberty Mutual Holding Company, Inc.

William C. Van Faasen \( ^{*} \) 
Chairman Emeritus,
Blue Cross Blue Shield of Massachusetts Inc.

Frederica M. Williams
President and Chief Executive Officer,
Whittier Street Health Center

 \( ^{*} \) Lead Trustee

## Eversource Energy Executive Officers

Joseph R. Nolan, Jr.
Chairman of the Board,
President and Chief Executive Officer

Gregory B. Butler
Executive Vice President and General Counsel

Christine M. Carmody
Executive Vice President – Human Resources and
Information Technology

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

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

John M. Moreira
Executive Vice President, Chief Financial Officer and
Treasurer

Werner J. Schweiger
Executive Vice President and Chief Operating Officer



## Shareholder Information

## Shareholders

As of December 31, 2022, there were 30,202 common shareholders of record of Eversource Energy holding an aggregate of 348,443,855 common shares.

## Transfer Agent and Registrar

Computershare Investor Services

P.O. Box 43078

Providence, RI 02940-3078

1-800-999-7269

TDD for hearing impaired: 1-800-952-9245

## Shareholder Account Access

We have partnered with Computershare to offer you online access to your important shareowner communications in a single secure place. You can manage your account online via the Investor Center website, Computershare's web-based tool for shareholders at www.computershare.com/investor. Through free around-the-clock access to the Investor Center website, you can view your account, access forms and request a variety of account transactions.

## Investor Relations

You may contact our Investor Relations Department:

Jeffrey Kotkin: 1-860-665-5154

Robert Becker: 1-860-665-3249

Melissa Cameron: 1-781-441-8862

www.eversource.com

## Dividend Reinvestment

## and Share Purchase Plan

Eversource offers a dividend reinvestment and share purchase plan. This plan is sponsored by the company and not only offers the reinvestment of dividends but provides both registered shareholders and interested first-time investors an affordable alternative for buying and selling Eversource common shares. To request an enrollment package, please call 1-800-999-7269 or log into:

www.computershare.com/investor

## Direct Deposit for Quarterly Dividends

Direct deposit provides the convenience of automatic and immediate access to your funds, while eliminating the possibility of mail delays and lost, stolen or destroyed checks. This service is free of charge to you. Please call 1-800-999-7269 to request an enrollment form.

## Common Share Dividend Payment Dates

Last business day of March, June, September and December.

## Common Share Information

The common shares of Eversource Energy are listed on the New York Stock Exchange. The ticker symbol is “ES.” The high and low daily prices and dividends paid for the past two years, by quarters, are shown in the table below.

<table><tr><td>Year</td><td>Quarter</td><td>High</td><td>Low</td><td>Quarterly Dividend per Share</td></tr><tr><td rowspan="4">2022</td><td>First</td><td>$90.85</td><td>$78.63</td><td>$0.6375</td></tr><tr><td>Second</td><td>$94.63</td><td>$77.07</td><td>$0.6375</td></tr><tr><td>Third</td><td>$94.41</td><td>$79.49</td><td>$0.6375</td></tr><tr><td>Fourth</td><td>$87.71</td><td>$70.54</td><td>$0.6375</td></tr><tr><td rowspan="4">2021</td><td>First</td><td>$92.21</td><td>$76.64</td><td>$0.6025</td></tr><tr><td>Second</td><td>$91.20</td><td>$78.44</td><td>$0.6025</td></tr><tr><td>Third</td><td>$92.66</td><td>$79.57</td><td>$0.6025</td></tr><tr><td>Fourth</td><td>$91.46</td><td>$81.60</td><td>$0.6025</td></tr></table>

## Corporate Governance

For information on Corporate Governance at Eversource, go to our website, www.eversource.com. Select “About” then “Investors” and scroll down to link under “Corporate Governance.”



Recognized by As You Sow and a Top 10 Company and #1 Utility for DE&I data transparency and commitment to racial equity and social justice.

## Institutional Investor \( ^{™} \) 

Recognized as a 2023 Institutional Investor “Most Honored Company” for industry leading ESG, investor relations and multiple other categories as voted by institutional investors.



Included in Newsweek’s list of Most Responsible Companies.



Included in the Forbes/Just Capital list of JUST 100 Companies, a ranking of most responsible publicly traded companies.



Recognized in Bloomberg’s Gender-Equality Index for our commitment to transparency in gender reporting and promoting women’s equality in the workplace.