Item 1. Business

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

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

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

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

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

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

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

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

• Aquarion Company (Aquarion), a utility holding company that owns five separate regulated water utility subsidiaries and collectively serves residential, commercial, industrial, and municipal and fire protection customers in parts of Connecticut, Massachusetts and New Hampshire.

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

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

Eversource has an offshore wind business, which includes 50 percent ownership interests in three offshore wind projects and a tax equity investment in one of the projects. For further information, see "Offshore Wind Business” below.

ELECTRIC DISTRIBUTION SEGMENT

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

ELECTRIC DISTRIBUTION – CONNECTICUT – THE CONNECTICUT LIGHT AND POWER COMPANY

CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2023, CL&P furnished retail franchise electric service to approximately 1.28 million customers in 157 cities and towns in Connecticut. CL&P does not own any electric generation facilities.

Rates

CL&P is subject to regulation by the Connecticut Public Utilities Regulatory Authority (PURA), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewable energy programs and other charges that are assessed on all customers.

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

The rates established by PURA for CL&P are comprised of the following:

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

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

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

• An Electric System Improvements (ESI) charge, which collects the costs of building and expanding the infrastructure to deliver electricity to customers above the level recovered through the distribution charge. The ESI also recovers costs associated with CL&P’s system resiliency program. The ESI is adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.

• A Federally Mandated Congestion Charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, any costs approved by PURA to reduce these charges, as well as other costs approved by PURA. The FMCC has both a bypassable component and a non-bypassable component, and is adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.

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

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

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

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

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

As required by regulation, CL&P has entered into long-term contracts for the purchase of (i) products from renewable energy facilities, which may include energy, renewable energy certificates, or capacity, (ii) capacity-related contracts with generation facilities, and (iii) contracts for peaking capacity. Some of these contracts are subject to sharing agreements with UI, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits. CL&P's portion of the costs and benefits of these contracts will be paid by, or refunded to, CL&P's customers.

Distribution Rate Case: CL&P's distribution rates were established in an April 2018 PURA-approved rate case settlement agreement with rates effective May 1, 2018, and incremental step adjustments effective May 1, 2019 and May 1, 2020.

CL&P Settlement Agreement: In accordance with a 2021 settlement agreement, CL&P agreed that its current base distribution rates would be frozen, subject to certain customer credits, until no earlier than January 1, 2024. The rate freeze applied only to base distribution rates (including storm costs) and not to other rate mechanisms such as the retail rate components, rate reconciling mechanisms, formula rates and any other adjustment mechanisms. The rate freeze also did not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings that were either pending or that could be initiated during the rate freeze period, that could have placed additional obligations on CL&P. The approval of the settlement agreement satisfied the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. During 2023, CL&P supplied approximately 56 percent of its customer load at SS or LRS rates while the other 44 percent of its customer load had migrated to competitive energy suppliers. In terms of the total number of CL&P customers, this equates to 25 percent being on competitive supply, while 75 percent remain with SS or LRS. Because customer migration is limited to energy supply service, it has no impact on CL&P's electric distribution business or its operating income.

As approved by PURA, CL&P periodically enters into full requirements supply contracts for SS loads for periods of up to one year. CL&P typically enters into full requirements supply contracts for LRS loads every three months. If CL&P does not obtain full requirements supply contracts for 100 percent of the customer load for any period, it is authorized by PURA to meet the remaining load obligations directly through the ISO-NE wholesale markets. Currently, CL&P has full requirements supply contracts in place for 100 percent of its SS load for the first half of 2024. For the second half of 2024, CL&P has 70 percent of its SS load under full requirements supply contracts and intends to purchase an additional 30 percent of full requirements. Ten percent of the SS load for 2025 has been procured. CL&P obtained a full requirements supply contract for its LRS load through June 2024 and intends to purchase 100 percent of full requirements for LRS for the remainder of 2024. CL&P is prepared to self-manage the LRS load if unable to obtain full requirements supply contracts for LRS.

ELECTRIC DISTRIBUTION – MASSACHUSETTS – NSTAR ELECTRIC COMPANY

NSTAR Electric's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2023, NSTAR Electric furnished retail franchise electric service to approximately 1.49 million customers in 161 cities and towns in eastern and western Massachusetts, including Boston, Cape Cod, Martha's Vineyard and the greater Springfield metropolitan area.

NSTAR Electric does not own any generating facilities that are used to supply customers, and purchases its energy requirements from competitive energy suppliers.

NSTAR Electric owns, operates and maintains a total of 70 MW of solar power facilities on twenty-two sites in Massachusetts. NSTAR Electric sells energy from these facilities into the ISO-NE market, with proceeds credited to customers.

Rates

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

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

The rates established by the DPU for NSTAR Electric are comprised of the following:

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

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

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

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

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

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

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

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

As approved by the DPU, NSTAR Electric has signed long-term commitments for the purchase of energy from renewable energy facilities.

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

Service Quality Metrics: NSTAR Electric is subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. NSTAR Electric will not be required to pay a SQ charge for its 2023 performance as the company achieved results at or above target for all of its SQ metrics in 2023.

Sources and Availability of Electric Power Supply

As noted above, NSTAR Electric does not own generation assets (other than 70 MW of solar power facilities that produce energy that is sold into the ISO-NE market) and purchases its energy supply requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. As approved by the DPU, NSTAR Electric enters into supply contracts for basic service for approximately 32 percentof its residential and 29 percent of its small commercial and industrial (C&I) customers twice per year for twelve-month terms. NSTAR Electric enters into supply contracts for basic service for 7 percentof its large C&I customers every three months.

During 2023, NSTAR Electric supplied approximately 18 percent of its overall customer load at basic service rates. The remaining 82 percent of its overall customer load was served either by municipal aggregation or competitive supply. Because customer migration is limited to energy supply service, it has no impact on NSTAR Electric’s electric distribution business or its operating income.

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

PSNH's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2023, PSNH furnished retail franchise electric service to approximately 539,000 retail customers in 215 cities and towns in New Hampshire. PSNH does not own any electric generation facilities.

Rates

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

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

The rates established by the NHPUC for PSNH are comprised of the following:

• A default energy service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers.

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

• A Transmission Charge Adjustment Mechanism (TCAM) that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.

• A Stranded Cost Recovery Charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations, other long-term investments and obligations, and the remaining costs associated with the 2018 sales of its generation facilities.

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

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

• A Pole Plant Adjustment Mechanism (PPAM) that recovers certain costs associated with poles acquired under a 2023 purchase agreement between PSNH and Consolidated Communications, including the operation and maintenance of poles, pole inspections, and vegetation management expenses incurred, beginning February 10, 2021 through April 30, 2023. For further information, see "Regulatory Developments and Rate Matters - New Hampshire" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

The default energy service charge changes semi-annually, the SCRC rate changes annually with the option to change semi-annually beginning in 2023, and the transmission and SBC rates change annually. These rates are reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers.

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

Distribution Rate Case: PSNH’s distribution rates were established in a December 2020 NHPUC-approved settlement agreement, with rates effective January 1, 2021. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant additions in calendar years 2019, 2020 and 2021, respectively. The NHPUC approved a rate increase effective February 1, 2022 designed to collect $1.1 million dollars annually to fund a reserve account to pay for arrearage forgiveness for customers with past due balances and the New Start Program. On October 20, 2022, the NHPUC approved the third step adjustment for 2021 plant in service to recover a revenue requirement of $8.9 million, with rates effective November 1, 2022. The total approved revenue requirement increase was collected over the remainder of the rate year (November 1, 2022 – July 31, 2023).

Sources and Availability of Electric Power Supply

PSNH does not own any generation assets and as approved by the NHPUC, purchases energy supply from a variety of competitive suppliers for its energy service customers through requests for proposals issued twice per year, for six-month terms, for approximately 64 percent of its residential and small C&I customers and for 9 percent of its large C&I customers.

During 2023, PSNH supplied approximately 37 percent of its customer load at default energy service rates while the other 63 percent of its customer load had migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on PSNH’s electric distribution business or its operating income.

ELECTRIC TRANSMISSION SEGMENT

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

Wholesale Transmission Rates

Wholesale transmission revenues are recovered through FERC-approved formula rates. Annual transmission revenue requirements include recovery of transmission costs and include a return on equity applied to transmission rate base. Transmission revenues are collected from New England customers, including distribution customers of CL&P, NSTAR Electric and PSNH. The transmission rates provide for an annual true-up of estimated to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission customers.

Transmission Rate Base

Transmission rate base under our FERC-approved tariff primarily consists of our investment in transmission net utility plant less accumulated deferred income taxes. Under our FERC-approved tariff, investments in net utility plant generally enter rate base after they are placed in commercial operation. At the end of 2023, our estimated transmission rate base was approximately $9.8 billion, including approximately $4.1 billion at CL&P, $3.9 billion at NSTAR Electric, and $1.8 billion at PSNH.

FERC ROE Complaints

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

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

During 2019 and 2020, FERC also issued multiple decisions in two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted new methodologies for determining base ROEs. On August 9, 2022, the Court issued a decision vacating these MISO FERC decisions and remanded to FERC to reopen the proceedings. At this time, Eversource cannot predict how and when FERC will address the Court’s findings on the remand of the MISO FERC opinions or any potential associated impact on the NETOs’ four pending ROE complaint cases.

Given the significant uncertainty regarding the applicability of the FERC opinions in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaint periods at this time. As well, Eversource cannot reasonably estimate a range of loss for any of the four complaint proceedings at this time.

For further information, see "FERC Regulatory Matters - FERC ROE Complaints" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

NATURAL GAS DISTRIBUTION SEGMENT

NSTAR Gas distributes natural gas to approximately 307,000 customers in 59 communities in central and eastern Massachusetts. EGMA distributes natural gas to approximately 336,000 customers in 66 communities throughout Massachusetts. Yankee Gas distributes natural gas to approximately 252,000 customers in 85 cities and towns in Connecticut. Total throughput (sales and transportation) in 2023 was approximately 67.1 Bcf for NSTAR Gas, 54.2 Bcf for EGMA, and 56.4 Bcf for Yankee Gas. Our natural gas businesses provide firm natural gas sales and transportation service to eligible retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, as well as commercial and industrial customers who rely on natural gas for space heating, hot water, cooking and commercial and industrial applications.

NSTAR Gas, EGMA and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. All NSTAR Gas and EGMA retail customers have the ability to choose to purchase gas from third party marketers under the Massachusetts Retail Choice program. In the past year in Massachusetts, Retail Choice represented only approximately one percent of the total residential load, while Retail Choice represented approximately 50 percent of the total commercial and industrial load. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers. For customers who purchase natural gas from NSTAR Gas, EGMA and Yankee Gas, the purchased natural gas commodity cost is passed through to those customers without mark-up. NSTAR Gas, EGMA and Yankee Gas do not earn a profit on the cost of purchased gas.

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

A portion of the storage of natural gas supply for NSTAR Gas and EGMA during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource. NSTAR Gas has access to facilities consisting of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas and facilities that include additional storage capacity of 0.5 Bcf. Total vaporization capacity of these facilities is 0.21 Bcf per day. EGMA has access to approximately 1.8 Bcf of LNG and 0.1 Bcf of LPG storage, with a total vaporization capacity of 0.14 Bcf per day. Yankee Gas owns a 1.2 Bcf LNG facility, which also has the ability to liquefy and vaporize up to 0.1 Bcf per day. This facility is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas, typically during periods of low demand.

Rates

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

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

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

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

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

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

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

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

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

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

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

Distribution Rate Cases:

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

EGMA: EGMA’s distribution rates were established in a DPU-approved October 7, 2020 rate settlement agreement, with rate increases on November 1, 2021 and November 1, 2022, and two rate base resets during an eight-year rate plan, occurring on November 1, 2024 and November 1, 2027. Notwithstanding the two distribution rate increases, the two rate base reset provisions, and potential adjustments for qualifying exogenous events, EGMA agreed not to file for an increase or redesign of distribution base rates effective prior to November 1, 2028.

Yankee Gas: Yankee Gas distribution rates were established in a December 2018 PURA-approved rate case settlement agreement, with rates effective November 15, 2018. PURA also approved step adjustments effective January 1, 2020 and January 1, 2021.

Service Quality Metrics: NSTAR Gas and EGMA are subject to SQ metrics that measure safety, reliability and customer service and each could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics. NSTAR Gas and EGMA will not be required to pay any SQ charges relating to their 2023 performance.

Natural Gas Replacement

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

In October 2020, the DPU opened Docket “DPU 20-80 The Future of Gas” to examine the role of Massachusetts natural gas local distribution companies (LDCs) in helping to meet the state’s 2050 climate goals. In December 2023, the DPU issued an order for this docket. The DPU will consider and, in some cases, require new processes and analysis for traditional natural gas investments, which may require significant changes to the LDC planning process and business models. The DPU intends to put policies and structures in place that would protect customers as Massachusetts works to decarbonize the building sector, which may involve subsequent dockets and regulatory proceedings and potentially recasting the role of LDCs in Massachusetts. The DPU preserved customer choice for energy needs and encouraged further development of decarbonized alternatives, such as the networked geothermal systems that NSTAR Gas is piloting in Framingham, Massachusetts. At this time, Eversource cannot predict the ultimate outcome of this proceeding, as the Company and other LDCs are seeking formal clarity from the DPU to fully understand the resulting impact to their natural gas businesses and the associated timing of any impacts. The Company does not believe there is any indication of an inability to recover costs or risk of impairment of our natural gas assets at this time.

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

In September 2021, PURA undertook a review of Connecticut natural gas companies’ infrastructure system expansion plan (SEP) to determine if the SEP continues to be in the best interest of the state’s comprehensive energy strategy. On April 27, 2022, PURA issued an order for the immediate winding down of the SEP by (1) ending the enrollment of new customers in the SEP program and permitting only a specific group of potential customers who have executed a services agreement with a natural gas company on or before a specified date (subsequently approved as August 16, 2022) to qualify for incentives under the current SEP; (2) directing all surplus non-firm margin to be deferred as a regulatory liability and applied to rate base in a future rate proceeding; and (3) directing the natural gas companies to cease all outbound and passive marketing regarding the SEP. On July 15, 2022, Yankee Gas appealed the portion of this order pertaining to the deferral of non-firm margin as a reduction to future rate base. On October 24, 2023, Yankee Gas informed the Connecticut Superior Court that the parties mutually agreed to resolve the appeal through a stipulation, which clarified that PURA will decide in Yankee Gas’s next gas rate case the ratemaking treatment of the deferred non-firm margin. Yankee Gas evaluated the prospective impact of this proceeding and does not believe the impact will be material to its future financial position, results of operations and cash flows.

Sources and Availability of Natural Gas Supply

NSTAR Gas and EGMA maintain flexible resource portfolios consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas and EGMA purchase transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport natural gas from major natural gas producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale (as well as Ontario, Canada specific to EGMA), which supply to the final delivery points in the NSTAR Gas and EGMA service areas. NSTAR Gas purchases all of its natural gas supply under a firm, competitively bid annual portfolio management contract. EGMA purchases the majority of its natural gas supply under a number of firm, competitively bid annual portfolio management contracts, and manages a portion of its own portfolio. In addition to the firm transportation and natural gas storage supplies discussed above, NSTAR Gas and EGMA utilize on-system LNG facilities (and also LPG facilities for EGMA) to meet winter peaking demands. These LNG facilities are located within NSTAR Gas' and EGMA’s distribution systems and are used to liquefy pipeline natural gas and/or receive liquefied natural gas or liquefied petroleum gas to be stored during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in Maryland and Pennsylvania. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf, and 3.5 Bcf LNG storage is provided by Hopkinton LNG Corp. in facilities located in two different locations in Massachusetts. EGMA has firm underground storage contracts and total storage capacity entitlements of approximately 8.6 Bcf, and 1.9 Bcf LNG and LPG storage is provided by Hopkinton LNG Corp. in facilities located at seven different locations in Massachusetts.

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

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

WATER DISTRIBUTION SEGMENT

Aquarion Company (Aquarion) operates five separate regulated water utilities in Connecticut (Aquarion Water Company of Connecticut, or AWC-CT, and The Torrington Water Company), Massachusetts (Aquarion Water Company of Massachusetts, or AWC-MA), and New Hampshire (Aquarion Water Company of New Hampshire, or AWC-NH, and Abenaki Water Company). These regulated companies provide water services to approximately 241,000 residential, commercial, industrial, municipal and fire protection and other customers, in 72 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, 2023, approximately 92 percent of Aquarion’s customers were based in Connecticut.

Rates

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

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

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

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

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

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

Sources and Availability of Water Supply

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

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

OFFSHORE WIND BUSINESS

Eversource’s offshore wind business includes 50 percent ownership interests in wind partnerships, which collectively hold the Revolution Wind, South Fork Wind and Sunrise Wind projects, and a tax equity investment in South Fork Wind. The offshore wind projects are being developed and constructed through joint and equal partnerships with Ørsted. Revolution Wind is a 704 MW offshore wind power project located approximately 15 miles south of the Rhode Island coast, and South Fork Wind is a 130 MW offshore wind power project located approximately 35 miles east of Long Island. Sunrise Wind is a 924 MW offshore wind facility located 35 miles east of Montauk Point, Long Island. The completion dates for these projects are subject to federal permitting through BOEM, engineering, state siting and permitting in New York, Rhode Island and Massachusetts and construction schedules.

We are in the process of selling our existing 50 percent interests in the three jointly-owned offshore wind projects. In connection with the sales process, we have recorded impairments to the carrying value of the offshore wind investments to reflect the investments at estimated fair value. For more information on these projects, the sales process, and the impairment evaluations, see "Business Development and Capital Expenditures – Offshore Wind Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

CAPITAL EXPENDITURES

For information on capital expenditures and projects during 2023, as well as projected capital expenditures by business, see "Business Development and Capital Expenditures" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

FINANCING

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

NUCLEAR FUEL STORAGE

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

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

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

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

Renewable Portfolio Standards

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

Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2023, the total RPS obligation was 35.0 percent and will ultimately reach 48.0 percent in 2030. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its generation service charge rate.

Massachusetts' RPS program requires electricity suppliers to meet renewable energy standards. For 2023, the RPS and Clean Energy Standard (CES) requirements were 59.2 percent, and will ultimately reach 63.1 percent in 2025. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 5.75 percent and Clean Peak Energy Standards (CPS) of 6.0 percent in 2023. Those requirements will reach 6.25 and 9.00 percent in 2025, respectively. NSTAR Electric is permitted to recover any costs incurred in complying with these requirements from its customers through rates. NSTAR Electric also owns renewable solar power facilities. The RECs generated from NSTAR Electric's solar power facilities are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.

New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2023, the total RPS obligation was 23.4 percent and it will ultimately reach 25.2 percent in 2025. The costs of the RECs are recovered by PSNH through rates charged to customers.

Environmental Regulation and Matters

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

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

We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or natural resource damages costs for waste disposal sites for which we have probable liability. Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at contaminated sites. As of December 31, 2023, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was $128.2 million, representing 65 sites. These costs could be significantly higher if additional remediation becomes necessary or when additional information as to the extent of contamination becomes available.

The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of natural gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose a potential risk to human health and the environment. We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $117.1 million of the total $128.2 million as of December 31, 2023. MGP costs are recoverable through rates charged to our customers.

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

Global Climate Change and Greenhouse Gas Emission Issues

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

Regulatory Impacts of Climate Change: Global climate change continues to receive increasing focus from the federal and state governments. The Biden administration has communicated a strong focus on addressing climate change by setting a U.S. target of reducing greenhouse gas (GHG) emissions by 50 percent by 2030, compared to 2005 levels, and achieving net-zero emissions by 2050 economy-wide. The plan calls for aggressive measures focused on clean transportation, clean energy and climate investments targeted at environmental justice communities. In support of this plan, federal funding and incentive programs for clean transportation and energy offer opportunities for Eversource to invest in projects that have the ability to reduce emissions in the region while benefiting our communities and shareholders. Similarly, some of the states in which we operate have aggressive climate goals and implementation plans. In Connecticut, legislation includes a target to achieve zero-carbon electricity by 2040. In response to the 2021 Massachusetts climate legislation calling for increased electrification of the transportation and building sectors, in 2023, Eversource developed an Electric Sector Modernization Plan (ESMP) detailing steps the Company will take over the next five and ten years to help ensure reliability and resiliency while supporting a clean energy future. Similarly, the Massachusetts “Future of Gas” docket (DPU 20-80) looks to identify ways for natural gas local distribution companies to support the state’s net zero by 2050 climate goal. These state regulations and related policies may introduce risks and opportunities to our businesses if demands for energy or heating change.

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

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

• Improving our system resiliency in response to climate change through vegetation management, pole and wire strengthening, flood proofing, and other system hardening measures;

• Implementing a grid modernization plan that will enhance our electric distribution infrastructure to improve resiliency and reliability and increase opportunities to facilitate integration of distributed energy resources and electric vehicle infrastructure;

• Focusing on improving the efficiency of our electric and natural gas distribution systems, preparing for increased opportunities that clean energy advancements create, and providing customers with ways to optimize their energy efficiency;

• Investigating emerging technologies such as energy storage and automation programs that improve reliability;

• Implementing programs to address risks that may impact water availability and water quality; and

• Evaluating opportunities for our natural gas system and exploring alternative, less carbon-intense, technologies like renewable natural gas and geothermal for heating.

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

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

Eversource has made a corporate commitment to reduce Scope 1 and 2 GHG emissions from our operations and reach carbon neutrality by 2030. In December 2023, we submitted an application to the Science Based Target initiative (SBTi) seeking validation of a broader GHG target, which will expand our emission reduction efforts and include indirect Scope 3 sources. Greenhouse gas emissions from our operations consist primarily of line loss (emissions associated with the energy lost when power is transmitted and distributed across the electric system), methane leaks from our natural gas distribution system, operating our facilities and vehicle fleet, and sulfur hexafluoride (SF6) leaks from electric equipment. To measure our influences on climate change, we quantify and publicly report our operational carbon footprint through a third-party verified GHG emission inventory on an annual basis. Our initiatives to reduce GHG emissions across our company include improving energy efficiency and expanding the use of renewable energy at our buildings, utilizing alternative fuels and introducing more hybrid vehicles into the company fleet, reducing fugitive emissions of methane and SF6 by replacing leak-prone natural gas pipes, improving maintenance of SF6 electrical equipment, and piloting innovative technologies, such as alternative SF6 electrical equipment.

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

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

Electric and Magnetic Fields

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

HUMAN CAPITAL

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

As of December 31, 2023, Eversource Energy employed a total of 10,171 employees, excluding temporary employees, of which 1,529 were employed by CL&P, 2,044 were employed by NSTAR Electric, and 830 were employed by PSNH. In addition, 4,007 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 49 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by various collective bargaining agreements.

Safety. At Eversource, our commitment to “Safety First and Always” is a principle and a mindset present in every job and every task, whether in the field, office or at home. A priority at Eversource is continuous improvement and safety is at the forefront as we continue to build a strong safety culture, embrace new technologies, and learn with our industry and community partners to improve safety performance. We provide safety training and perform field safety job observations of both internal and contractor crews with a focus on high-energy hazards. We use metrics such as Eversource Corporate Days Away Restricted Time (DART) and High Energy Field Observations, among others, to monitor safety performance. Our DART safety performance was 0.81 in 2023, measured by days away, restricted or transferred per 100 workers, using the DART-OSHA method of measurement.

Diversity, Equity & Inclusion. Our commitment to Diversity, Equity & Inclusion (DEI) is critical to building a diverse, empowered and engaged team that delivers superior service safely to our customers. A diverse workforce and inclusive culture contribute to our success and sustainability by driving innovation and creating trusted relationships with our employees, customers, suppliers, and community partners. We continue to identify and support many programs and agencies that address disparities in our communities and beyond. We also remain committed to developing a workforce that fully reflects the diversity of the people and communities we serve. Our hiring practices emphasize inclusion, and we encourage employees to embrace different people, perspectives, and experiences in our workplace and within our communities. Additionally, our leadership behaviors underscore the importance of creating inclusive teams, where employees’ voices and contributions are essential to delivering superior customer service.

Eversource continues to develop a diverse workforce and has DEI goals and initiatives for diversity in leadership promotions and new hires, diverse external hires, number of diverse applicants for jobs, key talent, workforce representation including female employees, diverse employees, and veteran hires, leadership engagement, community support and supplier spending. Eversource drives accountability for DEI progress throughout the company and executive compensation is linked to meeting these goals. We sustained our successful drive to increase workforce diversity in 2023 with 55.9% of our external hires being women and/or people of color and 48.1% percent of new hires and promotions into leadership roles being women and/or people of color.

Eversource’s executive leadership team promotes and supports DEI by building and leading diverse, inclusive work teams with high engagement. Leaders are committed to growing a pipeline of diverse talent, leveraging multiple perspectives to improve customer service, using diverse suppliers, and engaging with multicultural organizations in our communities. Our DEI council, business resource groups, and cross-functional pro-

equity advisory team, which developed equity guidelines and began to implement justice and equity training to all employees starting in 2022 and continuing into 2024, provide our leaders with valuable feedback on the impact of our DEI and environmental justice efforts.

Eversource's Board of Trustees is committed to diversity, equity and inclusion and receives regular monthly progress updates. The Corporate Governance, Environmental and Social Responsibility Committee of the Board of Trustees is responsible for the oversight of environmental, human capital management and social responsibility strategies, programs and policies. The Board of Trustees seeks diversity in gender, race, ethnicity and personal background when considering Trustee candidates.

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

Talent Development, Training Programs and Education Opportunities. Strategic workforce plans are developed every year as part of the annual business planning process to address immediate and long-range needs and to ensure that Eversource acquires, develops and retains diverse, capable talent. Eversource supports and develops its employees through training and development programs that build and strengthen employees’ leadership and skill set. Employee development programs are aligned to our strategic workforce plan to support succession within all levels of the organization. Continuous professional development is important to support our employees’ ongoing success. These professional development programs include leadership effectiveness programs designed to develop new and current supervisors; a talent management process to identify high potential and emerging talent and ensure their development; multiple early career development programs in Engineering, Transmission and Operations; educational and professional development opportunities for employees who are recent college graduates; tuition assistance program; paid internships and co-ops; and workforce development programs focused on building a talent pipeline for our technical craft roles.

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

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

See Item 11, Executive Compensation, included in this Annual Report on Form 10-K, as well as our 2022 Sustainability Report and our 2022 Diversity, Equity and Inclusion Report located on our website, for more detailed information regarding our human capital programs and initiatives. Nothing on our website, including our Sustainability Report, our Diversity, Equity and Inclusion Report, or sections thereof, shall be deemed incorporated by reference into this Annual Report.

INTERNET INFORMATION

Our website address is www.eversource.com. We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site Eversource's, CL&P's, NSTAR Electric's and PSNH's combined Annual Reports on Form 10-K, combined Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 107 Selden Street, Berlin, CT 06037.

ES - Eversource Energy

Company Overview

Sector Information

Other Information