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.

~~From time to time, we~~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 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 could cause our actual results 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,

• the negative impacts of the novel coronavirus (COVID-19) pandemic, including any new or emerging variants, on our customers, vendors, employees, regulators, and operations,

• 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 economic conditions, including impact on interest rates, tax policies, and customer demand and payment ability,~~

• changes in levels or timing of capital expenditures,

~~disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,~~

• 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 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; •	~~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;

•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

~~Eversource~~ •Aquarion ~~Holdings, Inc.~~Company (Aquarion), a utility holding company that owns ~~three~~four 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.

On October 9, 2020, Eversource acquired certain assets and liabilities that comprised NiSource Inc.’s natural gas distribution business in Massachusetts, which was previously doing business as Columbia Gas of Massachusetts (CMA). The natural gas distribution assets acquired from CMA were assigned to 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.

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, and the generation facilities of PSNH before such facilities were sold in January and August 2018.~~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, ~~2019,~~2021, CL&P furnished retail franchise electric service to approximately ~~1.26~~1.27 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 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, under SS rates for customers with less than 500 kilowatts of demand (residential customers and small and medium commercial and industrial customers), and LRS rates for customers with 500 kilowatts or more of demand (larger commercial and industrial customers), CL&P purchases power under standard offer contracts and passes the cost of the purchased power to customers through a combined supply charge on customers' bills.

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

•An electric ~~GSC,~~generation service charge, which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers. The ~~GSC~~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 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 PURA of $1.099 billion effective May 1, 2018, $1.127 billion effective May 1, 2019, and $1.158 billion effective May 1, 2020. These pre-established levels of baseline distribution delivery service revenue requirement are also subject to adjustment at each of these dates in accordance with provisions of the April 2018 rate case settlement agreement.

•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.

•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.

•An 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, ~~and~~ any costs approved by the PURA to reduce these ~~charges.~~charges, as well as other costs approved by the 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 the PURA, with any difference refunded to, or recovered from, customers.

•A ~~CTA~~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 the 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 the 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 the PURA, with any difference refunded to, or recovered from, customers through an approved adjustment to the following year’s energy conservation spending plan budget.

An 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 the 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 charge, comprised of both a statutory rate and Conservation Adjustment Mechanism (CAM) established to implement cost-effective energy conservation programs and market transformation initiatives. The conservation charge is reconciled annually to actual costs incurred, and reviewed by the 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.~~2018, and incremental step adjustments effective May 1, 2019 and May 1, 2020.

~~Sources~~CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel (OCC), Office of the Attorney General (AG) and ~~Availability of Electric Power Supply~~

~~As noted above,~~the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory proceedings initiated by the PURA. PURA approved the settlement agreement on October 27, 2021. In accordance with the settlement agreement, CL&P has 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 ~~own~~apply to 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 2019, CL&P supplied approximately 46 percent of its customer load at SS or LRS rates while the other 54 percent of its customer load had migrated to competitive energy suppliers. In termscost recovery mechanism outside of the ~~total number of CL&P customers, this equates~~base distribution rates with regard to ~~25 percent being on competitive supply, while 75 percent remain with SS~~grid-modernization initiatives or ~~LRS. Because this customer migration is only for energy supply service, it has no impact~~any other proceedings, either currently pending or that may be initiated during the rate freeze period, that may place additional obligations on CL~~&P's electric distribution business or its operating income.~~

CL&P periodically enters into full requirements contracts for SS loads for periods of up to one year. CL&P typically enters into full requirements contracts for LRS loads every three months. Currently, CL&P has full requirements contracts in place for 100 percent of its SS loads for the first half of 2020. For the second half of 2020, CL&P has 70 percent of its SS load under full requirements contracts and intends to purchase an additional 30 percent of full requirements. None&P. The approval of the ~~SS load for 2021 has been procured. CL&P has full~~settlement agreement satisfies the Connecticut statute of rate review requirements ~~contracts in place for its LRS loads through June 2020 and intends~~that requires electric utilities to ~~purchase 100 percent of full requirements for the remainder of 2020.~~

~~ELECTRIC DISTRIBUTION – MASSACHUSETTS – NSTAR ELECTRIC COMPANY~~

~~NSTAR Electric's~~file a distribution ~~business consists primarily~~rate case within four years of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2019, NSTAR Electric furnished retail franchise electric service to approximately 1.44 million customers in Boston and 139 cities and towns in eastern and western Massachusetts, including 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 installed and completed nineteen new solar power facilities for a total of 62 MW by the end of 2019. These solar sites are in addition to the 8 MW of solar power facilities constructed between 2010 and 2014. NSTAR Electric now owns, operates and maintains a total of 70 MW of solar power facilities on twenty-two sites in Massachusetts. NSTAR Electric will sell energy from the new facilities into the ISO-NE market, with proceeds credited to customers.

~~Rates~~

NSTAR Electric is subject to regulation by the 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. NSTAR Electric purchases power from competitive suppliers on behalf of, and passes the related cost through to, its customers who do not choose a competitive energy supplier (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. Most of the residential customers of NSTAR Electric have continued to buy their power from NSTAR Electric at basic service rates. Most commercial and industrial customers have switched to a competitive energy supplier.

The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha's Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, consumer advocacy, competitive electricity supply and green power options. NSTAR Electric continues to provide electric service to these customers including the delivery of power, maintenance of infrastructure, capital investment, meter reading, billing, and customer service.

~~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 that 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 of $956 million on an annualized basis for 2018 and $988 million for 2019. Annual base distribution amounts are adjusted for inflation and filed for approval by the DPU on an annual basis, until the nextlast 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, credits related to the Tax Cuts and Jobs Act of 2017, grid modernization costs, and storm restoration. These charges are reconciled annually to actual costs incurred and reviewed by the DPU, with any difference refunded to, or recovered from, customers.

~~NSTAR Electric has signed long-term commitments for the purchase of energy from renewable energy facilities.~~

~~Distribution Rate Case:~~ ~~NSTAR Electric's distribution rates were established in a 2017 DPU-approved rate case with rates effective February 1, 2018.~~

~~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 2019 performance as the company achieved results at or above target for all of its SQ metrics in 2019.

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 2021, CL&P supplied approximately 49 percent of its customer load at SS or LRS rates while the other 51 percent of its customer load had migrated to competitive energy suppliers. In terms of the total number of CL&P customers, this equates to 19 percent being on competitive supply, while 81 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 the 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. Currently, CL&P has full requirements supply contracts in place for 100 percent of its SS load for the first half of 2022. For the second half of 2022, 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. None of the SS load for 2023 has been procured. CL&P has full requirements supply contracts in place for its LRS load through June 2022 and intends to purchase 100 percent of full requirements for the remainder of 2022.

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, 2021, NSTAR Electric furnished retail franchise electric service to approximately 1.46 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 will sell energy from these facilities into the ISO-NE market, with proceeds credited to customers.

Rates

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 that 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, credits related to the Tax Cuts and Jobs Act of 2017, grid modernization costs, and storm restoration. 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's distribution rates were established in a 2017 DPU-approved rate case with rates effective February 1, 2018. DPU-approved inflation-based adjustments to annual base distribution amounts were effective annually beginning in 2019 and last through 2022. On January 14, 2022, NSTAR Electric filed an application with the DPU for new base distribution rates to be effective January 1, 2023.

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 2021 performance as the company achieved results at or above target for all of its SQ metrics in 2021.

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 4530 percent of its residential and 23 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 1813 percent of its large C&I customers every three months.

During ~~2019,~~2021, NSTAR Electric supplied approximately 4417 percent of its ~~residential customer load, 31 percent of its small C&I customer load, and 8 percent of its large C&I~~overall customer load at basic service rates. The ~~remainder~~remaining 83 percent of its overall customer load was ~~distributed between~~served either by municipal aggregation ~~and~~or competitive supply. Because customer migration is limited to energy supply service, it has no impact on ~~the delivery~~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, ~~2019,~~2021, PSNH furnished retail franchise electric service to approximately ~~523,000~~532,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles.

On January 10, 2018, PSNH completed the sale of its thermal generation assets pursuant to a 2017 purchase and sale agreement. The thermal generation facilities included approximately 1,100 MW of coal, natural gas, biomass and oil-fired electricity generation facilities. On August 26, 2018, PSNH completed the sale of its hydroelectric generation assets pursuant to a separate 2017 purchase and sale agreement. For further information, see "Generation Divestiture" below. As of December 31, 2019, PSNH does not own any electric generation facilities.

Rates

PSNH is subject to regulation by the 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. ~~During 2019, approximately 23 percent of all of PSNH's~~For those customers ~~(approximately 56 percent of load) were taking service from~~who do not choose a competitive energy ~~suppliers.~~supplier, PSNH purchases power on behalf of, and passes the related cost through to, those customers (default energy service).

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 that have not migrated to competitive energy suppliers. Through March 31, 2018, the default energy service charge recovered the costs of PSNH's generation, as well as purchased power, and included an allowed ROE of 9.81 percent. Effective April 1, 2018, as a result of the completion of the divestiture of its non-hydro generation assets, PSNH purchased power for retail customers who had not chosen a competitive supplier through a periodic market solicitation with the rate set to recover the cost of that power, statutorily mandated renewable portfolio standard costs and the continued cost associated with the ownership of the Hydro generation units until the completion of the divestiture of the hydro units in August 2018. Effective September 1, 2018, any remaining costs from ownership of generation are recovered as part of the SCRC described below.

•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.

~~An SCRC,~~•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.

~~An SBC,~~•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 and SCRC rates change semi-annually 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:~~Case ~~PSNH~~: PSNH’s distribution rates were ~~last~~ established in a settlement approved by the NHPUC in 2010. Prior to the expiration of that settlement on June 30, 2015, the NHPUC approved the continuation of those rates, and increased funding via rates, of PSNH's reliability enhancement program.

On April 26, 2019, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase of approximately $33 million, effective July 1, 2019. On June 27, 2019, the NHPUC approved aDecember 2020 NHPUC-approved settlement agreement, ~~that~~with rates effective January 1, 2021. PSNH was reached by PSNH, the NHPUC Staff, the Office of the Consumer Advocate, and another settling party, to implement a temporary annual base distribution rate increase of $28.3 million. Although new rates were implemented onalso permitted three step increases, effective January 1, 2021, August 1, 2019 to customers, the provisions of the temporary base distribution rate increase were effective July 1, 2019. The settlement agreement also permits PSNH to recover approximately $68.5 million in unrecovered storm costs over a five-year period beginning2021, and August 1, ~~2019, with debt carrying charges, which is included in the temporary rate increase.~~

On May 28, 2019, PSNH filed an application with the NHPUC for a permanent increase in base distribution rates of approximately $70 million, effective July 1, 2020, which includes the temporary rate increase request. The temporary rates are subject to reconciliation based on the outcome of the permanent rate case now before the NHPUC. The NHPUC is permitted up to twelve months to adjudicate the permanent rate application from the date of filing. A decision by the NHPUC is expected in the second quarter of 2020.

~~Generation Divestiture~~

In June 2015, Eversource and PSNH entered into the 2015 Public Service Company of New Hampshire Restructuring and Rate Stabilization Agreement, pursuant to which PSNH agreed to divest its generation assets, subject to NHPUC approval. The NHPUC approved this agreement as well as the final divestiture plan and auction process in 2016. On October 11, 2017, PSNH entered into two Purchase and Sale Agreements with private investors, one to sell its thermal generation assets at a purchase price of $175 million, subject to adjustment, (the “Thermal Agreement”) and a second to sell its hydroelectric generation assets at a purchase price of $83 million, subject to adjustment (the “Hydro Agreement”). The NHPUC approved these agreements in late November 2017.

On January 10, 2018, PSNH completed the sale of its thermal generation assets pursuant to the Thermal Agreement. In accordance with the Thermal Agreement, the original purchase price of $175 million was adjusted2022, to reflect ~~working capital adjustments, closing date adjustments~~plant additions in calendar years 2019, 2020 and proration of taxes and fees prior to closing, totaling $40.9 million. In the second quarter of 2018, the purchase price was further adjusted by $17.3 million relating to the valuation of certain allowances. As a result of these adjustments, net proceeds from the sale of the thermal assets totaled $116.8 million.2021, respectively.

On July 16, 2018, FERC issued its order approving the transfer of PSNH's six hydroelectric licenses to private investors. On August 26, 2018, PSNH completed the sale of its hydroelectric generation assets pursuant to the Hydro Agreement. In accordance with the Hydro Agreement, the original purchase price of $83 million was adjusted to reflect contractual adjustments totaling $5.8 million, resulting in net proceeds of $77.2 million. The difference between the carrying value of the hydroelectric generation assets and the sale proceeds resulted in a gain of $17.3 million. An estimated gain from the sale of these assets was included as an offset to the total remaining costs associated with the sale of generation assets that were securitized on May 8, 2018.

On May 8, 2018, PSNH Funding issued $635.7 million of securitized RRBs pursuant to a finance order issued by the NHPUC on January 30, 2018 to recover remaining costs resulting from the divestiture of PSNH’s generation assets, which included the deferred costs resulting from the sale of the thermal generation assets. These RRBs are secured by a non-bypassable charge recoverable from PSNH customers. PSNH recorded regulatory assets and other deferred costs in connection with the generation asset divestiture and the securitization of remaining costs, which are probable of recovery through collection of the non-bypassable charge.

On November 27, 2019, PSNH filed a motion for the commencement of audit of divestiture-related costs. PSNH’s actual balance of costs eligible for recovery as divestiture-related costs is $654.0 million, which is above the $635.7 million amount securitized in May 2018. PSNH proposed to recover this balance through the SCRC tracker mechanism and believes the amount deferred is probable of recovery.

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 7882 percent of its residential and small C&I customers and for 1417 percent of its large C&I customers.

During ~~2019,~~2021, PSNH supplied approximately 4347 percent of its customer load at default energy service rates while the other 5753 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

~~Each of~~ CL&P, NSTAR Electric and PSNH ~~owns~~each own and ~~maintains~~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 2021, our estimated transmission rate base was approximately $8.7 billion, including approximately $3.8 billion at CL&P, $3.5 billion at NSTAR Electric, and $1.4 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")~~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.

On November 21, 2019, FERC issued ~~an order concerning~~Opinion No. 569 affecting the two pending transmission ~~ROEs for~~ROE complaints against the Midcontinent ISO (MISO) transmission owners, ~~(MISO). In that order,~~in which FERC adopted ~~another~~a new methodology for determining base ~~ROEs for MISO, which differed significantly from the methodology and framework set forth in its October 16, 2018 FERC order on the NETOs’ ROE dockets.~~ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed ~~a Supplemental Paper Hearing Brief and a Motion to supplement the record~~supplementary materials in the ~~NETO ROE dockets~~NETOs' four pending cases to respond to ~~the~~this new methodology ~~proposed in~~because of the ~~MISO order, as there is~~ uncertainty ~~to whether it may be applied~~of the applicability to the ~~NETOs’~~NETOs' cases.

On ~~January~~May 21, 2020, the FERC issued anits order ~~granting rehearing for further consideration to give the FERC more time to act~~in Opinion No. 569-A on the ~~substantive issues~~rehearing of the MISO ~~ROE proceedings. Further changes to~~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 are ~~possible as a result of~~currently under appeal with the ~~arguments in both the MISO and NETO proceedings.~~ Court.

Given the significant uncertainty ~~relating~~regarding the applicability of the FERC opinions in the MISO transmission owners' two complaint cases to the October 2018 FERC order, the November 2019 FERC order to MISO, and the FERC's rehearing of the MISO order, the Company is unable to predict the potential effect of the MISO order on the NETO complaints or the outcome of theNETOs' pending four ~~complaints and~~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. ~~Further, the Company~~As well, Eversource cannot reasonably estimate a range of any gain or loss for any of the four complaint ~~proceedings.~~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.

Transmission Projects

During ~~2019,~~2021, we were involved in the planning, development and construction of a series of electric transmission projects that ~~will be built within the next two years and that will~~ enhance system reliability and improve capacity. For more information on transmission projects, see "Business Development and Capital Expenditures – Electric Transmission Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Northern Pass was Eversource's planned 1,090 MW HVDC transmission line that would have interconnected from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. As a result of a final decision received on July 19, 2019 from the New Hampshire Supreme Court, whereby the court denied Northern Pass’ appeal and affirmed the NHSEC’s denial of Northern Pass’ siting application on NPT, Eversource concluded that construction of NPT was no longer probable and that there was no constructive path forward for the project. Eversource terminated the project and permanently abandoned any further development. As a result, substantially all of the capitalized project costs, which totaled $318 million, certain of which are subject to cost reimbursement agreements, were impaired. For further information, see "Critical Accounting Policies - Impairment of Northern Pass Transmission" in the accompanying Item 7, ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

~~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, and with the exception of transmission projects that received specific FERC approval to include CWIP in rate base, transmission projects generally enter rate base after they are placed in commercial operation. At the end of 2019, our estimated transmission rate base was approximately $7.3 billion, including approximately $3.3 billion at CL&P, $2.9 billion at NSTAR Electric, and $1.1 billion at PSNH.

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 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 the first quarter of 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 ~~300,000~~303,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square ~~miles, and~~miles. EGMA distributes natural gas to approximately 335,000 customers in 65 communities throughout Massachusetts covering 1,206 square miles. Yankee Gas distributes natural gas to approximately ~~241,000~~249,000 customers in 7274 cities and towns in Connecticut covering ~~2,187~~2,632 square miles. Total throughput (sales and transportation) in ~~2019~~2021 was approximately ~~73.5~~66.9 Bcf for NSTAR Gas, 53.4 Bcf for EGMA, and ~~58.4~~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 that rely on natural gas for space heating, hot water, cooking and commercial and industrial applications.

A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource Energy. NSTAR Gas has access to Hopkinton LNG Corp. facilities in Hopkinton, Massachusetts consisting of a LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas. NSTAR Gas also has access to Hopkinton LNG Corp. facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf. Total vaporization capacity of these facilities is 0.21 Bcf per day. Yankee Gas owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, 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.

NSTAR Gas, EGMA and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. ~~While all~~All NSTAR Gas and EGMA retail customers have the ability to choose to ~~transport natural~~purchase gas infrom third party marketers under the Massachusetts Retail Choice program. In the past year ~~transportation~~in Massachusetts, Retail Choice represented only approximately ~~three~~one percent of the total residential load, while ~~transportation~~Retail Choice represented approximately 5859 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. Firm transportation service is offered to customers who purchase natural gas from sources other than NSTAR Gas, EGMA or Yankee Gas. NSTAR Gas ~~has~~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 that 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 Liquefied Petroleum Gas (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 ~~Yankee Gas~~EGMA are subject to regulation by the DPU and Yankee Gas is subject to regulation by the PURA, ~~respectively,~~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 ~~files~~and EGMA file interim changes to ~~its~~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 and costs associated with low income customers. 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 Revenue Decoupling Mechanism (RDM) at NSTAR 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 DPU in 2015. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment in accordance with provisions of the November 2015 NSTAR Gas distribution rate case.

A Purchased Gas Adjustment (PGA) clause, which is evaluated monthly and allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers. Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered from, or refunded to, customers during the following 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 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, as well as recovery of any lost revenues associated with implementation of energy conservation measures.~~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 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 effective January 1, 2019, January 1, 2020 and January 1, 2021. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment at each of these dates in accordance with provisions of the 2018 rate case settlement agreement.

•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 ~~purchases financial contracts based on~~and EGMA that reconciles annual base distribution rate recovery amounts recovered from customers to the ~~New York Mercantile Exchange (NYMEX) natural gas futures in order to reduce cash flow variability associated with the price for approximately one-third~~pre-established level of ~~its normal winter season natural gas supplies. These purchases are made under a program~~baseline distribution delivery service revenue requirement approved by the DPU in ~~2006. This practice attempts~~2020. The pre-established level of baseline distribution delivery service revenue requirement is also subject to ~~minimize~~adjustment in accordance with provisions of the impact of fluctuations in natural gas prices to NSTAR Gas' firm natural gas customers. These financial contracts do not procure natural gas supply. All costs incurred or benefits realized when these contracts are settled are included in the CGAC.

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 in 2018. 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.

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 aan SQ charge for ~~its 2019~~their 2021 performance as iteach achieved results at or above target for all of ~~its~~their SQ metrics in ~~2019.~~2021.

Distribution Rate ~~Case:~~Cases ~~On November 8, 2019,~~:

NSTAR Gas: NSTAR Gas ~~filed its application~~distribution rates were established in an October 2020 DPU-approved rate case, with rates effective November 1, 2020. NSTAR Gas' 2019 plant additions were allowed recovery beginning on November 1, 2021. DPU-approved inflation-based adjustments to annual base distribution amounts were 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 ~~DPU, which sought a~~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 ~~$38.0 million effective October 1, 2020. As part of this filing, NSTAR Gas also proposed to continue its ongoing Gas System Enhancement Program (GSEP), include the GSEP investments since 2015 into~~distribution base rates ~~and implement a performance-based ratemaking plan. A final decision from the DPU is expected by September 30, 2020.~~effective prior to November 1, 2028.

Yankee Gas: Yankee Gas distribution rates were ~~set~~established in a December 2018 ~~PURA approved~~PURA-approved rate case settlement agreement, with rates effective November 15, 2018. The 2018 Yankee Gas settlement agreement required Yankee Gas to implement a Distribution Integrity Management Program (DIMP) cost recovery mechanism to further invest capital to replace aging infrastructure. The DIMP mechanism allows for recovery of costs associated with capital additions of approximately $26 million to $37 million annually, which is incremental to the $150 million included in base distribution rate base per year. The settlement agreementPURA also provides Yankee Gas the opportunity to seek recovery of additional capital spending above these levels with PURA approval. PURA ordered an accelerated replacement program for Yankee Gas to fully replace its cast iron and bare steel facilities in 11 years and fully replace copper services and certain steel mains and services in 14 years. Yankee Gas was also authorized to continue its ongoing natural gas system expansion program, implement a revenue decoupling rate mechanism, and recover merger costs. The settlement agreement included a regulatory ROE of 9.3 percent. In addition, the distribution rates charged to customers were adjusted to reflect the prospective impacts of the lower federal corporate income tax rate, the overcollection of the lower income tax rate from January 1, 2018, and the EDIT from the Tax Cuts and Jobs Act. Although new rates wereapproved step adjustments effective January 1, 2019, ~~the provisions of the settlement agreement took effect November 15, 2018.~~January 1, 2020 and March 1, 2021.

Natural Gas Replacement ~~and Expansion~~

Massachusetts: Pursuant to Massachusetts legislation, in October of each year, NSTAR Gas ~~files the~~and EGMA file GSEP Plans with the DPU for the following construction year. ~~NSTAR Gas' program accelerates~~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.

~~NSTAR Gas'~~In October 2020, the DPU opened Docket “DPU 20-80 The Future of Gas” to examine the role of Massachusetts natural gas local distribution ~~rate case application filed on November 8, 2019 included a proposal~~companies (LDCs) in helping to ~~include GSEP additions through 2018 into base distribution rates~~meet the state’s 2050 climate goals. The DPU will consider new policies and structures that would protect ratepayers as Massachusetts works to ~~continue~~decarbonize the ~~operation~~building sector, potentially recasting the role of ~~the GSEP mechanism for GSEP investments made after 2018. In addition, the filing included a proposal for a customer connection surcharge,~~LDCs in Massachusetts, which ~~would be used to reduce up-front contribution in aid of construction (CIAC) costs for customers seeking to connect~~may require significant changes to the ~~company’s distribution system. A final decision from~~LDCs planning processes and business models. At this time, Eversource cannot predict the ~~DPU~~ultimate outcome of this proceeding and the resulting impact to its natural gas businesses, however the Company does not believe there is ~~expected by September 30, 2020.~~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”)~~(GSI) rate recovers accelerated pipeline replacement as well as other capital investment through an annual reconciliation. ~~The Company filed~~Yankee Gas files its ~~first~~ GSI reconciliation annually on March ~~1, 2019~~1st for rates effective April ~~1, 2019 and will continue to file annually on March 1 for rates effective April 1.~~1st.

In 2013, in accordance with Connecticut law and regulations, the PURA approved a comprehensive joint natural gas infrastructure expansion plan (the "Expansion Plan") filed by Yankee Gas and other Connecticut natural gas distribution companies. In January 2015, the PURA approved a joint settlement agreement proposed by Yankee Gas and other Connecticut natural gas distribution companies and regulatory agencies that clarified the procedures and oversight criteria applicable to the Expansion Plan. Yankee Gas received approval from PURA for its 2014, 2015 and 2016 System Expansion Reconciliations. Yankee Gas filed its 2017 and 2018 System Expansion Reconciliations in March 2018 and March 2019, respectively. Yankee Gas is now awaiting an order and does not anticipate any material changes to its 2017 and 2018 Reconciliations.

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, ~~of which~~and 3.5 Bcf LNG storage is provided by Hopkinton LNG Corp. in facilities located in ~~Hopkinton and Acushnet,~~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.

The 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, ~~will necessitate~~ a combination of pipeline, storage, and non-pipeline ~~solutions.~~solutions will be necessary.

WATER DISTRIBUTION SEGMENT

~~Eversource Water Ventures, Inc., a Connecticut corporation, through its wholly-owned subsidiary, Eversource~~ Aquarion ~~Holdings, Inc.~~Company (Aquarion), operates ~~three~~four separate regulated water utilities in Connecticut (Aquarion Water Company of Connecticut, or ~~“AWC-CT”)~~AWC-CT), Massachusetts (Aquarion Water Company of Massachusetts, or ~~“AWC-MA”) and~~AWC-MA), New Hampshire (Aquarion Water Company of New Hampshire, or ~~“AWC-NH”)~~AWC-NH) and Abenaki Water Company (Abenaki). These regulated companies provide water services to approximately ~~229,000~~226,000 residential, commercial, industrial, municipal and fire protection and other customers, in 6068 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, ~~2019,~~2021, approximately 8792 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”)~~(RAM) that reconciles earned revenues, with certain allowed adjustments, on an annual basis, to the revenue requirement approved by the ~~PURA in AWC-CT’s last rate case (2013), which is an annual amount of $178.0 million.~~PURA.

•In Connecticut and New Hampshire, a water infrastructure conservation adjustment ~~(“WICA”)~~(WICA) charge, and in Massachusetts, an annual main replacement adjustment mechanism ~~(“MRAM”)~~(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,~~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.

In Massachusetts, treatment plant surcharges, which are a series of three surcharges (one fixed and two volumetric in nature) that are designed to recover certain operating costs and the costs of the lease of the treatment plant located in Hingham. These surcharges are applicable only to customers in Hingham, Hull and Cohasset.

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 ~~131~~127 million gallons per day, as well as water purchased from other water suppliers. Approximately 99 percent of our annual production is self-supplied and processed at 10nine 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 PROJECTS

Eversource's offshore wind business includes a 50 percent ownership ~~interests~~interest in North East Offshore, ~~and Bay State Wind,~~ which ~~together hold~~holds power purchase agreements (PPAs) and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as offshore leases ~~through the U.S. Bureau of Ocean Energy Management (BOEM).~~issued by BOEM. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted. This partnership also participates in new procurement opportunities ~~for solicitations~~ for offshore wind energy in the Northeast U.S.

~~On February 8, 2019, Eversource and Ørsted entered into an equal partnership to acquire key~~The offshore ~~wind assets in the Northeast. Eversource has a 50 percent ownership interest in North East Offshore, which holds the Revolution Wind and South Fork Wind projects, as well as~~leases include a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode ~~Island. Eversource also has~~Island and a ~~50 percent ownership interest in Bay State Wind, which holds the Sunrise Wind project. Bay State Wind's~~ separate, ~~300-square-mile~~adjacent 300 square-mile ocean lease is located approximately 25 miles south of the coast of ~~Massachusetts adjacent to the North East Offshore area.~~Massachusetts. In aggregate, ~~the Bay State Wind and the North East Offshore~~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 ~~an 880~~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, and engineering, state siting and permitting in New York, ~~and~~ Rhode Island and ~~finalizing a PPA amendment in New York.~~Massachusetts. For more information on these projects, 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.

~~NATURAL GAS TRANSMISSION PROJECT~~

Access Northeast was a natural gas pipeline and storage project jointly owned by Eversource, Enbridge, Inc. (Enbridge) and National Grid plc (National Grid), through Algonquin Gas Transmission, LLC (AGT). In 2018, management determined that the future cash flows of the Access Northeast project were uncertain and could no longer be reasonably estimated and that the book value of our equity method investment was not recoverable. As a result, Eversource recorded an other-than-temporary impairment of $32.9 million pre-tax within Other Income, Net on our statement of income in 2018, which represented the full carrying value of our equity method investment. On April 1, 2019, in accordance with a provision of the AGT LLC operating agreement, the Access Northeast project was terminated. For further information, see "Critical Accounting Policies - Access Northeast" in the accompanying Item 7, ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

PROJECTED CAPITAL EXPENDITURES

We project to make capital expenditures of ~~$14.19~~$18.14 billion from ~~2020~~2022 through ~~2024,~~2026, of which we expect ~~$8.63~~$7.02 billion to be in our electric ~~and~~distribution segment, $4.53 billion to be in our natural gas distribution ~~segments, $3.98~~segment, $4.60 billion to be in our electric transmission segment and ~~$0.69~~$0.89 billion to be in our water distribution segment. We also project to invest ~~$0.90~~$1.10 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to our offshore wind ~~partnership.~~ business.

FINANCING

~~Our credit facilities~~For information regarding short-term and indentures require that Eversource parent and certain of its subsidiaries, including CL&P, NSTAR Electric, PSNH, NSTAR Gas, Yankee Gas, and Aquarion, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent. All of these companies currently are, and expect to remain, in compliance with these covenants.

~~As of December 31, 2019, $296.1 million of Eversource's~~ long-term debt ~~including $95.0 million, $50.0 million, $150.0 million,~~agreements, see "Liquidity" in the accompanying Item 7, Management's Discussion and ~~$1.1 million for NSTAR Electric, Yankee Gas, NSTAR Gas~~Analysis of Financial Condition and ~~Aquarion, respectively, will mature within~~Results of Operations, and Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt," of the ~~next 12 months.~~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 ~~more~~greater than 50 percent of each of these companies.

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated ~~in virtually all aspects of our business~~ 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 ~~NHPUC, which has jurisdiction over PSNH and Aquarion, and the~~ DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas, EGMA and Aquarion, and the NHPUC, which has jurisdiction over PSNH and Aquarion.

~~Environmental Regulation~~

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, major generation and transmission facilities 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.

Renewable Portfolio Standards

Each of the states in which we do business also 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.

New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2019, the total RPS obligation was 19.7 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.

~~Similarly,~~ Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In ~~2019,~~2021, the total RPS obligation was ~~27.5~~30.5 percentand will ultimately reach 4848.0 percent in 2030. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its ~~GSC~~Generation Service Charge rate.

Massachusetts' RPS program ~~also~~ requires electricity suppliers to meet renewable energy standards. For ~~2019,~~2021, the ~~requirement was 24.94~~RPS and Clean Energy Standard (CES) requirements were 49.26 percent, and will ultimately reach ~~38.96~~57.30 percent in 2025. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 5.25 percent and Clean Peak Energy Standards (CPS) of 3.0 percent in 2021. 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 ~~RPS~~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 2021, the total RPS obligation was 21.6 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

We are subject to various federal, state and local environmental legislation and regulation with respect to water quality, air quality, 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 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 any construction period-impacts.

Hazardous Materials Regulations

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~~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 hazardous ~~waste~~material sites. As of December 31, ~~2019,~~2021, 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 ~~$81.0~~$115.4 million, representing 5761 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 ~~$67.9~~$105.6 million of the total ~~$81.0~~$115.4 million as of December 31, ~~2019.~~2021. 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 plans adhere to applicable regulations while protecting human health and the environment. Projects that may be located in the vicinity of regulated resource areas (wetlands, waterways) are permitted to address local, state and federal requirements. In many cases, these 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 government and state governments. The Biden Administration has communicated a renewed 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. Similarly, the states in which we operate have aggressive climate goals and implementation plans. In Massachusetts, climate legislation was passed in 2021 requiring aggressive measures across all sectors to meet the state’s goal of achieving net-zero emissions by 2050 and Connecticut legislation includes a target to achieve zero-carbon electricity by 2040. 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 utility businesses. Potential future environmental statutes and regulations, such as additional greenhouse gas reduction regulation 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: Physical risks from climate change may result from sea level rise and shifting weather conditions, such as changes in precipitation, 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 business is transitioning in response to climate change and our evolution to a low-carbon environment. We actively support state and federal emission reduction goals and are developing adaptation and resiliency strategies to address climate change. We have implemented measures and made investments to strengthen our infrastructure to continue delivering reliable energy to customers and enable the integration of clean energy resources. Our system hardening and grid modernization programs also reduce the potential impact of severe weather events due to climate change on our electric transmission and distribution systems and natural gas facilities.

We have made a corporate commitment to reduce greenhouse gas emissions from our operations and reach carbon neutrality by 2030. Greenhouse gas emissions from our operations consist primarily of line loss (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 leaks from electric equipment. To measure our influences on climate change, we quantify and publicly report our operational carbon footprint through a comprehensive 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 sulfur hexafluoride by replacing leaky natural gas pipes, improving maintenance of electrical equipment, and piloting innovative technologies.

To address physical and transitional impacts related to climate change and maintain resiliency across our system in the face of climate change, we are pursuing the following actions:

•Working with our regulators to gain approval for new programs that will help improve our system resiliency in response to climate change, including 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 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 the opportunities that clean energy advancements create, and providing customers with ways to minimize their energy use;

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

Electric and Magnetic Fields

For more than ~~twenty~~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, ~~and~~including appliances, and wiring in buildings and homes. ~~Although weak~~Some epidemiology studies have reported a possible statistical association between adverse health ~~risk associations reported~~effects and exposure with EMF. The association identified in some ~~epidemiology~~of these studies remain unexplained ~~most researchers, as well as numerous~~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 ~~the~~a conclusion that EMF affects human ~~health.~~

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~~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. We recognize our employees are our most valuable asset and 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, 2021, Eversource Energy employed a total of 9,227 employees, excluding temporary employees, of which 1,382 were employed by CL&P, 1,599 were employed by NSTAR Electric, and 765 were employed by PSNH. In addition, 3,335 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 51 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 14 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 0.9 in 2021, measured by days away, restricted or transferred per 100 workers.

In our continued response to the COVID-19 pandemic, we operated under our company-wide pandemic plan in the best interest of our employees, customers, and communities. This included having nearly half of our employees working remotely, while implementing additional significant safety measures for employees that continued critical on-site work. State and federal guidelines, public health guidance, external conditions, and critical business priorities continue to inform our plan, with the safety of our employees and customers as our highest priority. By the end of 2021, we completed the re-entry phase of our pandemic response plan for those of our employees that were working remotely. Significant health and safety measures and pandemic protocols have remained in place, including the use of ~~designs~~personal protective equipment, social distancing requirements, sanitization efforts and employee training. No employees were subject to lay-offs as a result of the pandemic. We covered COVID-19 testing, treatment and vaccinations at no cost to our employees and their dependents under our medical plans. Beginning July 1, 2021, we provided all employees additional paid time off for COVID-related absences.

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 work toward 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, 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 2021, 57% of our external hires were women or people of color and 41.2% percent of new hires and promotions into leadership roles were women 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 cross-functional pro-equity advisory team.

Eversource's Board of Trustees is committed to diversity 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, ethnicity and personal background when considering Trustee candidates. Our Board of Trustees has been recognized as one of the most diverse in our industry.

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 support 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 2020 Sustainability Report located on our website, for more detailed information regarding our human capital programs and initiatives. Nothing on our website, including our Sustainability 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. 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. Although we did not experience any material impacts from the SolarWinds event in 2020 or the Log4j security vulnerability that was widely publicized in December 2021, there can be no assurance that we will not experience future events that may be material. 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 ~~without~~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 avert, prevent or stop 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 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 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. Our offshore wind partnership’s ability to generate returns from its offshore wind projects will depend on meeting construction schedules, controlling cost overruns, 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 delays in offshore wind projects, any changes to tax laws impacting Eversource’s ability to monetize tax attributes associated with these projects, or the cancellation of any projects, as well as the other risk factors described above, 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 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. As a result of our acquisition of the Columbia Gas of Massachusetts (CMA) assets from NiSource on October 9, 2020, we have entered into a Transition Services Agreement with NiSource whereby NiSource is performing certain services on behalf of Eversource Gas Company of Massachusetts in the areas of information technology, transaction processing, human resources, payroll and payroll processing and certain operational areas for periods ranging from 1 to 24 months from the acquisition date. 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. Due to the COVID-19 pandemic and current state of the global economy as a whole, we may experience supply chain issues with obtaining key materials, equipment or services timely and at a reasonable price across all business lines. We also continue to pursue enhancements to standardize our systems and processes. If any difficulties in the global supply chain cycle or operation of these systems were to occur, 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; extreme weather conditions 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 operation 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.

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. In addition, a significant portion of our workforce in our subsidiaries, including many workers with specialized skills maintaining and servicing the electric, natural gas and water infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals 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 and extreme weather events. Customers’ energy 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.

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 supplies, including water provided to our customers, are 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 ~~modest cost.~~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 ~~do not believe~~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.

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 ~~expenditures~~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 ~~appropriate~~required to ~~minimize unsubstantiated risks.~~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 prudency reviews by state regulators, whereby various portions of rates could

~~Global Climate Change~~be adjusted, subject to refund or disallowed, including cost recovery mechanisms. The ultimate outcome and ~~Greenhouse Gas Emission Issues~~timing of regulatory rate proceedings 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.

~~Global climate change~~There can be no assurance that regulators will approve the recovery of all costs incurred by our electric, natural gas and ~~greenhouse~~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. 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, 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 ~~emission issues~~and water utility subsidiaries, have ~~received an increased focus from state governments~~large customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the ~~federal government. The EPA initiated~~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 ~~rulemaking addressing greenhouse gas emissions~~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.

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 December 7, 2009, issued a finding that concluded that greenhouse gas emissions are "air pollution" that endangers public health and welfare and should be regulated. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspectsthe reputation of our business, ~~including volume~~on the morale and performance of ~~gas supplied to large~~our employees and on our relationships with respective regulators, customers and ~~fugitive emissions~~counterparties. The direct and indirect effects of ~~SF6 gas~~negative publicity, and ~~methane.~~the demands of responding to and addressing it, may have a material adverse effect on our financial position, results of operations and cash flows.

~~We are continually evaluating the regulatory risks~~Costs of compliance with environmental laws and ~~regulatory uncertainty presented by~~regulations, including those related to climate change, ~~concerns. Such concerns could potentially lead~~may increase and have an adverse effect on our business and results of operations.

Our subsidiaries' operations are subject to ~~additional~~extensive federal, state and local environmental statutes, rules and regulations that ~~impact how we operate our general utility business. These could include federal "cap~~govern, among other things, water quality, water discharges, the management of hazardous material and ~~trade" laws, carbon taxes,~~solid waste, and ~~fuel~~air emissions. Compliance with these requirements requires us to incur significant costs relating to environmental permitting, monitoring, maintenance and ~~energy taxes. We expect that any~~upgrading of facilities, and remediation.

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 ~~rules~~costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the remediation levels required by state and ~~regulations~~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.

Pandemic Risks, including COVID-19 Related Risks:

As evidenced by the global pandemic of the 2019 novel coronavirus (COVID-19), global pandemics result in widespread disruption to the overall economic market and outlook, which could cause various unfavorable impacts to our customers, vendors, employees, regulators, and operations and could adversely affect our financial position, results of operations and cash flows.

The COVID-19 pandemic, including any new or emerging variants, continues to evolve, and the extent of the impact to us in the future will vary and depend in large part on the duration, scope and severity of the pandemic and the timing and extent of COVID-19 relief legislation, and the resulting impact on economic, health care and capital market conditions. The continuing effects of the COVID-19 pandemic could lead to an increased risk of cybersecurity attacks, interruptions in the global supply chain that impact us and our vendors, and the loss of key personnel, among other effects. The future impact will also depend on the outcome of future proceedings before our state regulatory commissions to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses, and our financial condition may be adversely affected depending on the outcome of those proceedings. As a result, we are currently unable to estimate the potential impact of COVID-19 to our financial position, results of operations and cash flows. See the accompanying Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information.

Financial, Economic, and Market Risks:

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, 2021, totaled $4.48 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.

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, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations. 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.

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 ~~recovered~~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, 2021, Eversource and our electric operating subsidiaries owned the following:


	Electric Distribution	Electric Transmission
Eversource
Number of substations owned	478	75
Transformer capacity (in kVa)	44,361,360	20,299,000
Overhead lines (in circuit miles)	40,515	3,980
Underground lines (in circuit miles)	18,050	421
Capacity range of overhead transmission lines (in kV)	N/A	69 to 345
Capacity range of underground transmission lines (in kV)	N/A	69 to 345


	CL&P		NSTAR Electric		PSNH
	Distribution	Transmission	Distribution	Transmission	Distribution	Transmission
Number of substations owned	181	21	173	32	124	22
Transformer capacity (in kVa)	21,890,000	3,633,000	18,027,360	11,615,000	4,444,000	5,051,000
Overhead lines (in circuit miles)	16,770	1,677	11,469	1,249	12,276	1,054
Underground lines (in circuit miles)	6,834	143	9,163	275	2,053	3
Capacity range of overhead transmission lines (in kV)	N/A	69 to 345	N/A	69 to 345	N/A	115 to 345
Capacity range of underground transmission lines (in kV)	N/A	69 to 345	N/A	115 to 345	N/A	115


	Eversource	CL&P	NSTAR Electric	PSNH
Underground and overhead line transformers in service	634,839	292,902	172,876	169,061
Aggregate capacity (in kVa)	38,386,798	16,443,711	14,842,428	7,100,659

Electric Generating Plants

As of December 31, 2021, NSTAR Electric owned the following solar power facilities:

Type of Plant

Number
of Sites

Year
Installed

Claimed Capability**
(kilowatts, dc)

Solar Fixed Tilt, Photovoltaic

2010 - 2019

70,000

** Claimed capability represents the direct current nameplate capacity of the plants.

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

Natural Gas Distribution System

As of December 31, 2021, NSTAR Gas owned 22 active gate stations, 148 district regulator stations, and approximately 3,322 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, 2021, EGMA owned 14 active gate stations, 193 district regulator stations, and approximately 5,014 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.

As of December 31, 2021, Yankee Gas owned 28 active gate stations, 207 district regulator stations, and approximately 3,530 miles of natural gas main pipeline. Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut.

Natural Gas Transmission System

As of December 31, 2021, NSTAR Gas and EGMA owned 1.0 and 2.36 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, 2021, Aquarion owned and operated sources of water supply with a combined yield of approximately 127 million gallons per day; 3,573 miles of transmission and distribution mains; 9 surface water treatment plants; 29 dams; and 123 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 ~~customers.~~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 the PURA and a determination by the 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 MassachusettsEversource 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 the 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 ConnecticutAWC-CT derives its 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, AWC-CT has, with minor exceptions, solid franchises free from burdensome restrictions and unlimited as to time, and is authorized to sell potable water in the towns (or parts thereof) in which water is now being supplied by AWC-CT.

In addition to the right to sell water as set forth above, the franchises of AWC-CT 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 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 to supply potable water for public or domestic use in its franchise areas.

Aquarion Water Company of MassachusettsThrough 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 HampshireThe NHPUC, pursuant to statutory law, has issued orders granting and affirming AWC-NH’s exclusive franchise 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. That franchise territory encompasses the towns of Hampton, North Hampton and Rye. Abenaki Water Systems territory encompasses the towns of Belmont, Bow, Carroll, and Gilford. Subject to NHPUC’s regulations, AWC-NH has 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 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 status as a regulated public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for the establishment of plant and equipment. It 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~~Transmission and Distribution System

~~For information about Eversource Energy's executive officers, see Item 10,~~
~~Directors, Executive Officers and Corporate Governance,~~ ~~included in this Annual Report on Form 10-K.~~

~~EMPLOYEES~~

As of December 31, ~~2019,~~2021, Eversource ~~Energy employed a total~~and our electric operating subsidiaries owned the following:


	Electric Distribution	Electric Transmission
Eversource
Number of substations owned	478	75
Transformer capacity (in kVa)	44,361,360	20,299,000
Overhead lines (in circuit miles)	40,515	3,980
Underground lines (in circuit miles)	18,050	421
Capacity range of overhead transmission lines (in kV)	N/A	69 to 345
Capacity range of underground transmission lines (in kV)	N/A	69 to 345


	CL&P		NSTAR Electric		PSNH
	Distribution	Transmission	Distribution	Transmission	Distribution	Transmission
Number of substations owned	181	21	173	32	124	22
Transformer capacity (in kVa)	21,890,000	3,633,000	18,027,360	11,615,000	4,444,000	5,051,000
Overhead lines (in circuit miles)	16,770	1,677	11,469	1,249	12,276	1,054
Underground lines (in circuit miles)	6,834	143	9,163	275	2,053	3
Capacity range of overhead transmission lines (in kV)	N/A	69 to 345	N/A	69 to 345	N/A	115 to 345
Capacity range of underground transmission lines (in kV)	N/A	69 to 345	N/A	115 to 345	N/A	115


	Eversource	CL&P	NSTAR Electric	PSNH
Underground and overhead line transformers in service	634,839	292,902	172,876	169,061
Aggregate capacity (in kVa)	38,386,798	16,443,711	14,842,428	7,100,659

Electric Generating Plants

As of ~~8,234 employees, excluding temporary employees, of which 1,343 were employed by CL&P, 1,604 were employed by~~December 31, 2021, NSTAR Electric owned the following solar power facilities:

Type of Plant

Number
of Sites

Year
Installed

Claimed Capability**
(kilowatts, dc)

Solar Fixed Tilt, Photovoltaic

2010 - 2019

70,000

** Claimed capability represents the direct current nameplate capacity of the plants.

CL&P and ~~742 were employed by PSNH. Approximately 50 percent~~PSNH do not own any electric generating plants.

Natural Gas Distribution System

Natural Gas Transmission System

As of December 31, 2021, NSTAR Gas and EGMA owned 1.0 and 2.36 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 ~~employees are members~~systems, including the collection, treatment, storage, and distribution of ~~the International Brotherhood~~water.

As of ~~Electrical Workers, the Utility Workers Union~~December 31, 2021, Aquarion owned and operated sources of ~~America or The United Steelworkers,~~water supply with a combined yield of approximately 127 million gallons per day; 3,573 miles of transmission and ~~are covered by nine collective bargaining agreements.~~distribution mains; 9 surface water treatment plants; 29 dams; and 123 wellfields.

~~INTERNET INFORMATION~~Franchises

~~Our website address is www.eversource.com. We make available through our website a link~~CL&P Subject to the ~~SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at~~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 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 websiteit 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.

now supplying such service.

~~Item 1A.Risk Factors~~

In addition to the ~~matters~~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 ~~"Safe Harbor Statement Under~~Connecticut law and the ~~Private Securities Litigation Reform~~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 ~~of 1995" included immediately~~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 ~~to Item 1,~~ approval from the PURA and a determination by the PURA that such purchase is in the public interest.

~~Business,~~NSTAR Electric ~~above, we~~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.

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 ~~variety of significant risks. Our susceptibility~~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 ~~risks, including those discussed~~regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Utility Commission.

NSTAR Gas Through its charter, which is unlimited in ~~detail below, could exacerbate other risks. These risk factors should be considered carefully~~time, NSTAR Gas has the right to engage in ~~evaluating our risk profile.~~

~~Cyberattacks, including acts~~the business of ~~war or terrorism, targeted directly on or indirectly affecting our systems or~~delivering and selling natural gas within its respective service territory, and has the ~~systems~~power incidental thereto and is entitled to all the rights and privileges of ~~third parties on which we rely, could severely impair operations, negatively impact our business, lead~~and subject to the ~~disclosure of confidential information and adversely affect our reputation.~~

~~A successful cyberattack on the information technology systems that control our transmission and~~duties imposed upon natural gas companies under Massachusetts laws. The locations in public ways for natural gas distribution ~~systems or other assets could impair or prevent us~~pipelines are obtained 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 devote substantial resources to network and application security, encryption~~municipal and other ~~measures~~state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to protect our computer systems and infrastructure from unauthorized access or misuse and 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 dueappeal to the ~~evolving nature~~DPU. The rights to these locations are not limited in time and are subject to the action of ~~cyberattacks. We maintain cyber insurance to cover damages~~these authorities and ~~defense costs related to breaches of networks or operational technology, but it~~the legislature. Under Massachusetts law, no other entity may ~~be insufficient to cover all losses.~~

~~Any such cyberattacks could result in loss of~~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 ~~a significant decrease in revenues, which could have a material adverse impact on our financial position, results~~the municipality so affected.

Eversource Gas Company of ~~operations and cash flows.~~

Strategic development opportunities associated with offshore wind or investment opportunities in electric transmission or clean-energy opportunities may not be successful, and projects may not commence operation as scheduled 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~~MassachusettsEversource Gas Company of Massachusetts holds valid franchises to the construction of offshore wind electric generation facilities, and investment opportunities in electric transmission facilities and other clean-energy infrastructure. The development of these activities involves numerous significant risks around schedule, cost, capacity factors, tax strategies and permitting (both on and offshore). Various external factors could result in increased costs or result in delays or cancellation of these projects. Risks include both federal and state regulatory approval processes, new legislation impacting the industry, changes to federal income tax laws, 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, and actions of our strategic partners. Should any of these factors result in significant delays or cancellations, our financial position, results of operations, and cash flows could be materially adversely affected, or our future growth opportunities may not be realized as anticipated.

~~Eversource has a joint and equal partnership with Ørsted for the development and operation of three offshore wind projects. Offshore wind is currently an emerging industry~~sell natural gas in the ~~U.S., but~~areas in which it ~~has a very robust operational and construction history~~supplies natural gas service. Generally, Eversource Gas Company of Massachusetts holds franchises to serve customers in ~~Europe. As such, siting, permitting, tax legislation, and supply chain are currently being addressed for the first time in the U.S. The projects currently being developed~~areas designated by our partnership may not achieve the results we anticipate. The partnership’s ability to generate revenue from offshore wind projects depends on meeting our construction schedules, controlling cost overruns, maintaining continuing interconnection arrangements, power purchase agreements, or other market mechanismsthose franchises as well as ~~interconnecting~~in most other areas throughout Massachusetts so long as those areas are not occupied and served by another natural gas utility ~~and Regional Transmission Organizations rules, policies, procedures and FERC tariffs that permit future offshore wind project operations. After projects~~under a valid franchise of its own or are ~~placed in operation, capacity factors will directly affect revenues generated from these investments. Other factors that may have~~not subject to an ~~adverse impact on our anticipated project returns include significant schedule delays resulting from federal, state~~exclusive franchise of another natural gas utility or ~~local permitting processes. Specifically, the approval from the Bureau of Ocean Energy Management (BOEM) is a critical path item~~by consent.

Yankee Gas Yankee Gas holds valid franchises to sell natural gas in the projects' timeline. Any changes to tax laws or to Eversource’s ability to monetize tax attributes associated with these projects could also have a material adverse effect on cash flows and project returns.

~~As a result of legislative and regulatory changes, the states~~areas in which ~~we provide service have implemented new selection procedures for new major electric transmission, offshore wind and~~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 ~~clean energy facilities. These procedures require the review of competing projects and permit the selection of only~~areas throughout Connecticut so long as those ~~projects that are expected to provide the greatest benefit to customers. If the projects in which we have invested~~areas are not selected for construction, or even if our projects are selected, then legislative or regulatory actions could result in our projects not being probable of entering the construction phase, which could have a material adverse effect on our future financial position, results of operationsoccupied and ~~cash flows.~~

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,served by another natural gas utility under a valid franchise of its own or ~~operate our systems efficiently or at all. Because our electric transmission systems~~ are ~~part~~not subject to an exclusive franchise 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~~another natural gas ~~distribution system is connected~~utility or by consent. Yankee Gas' franchises are perpetual but remain subject to ~~transmission pipelines, not owned~~the power of alteration, amendment or repeal by ~~Eversource, if there was an attack on~~ the ~~transmission pipelines, it could impact our ability~~General Assembly of the State of Connecticut, the power of revocation by the 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 ~~deliver natural gas. If our assets were physically damaged~~manufacture, generate, purchase, transmit 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 to cover all losses.

~~The actions of regulators and legislators can significantly affect our earnings, liquidity and business activities.~~

~~The rates that our electric,~~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 MassachusettsThrough 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 ~~charge their customers are determined by their state regulatory commissions and by~~under Massachusetts laws. AWC-MA has 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 NERC.

~~Under state and federal law, our electric, natural gas and water companies are entitled~~right 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 capitalconstruct and maintain ~~their financial integrity, while also protecting relevant~~its mains and distribution pipes in and under any public ~~interests. Each~~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 ~~these companies prepares~~the water distributed 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~~establish reasonable regulations regarding the ~~rates we are allowed to charge our customers and may not match~~same. Certain of the timing of when costs are incurred. Additionally, a catastrophic event not involving Eversource could result in our regulators and legislators imposing additional requirements that may lead to additional costs for the Company.

There is 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, as well as a reasonable return on their respective regulated assets. The amount of costs incurred by the companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting 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~~towns within our service ~~territories,~~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.

AWC-NH's status as a regulated public utility gives it the ability to ~~competition~~petition the NHPUC for ~~construction~~the right to exercise eminent domain for the establishment of ~~transmission projects, additional regulatory considerations,~~plant and ~~potential delay with respect to future transmission projects, which may adversely affect our results of operations and lower rate base growth.~~

~~Changes in tax laws, as well as~~equipment. It can also petition the ~~potential tax effects of business decisions could negatively impact our business, results of operations (including our expected project returns~~NHPUC for exemption from ~~our planned offshore wind facilities), financial condition and cash flows.~~

We outsource certain business functions to third-party suppliers and service providers, and substandard performance 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 other 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. We also continue to pursue enhancements to standardize our systems and processes. If any difficulties in the operation of ~~these systems were~~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 ~~occur, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.~~

~~The effects of climate change, including severe storms, could cause significant damage to any of our facilities requiring extensive expenditures,~~water supply withdrawal, the ~~recovery for which~~exemption 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 and extreme weather events including drought. Customers’ energy 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 imposedrecommended by the ~~communities we serve could impact water usage. To~~New Hampshire Department of Environmental Services.

Item 3.Legal Proceedings

We are involved in legal, tax and regulatory proceedings regarding matters arising in the ~~extent weather conditions are affected by climate change, customers’ energy~~ordinary course of business. For information regarding material lawsuits and ~~water usage could increase or decrease depending on the duration~~proceedings, see Note 13, “Commitments and ~~magnitude~~Contingencies,” of the ~~changes.~~Combined Notes to Financial Statements.

Severe weather, such as ice and snow storms, hurricanes, 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. 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 to cover all losses.

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; extreme weather conditions beyond equipment and plant design capacity; human error; 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 electricity transmission system may increase. Any failure of our transmission and distribution systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation 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 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.

~~Our water supplies, including water provided to our customers, are 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 condition, results of operations and cash flows. We maintain liability insurance, but it may be insufficient to cover all losses.~~

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, 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 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 avert, prevent or stop 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.

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

~~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, 2019, totaled $4.4 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. The annual goodwill impairment test in 2019 resulted in a conclusion that our goodwill was not impaired.

~~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. 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 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.

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

~~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 federal, state and local environmental statutes, rules and regulations that govern, among other things, water quality, water discharges, the management of hazardous and solid waste, and air emissions. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, maintenance and upgrading of facilities, remediation and permitting.

The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. 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~~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~~Matters" for information about toxic substances and hazardous materials, climate change, and other matters. In addition, see Item 1A, Risk Factors, ~~included in this Annual Report on Form 10-K.~~for general information about several significant risks.

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. In addition, a significant portion of our workforce in our subsidiaries, including many workers with specialized skills maintaining and servicing the electric, natural gas and water infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals 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 intentional misconduct of employees or contractors, may also have an adverse effect on our business, financial position and results of operations.

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

Item ~~1B. Unresolved Staff Comments~~4. Mine Safety Disclosures

~~We do not have any unresolved SEC staff comments.~~Not applicable.

~~Item 2. Properties~~

Transmission and Distribution System

As of December 31, ~~2019,~~2021, Eversource and our electric operating subsidiaries owned the following:


	Electric Distribution	Electric Transmission
Eversource
Number of substations owned	478	75
Transformer capacity (in kVa)	44,361,360	20,299,000
Overhead lines (in circuit miles)	40,515	3,980
Underground lines (in circuit miles)	18,050	421
Capacity range of overhead transmission lines (in kV)	N/A	69 to 345
Capacity range of underground transmission lines (in kV)	N/A	69 to 345


				CL&P		NSTAR Electric		PSNH
	Electric Distribution	Electric Transmission		Distribution	Transmission	Distribution	Transmission	Distribution	Transmission
Eversource
Number of substations owned	486	77	Number of substations owned	181	21	173	32	124	22
Transformer capacity (in kVa)	42,891,000	16,149,000	Transformer capacity (in kVa)	21,890,000	3,633,000	18,027,360	11,615,000	4,444,000	5,051,000
Overhead lines (in circuit miles)	40,568	3,963	Overhead lines (in circuit miles)	16,770	1,677	11,469	1,249	12,276	1,054
Underground lines (in circuit miles)			Underground lines (in circuit miles)	6,834	143	9,163	275	2,053	3
Capacity range of overhead transmission lines (in kV)	N/A	69 to 345	Capacity range of overhead transmission lines (in kV)	N/A	69 to 345	N/A	69 to 345	N/A	115 to 345
Underground lines (in circuit miles)	17,764	406
Capacity range of underground transmission lines (in kV)	N/A	69 to 345	Capacity range of underground transmission lines (in kV)	N/A	69 to 345	N/A	115 to 345	N/A	115


	Eversource	CL&P	NSTAR Electric	PSNH
Underground and overhead line transformers in service	634,839	292,902	172,876	169,061
Aggregate capacity (in kVa)	38,386,798	16,443,711	14,842,428	7,100,659

CL&P NSTAR Electric PSNH
Distribution Transmission Distribution Transmission Distribution Transmission
Number of substations owned 181
20
169
35
136
22
Transformer capacity (in kVa) 21,618,000
3,633,000
16,937,000
7,465,000
4,336,000
5,051,000
Overhead lines (in circuit miles) 16,942
1,675
11,427
1,247
12,199
1,041
Capacity range of overhead transmission lines (in kV) N/A
69 to 345
N/A
69 to 345
N/A
115 to 345
Underground lines (in circuit miles) 6,722
137
9,076
268
1,966
1
Capacity range of underground transmission lines (in kV) N/A
69 to 345
N/A
115 to 345
N/A
115

Eversource CL&P NSTAR Electric PSNH
Underground and overhead line transformers in service 628,219
291,415
171,362
165,442
Aggregate capacity (in kVa) 37,019,694
16,092,291
14,338,752
6,588,651

Electric Generating Plants

On January 10, 2018, Eversource and PSNH completed the sale of PSNH's thermal generation assets, including steam, internal combustion and biomass units. The sale of hydroelectric generation assets was completed on August 26, 2018. See Note 14, "Generation Asset Sale," in the accompanying Item 8, ~~Financial Statements and Supplementary Data~~ ~~for further information.~~

As of December 31, ~~2019,~~2021, NSTAR Electric owned the following solar power facilities:

Type of Plant

Number
of Sites

Year
Installed

Claimed Capability**
(kilowatts, dc)

Solar Fixed Tilt, Photovoltaic

2010 - 2019

70,000

Type of Plant
Number
of Sites

Year
Installed

Claimed Capability**
(kilowatts)
Solar Fixed Tilt, Photovoltaic 22 2010 - 2019 70,000

** Claimed capability represents the direct current nameplate capacity of the plants.


**	~~Claimed capability represents the direct current nameplate capacity of the plants.~~

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

Natural Gas Distribution System

As of December 31, ~~2019, Yankee~~2021, NSTAR Gas owned 2822 active gate stations, ~~206~~148 district regulator stations, and approximately 3,445 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.

~~As of December 31, 2019, NSTAR Gas owned 21 active gate stations, 164 district regulator stations, and approximately 3,302~~3,322 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.

Natural Gas Transmission System

As of December 31, 2021, NSTAR Gas and EGMA owned 1.0 and 2.36 miles of intrastate transmission natural gas pipeline, respectively.

Water Distribution System

As of December 31, ~~2019,~~2021, Aquarion owned and operated sources of water supply with a combined yield of approximately ~~131~~127 million gallons per day; ~~3,639~~3,573 miles of transmission and distribution mains; 109 surface water treatment plants; 3129 dams; and ~~112~~123 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.

~~The~~ 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.

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

Yankee Gas Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas ~~service, which it acquired either directly or from its predecessors in interest.~~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 the 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 AWC-CT derives its 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, AWC-CT has, with minor exceptions, solid franchises free from burdensome restrictions and unlimited as to time, and is authorized to sell potable water in the towns (or parts thereof) in which water is now being supplied by AWC-CT.

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 The NHPUC, pursuant to statutory law, has issued orders granting and affirming AWC-NH’s exclusive franchise 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. That franchise territory encompasses the towns of Hampton, North Hampton and Rye. Abenaki Water Systems territory encompasses the towns of Belmont, Bow, Carroll, and Gilford. Subject to NHPUC’s regulations, AWC-NH has the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same.

Item 3. Legal Proceedings

1. ~~Yankee Companies v. U.S. Department of Energy~~

~~The Yankee Companies have filed complaints against the DOE~~We are involved in legal, tax and regulatory proceedings regarding matters arising in the ~~Court~~ordinary course of ~~Federal Claims seeking monetary damages resulting from the DOE's failure to accept delivery of,~~business. For information regarding material lawsuits and ~~provide for a permanent facility to store, spent nuclear fuel pursuant to the terms~~proceedings, see Note 13, “Commitments and Contingencies,” 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 and III of litigation resulting from the DOE's failureCombined Notes to meet its contractual obligations. These Phases covered damages incurred in the years 1998 through 2012, and the awarded damages have been received by the Yankee Companies with certain amounts of the damages refunded to their customers.

Financial Statements.

~~DOE Phase IV Damages -~~ ~~On May 22, 2017, each of the Yankee Companies filed a fourth set of lawsuits against the DOE in the Court of Federal~~

Claims. The Yankee Companies sought monetary damages totaling $104.4 million for CYAPC, YAEC and MYAPC, resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal covering the years from 2013 to 2016 (“DOE Phase IV”). On February 21, 2019, the Yankee Companies received a partial summary judgment and partial final judgment in their favor for the undisputed amount of monetary damages of $103.2 million. The court awarded CYAPC, YAEC, and MYAPC damages of $40.7 million, $28.1 million and $34.4 million, respectively. The DOE did not appeal the court's judgment and the decision became final on April 23, 2019. On June 12, 2019, each of the Yankee Companies received the damages proceeds. On June 12, 2019, the court accepted an offer of judgment in the amount of $0.5 million to settle the disputed amount of approximately $1 million in Phase IV contested damages. The Yankee Companies received the $0.5 million payment in July 2019. CYAPC's and YAEC's proceeds received were classified as operating activities on the Eversource consolidated statement of cash flows.

In September 2019, the Yankee Companies made a required informational filing with FERC as to the use of proceeds, for which approval was received in the fourth quarter of 2019. In December 2019, YAEC and MYAPC returned proceeds of $5.4 million and $21.0 million, respectively, to its member companies, of which the Eversource utilities (CL&P, NSTAR Electric and PSNH) received a total of $2.8 million from YAEC and $5.0 million from MYAPC. The Eversource utilities will ultimately refund these proceeds to utility customers. Also, in December 2019, CYAPC paid $29.0 million to the DOE to partially settle its pre-1983 spent nuclear fuel obligation.

2. ~~Other Legal Proceedings~~

~~For further discussion of legal proceedings,~~addition, see Item 1, Business: "– Electric Distribution Segment," "– Electric Transmission Segment," ~~and~~ "– 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 ~~waste, electric and magnetic fields,~~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 16, 2022. All of Eversource Energy’s officers serve terms of one year and until their successors elected and qualified.

Name

Age

Title

James J. Judge

Executive Chairman of the Board

Joseph R. Nolan, Jr.

President and Chief Executive Officer

Philip J. Lembo

Executive Vice President and Chief Financial 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

Werner J. Schweiger

Executive Vice President and Chief Operating Officer

Jay S. Buth

Vice President, Controller and Chief Accounting Officer

James J. Judge. Mr. Judge has served as Executive Chairman of the Board of Eversource Energy since May 5, 2021 and as a Trustee of Eversource Energy since May 4, 2016. Previously, Mr. Judge served as Chairman of the Board, President and Chief Executive Officer of Eversource Energy from May 3, 2017 until May 5, 2021, and as President and Chief Executive Officer of Eversource Energy from May 4, 2016 until May 3, 2017. Based on his experience described above, Mr. Judge has the skills and qualifications necessary to serve as a Trustee of Eversource Energy.

Joseph R. Nolan, Jr. Mr. Nolan has served as President and Chief Executive Officer and a Trustee of Eversource Energy. 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 described above, Mr. Nolan has the skills and qualifications necessary to serve as a Trustee of Eversource Energy.

Philip J. Lembo. Mr. Lembo has served as Chief Financial Officer of Eversource Energy since May 4, 2016. He previously served as Treasurer of Eversource Energy from April 10, 2012 until May 3, 2017. Mr. Lembo has served as Executive Vice President of Eversource Energy since August 8, 2016.

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, ~~2020,~~2022, there were ~~33,508~~31,020 registered common shareholders of our company on record. As of the same date, there were a total of ~~329,952,663~~344,439,905 shares outstanding.

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 ~~2014~~2016 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period ~~2014~~2016 through ~~2019,~~2021, assuming all dividends are reinvested.


December 31,
	2016	2017	2018	2019	2020	2021
Eversource Energy	$100	$118	$126	$169	$176	$191
EEI Index	$100	$112	$116	$146	$144	$169
S&P 500	$100	$122	$116	$153	$181	$233

December 31,
2014 2015 2016 2017 2018 2019
Eversource Energy $100 $99 $110 $130 $138 $186
EEI Index $100 $96 $113 $126 $131 $164
S&P 500 $100 $101 $114 $138 $132 $174

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to matching contributions under the Eversource 401k Plan.


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)
October 1 - October 31, 2021	—	$	—	—	—
November 1 - November 30, 2021	—	—		—	—
December 1 - December 31, 2021	2,081	90.70		—	—
Total	2,081	$	90.70	—	—

Period Total Number of Shares Purchased Average Price Paid per Share
Total Number of Shares Purchased as
Part of Publicly Announced Plans or Programs

Approximate Dollar
Value of Shares that
May Yet Be Purchased Under the Plans and Programs (at month end)
October 1 - October 31, 2019 —
$ —
—
—
November 1 - November 30, 2019 20
82.94
—
—
December 1 - December 31, 2019 2,169
84.78
—
—
Total 2,189
$ 84.76
—
—

~~Recent Sales of Unregistered Securities~~

In January 2020, we determined that during 2019 and early 2020, the Savings Plan for Employees of Aquarion Water Company, a 401(k) retirement plan (Plan), offered Eversource common shares (Shares) as an investment alternative for participants. The Plan trustee purchased Shares in the open market and allocated the Shares to participants’ Plan accounts at the election of participants. During this period, the Plan sold 5,990 Shares to 35 participants, which Shares were not registered on Form S-8. The investment alternative to purchase Shares under the Plan has been terminated, and we did not receive any proceeds from such sales, which were funded with participants' contributions to the Plan.

Item 6. ~~Selected Consolidated Financial Data~~

~~Eversource Selected Consolidated Financial Data (Unaudited)~~

(Thousands of Dollars, except percentages and
common share information)
2019 2018 2017 2016 2015
Balance Sheet Data:
Property, Plant and Equipment, Net $ 27,585,470
$ 25,610,428
$ 23,617,463
$ 21,350,510
$ 19,892,441
Total Assets 41,123,915
38,241,256
36,220,386
32,053,173
30,580,309
Common Shareholders' Equity 12,629,994
11,486,817
11,086,242
10,711,734
10,352,215
Noncontrolling Interest - Preferred Stock of Subsidiaries 155,570
155,570
155,570
155,568
155,568
Long-Term Debt ^(a)
14,098,239
13,086,062
12,325,520
9,603,237
9,034,457
Obligations Under Capital Leases^(a)
10,516
10,735
9,898
8,924
8,222
Obligations Under Operating Leases^(a)
49,966
—
—
—
—
Income Statement Data:

Operating Revenues $ 8,526,470
$ 8,448,201
$ 7,751,952
$ 7,639,129
$ 7,954,827
Net Income $ 916,572
$ 1,040,519
$ 995,515
$ 949,821
$ 886,004
Net Income Attributable to Noncontrolling Interests 7,519
7,519
7,519
7,519
7,519
Net Income Attributable to Common Shareholders $ 909,053
$ 1,033,000
$ 987,996
$ 942,302
$ 878,485
Common Share Data:

Net Income Attributable to Common Shareholders:

Basic Earnings Per Common Share $ 2.83
$ 3.25
$ 3.11
$ 2.97
$ 2.77
Diluted Earnings Per Common Share $ 2.81
$ 3.25
$ 3.11
$ 2.96
$ 2.76
Dividends Declared Per Common Share $ 2.14
$ 2.02
$ 1.90
$ 1.78
$ 1.67
Market Price - Closing (end of year) ^(b)
$ 85.07
$ 65.04
$ 63.18
$ 55.23
$ 51.07
Book Value Per Common Share (end of year) $ 38.29
$ 36.25
$ 34.98
$ 33.80
$ 32.64
Tangible Book Value Per Common Share (end of year) ^(c)
$ 24.86
$ 22.27
$ 21.00
$ 22.70
$ 21.54
Rate of Return Earned on Average Common Equity (%) ^(d)
7.5
9.2
9.1
9.0
8.7
Market-to-Book Ratio (end of year) ^(e)
2.2
1.8
1.8
1.6
1.6

CL&P Selected Financial Data (Unaudited)
(Thousands of Dollars) 2019 2018 2017 2016 2015
Balance Sheet Data:

Property, Plant and Equipment, Net $ 9,625,765
$ 8,909,701
$ 8,271,030
$ 7,632,392
$ 7,156,809
Total Assets 12,185,191
11,409,719
10,630,246
10,035,044
9,592,957
Common Stockholder's Equity 4,387,825
4,199,317
3,587,127
3,470,387
3,140,717
Preferred Stock Not Subject to Mandatory Redemption 116,200
116,200
116,200
116,200
116,200
Long-Term Debt ^(a)
3,518,136
3,254,016
3,059,135
2,766,010
2,763,682
Obligations Under Finance Leases^(a)
3,049
4,465
5,711
6,767
7,624
Obligations Under Operating Leases^(a)
745
—
—
—
—
Income Statement Data:

Operating Revenues 3,232,551
3,096,174
2,887,359
2,805,955
2,802,675
Net Income 410,852
377,717
376,726
334,254
299,360
Common Stock Data:

Cash Dividends on Common Stock 341,800
60,000
254,800
199,599
196,000

Removed and Reserved

^(a)~~Includes portions due within one year.~~

^(b)~~Market price information reflects closing prices as reflected by the New York Stock Exchange.~~

^(c)

~~Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.~~

^(d)~~Net Income Attributable to Common Shareholders divided by average Common Shareholders' Equity.~~

^(e)~~The closing market price divided by the book value per share.~~

~~See the~~ ~~Combined Notes to Financial Statements~~ in this Annual Report on Form 10-K for a description of the sale of PSNH's thermal and hydroelectric generation assets in 2018 and the December 31, 2017 classification of these generation assets as held for sale, the acquisition of Aquarion on December 4, 2017, and any accounting changes materially affecting the comparability of the information reflected in the tables above. As a result of the adoption of new accounting guidance on January 1, 2019, we recognized lease assets and liabilities for operating leases on the balance sheet. Prior period amounts were not adjusted and continue to be reported in accordance with our historic accounting policies.

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 ~~2019~~2021 compared to fiscal year ~~2018~~2020 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year ~~2017~~2019 items and of fiscal year ~~2018~~2020 compared to fiscal year ~~2017,~~2019, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2020~~2018~~ 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 discussed below 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 not recognized under GAAP (non-GAAP) that 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 a non-GAAP financial ~~measure~~measures referencing our ~~2019~~2021 earnings and EPS excluding charges at CL&P related to a settlement agreement that included credits to customers and funding of various customer assistance initiatives and a storm performance penalty imposed on CL&P by the ~~impairment charge for the NPT project.~~PURA and our 2021 and 2020 earnings and EPS excluding certain acquisition and transition costs.

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 ~~2019~~2021 and 2020 results without including these items. This information is among the ~~impact~~primary indicators we use as a basis for evaluating performance and planning and forecasting of ~~the NPT impairment charge.~~future periods. We believe the ~~NPT impairment charge is~~impacts of the CL&P settlement agreement, the storm performance penalty imposed on CL&P by the PURA, and acquisition and transition costs are not indicative of our ongoing costs and performance. We view these charges as not directly related to the ongoing operations of the business and therefore not an indicator of baseline operating performance. Due to the nature and significance of the ~~impairment charge~~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 ~~an alternative~~alternatives to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as ~~an indicator~~indicators of operating performance.

~~The results of Aquarion and its subsidiaries, hereinafter referred to as "Aquarion," are included from the date of the acquisition, December 4, 2017, through December 31, 2019 throughout this~~ ~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~.

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 Eversource Gas Company of Massachusetts (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 ~~$909.1 million,~~$1.22 billion, or ~~$2.81~~$3.54 per share, in ~~2019,~~2021, compared with ~~$1.03~~$1.21 billion, or ~~$3.25~~$3.55 per share, in ~~2018. Results for 2019~~2020.

•Our 2021 results include after-tax costs recorded within the electric distribution segment resulting from a PURA-approved CL&P settlement agreement and an after-tax ~~impairment~~ charge at CL&P for a PURA assessment as a result of ~~$204.4~~CL&P’s preparation for and response to Tropical Storm Isaias in August 2020. Our 2021 results also include after-tax acquisition and transition costs recorded at Eversource parent. In total, these after-tax costs were $109.7 million, or ~~$0.64 per share, related to our investment in the NPT project. Excluding that impairment charge, we earned $1.11 billion, or $3.45~~$0.32 per share in ~~2019.~~

2021. Our ~~electric distribution segment earned $513.3~~2020 results include after-tax acquisition and transition costs of $32.1 million, or ~~$1.59~~$0.09 per share, recorded primarily at Eversource parent. Excluding those costs, our non-GAAP earnings were $1.33 billion, or $3.86 per share, in ~~2019,~~2021, compared with ~~$455.4 million,~~$1.24 billion, or ~~$1.44~~$3.64 per share, in 2018. Our electric transmission segment earned $256.5 million, or $0.79 per share, in 2019, compared with $427.2 million, or $1.34 per share, in 2018. Excluding the after-tax NPT impairment charge of $204.4 million, or $0.64 per share, our electric transmission segment earned $460.9 million, or $1.43 per share, in 2019. Our natural gas distribution segment earned $96.2 million, or $0.30 per share, in 2019, compared with $93.2 million, or $0.29 per share, in 2018. Our water distribution segment earned $34.9 million, or $0.11 per share, in 2019, compared with $30.9 million, or $0.10 per share in 2018.2020.

~~Eversource parent and other companies earned $8.2 million, or $0.02 per share, in 2019, compared with $26.3 million, or $0.08 per share, in 2018.~~

•We currently project ~~2020 earnings~~2022 non-GAAP earning guidance of between ~~$3.60~~$4.00 per share and ~~$3.70~~$4.17 per ~~share.~~share, which excludes the impact of remaining integration costs as a result of transitioning EGMA onto Eversource’s systems. We also project that our long-term EPS growth rate through 2026 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 ~~$2.01~~$1.96 billion in ~~2019,~~2021, compared with ~~$1.83~~$1.68 billion in ~~2018.~~2020. Investments in property, plant and equipment totaled ~~$2.91~~$3.18 billion in ~~2019~~2021 and ~~$2.57~~$2.94 billion in ~~2018.~~ 2020.

•Cash totaled ~~$15.4~~$66.8 million as of December 31, ~~2019,~~2021, compared with ~~$108.1~~$106.6 million as of December 31, ~~2018.~~

2020. Our available borrowing capacity under our commercial paper programs totaled $1.14 billion as of December 31, 2021. In ~~2019,~~2021, we issued ~~11,980,000 common shares, which resulted in proceeds of $852.3 million, net of issuance costs.~~

~~In 2019, we issued $1.52~~$3.23 billion of new long-term debt ~~consisting of $500 million by CL&P, $400 million by NSTAR Electric, $300 million by PSNH, $200 million by Yankee Gas, $75 million by NSTAR Gas~~ and $45 million by Aquarion. Proceeds from these new issuances were used primarily to repay short-term borrowings, repay long-term debt at maturity and fund capital expenditures and working capital. In 2019, we repaid ~~at maturity, $801.1 million~~$1.14 billion of ~~previously~~long-term debt.

•In 2021, we issued ~~long-term debt, consisting of $350 million by Eversource parent, $250 million by CL&P, $150 million by PSNH, $50 million by Yankee Gas and $1.1 million by Aquarion.~~

~~In 2019, we paid cash~~ dividends ~~of $663.2 million and issued non-cash dividends of $22.8 million in the form of treasury shares,~~ totaling ~~dividends of $2.14~~$2.41 per common share, compared with ~~cash~~ dividends of ~~$640.1 million, or $2.02~~$2.27 per common share in ~~2018.~~2020. Our quarterly common share dividend payment was $0.6025 per share in 2021, as compared to $0.5675 per share in 2020. On February ~~5, 2020,~~2, 2022, our Board of Trustees approved a common share dividend payment of ~~$0.5675~~$0.6375 per share, payable on March 31, ~~2020~~2022 to shareholders of record as of March ~~4, 2020. The 2020 dividend represents an increase of 6.1 percent over the dividend paid in December 2019.~~3, 2022.

•We project to make capital expenditures of ~~$14.19~~$18.14 billion from ~~2020~~2022 through ~~2024,~~2026, of which we expect ~~$8.63~~$7.02 billion to be in our electric ~~and~~distribution segment, $4.53 billion to be in our natural gas distribution ~~segments, $3.98~~segment, $4.60 billion to be in our electric transmission segment, and ~~$0.69~~$0.89 billion to be in our water distribution segment. We also project to invest ~~$0.90~~$1.10 billion in information technology and facilities upgrades and enhancements. ~~These projections do not include any expected~~Additionally, we currently expect to make investments ~~related to~~in our offshore wind ~~projects.~~ business between $0.9 billion and $1.0 billion in 2022 and expect to make investments for our three projects in total between $3.0 billion and $3.6 billion from 2023 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned.

~~Strategic:~~Strategic and Regulatory Items:

•On ~~February 26, 2020, Eversource~~January 18, 2022, South Fork Wind received BOEM’s final approval of its Construction and ~~NiSource~~Operations Plan (COP), following BOEM’s November 2021 issuance of the Record of Decision, which concluded BOEM’s environmental review of the project. The COP approval outlines the project’s one nautical mile turbine spacing, the requirements on the construction methodology for all work occurring in federal ocean waters, and mitigation measures to protect marine habitats and species. The final decision from BOEM was needed to move the project toward the start of construction, and with the decision received, South Fork has now entered the construction phase.

•On October 1, 2021, CL&P entered into ~~an asset purchase~~a settlement agreement ~~where Eversource would acquire~~with the ~~assets~~DEEP, Office of Consumer Counsel (OCC), Office of the Attorney General (AG) and the Connecticut Industrial Energy Consumers, resolving certain issues that ~~comprise NiSource’s local gas distribution business~~arose in ~~Massachusetts~~then-pending regulatory proceedings initiated by the 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 fund to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages, as approved by the PURA. In exchange for the $75 million of customer credits and assistance, PURA’s interim rate reduction docket was resolved without findings. As a ~~purchase price~~result of ~~$1.1 billion. The liabilities~~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 ~~assumed by Eversource specifically exclude any liabilities (past or future) arising out of or~~implemented. Additionally, CL&P agreed to withdraw its pending appeals related to the ~~fires~~$28.6 million storm performance penalty imposed in PURA’s April 28, 2021 and ~~explosions that occurred on September 13, 2018~~July 14, 2021 decisions. CL&P has also agreed to freeze its current base distribution rates until no earlier than January 1, 2024. The cumulative pre-tax impact of the October 1, 2021 settlement agreement and the Storm Isaias penalty imposed by PURA totaled $103.6 million, and the after-tax earnings impact was $86.1 million, or $0.25 per share, in Lawrence, Andover and North Andover, Massachusetts. The acquisition and resulting rate plan both require DPU and other approvals. Eversource and NiSource expect to close this transaction later this year.2021.

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.


	For the Years Ended December 31,
	2021				2020				2019
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Common Shareholders (GAAP)	$	1,220.5	$	3.54	$	1,205.2	$	3.55	$	909.1	$	2.81

Regulated Companies (non-GAAP)	$	1,342.4	$	3.89	$	1,223.3	$	3.60	$	1,105.3	$	3.43
Eversource Parent and Other Companies (non-GAAP)	(12.2)		(0.03)		14.0		0.04		8.2		0.02
Non-GAAP Earnings	$	1,330.2	$	3.86	$	1,237.3	$	3.64	$	1,113.5	$	3.45
CL&P Settlement Impacts (after-tax) (1)	(86.1)		(0.25)		—		—		—		—
Acquisition and Transition Costs (after-tax) (2)	(23.6)		(0.07)		(32.1)		(0.09)		—		—
Impairment of Northern Pass Transmission (after-tax)	—		—		—		—		(204.4)		(0.64)
Net Income Attributable to Common Shareholders (GAAP)	$	1,220.5	$	3.54	$	1,205.2	$	3.55	$	909.1	$	2.81

For the Years Ended December 31,
2019 2018 2017
(Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share
Net Income Attributable to Common Shareholders (GAAP) $ 909.1
$ 2.81
$ 1,033.0
$ 3.25
$ 988.0
$ 3.11

Regulated Companies $ 1,105.3
$ 3.43
$ 1,006.7
$ 3.17
$ 962.7
$ 3.03
Eversource Parent and Other Companies 8.2
0.02
26.3
0.08
25.3
0.08
Non-GAAP Earnings $ 1,113.5
$ 3.45
$ 1,033.0
$ 3.25
$ 988.0
$ 3.11
Impairment of Northern Pass Transmission (after-tax) (204.4 ) (0.64 ) —
—
—
—
Net Income Attributable to Common Shareholders (GAAP) $ 909.1
$ 2.81
$ 1,033.0
$ 3.25
$ 988.0
$ 3.11

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


	For the Years Ended December 31,
	2021				2020				2019
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income - Regulated Companies (GAAP)	$	1,256.3	$	3.64	$	1,221.8	$	3.60	$	900.9	$	2.79

Electric Distribution, excluding CL&P Settlement Impacts (Non-GAAP)	$	556.2	$	1.61	$	544.0	$	1.60	$	513.3	$	1.59
Electric Transmission, excluding Impairment of Northern Pass Transmission (Non-GAAP)	544.6		1.58		502.5		1.48		460.9		1.43
Natural Gas Distribution, excluding Acquisition-Related Costs (Non-GAAP)	204.8		0.59		135.6		0.40		96.2		0.30
Water Distribution	36.8		0.11		41.2		0.12		34.9		0.11
Net Income - Regulated Companies (Non-GAAP)	$	1,342.4	$	3.89	$	1,223.3	$	3.60	$	1,105.3	$	3.43
CL&P Settlement Impacts (after-tax) (1)	(86.1)		(0.25)		—		—		—		—
Acquisition-Related Costs (after-tax) (2)	—		—		(1.5)		—		—		—
Impairment of Northern Pass Transmission (after-tax)	—		—		—		—		(204.4)		(0.64)
Net Income - Regulated Companies (GAAP)	$	1,256.3	$	3.64	$	1,221.8	$	3.60	$	900.9	$	2.79

For the Years Ended December 31,
2019 2018 2017
(Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share
Net Income - Regulated Companies (GAAP) $ 900.9
$ 2.79
$ 1,006.7
$ 3.17
$ 962.7
$ 3.03

Electric Distribution $ 513.3
$ 1.59
$ 455.4
$ 1.44
$ 497.4
$ 1.57
Electric Transmission, excluding Northern Pass Transmission impairment (Non-GAAP) 460.9
1.43
427.2
1.34
391.9
1.23
Natural Gas Distribution 96.2
0.30
93.2
0.29
74.6
0.23
Water Distribution 34.9
0.11
30.9
0.10
(1.2 ) —
Net Income - Regulated Companies (Non-GAAP) $ 1,105.3
$ 3.43
$ 1,006.7
$ 3.17
$ 962.7
$ 3.03
Impairment of Northern Pass Transmission (after-tax) (204.4 ) (0.64 ) —
—
—
—
Net Income - Regulated Companies (GAAP) $ 900.9
$ 2.79
$ 1,006.7
$ 3.17
$ 962.7
$ 3.03

(1) The 2021 after-tax costs are associated with the 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 charge to earnings to establish a fund to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages. The 2021 after-tax costs also include charges recorded at CL&P as a result of the April 28, 2021 and July 14, 2021 PURA decisions, which included a $28.4 million penalty for storm performance results and is currently being provided as credits to customer bills and a $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 2021 costs are for the transition of systems as a result of our purchase of the assets of CMA on October 9, 2020 and costs associated with our December 1, 2021 water business acquisition. The 2020 acquisition costs are associated with our CMA acquisition. We expect integration costs in 2022 as a result of continuing to transition the CMA assets onto Eversource’s systems.

Our electric distribution segment earnings ~~increased $57.9~~decreased $73.9 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to CL&P’s settlement agreement on October 1, 2021 resulting in a $75 million pre-tax charge to earnings and a $28.6 million pre-tax charge to earnings at CL&P for a storm performance penalty imposed by PURA as a result of CL&P’s preparation for and response to Tropical Storm Isaias in August 2020 that was recorded in 2021. The after-tax impact of the CL&P ~~NSTAR Electric~~settlement agreement and ~~PSNH~~CL&P storm performance penalty imposed by the PURA was $86.1 million, or $0.25 per share. For further information, see "Regulatory Developments and Rate Matters - Connecticut" included in this Management’s Discussion and Analysis. Excluding those charges, electric distribution segment earnings increased $12.2 million due primarily to base distribution rate increases at NSTAR Electric effective January 1, 2021, at PSNH effective January 1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020, and higher earnings from CL&P's capital tracker mechanism ~~effective July 1, 2018,~~ due to increased electric system ~~improvements, and higher~~improvements. Those earnings ~~from NSTAR Electric's solar generation capital tracker mechanism. The earnings increase was~~increases were partially offset by ~~higher depreciation expense, lower non-service income from our benefit plans,~~ higher operations and maintenance expense ~~the absence in 2019 of generation earnings at PSNH due to the sale of its generation assets in 2018,~~driven by higher employee-related expenses and ~~the absence in 2019 of a gain on the sale of~~higher vegetation management costs, higher depreciation expense, higher property ~~at PSNH in 2018.~~tax expense, and higher interest expense.

Our electric transmission segment earnings ~~decreased $170.7~~increased $42.1 million in ~~2019,~~2021, as compared to 2018, due primarily to the impairment of NPT, which resulted in an after-tax charge of $204.4 million, or $0.64 per share in 2019. Excluding the NPT impairment charge, earnings increased $33.7 million in 2019, as compared to 2018,2020, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and the absence in 2019 of approximately $6 million (after-tax) in tax-related regulatory assets that we concluded were not recoverable from customers in 2018. The earnings increase was partially offset by a lower benefit from the annual billing and cost reconciliation filing with FERC and the absence of the NPT AFUDC equity income.infrastructure.

Our natural gas distribution segment earnings increased ~~$3.0~~$70.7 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the incremental impact of EGMA earnings of $43.0 million. Additionally, the ~~Yankee Gas~~earnings increase was due to base distribution rate ~~increase~~increases at NSTAR Gas effective November ~~15, 2018~~1, 2021 and 2020 and at Yankee Gas effective January 1, 2021 (with changes to customer rates beginning March 1, 2021), and higher earnings from capital tracker mechanisms due to continued investments in natural gas infrastructure. The earnings increase was partially offset by higher ~~operations and maintenance expense, higher~~ depreciation expense, higher property ~~and other~~ tax expense and higher interest expense.

Our water distribution segment earnings ~~increased $4.0~~decreased $4.4 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the absence in 2021 of an after-tax gain of $3.5 million and lower revenues both as a ~~lower effective tax rate driven by~~result of the ~~elimination~~sale of ~~a tax-related regulatory liability.~~the water system and treatment plant in Hingham, Massachusetts in July 2020.

Eversource Parent and Other Companies:Eversource parent and other companies ~~earnings decreased $18.1~~had an increased loss of $19.2 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to a higher effective tax rate ~~due in part to~~and higher ~~income tax reserves in 2019 and the absence in 2019 of income tax benefits recognized in 2018,~~employee-related costs. The higher ~~interest expense, and the absence in 2019 of a 2018 benefit related to the allowed recovery of certain previously expensed merger-related costs in distribution rates. The earnings decrease~~loss was partially offset by ~~the absence~~a decrease of ~~the 2018 impairment~~$7.0 million in acquisition and transition costs of ~~our investment in the Access Northeast project,~~EGMA recorded at Eversource parent and a higher return at Eversource Service as a result of increased investments in property, plant and equipment.

~~Liquidity~~

Impact of COVID-19

~~Cash totaled $15.4 million~~

COVID-19 has adversely affected customers, workers and the U.S. economy. We provide a critical service to our customers and have taken extensive measures to maintain its safety and reliability. We continue to address the impacts of the COVID-19 pandemic and how the related developments affect Eversource. By the end of 2021, we completed the re-entry phase of our pandemic response plan for those of our employees that were working remotely. We have not experienced significant impacts directly related to the pandemic that have materially affected our current operations, our workforce, or results of operations. The extent of the impact to us in the future will vary, and depend on the duration, scope and severity of the pandemic and the resulting impact on economic, health care and capital market conditions. The future impact will also depend on the outcome of future proceedings before our state regulatory commissions to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses.

The current and expected future financial impacts of COVID-19 as it relates to our businesses primarily relate to collectability of customer receivables and customer payment plans and increased expenses for cleaning and supplies for personal protective equipment.

As of December 31, ~~2019, compared with $108.1~~2021, our allowance for uncollectible customer receivable balance of $417.4 million, as of ~~December 31, 2018.~~

~~Short-Term Debt - Commercial Paper Programs~~which $226.1 million relates to hardship accounts that are specifically recovered in rates charged to customers, adequately reflected the collection risk and ~~Credit Agreements: Eversource parent~~net realizable value for our receivables. Our evaluation of the uncollectible allowance has shown that our operating companies have experienced an increase in aged receivables and lower cash collections from customers because of the length of the moratorium on disconnections in Connecticut and Massachusetts, and the economic slowdown resulting from the COVID-19 pandemic. In Connecticut, the moratorium on disconnections of commercial and non-hardship residential customers ended in June 2021 and September 2021, respectively, but is still in place for hardship residential customers. In Massachusetts, the moratorium on disconnections of commercial customers and residential customers ended in September 2020 and July 2021, respectively. Disconnection activities have resumed after these moratoria have expired, which has resulted in recent improved collection experience, more customers applying for, and receiving, hardship status, and higher write-offs of aged receivable amounts. On July 7, 2021, the NHPUC issued an order to New Hampshire utilities that concluded that recovery of incremental bad debt or waived late fees related to the COVID-19 pandemic would be addressed in a ~~$1.45 billion commercial paper program allowing Eversource parent~~future rate case to ~~issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas and Aquarion Water Company of Connecticut~~the extent those costs are also parties to a five-year $1.45 billion revolving credit facility. Effective December 9, 2019, the revolving credit facility's termination date was extended for one additional year to December 6, 2024. The revolving credit facility serves to backstop Eversource parent's $1.45 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. Effective December 9, 2019, the revolving credit facility's termination date was extended for one additional year to December 6, 2024. The 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:~~

Borrowings Outstanding
as of December 31, Available Borrowing Capacity as of December 31, Weighted-Average Interest Rate as of December 31,
(Millions of Dollars) 2019 2018 2019 2018 2019 2018
Eversource Parent Commercial Paper Program $ 1,224.9
$ 631.5
$ 225.1
$ 818.5
1.98 % 2.77 %
NSTAR Electric Commercial Paper Program 10.5
278.5
639.5
371.5
1.63 % 2.50 %

~~There were no borrowings outstanding on either the Eversource parent or NSTAR Electric revolving credit facilities as of December 31, 2019 or 2018.~~

Amounts outstanding under the commercial paper programs and revolving credit facilities 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 daysrelevant at ~~one~~that time. As a result of the ~~Eversource parent long-term debt issuance~~order, PSNH removed its $0.6 million deferral of net incremental COVID-19 costs in 2021. In New Hampshire, the moratorium on ~~January 10,~~disconnections of non-hardship residential and commercial customers ended in late 2020 and for hardship residential customers ended in May 2021 and PSNH has resumed disconnection activities, which has resulted in improved collection of outstanding customer receivable balances.

Based upon the ~~net proceeds of which were used to repay short-term borrowings outstanding under its commercial paper program, $346.3 million of commercial paper borrowings under~~evaluation performed, for the ~~Eversource parent commercial paper program were classified as Long-Term Debt as of~~year ended December 31, ~~2019.~~

~~Intercompany Borrowings:~~2021, management increased the allowance for uncollectible accounts for amounts incurred as a result of COVID-19 by $24.1 million for Eversource ~~parent uses its available capital resources to provide loans to its subsidiaries to assist~~(increase of $20.1 million for CL&P and $6.6 million at our natural gas businesses, and decrease of $1.3 million at NSTAR Electric). The COVID-19 related uncollectible amounts were deferred either as incremental regulatory costs at our Connecticut and Massachusetts utilities 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 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.future rates. As of December 31, ~~2019, there were intercompany loans from~~2021, the total amount incurred as a result of COVID-19 included in the allowance for uncollectible accounts was $55.3 million at Eversource ~~parent~~($23.9 million at CL&P, $9.0 million at NSTAR Electric, and $21.4 million at our natural gas businesses). Based on the status of our COVID-19 regulatory dockets, communications with our state regulatory commissions, and policies and practices in the jurisdictions in which we operate, we believe our state regulatory commissions in Connecticut and Massachusetts will allow us to ~~CL&P~~recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses, while balancing the impact on our customers’ bills and our operating cash flows.

We worked closely with our state regulatory commissions and consumer advocates on customer assistance measures, including payment plan options as well as financial hardship and arrearage management programs, in order to mitigate the impact on customer rates in the future. We developed these long-term solutions for customers in order to help minimize the extent of ~~$63.8 million, to PSNH~~the impact of ~~$27.0~~COVID-19 on customer receivable balances and customers’ affordability in light of the current financial impact they may experience.

For the year ended December 31, 2021, net incremental costs incurred as a result of COVID-19 totaled $20.8 million, and related to ~~a subsidiary~~uncollectible expense that impacts earnings, facilities and fleet cleaning, sanitizing costs and supplies for personal protective equipment, net of ~~NSTAR Electric~~cost savings and benefits under the CARES Act. In 2021, we deferred $15.8 million of ~~$30.3 million.~~ these net incremental COVID-19 costs on the balance sheet. Net incremental COVID-19 expenses that reduced pre-tax earnings totaled $5.0 million on the statement of income in 2021.

As of December 31, ~~2018, there~~2021, a total of $39.8 million of net deferred incremental COVID-19 costs were ~~intercompany loans~~recorded on the balance sheet, of which $33.0 million of that deferral related to uncollectible expense that impacts earnings and $6.8 million related to cleaning and supplies for personal protective equipment.

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 ~~PSNH of $57.0 million. Intercompany loans from Eversource parent~~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 ~~included in Notes Payable~~also used as a bridge to ~~Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets.~~

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

(Millions of Dollars) Issue Date Issuance/(Repayment) Maturity Date Use of Proceeds for Issuance/
Repayment Information
CL&P:
4.00% 2018 Series A First Mortgage Bonds ⁽¹⁾
April 2019 $ 300.0
April 2048 Paid short-term borrowings that were used to pay long-term debt that matured on February 1, 2019 and fund capital expenditures and working capital
3.20% 2017 Series A First Mortgage Bonds ⁽²⁾
September 2019 200.0
March 2027 Paid short-term borrowings and fund capital expenditures and working capital
5.50% 2009 Series A First Mortgage Bonds February 2009 (250.0 ) February 2019 Paid at maturity on February 1, 2019
NSTAR Electric:
3.25% 2019 Debentures May 2019 400.0
May 2029 Paid short-term borrowings that were used to fund investments in eligible green expenditures
PSNH:
3.60% 2019 Series T First Mortgage Bonds June 2019 300.0
July 2049 Paid long-term debt that matured in December 2019, paid short-term borrowings and fund capital expenditures and working capital
4.50% 2009 Series P First Mortgage Bonds December 2009 (150.0 ) December 2019 Paid at maturity on December 1, 2019
Other:
Eversource Parent 4.50% Debentures November 2009 (350.0 ) November 2019 Paid at maturity on November 15, 2019
Eversource Parent 3.45% Series P Senior Notes January 2020 350.0
January 2050 Paid short-term borrowings
NSTAR Gas 3.74% Series Q First Mortgage Bonds July 2019 75.0
August 2049 Paid short-term borrowings and fund capital expenditures and working capital
Yankee Gas 2.23% Series P First Mortgage Bonds September 2019 100.0
October 2024 Paid short-term borrowings and for general corporate purposes
Yankee Gas 3.30% Series Q First Mortgage Bonds September 2019 100.0
October 2049 Paid short-term borrowings and for general corporate purposes
Yankee Gas 5.26% Series H First Mortgage Bonds November 2004 (50.0 ) November 2019 Paid at maturity on November 1, 2019
Aquarion 3.54% Senior Notes December 2019 45.0
December 2049 Paid short-term borrowings

⁽¹⁾ ~~These bonds are part~~financings. The levels of short-term borrowing may vary significantly over the course of the ~~same series issued by CL&P in March 2018. The aggregate outstanding principal amount of these bonds is now $800 million.~~

⁽²⁾ ~~These bonds are part of the same series issued by CL&P in March 2017. The aggregate outstanding principal amount of these bonds is now $500 million.~~

~~Long-Term Debt Issuance Authorizations:~~ On February 27, 2019, the DPU approved NSTAR Electric's request for authorization to issue up to $800 million in long-term debt through December 31, 2020. On April 26, 2019, the NHPUC approved PSNH's request for authorization to issue up to $300 million in long-term debt through December 31, 2019. On August 14, 2019, PURA approved CL&P's request for authorization to issue up to $675 million in long-term debt through December 31, 2022. On December 11, 2019, PURA approved Aquarion Water Company of Connecticut's request for authorization to issue up to $45 million of long-term debt. On January 27, 2020, the DPU approved NSTAR Gas' request for authorization to issue up to $270 million in long-term debt through December 31, 2021.

~~Rate Reduction Bonds:~~ PSNH's RRB payments consist of principal and interest and are paid semi-annually, beginning on February 1, 2019. PSNH paid $52.3 million of RRB principal payments and $26.8 million of interest payments in 2019.

~~Common Share Issuance and Forward Sale Agreement:~~ On June 4, 2019, Eversource completed an equity offering of 17,940,000 common shares, consisting of 5,980,000 common shares issued directly by the Company and 11,960,000 common shares issuable pursuant to a forward sale agreement with an investment bank. The issuance of 5,980,000 common shares resulted in proceeds of $426.9 million, net of issuance costs.

Under the forward sale agreement, a total of 11,960,000 common shares were borrowed from third parties and sold by the underwriters. The forward sale agreement allows Eversource, at its election and prior to May 29, 2020, to physically settle the forward sale agreement by issuing common shares in exchange for net proceeds at the then-applicable forward sale price specified by the agreement (initially, $71.48 per share) or, alternatively, to settle the forward sale agreement in whole or in part through the delivery or receipt of shares or cash. The forward sale price is subject to adjustment daily based on a floating interest rate factor and will decrease in respect of certain fixed amounts specified in the agreement, such as dividends.

On December 30, 2019, Eversource physically settled a portion of the forward sale agreement by delivering 6,000,000 common shares in exchange for net proceeds of $425.4 million. The forward sale price used to determine the cash proceeds received by Eversource was calculated based on the initial forward sale price of $71.48 per share, as adjusted in accordance with the forward sale agreement.

The 2019 issuances of 11,980,000 common shares resulted in proceeds of $852.3 million, net of issuance costs, and were reflected in shareholders’ equity and as financing activities on the statement of cash flows.

Eversource’s intent is to physically settle the forward sale agreement by issuing common shares. As of December 31, 2019, if Eversource had elected to net settle the forward sale agreement, Eversource would have been required to pay $84.4 million under a cash settlement or would have been required to deliver 992,189 common shares under a net share settlement.

~~Issuances of shares under the forward sale agreement are classified as equity transactions. Accordingly, no amounts relating~~year due to the ~~forward sale agreement have or will be recorded~~impact of fluctuations in the financial statements until settlements take place. Prior to any settlements, the only impact to the financial statements is the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method. See Note 22, "Earnings Per Share," to the financial statements for information on the forward sale agreement’s impact on the calculation of diluted EPS.

Eversource used the net proceeds received upon the direct issuance of common shares and the net proceeds received upon partial settlement of the forward sale agreement to repay short-term debt under the commercial paper program, to fund capital spending and clean energy initiatives, and for general corporate purposes.

~~Cash Flows:~~ ~~Cash flows provided by operating activities totaled $2.01 billion in 2019, compared with $1.83 billion in 2018. The increase in operating~~ cash flows was due primarily to a decrease in 2019 of approximately $148 million of major storm restoration cost payments, $116 million in lower payments made in 2019 to the DOE by CYAPC to partially settle its pre-1983 spent nuclear fuel obligation, and a $73.2 million decrease in pension and PBOP cashfrom operations, dividends paid, capital contributions made in 2019, as compared to 2018. Also contributing to the increase were $102.8 million of lower income tax payments made in 2019, as compared to 2018, $68.8 million in DOE Phase IV litigation proceeds received ~~by CYAPC and YAEC in 2019,~~ and the timing of cash collections on our accounts receivables. Partially offsetting these favorable impacts were the timing of collections for regulatory tracking mechanisms, which were significantly impacted by the timing of collections of purchased power and transmission costs at NSTAR Electric, and the timing of accounts payable cash payments and other working capital items.long-term debt financings.

Cash flows provided by operating activities totaled $1.83 billion in 2018, compared with $2.00 billion in 2017. The decrease in operating cash flows was due primarily to cash payments made in 2018 for storm restoration costs of approximately $252 million, an increase of $128 million in income tax payments made in 2018, as compared to 2017, and the unfavorable impacts related to the timing of payments of our working capital items, including accounts receivable and accounts payable. In addition, in December 2018, CYAPC paid $145 million to the DOE to partially settle its pre-1983 spent nuclear fuel obligation. Partially offsetting these unfavorable impacts were the timing of cash collected for regulatory tracking mechanisms~~and a decrease of $47.9 million in 2018 of pension and PBOP contributions.~~

In 2019, we paid cash dividends of $663.2 million and issued non-cash dividends of $22.8 million in the form of treasury shares, totaling dividends of $2.14 per common share, compared with cash dividends of $640.1 million, or $2.02 per common share, in 2018. Our quarterly common share dividend payment was $0.535 per share in 2019, as compared to $0.505 per share in 2018. On February 5, 2020, our Board of Trustees approved a common share dividend payment of $0.5675 per share, payable on March 31, 2020 to shareholders of record as of March 4, 2020. The 2020 dividend represents an increase of 6.1 percent over the dividend paid in December 2019.

Beginning in 2019, Eversource began issuing 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 2019, CL&P, NSTAR Electric and PSNH paid $341.8 million, $181.8 million and $271.0 million, respectively, in common stock dividends to Eversource parent.~~

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. ~~The current growth in~~ Eversource's ~~construction expenditures utilizes~~regulated companies’ spend a significant amount of cash ~~for~~on capital improvements and construction projects that have a long-term return on investment and recovery ~~period, totaling approximately $2.91 billion in cash capital spend in 2019.~~period. In addition, ~~Eversource's~~Eversource’s investments in its offshore wind business ~~totaled $415.0 million in 2019, which~~ are

recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by ~~$1.19~~$2.58 billion, ~~$91.7 million, $280.5~~$537.0 million, and ~~$36.7~~$165.0 million at Eversource, ~~CL&P,~~ NSTAR Electric and PSNH, respectively, as of December 31, ~~2019.~~2021.

As of December 31, ~~2019, $296.1 million~~2021, $1.18 billion of Eversource's long-term debt, including ~~$95.0~~$750.0 million ~~$50.0~~at Eversource parent, $400.0 million ~~$150.0 million, and $1.1 million for~~at NSTAR Electric, $20.0 million at Yankee Gas, ~~NSTAR Gas~~ and $5.4 million at Aquarion, ~~respectively,~~ will mature within the next 12 months. Included in the current portion of long-term debt on the Eversource balance sheet is $31.3 million related to fair value adjustments from our various business combinations that will be amortized within the next 12 months and have no cash flow impact. 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.

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.

Cash totaled $66.8 million as of December 31, 2021, compared with $106.6 million as of December 31, 2020.

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, 2026. 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, 2026. The 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:


	Borrowings Outstanding as of December 31,				Available Borrowing Capacity as of December 31,				Weighted-Average Interest Rate as of December 31,
(Millions of Dollars)	2021		2020		2021		2020		2021		2020
Eversource Parent Commercial Paper Program	$	1,343.0	$	1,054.3	$	657.0	$	945.7	0.31	%	0.25	%
NSTAR Electric Commercial Paper Program	162.5		195.0		487.5		455.0		0.14	%	0.16	%

There were no borrowings outstanding on the revolving credit facilities as of December 31, 2021 or 2020.

CL&P and PSNH have uncommitted line of credit agreements totaling $450 million and $300 million, respectively, which will expire on May 12, 2022. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2021.

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, 2021, there were intercompany loans from Eversource parent to PSNH of $110.6 million. As of December 31, 2020, there were intercompany loans from Eversource parent to PSNH of $46.3 million, and to a subsidiary of NSTAR Electric of $21.3 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 March 31, 2021, the DPU approved NSTAR Electric's request for authorization to issue up to $1.60 billion in long-term debt through December 31, 2023. On September 10, 2021, the DPU approved EGMA’s request for authorization to issue up to $725.0 million in long-term debt through December 31, 2023. The remaining Eversource operating companies, including CL&P and PSNH, 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:

(Millions of Dollars)

Issuance/(Repayment)

Issue Date or Repayment Date

Maturity Date

Use of Proceeds for Issuance/
Repayment Information

CL&P:

2.05% Series A First Mortgage Bonds

425.0

June 2021

July 2031

Repaid short-term debt, paid capital expenditures and working capital

4.38% Series A PCRB

(120.5)

September 2021

September 2028

Paid on par call date in advance of maturity

NSTAR Electric:

3.10% 2021 Debentures

300.0

May 2021

June 2051

Refinanced investments in eligible green

expenditures, which were previously financed in 2019 and 2020

3.50% Series F Senior Notes

(250.0)

June 2021

September 2021

Paid on par call date in advance of maturity

1.95% 2021 Debentures

300.0

August 2021

August 2031

Repaid short-term debt, paid capital expenditures and working capital

PSNH:

4.05% Series Q First Mortgage Bonds

(122.0)

March 2021

June 2021

Paid on par call date in advance of maturity

3.20% Series R First Mortgage Bonds

(160.0)

June 2021

September 2021

Paid on par call date in advance of maturity

2.20% Series V First Mortgage Bonds

350.0

June 2021

June 2031

Repaid short-term debt, including short-term debt used to redeem Series R First Mortgage Bonds, paid capital expenditures and working capital

Other:

Eversource Parent 2.50% Series I Senior Notes

(450.0)

February 2021

March 2021

Paid on par call date in advance of maturity

Eversource Parent 2.55% Series S Senior Notes

350.0

March 2021

March 2031

Repaid short-term debt, including short-term debt used to redeem Series I Senior Notes

Eversource Parent 1.40% Series U Senior Notes

300.0

August 2021

August 2026

Repaid short-term debt

Eversource Parent Variable Rate Series T Senior Notes (1)

350.0

August 2021

August 2023

Repaid short-term debt

Aquarion Water Company of Connecticut 3.31%
Senior Notes

100.0

April 2021

April 2051

Repaid 5.50% Notes, repaid short-term debt, paid capital expenditures and working capital

Aquarion Water Company of Connecticut 5.50% Notes

(40.0)

April 2021

Paid at maturity

Yankee Gas 1.38% Series S First Mortgage Bonds

90.0

August 2021

August 2026

(2)

Yankee Gas 2.88% Series T First Mortgage Bonds

35.0

August 2021

August 2051

(2)

EGMA 2.11% Series A First Mortgage Bonds

310.0

September 2021

October 2031

(2)

EGMA 2.92% Series B First Mortgage Bonds

240.0

September 2021

October 2051

(2)

NSTAR Gas 2.25% Series T First Mortgage Bonds

40.0

October 2021

November 2031

(2)

NSTAR Gas 3.03% Series U First Mortgage Bonds

40.0

October 2021

November 2051

(2)

(1) On August 13, 2021, Eversource Parent issued $350 million of floating rate Series T Senior Notes with a maturity date of August 15, 2023. The notes have a coupon rate based on Compounded SOFR plus 0.25%. The notes had an interest rate of 0.30% as of December 31, 2021.

(2) The use of proceeds from these various issuances refinanced existing indebtedness, funded capital expenditures and were for general corporate purposes. The EGMA indebtedness that was refinanced included $309.4 million of long-term debt.

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 $18.9 million of interest payments in 2021, and paid $43.2 million of RRB principal payments and $20.2 million of interest payments in 2020.

Cash Flows: Cash flows from operating activities primarily result from the transmission and distribution of electricity, and the distribution of natural gas and water. Cash flows provided by operating activities totaled $1.96 billion in 2021, compared with $1.68 billion in 2020. Changes in Eversource’s cash flows from operations were generally consistent with changes in its results of operations, as adjusted by changes in working capital in the normal course of business and as further discussed. Operating cash flows were favorably impacted by improvements in the timing of cash collections on our accounts receivable, the timing of collections for regulatory tracking mechanisms, and the timing of other working capital items. These favorable impacts were partially offset by the timing of cash payments made on our accounts payable, a $93.8 million increase in cost of removal expenditures, a $72.7 million increase in income tax payments made in 2021, as compared to 2020, and a $70.8 million increase in Pension and PBOP contributions made in 2021, as compared to 2020.

In 2021, we paid cash dividends of $805.4 million and issued non-cash dividends of $22.9 millionin the form of treasury shares, totaling dividends of $828.3 million, or $2.41 per common share. In 2020, we paid cash dividends of $744.7 million and issued non-cash dividends of $22.8 million in the form of treasury shares, totaling dividends of $767.5 million, or $2.27 per common share. Our quarterly common share dividend payment was $0.6025 per share in 2021, as compared to $0.5675 per share in 2020. On February 2, 2022, our Board of Trustees approved a common share dividend payment of $0.6375 per share, payable on March 31, 2022 to shareholders of record as of March 3, 2022.

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 2021, CL&P, NSTAR Electric and PSNH paid $341.4 million, $283.2 million and $260.8 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 expense. In 2021, investments for Eversource, CL&P, NSTAR Electric and PSNH were $3.18 billion, $790.1 million, $960.9 million and $326.4 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, 2021 and are as follows:


(Millions of Dollars)	2022		2023		2024		2025		2026		Thereafter		Total
Eversource	$	583.8	$	551.3	$	509.4	$	463.1	$	433.2	$	4,923.0	$	7,463.8
CL&P	159.7		154.7		149.7		138.6		135.6		1,784.8		2,523.1

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.

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 ~~Moody's,~~ S&P, Moody's, and Fitch is as follows:

~~Moody's~~S&P

~~S&P~~Moody's

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

Eversource Parent

~~Baa1~~A-

Stable

A-Baa1

~~Stable~~Negative

BBB+

Stable

CL&P

A3A

Stable

AA3

~~Stable~~Negative

A-

~~Stable~~Negative

NSTAR Electric

A1A

Stable

AA1

Stable

PSNH

A3A

Stable

AA3

Stable

A-

Stable

A summary of the current credit ratings and outlooks by ~~Moody's,~~ 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:

~~Moody's~~S&P

~~S&P~~Moody's

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

Eversource Parent

~~Baa1~~BBB+

Stable

~~BBB+~~Baa1

~~Stable~~Negative

BBB+

Stable

CL&P

A1A+

Stable

A+A1

~~Stable~~Negative

A+

~~Stable~~Negative

NSTAR Electric

A1A

Stable

AA1

Stable

A+

Stable

PSNH

A1A+

Stable

A+A1

Stable

A+

Stable

Business Development and Capital Expenditures

Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized and deferred portions of pension and PBOP expense (all of which are non-cash factors), totaled $3.54 billion in 2021, $3.06 billion in ~~2019, $2.86~~2020, and $3.06 billion in ~~2018, and $2.52 billion in 2017.~~2019. These amounts included $238.0 million in 2021, $239.1 million in 2020, and $239.0 million in 2019 ~~$184.6 million in 2018, and $165.9 million in 2017~~ 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 ~~$16.0~~$151.7 million in ~~2019,~~2021, as compared to ~~2018.~~2020. A summary of electric transmission capital expenditures by company is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2021		2020		2019
CL&P	$	400.0	$	402.9	$	459.5
NSTAR Electric	480.3		366.8		379.7
PSNH	235.0		193.9		190.4
NPT	—		—		9.8
Total Electric Transmission Segment	$	1,115.3	$	963.6	$	1,039.4

For the Years Ended December 31,
(Millions of Dollars) 2019 2018 2017
CL&P $ 459.5
$ 465.5
$ 431.5
NSTAR Electric 379.7
334.3
301.9
PSNH 190.4
194.2
155.6
NPT 9.8
29.4
43.3
Total Electric Transmission Segment $ 1,039.4
$ 1,023.4
$ 932.3

Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power, strengthen the electric grid's resilience against extreme weather and other safety and security threats, and increase access to clean power generation from renewable sources, such as solar and offshore wind. In Connecticut, Massachusetts and New Hampshire, our transmission projects include transmission line upgrades, the installation of new transmission lines, and substation enhancements.

~~Eastern~~

Our transmission projects in Massachusetts ~~Transmission Projects:~~ ~~These projects consist of a portfolio of~~include electric transmission upgrades in ~~southern New Hampshire, northern Massachusetts and continuing into~~ the greater Boston metropolitan ~~area,~~area. Two of ~~which 28~~these upgrades, ~~are in Eversource's service territory (two in New Hampshire~~the Mystic-Woburn and ~~26 in Massachusetts). The two New Hampshire upgrades, including~~ the Merrimack Valley Reliability Project, have been placed in service, and 20 Massachusetts upgrades have been placed in service. On December 17, 2019, the Massachusetts Siting Board issued a favorable decision on the Sudbury-Hudson Reliability Project, the last project requiring such approval. On January 17, 2020, the Town of Sudbury and Protect Sudbury, a community group, appealed the decision to the Massachusetts Supreme Judicial Court. The majority of the remaining upgradesWakefield-Woburn reliability projects, are under construction and are expected to be placed in service ~~in 2021. We estimate our portion of the investment will be approximately $750 million, of which $442.2 million has been spent and capitalized through December 31, 2019.~~

~~Hartford-Area Transmission Projects:~~ These projects consist of 27 projects in the Hartford, Connecticut area with an expected investment of approximately $350 million. As of December 31, 2019, 24 projects have been placed in service, and three projects are in active construction and are expected to be placed in service through mid-2020. As of December 31, 2019, CL&P had spent and capitalized $275.9 million in costs associated with these projects.

~~Seacoast Reliability Project~~: The Seacoast Reliability Project consists of a 13-mile, 115kV transmission line within several New Hampshire communities, using a combination of overhead, underground and underwater line designs to help meet the growing demand for electricity in the Seacoast region. On December 10, 2018, the NHSEC indicated its unanimous approval of the project, and subsequently issued its written decision on January 31, 2019. On May 13, 2019, two appeals of the NHSEC's approval orders were filed with the New Hampshire Supreme Court. On December 17, 2019, the Conservation Law Foundation requested the Court to withdraw its appeal, and the Court granted the request on December 20, 2019. The other appeal remains pending. This project is under construction and is scheduled to be completed inby the second quarter of ~~2020.~~2023. The last remaining upgrade, the Sudbury-Hudson Reliability Project, received siting approval, however one appeal remains pending with expected resolution in the first quarter of 2022. We ~~estimate~~spent $53 million during 2021 and we expect to make additional capital expenditures of approximately $170 million on these remaining transmission upgrades. There are also several transmission projects underway in southeastern Massachusetts, including Cape Cod, required to reinforce the ~~investment will be~~Southeastern Massachusetts transmission system and bring the system into compliance with applicable national and regional reliability standards. We spent $20 million during 2021 and we expect to make additional capital expenditures of approximately ~~$125~~$140 million ~~of which PSNH had spent and capitalized $89.0 million in costs through December 31, 2019.~~on these transmission upgrades.

~~All project costs are anticipated to be fully recoverable through transmission rates.~~

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


	For the Years Ended December 31,
(Millions of Dollars)	CL&P		NSTAR Electric		PSNH		Total Electric		Natural Gas		Water		Total
2021
Basic Business	$	256.2	$	179.9	$	56.0	$	492.1	$	206.1	$	16.5	$	714.7
Aging Infrastructure	178.0		219.1		67.7		464.8		509.6		127.1		1,101.5
Load Growth and Other	80.2		170.5		37.1		287.8		83.3		0.6		371.7
Total Distribution	514.4		569.5		160.8		1,244.7		799.0		144.2		2,187.9
Solar	—		(0.6)		—		(0.6)		—		—		(0.6)
Total	$	514.4	$	568.9	$	160.8	$	1,244.1	$	799.0	144.2		$	2,187.3

2020
Basic Business	$	233.4	$	195.1	$	52.4	$	480.9	$	88.2	$	10.9	$	580.0
Aging Infrastructure	179.9		237.1		80.2		497.2		391.3		115.5		1,004.0
Load Growth and Other	77.8		110.8		21.3		209.9		65.6		0.8		276.3
Total Distribution	491.1		543.0		153.9		1,188.0		545.1		127.2		1,860.3
Solar	—		1.4		—		1.4		—		—		1.4
Total	$	491.1	$	544.4	$	153.9	$	1,189.4	$	545.1	$	127.2	$	1,861.7

2019
Basic Business	$	228.7	$	201.0	$	47.3	$	477.0	$	71.2	$	15.0	$	563.2
Aging Infrastructure	224.5		255.5		90.8		570.8		315.2		93.9		979.9
Load Growth and Other	59.6		89.4		16.8		165.8		66.8		1.5		234.1
Total Distribution	512.8		545.9		154.9		1,213.6		453.2		110.4		1,777.2
Solar and Other	—		7.5		—		7.5		—		—		7.5
Total	$	512.8	$	553.4	$	154.9	$	1,221.1	$	453.2	$	110.4	$	1,784.7

For the Years Ended December 31,
(Millions of Dollars) CL&P NSTAR Electric PSNH Total Electric Natural Gas
Water ⁽¹⁾
Total
2019
Basic Business $ 228.7
$ 201.0
$ 47.3
$ 477.0
$ 71.2
$ 15.0
$ 563.2
Aging Infrastructure 224.5
255.5
90.8
570.8
315.2
93.9
979.9
Load Growth and Other 59.6
89.4
16.8
165.8
66.8
1.5
234.1
Total Distribution 512.8
545.9
154.9
1,213.6
453.2
110.4
1,777.2
Solar —
7.5
—
7.5
—
—
7.5
Total $ 512.8
$ 553.4
$ 154.9
$ 1,221.1
$ 453.2
110.4
$ 1,784.7

2018
Basic Business $ 256.3
$ 217.7
$ 69.3
$ 543.3
$ 72.9
$ 17.0
$ 633.2
Aging Infrastructure 151.6
133.3
73.0
357.9
280.2
81.1
719.2
Load Growth and Other 79.7
94.3
15.6
189.6
51.4
3.6
244.6
Total Distribution 487.6
445.3
157.9
1,090.8
404.5
101.7
1,597.0
Solar and Other —
53.4
0.9
54.3
—
—
54.3
Total $ 487.6
$ 498.7
$ 158.8
$ 1,145.1
$ 404.5
$ 101.7
$ 1,651.3

2017
Basic Business $ 214.0
$ 166.1
$ 67.2
$ 447.3
$ 67.7
N/A
$ 515.0
Aging Infrastructure 180.7
95.4
87.8
363.9
219.9
N/A
583.8
Load Growth and Other 52.3
96.6
13.2
162.1
47.7
N/A
209.8
Total Distribution 447.0
358.1
168.2
973.3
335.3
N/A
1,308.6
Solar and Other —
100.1
8.5
108.6
—
N/A
108.6
Total $ 447.0
$ 458.2
$ 176.7
$ 1,081.9
$ 335.3
N/A
$ 1,417.2


⁽¹⁾	~~Our water distribution business was acquired on December 4, 2017. Amounts are immaterial for the year ended December 31, 2017.~~

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 toof acquisitions, installation of new services, and interconnections of systems.

~~Acquisition of Assets of Columbia Gas of Massachusetts~~: On February 26, 2020, Eversource and NiSource entered into an asset purchase agreement (the Agreement) pursuant to which Eversource would acquire the assets that comprise NiSource’s local gas distribution business, currently doing business as Columbia Gas of Massachusetts (CMA). The purchase price of $1.1 billion includes a target working capital amount that would be adjusted to reflect actual working capital as of the closing date. Eversource would acquire approximately 330,000 residential, commercial, and industrial natural gas customers, as well as over 5,000 miles of natural gas distribution pipeline across more than 60 communities in Massachusetts.

The liabilities to be assumed by Eversource under the Agreement specifically exclude any liabilities (past and future) arising out of or related to the fires and explosions that occurred on September 13, 2018 in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by CMA, including certain subsequent events, all as described in the DPU's Order on Scope dated December 23, 2019 (D.P.U. 19-141) (the Greater Lawrence Incident or GLI), and any further emergency events prior to the closing of the acquisition related to the restoration and reconstruction with respect to the GLI, including any losses arising out of or related to any litigation, demand, cause of action, claim, suit, investigation, proceeding, indemnification agreements or rights.

~~The acquisition and resulting rate plan both require DPU and other approvals. Eversource and NiSource expect to close this transaction later this year.~~

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 ~~2020~~2022 through ~~2024,~~2026, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:


	Years
(Millions of Dollars)	2022		2023		2024		2025		2026		2022 - 2026 Total
CL&P Transmission	$	381	$	240	$	218	$	207	$	201	$	1,247
NSTAR Electric Transmission	459		462		382		459		446		2,208
PSNH Transmission	278		277		261		168		161		1,145
Total Electric Transmission	$	1,118	$	979	$	861	$	834	$	808	$	4,600
Electric Distribution	$	1,450	$	1,469	$	1,391	$	1,372	$	1,338	$	7,020
Natural Gas Distribution	921		849		926		895		938		4,529
Total Electric and Natural Gas Distribution	$	2,371	$	2,318	$	2,317	$	2,267	$	2,276	$	11,549
Water Distribution	$	154	$	163	$	176	$	190	$	206	$	889
Information Technology and All Other	$	254	$	224	$	208	$	203	$	214	$	1,103
Total	$	3,897	$	3,684	$	3,562	$	3,494	$	3,504	$	18,141

Years
(Millions of Dollars) 2020 2021 2022 2023 2024
2020 - 2024
Total
CL&P Transmission $ 384
$ 209
$ 184
$ 182
$ 141
$ 1,100
NSTAR Electric Transmission 366
478
436
296
284
1,860
PSNH Transmission 160
145
235
233
243
1,016
Total Electric Transmission
$ 910
$ 832
$ 855
$ 711
$ 668
$ 3,976
Electric Distribution $ 1,347
$ 1,208
$ 1,162
$ 1,170
$ 1,234
$ 6,121
Natural Gas Distribution 470
498
501
507
537
2,513
Total Electric and Natural Gas Distribution
$ 1,817
$ 1,706
$ 1,663
$ 1,677
$ 1,771
$ 8,634
Water Distribution $ 124
$ 127
$ 134
$ 147
$ 153
$ 685
Information Technology and All Other $ 220
$ 169
$ 165
$ 171
$ 171
$ 896
Total $ 3,071
$ 2,834
$ 2,817
$ 2,706
$ 2,763
$ 14,191

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 New England Service Company: Following receipt of all required approvals, 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. NESC’s utility subsidiaries provided regulated water service to approximately 10,000 customers in Connecticut, Massachusetts, and New Hampshire.

Offshore Wind Business: Our offshore wind business includes a 50 percent ownership ~~interests~~interest in North East Offshore, ~~and Bay State Wind,~~ which ~~together hold~~holds PPAs and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as offshore leases ~~through~~issued by BOEM. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted. This partnership also participates in new procurement opportunities ~~for solicitations~~ for offshore wind energy in the Northeast U.S.

~~On February 8, 2019, Eversource and Ørsted entered into an equal partnership to acquire key~~The offshore ~~wind assets in the Northeast. Eversource has a 50 percent ownership interest in North East Offshore, which holds the Revolution Wind and South Fork Wind projects, as well as~~leases include a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode ~~Island. Eversource also has~~Island and a ~~50 percent ownership interest in Bay State Wind, which holds the Sunrise Wind project. Bay State Wind's~~ separate, adjacent 300-square-mile ocean lease is located approximately 25 miles south of the coast of ~~Massachusetts adjacent to the North East Offshore area.~~Massachusetts. In aggregate, ~~the Bay State Wind and the North East Offshore~~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, 2019, Eversource's total equity investment balance in its offshore wind business was $649.3 million.~~

Currently we are developing our construction and operations plans, concluding on final offshore and onshore project designs and working through our siting and permitting processes, all of which is competitively sensitive. Subject to finalization of these plans, designs and processes, all of which are subject to change and modification as a result of our investment decisions, permit approval timelines and final design decisions, we currently expect to make additional investments in our offshore wind business of approximately $300 million to $400 million over the course of 2020.

The following table provides a summary of the Eversource and Ørsted major projects with announced contracts:

Wind Project

State Servicing

Size (MW)

Term (Years)

Price per MWh

Pricing Terms

Contract Status

Revolution Wind

Rhode Island

400

$98.43

Fixed price contract; no price escalation

Approved

Revolution Wind

Connecticut

304

$98.43 - $99.50

Fixed price contracts; no price escalation

Approved

South Fork Wind

New York (LIPA)

$160.33

2 percent average price escalation

Approved

South Fork Wind

New York (LIPA)

$86.25

2 percent average price escalation

Approved

Sunrise Wind

New York (NYSERDA)

924 (1)

$110.37 (2)

Fixed price contract; no price escalation

Approved

Wind Project State Servicing Size (MW) Term (Years) Price per MWh Pricing Terms Projected In-Service Date Contract Status
Revolution Wind Rhode Island 400 20 $98.43 Fixed price contract; no price escalation End of 2023 Approved
Revolution Wind Connecticut 304 20
⁽¹⁾
Fixed price contracts; no price escalation End of 2023 Approved
South Fork Wind New York (LIPA) 90 20 $160.33 2 percent average price escalation End of 2022 Approved
South Fork Wind New York (LIPA) 40 20 $86.25 2 percent average price escalation End of 2022
⁽³⁾
Sunrise Wind New York (NYSERDA) 880 25
$110.37 ⁽²⁾
Fixed price contract; no price escalation End of 2024 Approved


⁽¹⁾	~~The pricing for the Revolution Wind contracts in Connecticut has not yet been publicly disclosed.~~


⁽²⁾	~~Index OREC strike price.~~


⁽³⁾	~~The Long Island Power Authority (LIPA) agreed to expand~~(1) The contractual capacity increased from 880 MWs to 924 MWs, as allowed under the original ~~20-year PPA from 90 MW to 130 MW through an amendment to the original agreement. Negotiations are currently underway, and a final amendment is expected in the first half of 2020.~~

~~On October 23, 2019, the New York State Energy Research and Development Authority (NYSERDA) announced the execution of a 25-year~~ agreement with ~~the Sunrise Wind project to purchase~~NYSERDA.

(2) Index Offshore Wind Renewable Energy ~~Certificates (ORECs) from an 880 MW~~Certificate (OREC) strike price.

As of December 31, 2021 and 2020, Eversource's total equity investment balance in its offshore wind ~~facility. The Sunrise Wind project is held by Bay State Wind~~business was $1.21 billion and ~~will use a combination~~$887 million, 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, ~~from Bay State Wind~~ and ~~North East Offshore. Sunrise Wind will be developed 35 miles east of Montauk Point, Long Island.~~capitalized interest.

~~The completion dates for these~~Our offshore wind projects are subject to receipt of federal, state and local approvals necessary to construct and operate the projects. The federal permitting ~~through~~process is led by BOEM, ~~engineering,~~and state ~~siting and permitting in~~approvals are required from New York, ~~and~~ Rhode Island and ~~finalizing a PPA amendment in New York.~~Massachusetts. Significant delays in the siting and permitting process ~~including~~resulting from the ~~timing of~~timeline for obtaining approval from BOEM ~~approval,~~and the state and local agencies could adversely impact the timing of these projects' in-service dates. ~~Currently,~~

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 ~~has indicated it will~~review process is an issuance of a Notice of Intent (NOI) to complete ~~its Cumulative Impact Study as part of the Draft Supplemental~~an Environmental Impact Statement (EIS). BOEM then provides a final review schedule for ~~a non-affiliated offshore wind~~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 ~~during~~and recommends measures to minimize impacts. The Final EIS will inform BOEM in deciding whether to approve the ~~second quarter~~project or to approve with modifications and BOEM will then issue its Record of ~~2020. The study is designed to assess~~Decision. BOEM issues its final approval of the ~~overall environmental impact~~COP following the Record of ~~all offshore wind projects. Federal siting~~Decision.

South Fork Wind filed its COP application with BOEM in 2018 and ~~permitting have commenced~~BOEM issued the NOI in 2018. In August 2020, South Fork Wind received the final review schedule from BOEM regarding its COP approval. In January 2021, BOEM released its Draft EIS for the South Fork Wind project ~~as it has filed~~and in August 2021, BOEM released its ~~Construction Operations Plan (COP) application with BOEM.~~Final EIS. On November 24, 2021, BOEM issued its Record of Decision, which concluded BOEM’s environmental review of the project and identified the recommended configuration. The Record of Decision supported South Fork Wind’s proposed turbine layout. On January 18, 2022, South Fork Wind ~~is designated as "FAST-41" by~~received BOEM’s final approval of its COP. The COP approval outlines the ~~U.S. Federal Permitting Improvement Council’s FAST-41 infrastructure projects, which provides greater~~project’s one nautical mile turbine spacing, the requirements on the construction methodology for all work occurring in federal ~~assistance associated with program timelines.~~ ocean waters, and mitigation measures to protect marine habitats and species.

Revolution Wind and Sunrise Wind filed their COP ~~filings are planned~~applications with BOEM in ~~2020.~~ March 2020 and September 2020, respectively. On April 30, 2021, Revolution Wind received BOEM’s NOI to prepare an EIS for the review of the COP submitted by Revolution Wind. For Revolution Wind, a final EIS is expected in the first quarter of 2023, the Record of Decision in the second quarter of 2023, and final approval is expected in the third quarter of 2023. On August 31, 2021, Sunrise Wind received BOEM’s NOI to prepare an EIS for the review of the COP. For Sunrise Wind, a final EIS and Record of Decision is expected in the third quarter of 2023, and final approval is expected in the fourth quarter of 2023.

South Fork Wind, ~~previously filed federal and state applications in 2018. State agencies also will review siting applications for~~ 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:South Fork Wind commenced the New York state siting process in 2018. On September 17, 2020, South Fork Wind filed a Joint Proposal in the New York State Article VII siting application. Among other things, the Joint Proposal included proposed mitigation for certain environmental, community and construction impacts associated with constructing the project. South Fork Wind was joined by PSEG Long Island and several citizens advocacy organizations. On October 9, 2020, the Joint Proposal was signed by the New York Departments of Public Service, Environmental Conservation, Transportation and State as well as the Office of Parks, Recreation and Historic Preservation. On March 18, 2021, the New York Public Service Commission approved an order adopting the Joint Proposal and granting a Certificate of Environmental Compatibility and Public Need. Two petitions for re-hearing of the New York Public Service Commission decision have been filed, and South Fork Wind responded on May 3, 2021 opposing the re-hearing requests. In April 2021, South Fork 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 reviewing agencies and parties have been received and South Fork Wind has responded to and addressed those comments in the plan which was re-submitted in September 2021. The project received approval of the EM&CP in November 2021.

On September 10, 2020, the Town of East Hampton and the East Hampton Town Trustees announced that they had reached an agreement with South Fork Wind to issue the necessary easements and other real estate rights necessary to construct the South Fork Wind project. The Town approved the easements on January 21, 2021, and Trustees approved the real estate lease on January 25, 2021.

State permitting applications in Rhode Island for Revolution Wind and in New York for Sunrise Wind were filed in December 2020. The Revolution Wind state siting application was deemed complete on January 22, 2021, and the preliminary hearing was completed on March 22, 2021. On April 26, 2021, the Rhode Island Energy Facilities Siting Board issued a Preliminary Decision and Order on scheduling with Advisory Opinions for local and state agencies. All advisory opinions were received in August, in accordance with the expedited schedule, and evidentiary hearings began in October 2021. The Sunrise Wind state siting application ~~filings planned~~was deemed complete on July 1, 2021, initiating the formal review process, and Sunrise Wind filed a formal notice of intent to commence settlement negotiations towards a Joint Proposal on August 31, 2021. Settlement negotiations are ongoing.

Construction Process - South Fork Wind: South Fork Wind has received all required approvals to start construction and the project has now entered the construction phase. Site preparation and onshore activities for the project’s underground onshore transmission line and construction of the onshore interconnection facility located in ~~2020.~~ East Hampton, New York will be the first to begin. Offshore installation, including the project’s monopile foundations, 11-megawatt wind turbines, and offshore substation, is 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 agency approvals, however it believes it will be able to overcome these challenges.

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, and are continuing to analyze the overall project schedules.

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 now underway. Construction-related purchase agreements with third-party contractors and materials contracts are approximately 80 percent 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 $0.9 billion and $1.0 billion in 2022 and expect to make investments for our three projects in total between $3.0 billion and $3.6 billion from 2023 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned.

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, the FERC 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, ~~2019.~~2021 and 2020. 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, ~~2019.~~2021 and 2020.

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.

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 2021 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 ~~Notices~~Notice of ~~Inquiry:~~Inquiry on ROE: On March 21, 2019, FERC issued ~~two Notices~~a Notice of Inquiry (NOI) ~~that may affect Eversource transmission ROEs and incentives. One NOI (the "FERC ROE NOI") seeks~~seeking comments from all stakeholders on FERC's policies for evaluating ROEs for electric public utilities, and interstate natural gas and oil pipelines. ~~The other NOI (the FERC transmission incentives NOI) seeks comments on FERC's policies for implementing electric transmission incentives.~~ On June 26, 2019, the NETOs jointly filed comments ~~in the FERC ROE NOI,~~ supporting the methodology established in the FERC’s October 16, 2018 order with minor enhancements going forward. ~~Also,~~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 ~~in the FERC transmission incentives NOI,~~ 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. ~~The NETOs jointly filed reply comments in the FERC ROE NOI on July 26, 2019.~~ Eversource filed reply comments ~~in the FERC transmission incentives NOI~~ 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 the Commission’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 the FERC issues a final order eliminating the RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual impact (using 2021 estimated rate base) on Eversource’s after-tax earnings is approximately $17 million. The Supplemental NOPR contemplates an effective date 30 days from the final order.

At this time, Eversource cannot predict ~~how~~the ultimate outcome of these ~~NOIs will affect its ROEs or incentives.~~

~~FERC Transmission Rate Settlement:~~ ~~On December 28, 2015, FERC initiated a proceeding to~~proceedings, including possible appellate review, the NETOs' regional and local transmission formula rates due to a lack of transparency, finding that the formula rates appeared to lack sufficient details to determine how costs are derived and recovered in rates. This proceeding was set for hearing but held in abeyance to provide time for settlement judge procedures. On August 17, 2018, a signed Settlement Agreement between twenty-eight parties, including all six New England state regulatory commissions, the NETOs (including CL&P, NSTAR Electric and PSNH) and other settling parties, was filed at the FERC. The Settlement Agreement included, among other things, a new formula rate template in which all regional and local transmission revenue requirements will be determined through a single formula rate. The Settlement Agreement was contested by a group of municipal entities and the FERC Trial Staff. On May 22, 2019, FERC rejected the Settlement Agreement and remanded the proceeding for hearings. The parties have been engaged in further settlement negotiations and reached an agreement in principleresulting impact on October 22, 2019. The FERC Chief Administrative Law Judge has approved two suspensions of the schedule for ninety days each for the NETOs to review the terms with other active parties and finalize the settlement. The procedural schedule has been suspended to April 22, 2020.

its transmission incentives.

~~U.S. Federal Corporate Income Taxes:~~
Effective January 1, 2018, the local transmission service rates were updated to reflect the lower U.S. federal corporate income tax rate that resulted from the Tax Cuts and Jobs Act. On June 28, 2018, FERC granted a one-time waiver of tariff provisions related to the federal corporate income tax rate so that, effective June 1, 2018, the regional transmission service rates also reflect the reduced federal corporate income tax rate of 21 percent. The local and regional transmission service rates do not currently reflect amortization of excess ADIT (EDIT) balances that resulted from the Act. On November 15, 2018, FERC issued a Policy Statement and a separate Notice of Proposed Rulemaking addressing accounting and rate issues related to ADIT changes resulting from the Act. On November 21, 2019, FERC issued its final rule requiring public utilities with transmission formula rates to make adjustments to ADIT and EDIT. Eversource expects to submit a filing demonstrating its compliance with the final rule in the second half of 2020.

Regulatory Developments and Rate Matters

Electric, Natural Gas and Water Utility ~~Base Distribution~~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 ~~or for PURA to initiate a rate review,~~ within four years of the last rate case. CL&P's and Yankee Gas' distribution rates were each established in ~~an April~~ 2018 PURA-approved rate case settlement agreements. On October 27, 2021, PURA approved a settlement agreement ~~with rates effective May~~at CL&P that included a current base distribution rate freeze until no earlier than January 1, ~~2018. Yankee Gas'~~2024. The approval of the settlement agreement satisfies the Connecticut statute of rate review requirements that requires electric utilities to file a distribution ~~rates were established in a December 2018 PURA-approved~~ rate case ~~settlement agreement with rates effective November 15, 2018.~~within four years of the last rate case. Aquarion is not required to initiate a rate review with the ~~PURA.~~PURA on a set schedule. Aquarion rates were established in a 2013 PURA-approved rate case.

In Massachusetts, electric distribution companies are required to file at least one distribution rate case every five years, and natural gas local distribution companies to file at least one distribution rate case every 10 years, and those companies are limited to one settlement agreement in any 10-year period. NSTAR Electric's distribution rates were established in a 2017 DPU-approved rate ~~case~~case. On January 14, 2022, NSTAR Electric filed an application with the DPU for an increase in base distribution rates, effective ~~February~~January 1, ~~2018.~~

2023. NSTAR Gas' distribution rates were established in ~~a 2015~~an October 2020 DPU-approved rate case. ~~See "Regulatory Developments and Rate Matters - Massachusetts"~~EGMA's distribution rates were established in ~~this~~ ~~Management's Discussion and Analysis of Financial Condition and Results of Operations,~~ ~~for NSTAR Gas' November 2019~~an October 2020 DPU-approved rate ~~case application with the DPU.~~settlement agreement. Aquarion is not required to initiate a rate review with the DPU. Aquarion rates were established in ~~an October~~a 2018 DPU-approved rate case.

In New Hampshire, PSNH's ~~temporary~~ distribution rates were established in a December 2020 NHPUC-approved rate case settlement agreement approved by the NHPUC on June 27, 2019, with temporary rates effective July 1, 2019. On May 28, 2019, PSNH filed an application with the NHPUC for a permanent increase in base distribution rates, effective July 1, 2020. See "Regulatory Developments and Rate Matters - New Hampshire" in this ~~Management's Discussion and Analysis of Financial Condition and Results of Operations,~~ ~~for more information.~~agreement. Aquarion rates were established in a 2013 NHPUC-approved rate case, further revised in 2016. InOn December 18, 2020, Aquarion filed an application with the NHPUC for a ~~2019 settlement approved~~permanent increase in base rates and a decision by the NHPUC ~~Aquarion was ordered to file its next full rate proceeding no later than 2020.~~is expected in the second quarter of 2022.

~~Electric, Natural Gas and Water Utility Retail Rates:~~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 ~~have~~has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, electric retail transmission charges, energy efficiency program costs, electric ~~retail transmission charges, electric~~ restructuring and stranded ~~costs~~cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for ~~our~~the Massachusetts ~~companies,~~utilities, pension and PBOP benefits, ~~and~~ net metering for distributed ~~generation.~~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 ~~rate base,~~capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings.

~~U.S. Federal Corporate Income Taxes:~~ Excess ADIT Amortization:On Eversource amortized excess ADIT (EDIT) of $69.1 million in 2021, $48.7 million in 2020 and $37.4 million in 2019. In 2021, EDIT amortization was $9.8 million at CL&P, $43.2 million at NSTAR Electric, and $10.5 million at PSNH. Of the 2021 total EDIT amortized, the Company’s transmission businesses amortized $15.4 million pursuant to FERC orders issued on December 22, ~~2017,~~2021 and December 30, 2021 that approved the ~~Tax Cuts~~refund of EDIT to its transmission customers ($1.6 million at CL&P, $12.0 million at NSTAR Electric and ~~Jobs Act became law, which amended existing federal tax rules~~$1.8 million at PSNH). The effective date of these FERC orders was January 27, 2020, resulting in catch-up amortization recorded in 2021. EDIT amortization in 2020 and 2019 pertained solely to ~~reduce~~ the U.S. federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. For our regulated companies, the most significant changes are (1) the benefit of incurring a lower federal income tax expense and (2) the reduction in ADIT liabilities (now excess ADIT or EDIT), which are estimated to be approximately $2.8 billion and are included in regulatory liabilities as of December 31, 2019.Company’s distribution businesses. The refund of these EDIT regulatory liabilities to customers will generally be made over the same period as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities. The refund ~~of EDIT has begun at most of our distribution companies and is reflected in rates. The refund~~ to customers and resulting amortization of the EDIT regulatory liabilities results in lower ~~Revenues on~~revenues (for the ~~statements~~amortization of the EDIT and the tax gross up portion) and lower income tax expense (for the amortization of EDIT and lower current tax ~~expense. This is offset by~~benefits from the ~~reduction to Income Tax Expense due to~~tax gross up portion) on the ~~amortization~~statement of ~~the EDIT.~~income. The refund of EDIT results in a lower effective tax rate and no impact on net income.

Connecticut:

CL&P Deferred Storm Costs: In 2021 and 2020, multiple tropical and severe storms caused extensive damage to CL&P’s electric distribution systems and customer outages, along with significant pre-staging costs. These storms resulted in deferred pre-staging and storm restoration costs at CL&P of $232 million for 2021 storms and $344 million for 2020 storms, including the catastrophic impact of Tropical Storm Isaias in August 2020, among others. Management believes that all of these storm costs were prudently incurred and meet the criteria for specific cost recovery. As part of CL&P’s October 1, 2021 settlement agreement described below, it agreed to freeze its current base distribution rates (including storm costs) until no earlier than January 1, 2024.

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 prudency 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 $234 million at CL&P and $251 million at Eversource ~~established~~as of December 31, 2021. 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 the 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 the PURA to have a material impact on the financial position or results of operations of Eversource or CL&P.

CL&P Tropical Storm Isaias Response Investigation: In August 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by Connecticut utilities, including CL&P. 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. Specifically, PURA concluded that CL&P did not satisfy the performance standards for managing its municipal liaison program, timely removing electrical hazards from blocked roads, communicating critical information to its customers, or meeting its obligation to secure adequate external contractor and mutual aid resources in a timely manner. 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. In its decision, PURA explained that additional monetary penalties and further enforcement orders pursuant to Connecticut statute would be considered in a separate proceeding that was initiated on May 6, 2021.

On May 6, 2021, as part of the penalty proceeding, PURA issued a notice of violation that included an assessment of $30 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 $1.6 million fine for violations of accident reporting requirements to be paid to the State of Connecticut’s general fund. On July 14, 2021, PURA issued a final decision in this penalty proceeding that included an assessment of $28.6 million, maintaining the $28.4 million performance penalty and reducing the $1.6 million fine for accident reporting to $0.2 million. The $28.4 million performance penalty is currently being 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 ~~recorded~~on CL&P’s balance sheet and as a reduction to ~~revenue,~~Operating Revenues on the year ended December 31, 2021 statement of income. The after-tax earnings impact of this charge was $0.07 per share.

PURA New Rate Design and Rate Review Proceeding: Pursuant to ~~reflect~~an October 2020 Connecticut law, PURA opened a proceeding related to new

rate designs to consider the ~~difference between the 35 percent federal corporate income tax~~implementation of an interim rate ~~included in~~decrease, low-income and economic development rates ~~charged to~~for electric customers, and a

review of that rate design implementation process. The proceeding has separate phases. In the ~~21 percent federal corporate income tax~~first phase, PURA issued a final decision on June

23, 2021 directing CL&P to offer new rates to certain small commercial and industrial customers that will reduce demand charges and instead

include volumetric charges for electricity based on kWh used. Customers can elect to transition to these new offered rates, which became effective

November 1, 2021. PURA’s decision in the first phase of the proceeding is not expected to have a material impact on CL&P’s earnings,

financial position, or cash flows. The second phase of this proceeding was addressed in PURA’s September 14, 2021 decision, and would have resulted in an interim rate ~~effective January 1, 2018~~decrease associated with a 45 basis point reduction in CL&P’s authorized ROE. This phase of the proceeding was resolved as a result of the ~~Tax Cuts~~October 2021 settlement agreement, described below. In addition, PURA is also investigating low-income and ~~Jobs Act, until rates billed~~other economic development rates. A procedural schedule for this part of the proceeding has not yet been set by the PURA.

CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel (OCC), Office of the Attorney General (AG) and the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory proceedings initiated by the 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 to provide bill payment assistance to certain existing non-hardship and hardship customers ~~reflected~~carrying arrearages, as approved by the ~~lower federal tax rate. As~~PURA, with the objective of disbursing the funds prior to April 30, 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, ~~2019, this liability, net~~2021 statement of ~~amounts refunded~~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 ~~customers, was $14.6 million.~~

~~Eversource's regulated companies are~~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 ~~process~~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 ~~will, refund~~any other proceedings, either currently pending or that may be initiated during the ~~decrease~~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 ~~income tax~~interim rate ~~based on orders~~reduction docket. The settlement agreement assures that CL&P will have the opportunity to petition for and demonstrate the prudency 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.

CL&P Rate Adjustment Mechanisms (RAM) Filing: On July 31, 2020, PURA temporarily suspended its June 26, 2020 approval of certain delivery rate components effective July 1, 2020, and ordered CL&P to restore rates to those in effect as of June 30, 2020 in order to allow PURA time to reexamine the rates. Rates were adjusted effective August 1, 2020. On December 2, 2020, PURA issued ~~by applicable state and federal regulatory commissions. A summary of~~a final decision in which it adjusted the timing of ~~refunds related~~the annual rate adjustments for the Transmission Adjustment Clause (TAC) charge, the Non-Bypassable Federally Mandated Congestion Charge (NBFMCC), the Electric System Improvements Tracker (ESI), Competitive Transition Assessment (CTA), System Benefits Charge (SBC) and Revenue Decoupling Mechanism (RDM) so that these rates take effect on May 1st of each year. On April 28, 2021, PURA issued its interim decision on CL&P’s proposal that accepted the May 1, 2021 rate proposals for the CTA, TAC, ESI and RDM, but ordered that these rate changes go into effect on June 1, 2021, as opposed to May 1, 2021. Further, PURA elected to keep in place the current rates for the NBFMCC and SBC until further review of the costs being recovered in those rates could be performed. Finally, PURA indicated it would further review CL&P’s proposal to begin recovery of 2020 under-recoveries associated with these rates on October 1, 2021.

On September 15, 2021, PURA issued its final decision in the 2020 RAM reconciliation filing, which required no adjustment to the ~~change~~GSC, BFMCC, NBFMCC, SBC, CTA, ESI and base distribution rates, but resulted in changes to the ~~tax rate is as follows:~~



~~Eversource Utility and Jurisdiction~~	~~EDIT Refund Timing~~	~~Effective Date of~~ ~~January 1, 2018 Tax Rate~~ ~~Reflected in Rates~~
~~Connecticut~~
~~CL&P~~	~~Reflected in rates effective May 1, 2019~~	~~May 1, 2018~~
~~Yankee Gas~~	~~Reflected in rates effective November 15, 2018~~	~~November 15, 2018~~
~~Massachusetts~~
~~NSTAR Electric~~	~~Reflected in rates effective January 1, 2019~~	~~February 1, 2018~~
~~NSTAR Gas~~	~~Reflected in rates effective February 1, 2019~~	~~July 1, 2018~~
~~New Hampshire~~
~~PSNH~~	~~Refunds for EDIT are being addressed in permanent distribution rate case filing~~ ~~Refunds for EDIT related to PSNH's divested generation assets reflected in rates effective August 1, 2018~~	~~July 1, 2019 for distribution~~
~~Transmission~~
~~CL&P, NSTAR Electric and PSNH~~	~~Refunds for EDIT will be made based on November 2019 final ruling from FERC. Eversource expects to submit a filing demonstrating its compliance with the final rule in the second half of 2020.~~	~~January 1, 2018 for local transmission service and~~ ~~June 1, 2018 for regional transmission service~~

TAC and RDM rates effective October 1, 2021. As part of this decision, PURA also approved the recovery of cumulative under-recoveries associated with the NBMFCC, TAC, and RDM of $193 million effective October 1, 2021. The NBFMCC and TAC under-recoveries will be recovered over a 31-month period and the RDM under-recovery will be recovered over a 15-month period.

~~Connecticut:~~

CL&P ~~Storm~~Impact of 2021 Rate Changes (Excluding Supply Rates): On June 1, 2021, CL&P implemented an overall rate increase of $0.00411 per kWh for residential customers. The rate increase included delivery rate changes for the CTA, TAC, ESI and RDM charges. Partially offsetting the rate increase was a base distribution rate decrease, which was driven by a reduction to storm cost amortization resulting from a 2019 PURA decision. For residential customers with 700 kWh monthly usage, the impact of the June 1, 2021 rate changes equated to an increase of $2.88 on monthly customer bills.

On September 1, 2021, CL&P adjusted its rates for the $28.4 million penalty imposed by the PURA for non-compliance with performance standards that is being provided as credits on customer bills over a one-year period. On October 1, 2021, CL&P implemented new TAC and RDM delivery rates. In total, CL&P implemented an overall net rate increase of $0.00174 per kWh for residential Rate 1 customers for these rate component charges, net of the rate decrease for the storm penalty credit. The impact of the September 1 and October 1, 2021 rate changes equated to an increase of $1.22 on monthly customer bills for residential customers with 700 kWh monthly usage.

On December 1, 2021, CL&P adjusted its rates for the $65 million of customer credits resulting from the October settlement agreement that were distributed based on customer sales over a two-month period from December 1, 2021 to January 31, 2022. For residential customers with 700 kWh monthly usage, the impact of the settlement credit equated to $34.25 for the two-month period.

Residential Customer Bill Credits and Reimbursements for Storm-Related Outages: On June 30, 2021, in accordance with an October 2020

Connecticut law, PURA issued a final decision establishing standards and procedures for residential customers to receive bill credits and other

compensation for spoiled food and medicine from Connecticut utilities, including CL&P, after future weather-related emergencies. The PURA

decision requires, effective after July 1, 2021, that Connecticut utilities provide customers with a $25 bill credit for each 24-hour time period

following the initial 96 consecutive hours of an electric distribution outage after a major storm or emergency. The decision also authorizes residential customers to submit a claim to receive up to $250 in compensation for any medication and food that expired or spoiled due to an electric distribution outage lasting longer than 96 consecutive hours. The decision also establishes a process by which the electric utilities (i) can elect to submit a filing within seven days of a storm event that proposes when the 96-hour time period commenced for that storm event based on relevant weather data, when it was safe to deploy crews into the field, and the other relevant factors identified in the decision; and (ii) can elect to seek within 14 days of a storm event a waiver from providing customer bill credits, for reasons such as line worker safety and continuing emergency or potentially hazardous conditions that prevented or delayed restoration activities.

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 and procedural schedule established for the second phase expected in March 2023. At this time, we cannot predict the ultimate outcome of this proceeding and the resulting impact to CL&P.

CL&P Advanced Metering Infrastructure Filing: On July 31, 2020, CL~~&P's approved rate~~&P submitted to PURA its proposed $512 million Advanced Metering Infrastructure investment and implementation plan for the years 2021 through 2027. 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, which included additional information as required by the PURA. As required, the plan includes a full deployment of advanced metering functionality and a composite business case ~~settlement~~ in 2018 incorporated $18.6 million of rate base recovery for catastrophic storms occurring after December 31, 2016, subject to a future storm filing. On November 16, 2018, CL&P filed for recovery of $153 million of storm costs incurred from October 2017 through May 2018, with recovery over six years to begin May 1, 2019. Through the coursesupport of the Advanced Metering Infrastructure plan. A procedural schedule in this proceeding ~~CL&P updated its request to $145.5 million to reflect final invoicing and capitalization amounts. On April 17, 2019, PURA authorized recovery of $141.0 million as part of storm cost recovery and~~has not been issued by the ~~remainder to be recorded to plant or other balance sheet accounts.~~PURA.

Massachusetts:

NSTAR Electric Distribution Rates: As part of an inflation-based mechanism, NSTAR Electric submitted its fourth annual Performance Based

Rate Adjustment filing on November 10, 2021 and on December 22, 2021, the DPU approved a $36.8 million increase to base distribution rates for effect on January 1, 2022.

NSTAR Electric Distribution Rate Case: On January 14, 2022, NSTAR Electric filed an application with the DPU for approval of an $89 million increase in base distribution rates, with new rates anticipated to be effective January 1, 2023. As part of this filing, NSTAR Electric is requesting a renewal of the performance-based ratemaking plan originally authorized in its last rate case for up to a ten-year term, alignment with state electrification policy, storm fund refinements, and Advanced Metering Infrastructure tariff approval. A final decision from the DPU is expected on December 1, 2022.

NSTAR Electric Grid Modernization and Advanced Metering Infrastructure Filing: On July 1, 2021, NSTAR Electric submitted for DPU approval its four-year $198.8 million grid modernization plan for the years 2022 through 2025 and proposed $620 million Advanced Metering Infrastructure investment and implementation plan for the years 2023 through 2028. As required, the plan includes a ten-year vision, five-year strategic plan, including a full deployment of advanced metering functionality, separate four-year grid-facing and customer-facing short-term investment plans, and a composite business case in support of the Advanced Metering Infrastructure plan. NSTAR Electric has requested expedited approval of $38.3 million of the $198.8 million grid modernization plan for previously approved continuing investments that are currently in process and are expected to be spent in 2022 so these activities will not be interrupted pending full plan approval. NSTAR Electric expects DPU guidance for all investment years by the second quarter of 2022. For Advanced Metering Infrastructure investments, additional review of the cost recovery mechanism will be conducted in NSTAR Electric’s base distribution rate case that was filed on January 14, 2022 with a decision expected on December 1, 2022.

NSTAR Electric Storm Threshold Filing: On December 22, 2021, the DPU approved NSTAR Electric to defer for future recovery the storm cost threshold amounts associated with six qualifying major storm events that occurred during 2020, totaling $7.2 million. The DPU approved the deferral of threshold costs that exceeded four storms (those recovered in base rates plus one additional storm) until the next rate case proceeding, at which time the DPU will determine the appropriate level of recovery of storm threshold amounts. In its January 14, 2022 distribution rate case filing, NSTAR Electric is also seeking recovery of the deferral of threshold costs for an additional seven storms in 2021. The pre-tax benefit to earnings for the deferral as a regulatory asset of threshold costs for both the 2020 and 2021 major storms was $15.6 million and was recorded in the fourth quarter of 2021.

NSTAR Gas and EGMA Distribution Rates and Mitigation Filings: As part of an inflation-based mechanism, NSTAR Gas submitted its first annual Performance Based Rate Adjustment filing on September ~~16, 2019~~15, 2021, for rates effective November 1, 2021. As established in the October 7, 2020 EGMA Rate Settlement Agreement, EGMA filed for its first base distribution rate increase on September 17, 2021, for rates effective November 1, 2021. Subsequent to those base distribution rate filings, on October 6, 2021, NSTAR Gas and EGMA made filings with the DPU to defer recovery of certain costs for the purpose of mitigating November 1, 2021 bill impacts associated with the new delivery rates as a result of increases in natural gas supply costs, thereby providing rate relief to customers. These adjustments to rates do not impact the recovery of costs, only the timing of when the costs are collected in rates. For NSTAR Gas and EGMA, these adjustments included delaying the decoupling revenue requirement, the recovery of certain prior period under-collections, and portions of the base distribution rate change for NSTAR Gas, until November 1, 2022. These adjustments delay recovery of $16.7 million for NSTAR Gas and $19.7 million for EGMA for a one-year period. These adjustments result in the under-recovery of costs beginning November 1, 2021, with no material impact on the statement of income.

For NSTAR Gas, the DPU approved a ~~$33.6~~$13.6 million increase to base distribution rates on ~~December 19, 2019 for effect on January~~October 29, 2021, effective November 1, ~~2020.~~

~~NSTAR Gas Rate Case: On November 8, 2019, NSTAR Gas filed its application with~~2021. For EGMA, the DPU ~~which sought~~approved a $13 million increase to base distribution ~~rate increase of $38.0 million~~rates on October 28, 2021, effective ~~October~~November 1, 2020. As part of this filing, NSTAR Gas also proposed to continue its ongoing Gas System Enhancement Program (GSEP), include the GSEP investments since 2015 into base rates, and implement a performance-based ratemaking plan. A final decision from the DPU is expected by September 30, 2020.

2021.

~~Hingham Vote to Acquire Water System:~~
On April 22, 2019, the town of Hingham, Massachusetts voted to acquire the water system and treatment plant that supplies water to the towns of Hingham, Hull and North Cohasset. The acquisition price is currently estimated to be more than $100 million, subject to adjustment based on actual capital investments as legally required and other future closing adjustments. Aquarion will continue to operate the water system consistent in all material respects with its obligations under applicable law during the transition period, until the sale closes. The Company is evaluating the impact of the sale on its financial statements, which will be recorded when the sale transaction closes. No loss is expected upon the ultimate conclusion of this transaction. The transaction is expected to close in the second half of 2020. As of December 31, 2019, these water distribution assets were included within Property, Plant and Equipment, Net and goodwill on the balance sheet and were also reflected in the Water Distribution segment and reporting unit.

New Hampshire:

PSNH Distribution Rates: ~~On April 26, 2019, PSNH filed~~In connection with an ~~application with the NHPUC for approval of a temporary annual base distribution rate increase of approximately $33 million, effective July 1, 2019. On June 27, 2019,~~October 9, 2020 settlement agreement, the NHPUC approved a ~~settlement agreement that was reached by PSNH, the NHPUC Staff, the Office of the Consumer Advocate, and another settling party, to implement a temporary annual base distribution~~permanent rate increase of ~~$28.3 million. Although new rates were implemented on~~$45.0 million 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, ~~to customers,~~2020 and 2021, respectively. On December 23, 2020, the ~~provisions of~~NHPUC approved the ~~temporary base distribution rate increase were effective July 1, 2019. The settlement agreement also permits PSNH~~first step adjustment for 2019 plant in service to recover ~~approximately $68.5~~a revenue requirement of $10.6 million, ~~in unrecovered storm costs over a five-year period beginning August~~effective January 1, ~~2019, with debt carrying charges, which is included in the temporary rate increase.~~

2021. On ~~May 28, 2019, PSNH filed an application with~~July 30, 2021, the NHPUC approved the second step adjustment for 2020 plant in service to recover a ~~permanent increase in base distribution rates~~revenue requirement of ~~approximately $70~~$11.0 million, ~~effective July 1, 2020, which includes the temporary rate increase request. The temporary rates are~~ subject to reconciliation ~~based on~~after completion of an audit, with rates effective August 1, 2021.

COVID Regulatory Docket: On July 7, 2021, the ~~outcome~~NHPUC issued an order to New Hampshire utilities that concluded that recovery of incremental bad debt or waived late fees related to the COVID-19 pandemic would be addressed in the context of the ~~permanent~~utility’s next rate case ~~now before~~when related costs, to the ~~NHPUC.~~extent those costs remain relevant under test year based rate-setting, would be considered in the context of the utility’s full revenue requirement and overall rate of return. The NHPUC isconcluded that New Hampshire utilities would not be permitted up to ~~twelve months to adjudicate~~establish a regulatory asset for these items. As a result of the ~~permanent rate application from the date of filing. A decision by the NHPUC is expected~~order, in the second quarter of ~~2020.~~

2021, PSNH removed its $0.6 million deferral of net incremental COVID-19 costs.

~~2013 through 2016 Storm Costs:~~

Energy Efficiency Plan: On ~~March 26, 2019,~~November 12, 2021, the NHPUC ~~approved~~issued an order rejecting the proposed 2021 through 2023 energy efficiency plan and significantly reduced funding and operational functions of the program. PSNH made programmatic adjustments in late November and December 2021 to ensure utilization of the 2021 budget and achievement of the 2021 performance incentive. The order eliminated the recovery of ~~$38.1 million, plus carrying charges,~~performance incentives beginning in 2022. PSNH sought rehearing of ~~storm costs incurred from December 2013 through April 2016~~the order and was denied. There is state legislation pending that would undo the most impactful effects of the order. PSNH, as well as various other parties, have appealed the order to the New Hampshire Supreme Court. The energy efficiency rate for 2022 went into effect January 1, 2022 at a level that is 29 percent lower than the 2021 rate. However, effective March 1, 2022, the energy efficiency rate will be restored to the 2021 level. Given the pending legislation that has already passed the New Hampshire Senate and the ~~transfer of funding from PSNH’s major storm reserve to recover those costs. The costs of these storms (excluding the equity return component~~four Supreme Court appeals filed, it is likely that at least some of the ~~carrying charges) were deferred as regulatory assets,~~provisions of the NHPUC order will be undone. At this time, PSNH cannot predict the ultimate outcome of this order, and the funding reserve collected from customers was accrued as a regulatory liability. As a result of the duration of time between incurring storm costs in December 2013 through April 2016 and final approval from the NHPUC in 2019, PSNH recognized $5.2 million (pre-tax) for the equity return component of the carrying charges within Other Income, Netresulting impact on ~~the statement of income in 2019, which has been collected from customers. Also included in the March 26, 2019 NHPUC approval is a prospective requirement for PSNH to annually net~~ its ~~storm funding reserve collected from customers against deferred storm costs.~~financial statements.

Legislative and Policy Matters

~~New Hampshire:~~Federal: 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.

Massachusetts: On ~~July 8, 2019,~~March 26, 2021, Governor Baker signed into law a climate change bill which permits electric or natural gas distribution companies to assist Massachusetts municipalities in responding to the ~~New Hampshire Superior Court approved a settlement between PSNH and the Town~~risks of ~~Bow, New Hampshire, where the town had over-assessed the value~~climate change by owning solar facilities equal to up to 10 percent of the ~~property owned by PSNH for~~total installed solar generating capacity in Massachusetts as of July 31, 2020. Such facilities may be paired with energy storage where feasible to do so. This law will allow each of Eversource’s Massachusetts operating companies to own up to approximately 280 MWs of solar generating facilities in addition to the 2014 through 2018 property tax years. The result of this settlement was $10.0 million in over-paid property taxes, of which PSNH has received $4.25 million in cash through December 31, 2019. PSNH will receive the balance thereafter to be credited against future property taxes payable, annually through 2023.70 MWs previously constructed at NSTAR Electric.

In addition, PSNH reached a collective resolution with an additional 61 municipalities for an aggregate total of approximately $7 million, where the towns had over-assessed the value of the property owned by PSNH for the 2015 through 2017 property tax years.

~~Federal:~~ On December 20, 2019, the "Further Consolidated Appropriations Act, 2020," became law, which provided a one-year extension of the production tax credit or the investment tax credit for renewable wind projects under Section 45 of the Internal Revenue Code of 1986 on which construction begins before January 1, 2021. If construction begins on a qualifying wind project in 2020, the project will qualify for a production tax credit of $15 per MWh or an 18 percent investment tax credit.

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 use judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. The ultimate outcome of regulatory rate proceedings could have a significant effect on our ability to recover costs or earn an adequate return. Established rates are also often subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. We have approximately $1 billion of storm restoration and pre-staging costs that are subject to prudency reviews from our regulators. We believe that our storm costs were prudently incurred and are probable of recovery.

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 believe it is probable that each of ~~the~~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, ~~to our operations,~~ 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. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost. 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 at least 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: 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 when appropriate.~~allocations. For the year ended December 31, ~~2019,~~2021, 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 ~~2020~~2022 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: 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, ~~2019,~~2021, the discount rates used to determine the funded status were within a range of ~~3.04~~2.8 percent to ~~3.35~~3.0 percent for the Pension and SERP Plans, and within a range of ~~3.26~~2.91 percent to ~~3.28~~2.92 percent for the PBOP Plans. As of December 31, ~~2018,~~2020, the discount rates used were within a range of ~~4.22~~2.4 percent to ~~4.45~~2.7 percent for the Pension and SERP Plans, and within a range of ~~4.38~~2.5 percent to ~~4.41~~2.6 percent for the PBOP Plans. The ~~decrease~~increase in the discount rates used to calculate the funded status resulted in ~~an increase~~a decrease to the Pension and PBOP Plans' liability of ~~$813.1~~$286.8 million and ~~$88.6~~$29.8 million, respectively, as of December 31, ~~2019.~~2021.

The Company uses the spot rate methodology for the service and interest cost components of Pension, SERP and PBOP expense because it provides a ~~more~~relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. The discount rates used to estimate the ~~2019~~2021 expense were within a range of ~~2.63~~1.5 percent to ~~3.55~~3.0 percent for the Pension and SERP Plans, and within a range of ~~3.85~~1.8 percent to ~~4.65~~3.1 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. In ~~2019,~~2021, a revised scale for the mortality table was released, and we utilized it in our measurements.

Compensation/Progression Rate: 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 receive in the future. As of December 31, ~~2019~~2021 and ~~2018,~~2020, the compensation/progression ~~rate~~rates used to determine the funded status ~~was 3.50~~were within a range of 3.5 percent ~~for the Eversource Service plans and 4 percent for the Aquarion plans.~~to 4.0 percent.

Health Care Cost: The Eversource Service PBOP Plan is not subject to health care cost trends. As of December 31, ~~2019,~~2021, for the Aquarion PBOP Plan, the health care ~~cost~~ trend rate for pre-65 retirees is ~~a range of 3.5 percent to~~ 6.5 percent, with an ultimate rate of ~~3.5 percent to~~ 5 percent in ~~2019~~2028, and ~~2023,~~ for post-65 retirees, the health care trend rate and ~~pre-65 retirees, respectively.~~ultimate rate is 3.5 percent.

Actuarial Determination of Expense: Pension, SERP and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, and amortization of actuarial gains and losses, offset by the expected return on plan assets. Actuarial gains and losses represent the amortization of differences between assumptions and actual information or updated assumptions. Pre-tax net periodic benefit expense for the Pension and SERP Plans was ~~$63.7~~$23.6 million, ~~$39.6~~$56.9 million and ~~$64.9~~$63.7 million for the years ended December 31, ~~2019, 2018~~2021, 2020 and ~~2017,~~2019, respectively. For the PBOP Plans, there was net periodic PBOP income of ~~$41.5~~$60.5 million, ~~$45.0~~$51.6 million and ~~$39.6~~$41.5 million for the years ended December 31, ~~2019~~, ~~2018~~2021, 2020 and ~~2017,~~2019, respectively.

The expected return on plan assets is determined by applying the assumed long-term rate of return to the Pension and PBOP Plan asset balances. This calculated expected return 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.

Forecasted Expenses and Expected Contributions: We estimate that ~~expense~~income in ~~2020~~2022 for the Pension and SERP Plans will be approximately ~~$53~~$177 million and income in ~~2020~~2022 for the PBOP Plans will be approximately ~~$52~~$80 million. Pension, SERP and PBOP expense 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 ~~$112.5~~$180.0 million to the Pension Plans in ~~2019.~~2021. We currently estimate contributing ~~$105.0~~between $100 million to $175 million to the Pension Plans in ~~2020.~~

2022, however, there is no minimum funding requirement for our Pension Plans for 2022, and therefore the planned contribution is discretionary and subject to change. It is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts. We contributed ~~$9.3~~$2.3 million to the PBOP Plans in ~~2019.~~2021. We currently estimate contributing ~~$2.9~~$2.4 million to the PBOP Plans in ~~2020.~~2022.

Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plans' (excluding the SERP Plans) reported annual cost and a decrease to the PBOP Plans' reported annual income as a result of a change in the following assumptions by 50 basis points:


(Millions of Dollars)	Increase in Pension Plan Cost				Decrease in PBOP Plan Income
Assumption Change	For the Years Ended December 31,				For the Years Ended December 31,
Eversource	2021		2020		2021		2020
Lower expected long-term rate of return	$	26.5	$	25.0	$	4.8	$	4.5
Lower discount rate	27.0		25.4		2.6		1.7
Higher compensation rate	9.9		8.8		N/A		N/A

(Millions of Dollars) Increase in Pension Plan Cost Decrease in PBOP Plan Income
Assumption Change As of December 31, As of December 31,
Eversource 2019 2018 2019 2018
Lower expected long-term rate of return $ 22.9
$ 23.7
$ 4.1
$ 4.5
Lower discount rate 21.7
25.5
1.7
2.9
Higher compensation rate 8.7
6.8
N/A
N/A

Goodwill: We recorded goodwill on our balance sheet associated with previous mergers and acquisitions, all of which totaled ~~$4.4~~$4.48 billion as of December 31, ~~2019.~~2021. 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 ~~Yankee Gas.~~EGMA. The Water Distribution reporting unit includes the Aquarion water utility businesses. As of December 31, ~~2019,~~2021, goodwill was allocated to the reporting units as follows: ~~$2.5~~$2.54 billion to Electric Distribution, ~~$0.6 billion~~$577 million to Electric Transmission, ~~$0.4 billion~~$451 million to Natural Gas Distribution and ~~$0.9 billion~~$905 million to Water Distribution.

We recorded $51.9 million of goodwillarising from the acquisition of CMA on October 9, 2020, which included measurement period adjustments in 2021. This goodwill was allocated to the Natural Gas Distribution reporting unit. We recorded $21.7 million of goodwill arising from the acquisition of NESC on December 1, 2021, which was allocated to the Water Distribution reporting unit.

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 ~~testing~~test date. Goodwill impairment is deemed to exist if the carrying amount of a reporting unit exceeds its estimated fair ~~value and if the implied fair value of goodwill based on the estimated fair values of the reporting units' assets and liabilities is less than the carrying amount of the goodwill.~~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 it’s carrying amount.

We performed an impairment test of goodwill as of October 1, ~~2019~~2021 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units. ~~This~~Our qualitative evaluation ~~required the consideration~~included an evaluation of ~~several~~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.~~ income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings.

The ~~2019~~2021 goodwill impairment ~~test~~assessment resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment. ~~The~~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. 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.

Impairment of Northern Pass Transmission: Northern Pass was Eversource's planned 1,090 MW HVDC transmission line that would have interconnected from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. As a result of a final decision received on July 19, 2019 from the New Hampshire Supreme Court, whereby the court denied Northern Pass’ appeal and affirmed the NHSEC’s denial of Northern Pass’ siting application on NPT, Eversource concluded that construction of NPT was no longer probable and that there was no constructive path forward for the project. Eversource terminated the project and permanently abandoned any further development. As a result, substantially all of the capitalized project costs, which totaled $318 million, certain of which are subject to cost reimbursement agreements, were impaired.

Based on the conclusion that the construction of Northern Pass was no longer probable, Eversource recorded an impairment charge in 2019 for all of the project costs associated with Northern Pass, which were primarily engineering design, siting, permitting and legal costs, along with appropriate allowances for funds used during construction, and recognized a receivable for certain cost reimbursement agreements. Additionally, Eversource recorded an impairment charge associated with the land acquired to construct Northern Pass in order to recognize the land at its estimated fair value based on assessed values and transaction costs. In total, this resulted in a pre-tax impairment charge of $239.6 million within Operating Income on the statement of income for the year ended December 31, 2019, and was reflected in the Electric Transmission segment. The after-tax impact of the impairment charge was $204.4 million, or $0.64 per share, after giving effect to the estimated fair value of the related land, reimbursement agreements, and the impact of expected income tax benefits associated with the impairment charge. As a result of the decision to terminate the NPT project and permanently abandon any further development, Eversource does not expect any future cash expenditures associated with this project.

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 ~~are~~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 and developing an estimate of undiscounted future cash flows.

Eversource recorded an other-than-temporary impairment of $32.9 million within Other Income, Net on our statement of income in 2018, related to Access Northeast, an equity method investment. In September 2018, a series of non-Eversource natural gas explosions in eastern Massachusetts resulted in widespread property and system damage, personal injuries, and a fatality. Eversource identified the September 2018 natural gas series of explosions, compounded by the adverse legislative environment, as negative evidence that indicated potential impairment of our investment in Access Northeast. Our impairment assessment used a discounted cash flow approach, including consideration of the severity and duration of any decline in fair value of our investment in the project, and involved significant management judgment and estimation, including projections of the project’s discounted cash flows and assumptions about exit price. In the third quarter of 2018, management determined that the future cash flows of the Access Northeast project were uncertain and could no longer be reasonably estimated and that the book value of our equity method investment was not recoverable. On April 1, 2019, pursuant to a provision in the partnership agreement jointly entered into by Eversource, Enbridge, Inc. and National Grid plc, through Algonquin Gas Transmission, LLC, the Access Northeast project was terminated.

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, non-tax deductible expenses, 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.

~~On December 22, 2017,~~The interpretation of tax laws and associated regulations involves uncertainty since tax authorities may interpret the ~~Tax Cuts and Jobs Act became law, which amended existing federal tax rules and included numerous provisions that impacted corporations. In particular, the act reduced the U.S. federal corporate~~laws differently. Ultimate resolution or clarification of income tax ~~rate~~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 ~~35 percent~~estimated amounts due to ~~21 percent effective January 1, 2018. For our regulated companies,~~ the ~~most significant~~future impacts of various items, including future changes ~~are (1) the benefit of incurring a lower federal~~in income tax ~~expense~~laws, not realizing expected tax planning strategy amounts, as well as results of audits and ~~(2) the reduction in ADIT liabilities (now excess ADIT or EDIT), which are estimated to be approximately $2.8 billion and are included in regulatory liabilities as~~examinations of ~~December 31, 2019. Eversource's regulated companies are in the process of, or will be, refunding the EDIT liabilities to customers based on orders issued~~filed tax returns by applicable state regulatory commissions. The refund of these regulatory liabilities to customers will generally be made over the same period as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities.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 due to certain economic factors.~~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" (normal), 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, and ~~AROs. We also applied this guidance~~AROs, and in the valuation of ~~our basis differences~~the acquisition of CMA in ~~our equity method offshore wind investments.~~2020. 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 ~~the~~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 and~~ energy-related products in future years ~~for which markets have not yet developed~~ and assumptions ~~are~~ made.

We use quoted market prices when available to determine the fair value of financial instruments. If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations. 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 and~~ 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.

~~Other Matters~~

~~Accounting Standards:~~ ~~For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies - Accounting Standards," to the financial statements.~~

~~Contractual Obligations and Commercial Commitments:~~ ~~Information regarding our contractual obligations and commercial commitments as of December 31, 2019, is summarized annually through 2024 and thereafter as follows:~~

Eversource
(Millions of Dollars) 2020 2021 2022 2023 2024 Thereafter Total
Long-term debt maturities ^(a)
$ 296.1
$ 1,033.6
$ 1,188.9
$ 1,665.2
$ 1,049.8
$ 8,447.8
$ 13,681.4
Rate reduction bond maturities 43.2
43.2
43.2
43.2
43.2
367.3
583.3
Estimated interest payments on existing debt ^(b)
511.5
493.4
458.4
425.5
384.1
4,020.3
6,293.2
Operating leases^(c)
10.2
9.0
7.4
4.9
2.8
28.9
63.2
Finance leases^(c)
3.4
2.9
1.5
0.8
0.8
13.1
22.5
Funding of pension obligations ^{(d) (e)}
105.0
—
—
—
—
—
105.0
Funding of PBOP obligations ^{(d) (e)}
2.9
—
—
—
—
—
2.9
Estimated future annual long-term contractual costs ^(f)
998.8
941.6
946.5
897.5
881.9
4,785.2
9,451.5
Total ^(g)
$ 1,971.1
$ 2,523.7
$ 2,645.9
$ 3,037.1
$ 2,362.6
$ 17,662.6
$ 30,203.0

CL&P
(Millions of Dollars) 2020 2021 2022 2023 2024 Thereafter Total
Long-term debt maturities ^(a)
$ —
$ —
$ —
$ 400.0
$ 139.8
$ 2,975.5
$ 3,515.3
Estimated interest payments on existing debt ^(b)
153.2
153.2
153.2
148.2
143.2
2,016.2
2,767.2
Operating leases ^(c)
0.5
0.2
—
—
—
0.1
0.8
Finance leases^(c)
2.0
1.5
—
—
—
—
3.5
Funding of pension obligations ^{(d) (e)}
23.2
—
—
—
—
—
23.2
Estimated future annual long-term contractual costs ^(f)
558.2
547.9
602.7
614.3
605.8
2,875.9
5,804.8
Total ^(g)
$ 737.1
$ 702.8
$ 755.9
$ 1,162.5
$ 888.8
$ 7,867.7
$ 12,114.8


~~(a)~~	~~Long-term debt maturities exclude the CYAPC pre-1983 spent nuclear fuel obligation, net unamortized premiums, discounts and debt issuance costs, and other fair value adjustments.~~


~~(b)~~	~~Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement.~~


~~(c)~~	~~The operating and finance lease obligations include interest.~~


~~(d)~~	~~Amounts are not included on our balance sheets.~~


~~(e)~~	These amounts represent expected pension and PBOP contributions for 2020. Future contributions will vary depending on many factors, including the performance of existing plan assets, valuation of the plans' liabilities and long-term discount rates.


~~(f)~~	~~Other than certain derivative contracts held by the regulated companies, these obligations are not included on our balance sheets.~~

~~(g)~~

Does not include other long-term liabilities recorded on our balance sheet, such as environmental reserves, employee medical insurance, workers compensation and long-term disability insurance reserves, ARO liability reserves and other reserves, as we cannot make reasonable estimates of the timing of payments. Also, does not include amounts not included on our balance sheets for future funding of Eversource's equity method investments, as we cannot make reasonable estimates of the periods or the investment contributions.

For further information regarding our contractual obligations and commercial commitments, see Note 7, "Asset Retirement Obligations," Note 8, "Short-Term Debt," 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 15, "Leases," to the financial statements.

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, ~~2019~~2021 and ~~2018~~2020 included in this Annual Report on Form 10-K:


	For the Years Ended December 31,
(Millions of Dollars)	2021		2020		Increase/(Decrease)
Operating Revenues	$	9,863.1	$	8,904.4	$	958.7
Operating Expenses:
Purchased Power, Fuel and Transmission	3,372.3		2,987.8		384.5
Operations and Maintenance	1,739.7		1,480.3		259.4
Depreciation	1,103.0		981.4		121.6
Amortization	232.0		177.7		54.3
Energy Efficiency Programs	592.8		535.8		57.0
Taxes Other Than Income Taxes	830.0		752.7		77.3

Total Operating Expenses	7,869.8		6,915.7		954.1
Operating Income	1,993.3		1,988.7		4.6
Interest Expense	582.4		538.4		44.0
Other Income, Net	161.3		108.6		52.7
Income Before Income Tax Expense	1,572.2		1,558.9		13.3
Income Tax Expense	344.2		346.2		(2.0)
Net Income	1,228.0		1,212.7		15.3
Net Income Attributable to Noncontrolling Interests	7.5		7.5		—
Net Income Attributable to Common Shareholders	$	1,220.5	$	1,205.2	$	15.3

For the Years Ended December 31,
(Millions of Dollars) 2019 2018 Increase/(Decrease)
Operating Revenues $ 8,526.5
$ 8,448.2
$ 78.3
Operating Expenses:

Purchased Power, Fuel and Transmission 3,040.2
3,139.0
(98.8 )
Operations and Maintenance 1,363.1
1,335.2
27.9
Depreciation 885.3
819.9
65.4
Amortization 195.4
252.0
(56.6 )
Energy Efficiency Programs 501.4
472.4
29.0
Taxes Other Than Income Taxes 711.0
729.8
(18.8 )
Impairment of Northern Pass Transmission 239.6
—
239.6
Total Operating Expenses 6,936.0
6,748.3
187.7
Operating Income 1,590.5
1,699.9
(109.4 )
Interest Expense 533.2
498.8
34.4
Other Income, Net 132.8
128.4
4.4
Income Before Income Tax Expense 1,190.1
1,329.5
(139.4 )
Income Tax Expense 273.5
289.0
(15.5 )
Net Income 916.6
1,040.5
(123.9 )
Net Income Attributable to Noncontrolling Interests 7.5
7.5
—
Net Income Attributable to Common Shareholders $ 909.1
$ 1,033.0
$ (123.9 )

Eversource's consolidated financial information includes the results of EGMA beginning on October 9, 2020. The natural gas distribution assets acquired from CMA on October 9, 2020 were assigned to EGMA.

Operating Revenues

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


	Electric				Firm Natural Gas				Water
	Sales Volumes (GWh)		Percentage Increase		Sales Volumes (MMcf)		Percentage Increase		Sales Volumes (MG)		Percentage Decrease
	2021	2020			2021	2020			2021	2020
Traditional	7,782	7,675	1.4	%	—	—	—	%	1,256	2,011	(37.5)	%
Decoupled and Special Contracts (1)(2)	43,228	42,531	1.6	%	150,145	147,123	2.1	%	22,099	23,122	(4.4)	%
Total Sales Volumes	51,010	50,206	1.6	%	150,145	147,123	2.1	%	23,355	25,133	(7.1)	%

Electric Firm Natural Gas Water
Sales Volumes (GWh) Percentage
Decrease Sales Volumes (MMcf) Percentage
Increase Sales Volumes (MG) Percentage
Decrease
2019
2018 ⁽¹⁾
2019
2018⁽²⁾
2019 2018
Traditional 7,685
7,915
(2.9 )% —
—
— % 2,161
2,252
(4.0 )%
Decoupled and Special Contracts ⁽³⁾
43,934
45,466
(3.4 )% 107,806
105,957
1.7 % 21,370
21,479
(0.5 )%
Total Sales Volumes 51,619
53,381
(3.3 )% 107,806
105,957
1.7 % 23,531
23,731
(0.8 )%

(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.


⁽¹⁾ (2) Eversource acquired CMA's natural gas distribution assets on October 9, 2020. Prior year sales volumes have been presented for comparative purposes.	Effective February 1, 2018, NSTAR Electric operated entirely under a decoupled rate structure. The 2018 sales volumes for NSTAR Electric have been recast to present January 2018 as decoupled to conform to the current year presentation.


⁽²⁾	Effective November 15, 2018, Yankee Gas operated under a decoupled rate structure. The 2018 sales volumes for Yankee Gas have been recast to present 2018 as decoupled to conform to the current year presentation.


⁽³⁾	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 ~~NSTAR Gas,~~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. ~~Fluctuations in water sales volumes largely do not impact earnings as our Connecticut water distribution business is also decoupled.~~

Operating Revenues: Operating Revenues by segment ~~increased/(decreased)~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, as follows:


(Millions of Dollars)	Increase/(Decrease)
Electric Distribution	$	291.3
Natural Gas Distribution	580.9
Electric Transmission	98.5
Water Distribution	(4.1)
Other	118.1
Eliminations	(126.0)
Total Operating Revenues	$	958.7

(Millions of Dollars) Increase/(Decrease)
Electric Distribution $ 19.3
Natural Gas Distribution 40.0
Electric Transmission 102.7
Water Distribution 2.6
Other 92.2
Eliminations (178.5 )
Total Operating Revenues $ 78.3

Electric and Natural Gas (excluding EGMA) Distribution Revenues:

Base Distribution Revenues:

•Base electric distribution revenues increased ~~$107.7~~$28.8 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the impact of ~~CL&P's~~ base distribution rate increases at NSTAR Electric effective January 1, 2021, at PSNH effective January 1, 2021 and August 1, 2021, and at CL&P effective May 1, ~~2019 and May 1, 2018, which include recovery of storm costs and certain other items that do not impact earnings, an NSTAR Electric~~2020. These increases were partially offset by a base distribution rate ~~increase effective January~~decrease at CL&P implemented June 1, ~~2019, and a PSNH temporary~~2021. The decrease in the CL&P base distribution rate ~~increase effective July~~on June 1, ~~2019.~~2021 was due primarily to the completion of the recovery of certain storm cost amortization and therefore the base rate decrease did not impact earnings.

•Base natural gas distribution revenues increased ~~$7.6~~$62.8 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to base distribution rate increases at NSTAR Gas effective November 1, 2021 and November 1, 2020, which includes a shift of recovery into base rates of certain GSEP investments, and at Yankee Gas effective January 1, 2021. Although new rates at Yankee Gas were implemented on March 1, 2021 to customers, the ~~impact~~provisions of the ~~Yankee Gas~~ base distribution rate increase were effective ~~November 15, 2018.~~January 1, 2021.

Electric distribution revenues at CL&P also decreased $93.4 million in 2021, as compared to 2020, due to a 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 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 recorded a $28.4 million reserve in 2021 for a civil penalty for non-compliance with storm performance standards that is currently being credited to customers on electric bills beginning on September 1, 2021 over a one-year period. CL&P recorded these reserves as a current regulatory liability and a reduction to Operating Revenues. As of December 31, 2021, the remaining reserve that has not yet been issued as customer credits and not yet reflected in rates totaled $71.1 million. For further information, see "Regulatory Developments and Rate Matters - Connecticut" included in this Management’s Discussion and Analysis.

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, ~~and~~ electric retail transmission charges, ~~which decreased significantly due primarily to the lower federal corporate income tax rate that was reflected effective January 1, 2019. In addition, cost tracking mechanisms include~~ energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for ~~NSTAR Electric,~~the Massachusetts utilities, pension and PBOP benefits, ~~and~~ net metering for distributed ~~generation.~~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. ~~However, tracked revenues do include certain incentives earned, return on rate base, and carrying charges that are billed in rates to customers, which do impact earnings.~~

Tracked distribution revenues increased/(decreased) in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:


(Millions of Dollars)	Electric Distribution		Natural Gas Distribution
Retail Tariff Tracked Revenues:
Energy supply procurement	$	(152.1)	$	70.0
Retail transmission	222.2		—
Other distribution tracking mechanisms	47.3		11.7
Wholesale Market Sales Revenue	248.5		4.9

The decrease in energy supply procurement within electric distribution in 2021 as compared to 2020, was driven primarily by lower average supply-related sales volumes and lower average prices. The increase in energy supply procurement within natural gas distribution in 2021, as compared to 2020, was driven primarily by higher average prices and higher average supply-related sales volumes.

Fluctuations in retail electric transmission revenues are driven by the recovery of the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges. For further information, see "Purchased Power and Transmission Expense" below.

(Millions of Dollars) Electric Distribution Natural Gas Distribution
Retail Tariff Tracked Revenues
Energy supply procurement $ —
$ 24.2
Retail transmission ⁽¹⁾
(123.3 ) N/A
Other distribution tracking mechanisms 18.7
13.8
Wholesale Market Sales Revenue 36.2
(2.1 )
The increase in electric distribution wholesale market sales revenue was due primarily to higher average electricity market prices received for

wholesale sales in 2021, as compared to 2020. ISO-NE average market prices received for CL&P’s wholesale sales increased approximately 95 percent in 2021, as compared to 2020, driven primarily by higher natural gas prices in New England. Volumes sold into the market were primarily from the sale of output generated by the Millstone PPA that CL&P entered into in 2019, as required by regulation. The increase in electric distribution wholesale market sales revenues was also driven by higher proceeds from a one-year sale of transmission rights, effective June 2021, under CL&P’s, NSTAR Electric’s and PSNH’s Hydro-Quebec transmission support agreements. Proceeds from these sales are credited back to customers.

⁽¹⁾

EGMA Natural Gas Distribution Revenues: The ~~decrease reflects a decrease~~incremental impact of EGMA increased total operating revenues at the natural gas distribution segment by $431.5 million in ~~the retail transmission rate billed~~2021, as compared to ~~customers that was adjusted on January 1, 2019 to reflect the lower federal corporate income tax rate.~~2020.

Electric Transmission ~~Revenues:~~Revenues: Electric transmission revenues increased ~~$102.7~~$98.5 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to a higher transmission rate base as a result of our continued investment in our transmission ~~infrastructure and a higher recovery of tracked costs.~~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.~~business in rates charged to their customers.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our ~~customers.~~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, Fuel and Transmission expense ~~increased/(decreased)~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	(56.7)
Natural Gas Costs	313.4
Transmission Costs	225.2
Eliminations	(97.4)
Total Purchased Power, Fuel and Transmission	$	384.5

(Millions of Dollars) Increase/(Decrease)
Electric Distribution $ 88.1
Natural Gas Distribution 21.8
Transmission (124.4 )
Eliminations (84.3 )
Total Purchased Power, Fuel and Transmission $ (98.8 )

The ~~increase~~decrease in purchased power expense at the electric distribution business in ~~2019~~2021, as compared to ~~2018,~~2020, was driven primarily by ~~a new zero-carbon power purchase agreement entered into~~lower expense related to the procurement of energy supply resulting from lower average supply-related sales volumes and lower average prices. The lower energy supply expense was partially offset by higher long-term contractual energy-related costs that are recovered in ~~2019, as required by regulation in Connecticut, from which~~ the ~~energy purchased from Millstone Nuclear Power Station is sold into the market. Additionally, as a result of the sale of PSNH's thermal generation assets on January 10, 2018,~~NBFMCC mechanism at CL&P and ~~the sale of PSNH's hydroelectric assets on August 26, 2018, PSNH purchased power in place of its self-generation output.~~ higher net metering costs at NSTAR Electric.

The increase in costs at the natural gas distribution segment in 2021, as compared to 2020, was due primarily to the incremental impact of EGMA natural gas supply costs ~~at our natural gas distribution business was due primarily to~~of $145.0 million, as well as higher average prices and higher average supply-related sales volumes.

The ~~decrease~~increase in transmission costs in ~~2019,~~2021, as compared to ~~2018,~~2020, was primarily the result of ~~a decrease~~an increase in costs billed by ISO-NE that support regional grid investments and an increase resulting from the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers, and a decrease in costs billed by ISO-NE that support regional grid investments. The retail transmission rate was adjusted on January 1, 2019 to reflect the lower federal corporate income tax rate, resulting in a decrease in the cost of retail transmission service.customers. This was partially offset by ~~an increase~~a decrease in Local Network Service charges, which ~~reflect~~reflects the cost of transmission service provided by Eversource over our local transmission network.

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/(decreased)~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits	$	47.9
Shared corporate costs (including computer software depreciation at Eversource Service)	21.6
Vegetation Management	19.1
Funding of CL&P storm reserve as part of June 1, 2021 rate change (offset by lower Amortization expense; no earnings impact)	16.0
CL&P charge to fund customer assistance initiatives associated with the settlement agreement on October 1, 2021	10.0
Storm restoration costs	(24.2)
Operations-related expenses, including vehicles and outside services	3.1
Other non-tracked operations and maintenance	8.5
Total Base Electric Distribution (Non-Tracked Costs)	102.0
Tracked Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher transmission expenses of $6.5 million and increase of $16.3 million due to higher pension tracking mechanism at NSTAR Electric	30.3
Total Electric Distribution and Electric Transmission	132.3
Natural Gas Distribution:
Base (Non-Tracked) Costs, excluding EGMA	3.5
Tracked Costs, excluding EGMA	7.3
EGMA Operations and Maintenance	123.1
Total Natural Gas Distribution	133.9
Water Distribution:
Absence in 2021 of gain on sale of Hingham water system in July 2020	16.0
Other	(1.1)
Total Water Distribution	14.9
Parent and Other Companies and Eliminations:
Eversource Parent and Other Companies - other operations and maintenance	106.9
Acquisition and Transition Costs	(9.7)
Eliminations	(118.9)
Total Operations and Maintenance	$	259.4

(Millions of Dollars) Increase/(Decrease)
Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits $ (27.6 )
Storm restoration costs 8.8
Shared corporate costs (including computer software depreciation at Eversource Service) 22.3
Operations-related expenses, including vegetation management, vehicles, and outside services 14.6
Other non-tracked operations and maintenance (2.9 )
Total Base Electric Distribution (Non-Tracked Costs) 15.2
Base Natural Gas Distribution (Non-Tracked Costs) - Increase due primarily to higher shared corporate costs of $10.8 million 16.6
Water Distribution 0.1
Tracked Costs (Electric Distribution, Electric Transmission and Natural Gas Distribution) - Increase due to higher transmission and vegetation management expenses, partially offset by the absence in 2019 of PSNH generation operations expenses due to the sale of its generation assets in 2018, and a decrease in employee-related benefit costs 29.2
Other and eliminations:
Eversource Parent and Other Companies - other operations and maintenance 59.8
Eliminations (93.0 )
Total Operations and Maintenance $ 27.9

Depreciation expense increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due ~~primarily~~ to higher utility plant in service balances, the incremental impact of EGMA utility plant balances of $36.8 million and new depreciation rates effective ~~with the CL&P~~January 1, 2021 resulting from PSNH’s 2020 distribution rate ~~case~~ settlement agreement.

Amortizationexpense includes the deferral of energy supply, ~~and~~ energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking ~~mechanisms, and the amortization of certain costs.~~mechanisms. This deferral adjusts expense to match the corresponding ~~revenues.~~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 ~~decreased~~expense also includes the amortization of certain costs as those costs are collected in ~~2019,~~rates.

Amortization increased in 2021, as compared to ~~2018,~~2020, due primarily to the deferral adjustment of energy supply, energy-related and ~~energy-related~~other tracked costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The increase was partially offset by a decrease in storm amortization expense at CL&P ~~and PSNH, partially offset by an increase in storm cost recovery at CL&P, NSTAR Electric and PSNH, and by increased amortization of PSNH's securitized regulatory asset~~ related to the ~~May 2018 RRB issuance~~completion of ~~$15.7 million.~~the amortization period of certain storm costs deferred assets.

Energy Efficiency Programs expense increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to ~~an increase in spending for CL&P's and PSNH's~~the incremental impact of EGMA energy efficiency ~~programs.~~program costs of $48.0 million. The increase was also due to the deferral adjustment at NSTAR Electric, 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.~~CL&P, NSTAR Electric and PSNH energy efficiency programs will include additional authorized spending totaling approximately $60 million in 2020, as compared to 2019.~~

Taxes Other Than Income Taxes expense ~~decreased~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to a decrease of $25.4 million related to CL&P's remittance of energy efficiency funds to the State of Connecticut. Energy efficiency funds collected from CL&P's customers after July 1, 2019 are no longer subject to remittance to the State of Connecticut. The decrease is also due to amounts received by PSNHan increase in ~~the third quarter of 2019 relating to a refund of~~ property taxes as a result of ~~a settlement with~~higher utility plant balances, the ~~town of Bow, New Hampshire ($8.3 million).~~

~~Impairment of Northern Pass Transmission~~ ~~reflects an impairment charge of $239.6 million that was recorded in the second quarter of 2019 as a result of the July 19, 2019 New Hampshire Supreme Court decision. The after-tax~~incremental impact of ~~this impairment charge was $204.4 million.~~EGMA property and other taxes of $23.5 million, higher Connecticut gross earnings taxes, and the absence in 2021 of a benefit at NSTAR Gas in 2020 relating to the resolution of disputed property taxes for prior years.

Interest Expense increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to an increase in interest on long-term debt as a result of new debt issuances ($~~38.9~~29.5 million), an increase in interest ~~due~~expense on regulatory deferrals ($12.2 million), the absence in 2021 of a benefit at NSTAR Gas in 2020 relating to the ~~May 2018 PSNH RRB issuance~~resolution of disputed property taxes and interest thereon for prior years ($~~6.7~~5.7 million), and ~~an increase~~higher amortization of debt discounts and premiums, net ($0.8 million), partially offset by a decrease in interest on notes payable ($~~4.1~~3.4 million)~~. Partially offsetting these increases were~~, a decrease in RRB interest expense ($1.3 million), and an increase in capitalized AFUDC related to debt funds ~~($5.9 million)~~ and ~~higher~~ other capitalized interest ($~~17.0~~1.1 million).

Other Income, Net increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to an increase in equity in earnings of unconsolidated affiliates related to Eversource's equity method investments, net of impairment ($38.4 million) and investment income in 2019 compared to investment losses in 2018 ($4.8 million). In 2018, Eversource recognized a $32.9 million other-than-temporary impairment charge to our equity method investment in the Access Northeast project, which was reflected as a loss within equity in earnings. Partially offsetting these increases were a decrease related to pension, SERP and PBOP non-service income components ($~~29.5~~40.0 million)~~, lower gains on sales of property ($4.8 million),~~ and ~~a decrease in the recognition of the equity component of the carrying charges related to storm costs recorded~~an increase in interest income ~~at PSNH~~primarily from regulatory deferrals ($~~2.4~~20.8 million), partially offset by lower AFUDC related to equity funds ($4.7 million) and investment losses in 2021 compared to investment income in 2020 driven by market volatility ($1.3 million).

Income Tax Expense decreased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the absence of the sale of the Hingham water system ($12.5 million), an increase in amortization of EDIT ($~~32.4~~20.4 million), by the ~~impairment of NPT in 2019, compared to the write-off of Access Northeast in 2018~~CL&P settlement agreement ($~~37.8~~17.5 million), ~~partially offset by higher pre-tax earnings ($15.0 million), by~~a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~8.4~~0.6 million), ~~an increase~~and a decrease in valuation allowance ~~against~~($17.6 million), partially offset by higher pre-tax earnings excluding the CL&P settlement agreement charges and gain on Hingham sale ($27.8 million), higher state taxes ($31.6 million), lower share-based payment excess tax ~~credits~~benefits ($~~13.3~~2.6 million), and ~~due~~a lower return to ~~the offset of one-time items relating to federal tax reform and release of tax reserve in 2018~~provision adjustment ($~~18.0~~4.6 million) that did not occur in 2019. The impact of the amortization of the EDIT regulatory liability, including the tax gross up portion, that reduced revenue was $51.5 million, offset by current tax benefits of $14.1 million and amortization of EDIT of $37.4 million, for the year ended December 31, 2019, which results in no impact on earnings..

RESULTS OF OPERATIONS –

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P, NSTAR Electric and PSNH for the years ended December 31, ~~2019~~2021 and ~~2018~~2020 included in this Annual Report on Form 10-K:


	For the Years Ended December 31,
	CL&P						NSTAR Electric						PSNH
(Millions of Dollars)	2021		2020		Increase/(Decrease)		2021		2020		Increase/(Decrease)		2021		2020		Increase/(Decrease)
Operating Revenues	$	3,637.4	$	3,547.5	$	89.9	$	3,056.4	$	2,941.1	$	115.3	$	1,177.2	$	1,079.1	$	98.1
Operating Expenses:
Purchased Power and Transmission	1,393.0		1,369.2		23.8		932.5		879.2		53.3		370.3		364.1		6.2
Operations and Maintenance	644.2		572.9		71.3		563.2		534.1		29.1		237.7		219.3		18.4
Depreciation	338.9		320.7		18.2		337.5		319.5		18.0		120.1		100.4		19.7
Amortization of Regulatory Assets, Net	99.0		58.4		40.6		55.8		83.2		(27.4)		86.8		52.8		34.0
Energy Efficiency Programs	129.6		141.5		(11.9)		288.6		264.0		24.6		38.7		37.6		1.1
Taxes Other Than Income Taxes	363.8		344.4		19.4		216.7		206.8		9.9		91.5		81.6		9.9
Total Operating Expenses	2,968.5		2,807.1		161.4		2,394.3		2,286.8		107.5		945.1		855.8		89.3
Operating Income	668.9		740.4		(71.5)		662.1		654.3		7.8		232.1		223.3		8.8
Interest Expense	166.1		153.6		12.5		146.0		130.5		15.5		57.0		58.1		(1.1)
Other Income, Net	30.2		20.8		9.4		74.8		52.0		22.8		14.6		13.8		0.8
Income Before Income Tax Expense	533.0		607.6		(74.6)		590.9		575.8		15.1		189.7		179.0		10.7
Income Tax Expense	131.3		149.7		(18.4)		114.3		130.8		(16.5)		39.4		31.7		7.7
Net Income	$	401.7	$	457.9	$	(56.2)	$	476.6	$	445.0	$	31.6	$	150.3	$	147.3	$	3.0

For the Years Ended December 31,
CL&P NSTAR Electric PSNH
(Millions of Dollars) 2019 2018 Increase/(Decrease) 2019 2018 Increase/(Decrease) 2019 2018 Increase/(Decrease)
Operating Revenues $ 3,232.6
$ 3,096.2
$ 136.4
$ 3,044.6
$ 3,112.9
$ (68.3 ) $ 1,065.9
$ 1,047.6
$ 18.3
Operating Expenses:

Purchased Power, Fuel and Transmission 1,188.2
1,095.2
93.0
1,064.3
1,257.1
(192.8 ) 398.4
370.2
28.2
Operations and Maintenance 549.2
506.4
42.8
468.4
462.1
6.3
211.0
210.5
0.5
Depreciation 301.2
278.6
22.6
296.5
276.4
20.1
93.7
92.1
1.6
Amortization of Regulatory Assets, Net 51.6
129.0
(77.4 ) 103.7
46.7
57.0
57.7
81.0
(23.3 )
Energy Efficiency Programs 118.2
94.0
24.2
289.2
292.3
(3.1 ) 26.0
20.1
5.9
Taxes Other Than Income Taxes 342.5
357.2
(14.7 ) 195.6
194.2
1.4
62.6
77.3
(14.7 )
Total Operating Expenses 2,550.9
2,460.4
90.5
2,417.7
2,528.8
(111.1 ) 849.4
851.2
(1.8 )
Operating Income 681.7
635.8
45.9
626.9
584.1
42.8
216.5
196.4
20.1
Interest Expense 151.4
151.7
(0.3 ) 114.2
105.2
9.0
60.7
60.6
0.1
Other Income, Net 17.6
22.7
(5.1 ) 44.6
53.1
(8.5 ) 19.2
27.7
(8.5 )
Income Before Income Tax Expense 547.9
506.8
41.1
557.3
532.0
25.3
175.0
163.5
11.5
Income Tax Expense 137.0
129.1
7.9
125.3
148.9
(23.6 ) 41.0
47.6
(6.6 )
Net Income $ 410.9
$ 377.7
$ 33.2
$ 432.0
$ 383.1
$ 48.9
$ 134.0
$ 115.9
$ 18.1

Operating Revenues

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


	For the Years Ended December 31,							For the Years Ended December 31,
	2019	2018	Decrease		Percent			2021	2020	Increase	Percentage Increase
CL&P	20,719	21,467	(748	)	(3.5	)%	CL&P	20,501	20,113	388	1.9	%
NSTAR Electric	23,215	23,999	(784	)	(3.3	)%	NSTAR Electric	22,727	22,418	309	1.4	%
PSNH	7,685	7,915	(230	)	(2.9	)%	PSNH	7,782	7,675	107	1.4	%

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

Operating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased ~~$136.4~~$89.9 million at CL&P, ~~and $18.3 million at PSNH, and decreased $68.3~~$115.3 million at NSTAR Electric, and $98.1 million at PSNH in ~~2019,~~2021, as compared to ~~2018.~~2020.

Base Distribution Revenues:

•CL&P's distribution revenues ~~increased $60.8~~decreased $12.0 million due primarily to the ~~impact of its~~ base distribution rate ~~increases~~decrease implemented June 1, 2021. The decrease in the base distribution rate on June 1, 2021 was due primarily to the completion of the recovery of certain storm cost amortization and therefore the base rate decrease did not impact earnings. Excluding the reduction to revenue resulting from the completion of certain storm cost amortization, base distribution revenues increased due to the impact of a base distribution rate increase effective May 1, ~~2019 and May 1, 2018, which include recovery of storm costs and certain other items that do not impact earnings.~~2020.

•NSTAR Electric's distribution revenues increased ~~$27.3~~$9.3 million due primarily to the impact of its base distribution rate increase effective January 1, ~~2019.~~2021.

•PSNH's distribution revenues increased ~~$19.6~~$31.5 million due primarily to the impact of its ~~temporary~~ base distribution rate ~~increase~~increases effective ~~July~~January 1, ~~2019.~~2021 and August 1, 2021.

Tracked Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory

commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Revenues from certain of these

cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in

rates to customers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply

procurement and other energy-related costs, ~~and~~ retail transmission charges, ~~which decreased significantly due primarily to the lower federal corporate income tax rate that was reflected effective January 1, 2019. In addition, cost tracking mechanisms include~~ energy efficiency program costs, electric restructuring and stranded cost

recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, ~~and~~ net metering for distributed ~~generation.~~generation, and solar-related programs. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties. ~~However, tracked revenues do include certain incentives earned, return on rate base, and carrying charges that are billed in rates to customers, which do impact earnings.~~

Tracked revenues increased/(decreased) in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:


(Millions of Dollars)	CL&P		NSTAR Electric		PSNH
Retail Tariff Tracked Revenues:
Energy supply procurement	$	(30.5)	$	(124.8)	$	3.2
Retail transmission	47.0		138.5		36.7
Other distribution tracking mechanisms	(6.4)		40.6		13.1
Wholesale Market Sales Revenue	178.7		50.8		19.0

(Millions of Dollars) CL&P NSTAR Electric PSNH
Retail Tariff Tracked Revenues:
Energy supply procurement $ 26.0
$ (29.9 ) $ 3.9
Retail transmission (10.7 ) (94.0 ) (18.6 )
Other distribution tracking mechanisms (13.7 ) 20.7
11.7
Wholesale Market Sales Revenue 56.8
(3.0 ) (19.1 )

~~PSNH's~~The decrease in energy supply procurement at CL&P was driven primarily by lower average prices, partially offset by higher average supply-related sales volumes. The decrease in energy supply procurement at NSTAR Electric was driven by lower average supply-related sales volumes, partially offset by higher average prices. The increase in energy supply procurement at PSNH was driven primarily by higher average supply-related sales volumes, partially offset by lower average prices. Fluctuations in retail transmission revenues ~~include the absence in 2019 of~~are driven by the recovery of ~~generation rate base return due to~~ the ~~sale~~costs of ~~its thermal~~our wholesale transmission business, such as those billed by ISO-NE and ~~hydroelectric generation assets~~Local and Regional Network Service charges. For further information, see "Purchased Power and Transmission Expense" below.

The increase in ~~2018. Revenues from CL&P's other distribution tracking mechanisms include higher earnings from its capital tracker mechanism effective July 1, 2018 due to increased electric system improvements.~~

~~CL&P's~~ wholesale market sales revenue ~~increase~~ was due primarily to ~~a new zero-carbon power purchase agreement~~higher average electricity market prices received for wholesale sales at CL&P, NSTAR Electric and PSNH in 2021, as compared to 2020. ISO-NE average market prices received for CL&P’s wholesale sales increased approximately 95 percent for the year ended December 31, 2021, as compared to 2020, driven primarily by higher natural gas prices in New England. Volumes sold into the market were primarily from the sale of output generated by the Millstone PPA that CL&P entered into in 2019, as required by ~~regulation, from which the energy purchased from Millstone Nuclear Power Station is sold into the market.~~regulation. The ~~decrease~~increase in ~~retail transmission~~wholesale market sales revenues at CL&P, NSTAR Electric and PSNH ~~reflects~~was also driven by higher proceeds from a ~~decrease in the retail~~one-year sale of transmission ~~rate billed~~rights, effective June 2021, under CL&P’s, NSTAR Electric’s and PSNH’s Hydro-Quebec transmission support agreements. Proceeds from these sales are credited back to ~~customers that was adjusted on January 1, 2019 to reflect the lower federal corporate income tax rate.~~customers.

Transmission Revenues: Transmission revenues increased ~~$59.9~~$42.6 million at CL&P, ~~$27.5~~$30.1 million at NSTAR Electric and ~~$15.3~~$25.8 million at PSNH in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to a higher transmission rate base as a result of our continued investment in our transmission ~~infrastructure and a higher recovery of tracked costs.~~infrastructure.

Eliminations: Eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission ~~business.~~business in rates charged to their customers. The impact of eliminations decreased revenues by $27.8 million at CL&P, ~~and $13.0~~$29.1 million at NSTAR Electric and ~~increased revenues by $4.5~~$29.5 million at PSNH in ~~2019,~~2021, as compared to ~~2018.~~2020.

Purchased Power ~~Fuel~~ and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's ~~customers.~~customers and the cost of energy purchase contracts, as required by regulation. These energy supply 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 ~~Fuel~~ and Transmission expense ~~increased/(decreased)~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:


(Millions of Dollars)	CL&P		NSTAR Electric		PSNH
Purchased Power Costs	$	2.1	$	(55.5)	$	(3.3)
Transmission Costs	48.2		138.0		39.0
Eliminations	(26.5)		(29.2)		(29.5)
Total Purchased Power and Transmission	$	23.8	$	53.3	$	6.2

(Millions of Dollars) CL&P NSTAR Electric PSNH
Purchased Power Costs $ 132.7
$ (86.3 ) $ 41.7
Transmission Costs (12.5 ) (93.9 ) (18.0 )
Eliminations (27.2 ) (12.6 ) 4.5
Total Purchased Power, Fuel and Transmission $ 93.0
$ (192.8 ) $ 28.2

Purchased Power Costs: Included in purchased power costs are the costs associated with providing electric generation service supply to all customers who have not migrated to third party suppliers and the cost of energy purchase contracts, as required by regulation.

•The increase at CL&P was due primarily to ~~a new zero-carbon power purchase agreement entered into~~higher long-term contractual energy-related costs that are recovered in ~~2019, as required~~the NBFMCC mechanism, partially offset by ~~regulation,~~lower expense related to the procurement of energy supply resulting from ~~which the energy purchased from Millstone Nuclear Power Station is sold into the market.~~lower average prices.

•The decrease at NSTAR Electric was due primarily to alower expense related to the procurement of energy supply resulting from lower average supply-related sales volumes, partially offset by higher net metering costs.

•The decrease ~~in the volume of power procured on behalf of our customers.~~

~~The increase~~ at PSNH was due primarily to lower stranded costs resulting from higher ~~purchased power energy expenses that~~Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are ~~recovered~~credited back to customers. The higher RGGI proceeds resulted from an increase in RGGI auction clearing prices for allowances in 2021 as a component of the Energy Service and Stranded Cost Recovery Charge tracking mechanisms. As a result of the sale of its thermal generation assets on January 10, 2018 and its hydroelectric generation assets on August 26, 2018, PSNH has purchased power in place of its self-generation output.compared to 2020.

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

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

•The ~~decrease~~increase in transmission costs at NSTAR Electric and PSNH was due primarily to an increase in costs billed by ISO-NE, an increase resulting from the ~~result of a decrease~~retail transmission cost deferral, and an increase in costs billed by ISO-NE that support regional grid ~~investment and a decrease in the retail transmission cost deferral.~~investments. This was partially offset by ~~an increase~~a decrease in Local Network Service charges.

The decrease in transmission costs at CL&P, NSTAR Electric and PSNH also pertains to a reduction to the retail transmission rate that was adjusted on January 1, 2019 to reflect the lower federal corporate income tax rate, resulting in a decrease in the cost of retail transmission service.

Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense ~~increased/(decreased)~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:


(Millions of Dollars)	CL&P		NSTAR Electric		PSNH
Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits	$	17.2	$	14.3	$	7.9
Shared corporate costs (including computer software depreciation at Eversource Service)	6.9		12.7		2.0
Vegetation Management	6.8		(0.8)		13.1
Funding of CL&P storm reserve as part of June 1, 2021 rate change (offset by lower Amortization expense; no earnings impact)	16.0		—		—
CL&P charge to fund customer assistance initiatives associated with the settlement agreement	10.0		—		—
Storm restoration costs	(6.9)		(15.3)		(2.0)
Operations-related expenses, including vehicles and outside services	4.8		(0.7)		(1.0)
Other non-tracked operations and maintenance	6.4		(3.9)		1.0
Total Base Electric Distribution (Non-Tracked Costs)	61.2		6.3		21.0
Tracked Costs:
Transmission expenses	(1.2)		1.9		5.8
Other tracked operations and maintenance	11.3		20.9		(8.4)
Total Tracked Costs	10.1		22.8		(2.6)
Total Operations and Maintenance	$	71.3	$	29.1	$	18.4

(Millions of Dollars) CL&P NSTAR Electric PSNH
Base Electric Distribution (Non-Tracked Costs):
Employee-related expenses, including labor and benefits $ (9.1 ) $ (16.1 ) $ (2.4 )
HEEC Boston Harbor distribution cable costs —
(6.5 ) —
Storm restoration costs (1.9 ) 10.7
—
Shared corporate costs (including computer software depreciation at Eversource Service) 9.2
10.7
2.4
Operations-related expenses, including vegetation management, vehicles, and outside services 3.6
2.8
8.2
Other non-tracked operations and maintenance 7.3
(4.2 ) 0.5
Total Base Electric Distribution (Non-Tracked Costs) 9.1
(2.6 ) 8.7
Tracked Costs:
Absence in 2019 of PSNH generation operations expenses due to the 2018 sales of thermal and hydroelectric generation assets —
—
(10.9 )
Transmission expenses 23.5
2.5
(1.8 )
Other tracked operations and maintenance 10.2
6.4
4.5
Total Tracked Costs 33.7
8.9
(8.2 )
Total Operations and Maintenance $ 42.8
$ 6.3
$ 0.5

Depreciation expense increased in ~~2019,~~2021, as compared to ~~2018, due primarily to the following:~~

~~The increase at~~2020, for CL&P, ~~was~~NSTAR Electric and PSNH due to higher net plant in service ~~balances and the implementation of new depreciation rates effective with the 2018 CL&P distribution rate case settlement agreement.~~

~~The increase at NSTAR Electric was due to higher net plant in service~~ balances.

The increase at PSNH was also due to ~~higher~~new depreciation rates effective January 1, 2021 resulting from the 2020 distribution ~~depreciation expense, partially offset by the sale of the thermal and hydroelectric generation assets in 2018.~~rate settlement agreement.

Amortization of Regulatory Assets, Net expense includes the deferral of energy supply, ~~and~~ energy-related costs and other costs that are included in certain regulatory-approved cost tracking ~~mechanisms, and the amortization of certain costs.~~mechanisms. This deferral adjusts expense to match the corresponding ~~revenues.~~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 of Regulatory Assets, Net increased/decreased in 2021, as compared to 2020, due primarily to the following:

•The increase at ~~NSTAR Electric in 2019, as compared to 2018,~~CL&P was due primarily to ~~an increase in both storm cost recovery and costs associated with low income customers. The remaining increase in amortization was driven by~~ the deferral adjustment of energy supply, energy-related and ~~energy-related~~other tracked costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The increase was partially offset by a decrease in storm amortization expense related to the completion of the amortization period of certain storm cost deferred assets.

•The decrease at ~~CL&P~~NSTAR Electric was due to the deferral adjustment of energy supply, energy-related costs and other tracked costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs.

•The increase at PSNH was due ~~primarily~~ to the deferral adjustment of ~~energy supply~~energy-related and ~~energy-related~~other tracked costs, ~~partially offset by an increase in storm cost recovery. The decrease at PSNH is also partially offset by $15.7 million~~which can fluctuate from period to period based on the timing of ~~higher amortization of PSNH's securitized regulatory asset~~costs incurred and related rate changes to ~~the May 2018 RRB issuance.~~recover these costs.

Energy Efficiency Programs expense includes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expense increased/~~(decreased)~~decreased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:

~~The increase at CL&P and PSNH was due to higher spending for energy efficiency programs.~~

•The decrease at ~~NSTAR Electric~~CL&P was due to the deferral adjustment, which reflects actual costs of energy efficiency programs compared to the estimated amounts billed to customers, and the timing of ~~spending on certain large~~the recovery of energy efficiency ~~projects in 2019.~~costs.

~~CL&P,~~•The increases at NSTAR Electric and PSNH were due to the deferral adjustment, which reflects actual costs of energy efficiency programs ~~will include additional authorized spending of approximately $5 million, $40 million, and $15 million, respectively, in 2020 as~~ compared to ~~2019.~~the estimated amounts billed to customers, and the timing of the recovery of energy efficiency costs.

Taxes Other Than Income Taxes ~~decreased~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:

•The ~~decrease~~increase at CL&P was ~~due to a decrease of $25.4 million~~ related to ~~CL&P's remittance~~higher property taxes as a result of ~~energy efficiency funds~~a higher utility plant balance and higher gross earnings taxes.

•The increases at NSTAR Electric and PSNH were due to ~~the State of Connecticut. Energy efficiency funds collected from customers after July 1, 2019 are no longer subject to remittance to the State of Connecticut. The decrease was partially offset by~~ higher property taxes as a result of higher utility plant ~~balances and higher gross earnings taxes (the costs of which are tracked).~~balances.

~~The decrease at PSNH was due to lower property taxes and a refund of property taxes as a result of a settlement with the town of Bow, New Hampshire ($8.3 million).~~

Interest Expense increased/~~(decreased)~~decreased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:

•The ~~decrease~~increase at CL&P was due primarily to ~~lower~~higher interest on long-term debt ($~~2.6~~5.4 million), an increase in interest expense on regulatory deferrals ($3.7 million), a decrease in AFUDC related to debt funds ($~~0.8~~3.7 million), and higher amortization of debt discounts and premiums, net ($0.9 million).

•Theincrease at NSTAR Electric was due primarily to an increase in interest expense on regulatory deferrals ($7.6 million), higher interest on long-term debt ($6.0 million), and higher amortization of debt discounts and premiums, net ($0.4 million).

•The decrease at PSNH was due primarily to a decrease in RRB interest expense ($1.3 million), lower amortization of debt discounts and premiums, net ($~~0.8~~0.7 million), and lower interest on long-term debt ($0.5 million), partially offset by a decrease in AFUDC related to debt funds ($1.3 million) and an increase in interest expense on regulatory deferrals ($~~2.2~~0.4 million) ~~and an increase in interest on notes payable ($1.4 million).~~


•	~~Theincrease at NSTAR Electric was due to higher interest on long-term debt ($8.1 million)~~.

Interest expense at PSNH did not significantly change as the increase in interest due to the May 2018 RRB issuance ($6.7 million) was offset by a decrease in interest expense on regulatory deferrals ($3.1 million), a decrease in interest on notes payable ($2.0 million) and an increase in AFUDC related to debt funds ($1.5 million).

Other Income, Net ~~decreased~~increased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:

•The ~~decrease~~increase at CL&P was due primarily to ~~a decrease~~an increase related to pension, SERP and PBOP non-service income components ($~~9.0~~11.4 million), higher interest income ($3.9 million), and an increase in investment income ($0.2 million), partially offset by ~~investment income~~a decrease in ~~2019 compared~~AFUDC related to ~~investment losses in 2018~~equity funds ($~~5.3~~6.1 million).

•The ~~decrease~~increase at NSTAR Electric was due primarily to ~~a decrease~~higher interest income ($12.5 million) and an increase related to pension, SERP and PBOP non-service income components ($~~12.5 million) and an increase in investment losses in 2019 compared to 2018 ($2.7~~10.9 million), partially offset by ~~an increase~~a decrease in AFUDC related to equity funds ($~~4.2~~1.1 million) ~~and an~~.

•The increase ~~in amounts related to officers' life insurance policies ($2.8 million).~~

~~The decrease~~ at PSNH was due primarily to ~~a decrease~~an increase related to pension, SERP and PBOP non-service income components ($~~5.0~~3.3 million), ~~the absence in 2019 of~~partially offset by a ~~gain on the sale of property ($4.4 million) and a~~ decrease ~~in the recognition of the equity component of the carrying charges related to storm costs recorded in interest income ($2.4 million). Partially offsetting these decreases was an increase~~ in AFUDC related to equity funds ($~~3.4~~2.6 million).

Income Tax Expense increased/~~(decreased)~~decreased in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the following:

•The ~~increase~~decrease at CL&P was due primarily to ~~higher pre-tax earnings~~the CL&P settlement agreement ($~~8.6~~17.5 million) ~~and an increase~~, a decrease in a valuation allowance ~~against state tax credits~~ ($~~9.8 million). These increases were partially offset by amortization of EDIT ($5.8 million), return to provision ($3.0 million), lower state taxes ($1.3~~17.0 million), and bya decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~0.4~~9.8 million)~~. The impact of the amortization of the EDIT regulatory liability, including the tax gross up portion, that reduced revenue was $7.9 million,~~, partially offset by ~~a current~~higher pre-tax earnings excluding the settlement agreement charges ($6.2 million), higher state taxes ($18.9 million) and lower share-based payment excess tax ~~benefit of $2.1 million and amortization of EDIT of $5.8 million for the year ended December 31, 2019, which results in no impact on earnings.~~benefits ($0.8 million).

•The decrease at NSTAR Electric was due primarily to an increase in amortization of EDIT ($~~22.9~~22.8 million), ~~return to provision~~partially offset by higher pre-tax earnings ($~~1.3~~3.2 million), higher state taxes ($1.4 million), an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~6.3~~0.8 million), and ~~partially offset by~~lower share-based payment excess tax benefits ($0.9 million).

•The increase at PSNH was due primarily to a decrease in amortization of EDIT ($4.9 million), higher state taxes ($0.4 million), higher pre-tax earnings ($5.4 million) and higher state taxes ($1.5 million). The impact of the amortization of the EDIT regulatory liability, including the tax gross up portion, that reduced revenue was $31.5 million, offset by a current tax benefit of $8.6 million and amortization of EDIT of $22.9 million for the year ended December 31, 2019, which results in no impact on earnings.

~~The decrease at PSNH was due to lower state taxes ($4.4~~2.2 million), ~~return to provision ($1.1 million),~~ and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~3.8~~0.2 million). These decreases were partially offset by higher pre-tax earnings ($2.7 million). The impact of the amortization of the EDIT regulatory liability, including the tax gross up portion, that reduced revenue was $5.6 million, offset by a current tax benefit of $1.6 million and amortization of EDIT of $4.0 million for the year ended December 31, 2019, which results in no impact on earnings.

EARNINGS SUMMARY

CL&P's earnings ~~increased $33.2~~decreased $56.2 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the settlement agreement on October 1, 2021 resulting in a total $75 million pre-tax charge to earnings and a $28.6 million pre-tax charge to earnings for a storm performance penalty imposed by the PURA as a result of CL&P’s preparation for and response to Tropical Storm Isaias in August 2020 that was recorded in 2021. The after-tax impact of the settlement agreement and storm performance penalty was $86.1 million. Earnings were also unfavorably impacted by higher operations and maintenance expense primarily driven by higher employee-related expenses, higher shared corporate costs, and higher vegetation management costs, higher depreciation expense, higher property tax expense, and higher interest expense. The earnings decrease was partially offset by higher earnings from its capital tracker mechanism due to increased electric system improvements, the base distribution rate ~~increases~~increase effective May 1, ~~2019 and May 1, 2018,~~2020, an increase in transmission earnings driven by a higher transmission rate base, and an increase in the non-service income components of pension, SERP and PBOP net periodic benefit plan cost.

NSTAR Electric's earnings increased $31.6 million in 2021, as compared to 2020, due primarily to an increase in transmission earnings driven by a higher transmission rate base, the base distribution rate increase effective ~~July~~January 1, ~~2018, higher~~2021, a lower effective tax rate, and the earnings ~~from its capital tracker mechanism due to increased electric system improvements.~~benefit in 2021 associated with the deferral of threshold costs for certain 2020 and 2021 major storms. The earnings increase was partially offset by higher operations and maintenance expense primarily driven by higher employee-related expenses and higher shared corporate costs, higher depreciation expense, ~~lower non-service income from our benefit plans,~~ and higher ~~property tax~~interest expense.

~~NSTAR Electric's~~PSNH's earnings increased ~~$48.9~~$3.0 million in ~~2019,~~2021, as compared to ~~2018,~~2020, due primarily to the base distribution rate ~~increase~~increases effective January 1, ~~2019,~~2021 and August 1, 2021, an increase in transmission earnings driven by a higher transmission rate base, and ~~higher earnings from its solar generation capital~~the impact in 2021 of a new tracker ~~mechanism.~~mechanism at PSNH approved as part of the 2020 rate settlement agreement. The earnings increase was partially offset by higher operations and maintenance expense primarily driven by higher vegetation management costs and higher employee-related expenses, higher depreciation expense, and higher ~~interest~~property tax expense.

PSNH's earnings increased $18.1 million in 2019, as compared to 2018, due primarily to the temporary base distribution rate increase effective July 1, 2019 and an increase in transmission earnings driven by a higher transmission rate base. The earnings increase was partially offset by the absence in 2019 of generation earnings as a result of the sale of its generation assets in 2018, higher operations and maintenance expense, the absence in 2019 of a gain on the sale of property in 2018, and lower non-service income from our benefit plans.

LIQUIDITY

Cash Flows: CL&P had cash flows provided by operating activities of ~~$726.4~~$612.9 million in ~~2019,~~2021, as compared to ~~$588.1~~$397.1 million in ~~2018.~~2020. The increase in operating cash flows was due primarily to the timing of cash payments made on our accounts payable and collections on our accounts receivable, a decrease in 2019 of approximately $98 million of storm restoration cost payments, an increase related to the timing of cash collected for regulatory tracking mechanisms, and a decrease in 2019 of $17.2 million of pension contributions. Partially offsetting these favorable impacts were higher income tax payments made in 2019 of $14.5 million, and the timing of other working capital items.

~~NSTAR Electric had cash flows provided by operating activities of $698.3 million in 2019, as compared to $780.5 million in 2018. The decrease~~ in operating cash flows was due primarily to the timing of collections for regulatory tracking mechanisms, ~~which were significantly impacted by~~ the timing of cash collections ~~of purchased power and transmission costs,and~~on our accounts receivable, the timing of cash payments made on our accounts payable, and the timing of other working capital items. ~~Partially offsetting these unfavorable~~These favorable impacts were partially offset by a ~~decrease~~$75.7 million increase in ~~2019~~pension contributions made in 2021, as compared to 2020, a $38.4 million increase in cost of ~~approximately $45~~removal expenditures, and a $27.5 million ~~of storm restoration cost payments, the timing of cash collections on our accounts receivable, a decrease~~increase in ~~2019 of $55.4 million of pension and PBOP cash contributions, and lower~~ income tax payments made in ~~2019 of $42.1 million.~~2021, as compared to 2020.

~~PSNH~~NSTAR Electric had cash flows provided by operating activities of ~~$274.4~~$700.9 million in ~~2019,~~2021, as compared to ~~$259.9~~$525.8 million in ~~2018.~~2020. The increase in operating cash flows was due primarily to the timing of collections for regulatory tracking mechanisms, the timing of other working capital items, a $36.5 million decrease in income tax payments made in 2021, as compared to 2020, the timing of cash collections on our accounts receivable, and the timing of cash payments made on our accounts payable. These favorable impacts were partially offset by a $29.4 million increase in pension contributions made in 2021, as compared to 2020, and a $19.8 million increase in cost of removal expenditures.

PSNH had cash flows provided by operating activities of $336.1 million in 2021, as compared to $218.7 million in 2020. The increase in operating cash flows was due primarily to the timing of collections for regulatory tracking mechanisms, the timing of other working capital items, and the absence in 2021 of pension contributions of $19.5 million made in 2020. These favorable impacts were partially offset by the timing of cash payments made on our accounts payable, ~~and lower~~a $16.9 million increase in income tax payments made in ~~2019~~2021, as compared to 2020, and an $8.7 million increase in cost of ~~$23.9 million. Partially offsetting these favorable impacts were $15.4 million of pension contributions made in 2019 and the timing of other working capital items.~~removal expenditures.

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

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

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

Other Risk Management Activities

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

Interest Rate Risk Management: 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, ~~2019, all~~2021, approximately 98 percent of our long-term debt ~~except for $11.6 million of fees and interest due for CYAPC's spent nuclear fuel disposal costs,~~ 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, ~~2019,~~2021, our regulated companies held collateral (letters of credit or cash) of ~~$20.0~~$210.9 million from counterparties related to our standard service contracts. As of December 31, ~~2019,~~2021, Eversource had ~~$19.3~~$34.6 million of cash posted with ISO-NE related to energy transactions.

For further information on cash collateral deposited and posted with counterparties, see Note 1O, "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 or S&P, certain of Eversource's contracts would require additional collateral in the form of cash 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
			~~Company~~Management’s Report on Internal Controls Over Financial Reporting
			Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
			Consolidated Financial Statements

CL&P
			~~Company~~Management’s Report on Internal Controls Over Financial Reporting
			Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
			Financial Statements

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

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

~~Company~~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, ~~2019.~~2021.

February 16, 2022

~~February 26, 2020~~

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~Shareholders and the~~ Board of Trustees and Shareholders of Eversource ~~Energy~~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, ~~2019,~~2021, 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, ~~2019,~~2021, 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, ~~2019,~~2021, of the Company and our report dated February ~~26, 2020,~~16, 2022, 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 ~~Company~~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 ~~26, 2020~~16, 2022

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, ~~2019~~2021 and ~~2018,~~2020, 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, ~~2019,~~2021, 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, ~~2019~~2021 and ~~2018,~~2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2019,~~2021, 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, ~~2019,~~2021, 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 ~~26, 2020,~~16, 2022, 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 ~~one or more of~~ the Federal Energy Regulatory Commission and ~~the Connecticut, Massachusetts, and New Hampshire~~by their respective state public utility authorities in Connecticut, Massachusetts, or New Hampshire (the “Commissions”) ~~that~~. The rate regulation by these Commissions 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.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'~~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 ~~depreciation expense.~~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. This included an evaluation of disclosures related to Tropical Storm Isaias costs and other associated regulatory proceedings in Connecticut.

• We read relevant regulatory orders issued by the Commissions for the Company, including orders in Connecticut associated with the Tropical Storm Isaias Response Investigation and associated settlement agreement. We also read orders issued by the Commissions for other public utilities, ~~in Connecticut, Massachusetts, and New Hampshire,~~ 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 ~~precedence~~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, including amounts related to Tropical Storm Isaias restoration costs and associated regulatory proceedings in Connecticut, 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 ~~26, 2020~~16, 2022

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

EVERSOURCE ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	As of December 31,
(Thousands of Dollars)	2021		2020

ASSETS
Current Assets:
Cash	$	66,773	$	106,599
Receivables, Net (net of allowance for uncollectible accounts of $417,406 and $358,851 as of December 31, 2021 and 2020, respectively)	1,226,069		1,195,925
Unbilled Revenues	210,879		233,025
Fuel, Materials, Supplies and REC Inventory	267,547		265,599
Regulatory Assets	1,129,093		1,076,556
Prepayments and Other Current Assets	369,759		252,439
Total Current Assets	3,270,120		3,130,143
Property, Plant and Equipment, Net	33,377,650		30,882,523
Deferred Debits and Other Assets:
Regulatory Assets	4,586,709		5,493,330
Goodwill	4,477,269		4,445,988
Investments in Unconsolidated Affiliates	1,436,293		1,107,143
Marketable Securities	460,347		456,617
Other Long-Term Assets	883,756		583,854
Total Deferred Debits and Other Assets	11,844,374		12,086,932
Total Assets	$	48,492,144	$	46,099,598

LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable	$	1,505,450	$	1,249,325
Long-Term Debt – Current Portion	1,193,097		1,053,186
Rate Reduction Bonds – Current Portion	43,210		43,210
Accounts Payable	1,672,230		1,370,647
Regulatory Liabilities	602,432		389,430
Other Current Liabilities	830,620		809,214
Total Current Liabilities	5,847,039		4,915,012
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	4,597,120		4,095,339
Regulatory Liabilities	3,866,251		3,850,781
Derivative Liabilities	235,387		294,535
Asset Retirement Obligations	500,111		499,713
Accrued Pension, SERP and PBOP	242,463		1,653,788
Other Long-Term Liabilities	971,080		948,506
Total Deferred Credits and Other Liabilities	10,412,412		11,342,662
Long-Term Debt	17,023,577		15,125,876
Rate Reduction Bonds	453,702		496,912
Noncontrolling Interest - Preferred Stock of Subsidiaries	155,570		155,570
Common Shareholders' Equity:
Common Shares	1,789,092		1,789,092
Capital Surplus, Paid In	8,098,514		8,015,663
Retained Earnings	5,005,391		4,613,201
Accumulated Other Comprehensive Loss	(42,275)		(76,411)
Treasury Stock	(250,878)		(277,979)
Common Shareholders' Equity	14,599,844		14,063,566
Commitments and Contingencies (Note 13)	0		0
Total Liabilities and Capitalization	$	48,492,144	$	46,099,598

As of December 31,
(Thousands of Dollars) 2019 2018

ASSETS

Current Assets:

Cash $ 15,432
$ 108,068
Receivables, Net 989,383
994,055
Unbilled Revenues 181,006
176,285
Fuel, Materials, Supplies and REC Inventory 235,471
238,042
Regulatory Assets 651,112
514,779
Prepayments and Other Current Assets 342,135
260,995
Total Current Assets 2,414,539
2,292,224

Property, Plant and Equipment, Net 27,585,470
25,610,428

Deferred Debits and Other Assets:

Regulatory Assets 4,863,639
4,631,137
Goodwill 4,427,266
4,427,266
Investments in Unconsolidated Affiliates 871,633
464,286
Marketable Securities 449,130
417,508
Other Long-Term Assets 512,238
398,407
Total Deferred Debits and Other Assets 11,123,906
10,338,604

Total Assets $ 41,123,915
$ 38,241,256

LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable $ 889,084
$ 910,000
Long-Term Debt – Current Portion 327,411
837,319
Rate Reduction Bonds – Current Portion 43,210
52,332
Accounts Payable 1,147,872
1,119,995
Regulatory Liabilities 361,152
370,230
Other Current Liabilities 836,834
823,006
Total Current Liabilities 3,605,563
4,112,882

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes 3,755,777
3,506,030
Regulatory Liabilities 3,658,042
3,609,475
Derivative Liabilities 338,710
379,562
Asset Retirement Obligations 488,511
466,236
Accrued Pension, SERP and PBOP 1,370,245
962,510
Other Long-Term Liabilities 810,553
730,100
Total Deferred Credits and Other Liabilities 10,421,838
9,653,913

Long-Term Debt 13,770,828
12,248,743

Rate Reduction Bonds 540,122
583,331

Noncontrolling Interest - Preferred Stock of Subsidiaries 155,570
155,570

Common Shareholders' Equity:
Common Shares 1,729,292
1,669,392
Capital Surplus, Paid In 7,087,768
6,241,222
Retained Earnings 4,177,048
3,953,974
Accumulated Other Comprehensive Loss (65,059 ) (60,000 )
Treasury Stock (299,055 ) (317,771 )
Common Shareholders' Equity 12,629,994
11,486,817

Commitments and Contingencies (Note 13)

Total Liabilities and Capitalization $ 41,123,915
$ 38,241,256

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

EVERSOURCE ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


	For the Years Ended December 31,							For the Years Ended December 31,
(Thousands of Dollars, Except Share Information)	2019		2018		2017		(Thousands of Dollars, Except Share Information)	2021		2020		2019

Operating Revenues	$	8,526,470	$	8,448,201	$	7,751,952	Operating Revenues	$	9,863,085	$	8,904,430	$	8,526,470

Operating Expenses:							Operating Expenses:
Purchased Power, Fuel and Transmission	3,040,160		3,138,969		2,535,271		Purchased Power, Fuel and Transmission	3,372,344		2,987,840		3,040,160
Operations and Maintenance	1,363,113		1,335,213		1,307,052		Operations and Maintenance	1,739,685		1,480,252		1,363,113
Depreciation	885,278		819,930		773,802		Depreciation	1,103,008		981,380		885,278
Amortization	195,380		252,026		89,986		Amortization	231,965		177,679		195,380
Energy Efficiency Programs	501,369		472,380		480,835		Energy Efficiency Programs	592,775		535,760		501,369
Taxes Other Than Income Taxes	711,035		729,753		676,757		Taxes Other Than Income Taxes	829,987		752,785		711,035
Impairment of Northern Pass Transmission	239,644		—		—		Impairment of Northern Pass Transmission	—		—		239,644
Total Operating Expenses	6,935,979		6,748,271		5,863,703		Total Operating Expenses	7,869,764		6,915,696		6,935,979
Operating Income	1,590,491		1,699,930		1,888,249		Operating Income	1,993,321		1,988,734		1,590,491
Interest Expense	533,197		498,805		421,755		Interest Expense	582,334		538,452		533,197
Other Income, Net	132,777		128,366		107,913		Other Income, Net	161,282		108,590		132,777
Income Before Income Tax Expense	1,190,071		1,329,491		1,574,407		Income Before Income Tax Expense	1,572,269		1,558,872		1,190,071
Income Tax Expense	273,499		288,972		578,892		Income Tax Expense	344,223		346,186		273,499
Net Income	916,572		1,040,519		995,515		Net Income	1,228,046		1,212,686		916,572
Net Income Attributable to Noncontrolling Interests	7,519		7,519		7,519		Net Income Attributable to Noncontrolling Interests	7,519		7,519		7,519
Net Income Attributable to Common Shareholders	$	909,053	$	1,033,000	$	987,996	Net Income Attributable to Common Shareholders	$	1,220,527	$	1,205,167	$	909,053

Basic Earnings Per Common Share	$	2.83	$	3.25	$	3.11	Basic Earnings Per Common Share	$	3.55	$	3.56	$	2.83

Diluted Earnings Per Common Share	$	2.81	$	3.25	$	3.11	Diluted Earnings Per Common Share	$	3.54	$	3.55	$	2.81

Weighted Average Common Shares Outstanding:							Weighted Average Common Shares Outstanding:
Basic	321,416,086		317,370,369		317,411,097		Basic	343,972,926		338,836,147		321,416,086
Diluted	322,941,636		317,993,934		318,031,580		Diluted	344,631,056		339,847,062		322,941,636

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

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	For the Years Ended December 31,
(Thousands of Dollars)	2021		2020		2019

Net Income	$	1,228,046	$	1,212,686	$	916,572
Other Comprehensive Income/(Loss), Net of Tax:
Qualified Cash Flow Hedging Instruments	972		1,596		1,393
Changes in Unrealized (Losses)/Gains on Marketable Securities	(671)		342		1,166
Changes in Funded Status of Pension, SERP and PBOP Benefit Plans	33,835		(13,290)		(7,618)
Other Comprehensive Income/(Loss), Net of Tax	34,136		(11,352)		(5,059)
Comprehensive Income Attributable to Noncontrolling Interests	(7,519)		(7,519)		(7,519)
Comprehensive Income Attributable to Common Shareholders	$	1,254,663	$	1,193,815	$	903,994

For the Years Ended December 31,
(Thousands of Dollars) 2019 2018 2017

Net Income $ 916,572
$ 1,040,519
$ 995,515
Other Comprehensive (Loss)/Income, Net of Tax:
Qualified Cash Flow Hedging Instruments 1,393
1,756
1,974
Changes in Unrealized Gains/(Losses) on Marketable Securities 1,166
(547 ) (350 )
Changes in Funded Status of Pension, SERP and PBOP Benefit Plans (7,618 ) 5,194
(2,745 )
Other Comprehensive (Loss)/Income, Net of Tax (5,059 ) 6,403
(1,121 )
Comprehensive Income Attributable to Noncontrolling Interests (7,519 ) (7,519 ) (7,519 )
Comprehensive Income Attributable to Common Shareholders $ 903,994
$ 1,039,403
$ 986,875

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

EVERSOURCE ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY


	Common Shares			Capital Surplus, Paid In		Retained Earnings		Accumulated Other Comprehensive Loss		Treasury Stock		Total Common Shareholders' Equity
(Thousands of Dollars, Except Share Information)	Shares	Amount
Balance as of January 1, 2019	316,885,808	$	1,669,392	$	6,241,222	$	3,953,974	$	(60,000)	$	(317,771)	$	11,486,817
Net Income						916,572						916,572
Dividends on Common Shares - $2.14 Per Share						(685,979)						(685,979)
Dividends on Preferred Stock						(7,519)						(7,519)
Issuance of Common Shares - $5 par value	11,980,000	59,900		808,650								868,550
Long-Term Incentive Plan Activity				3,434								3,434
Issuance of Treasury Shares	1,014,837			50,758						18,716		69,474
Capital Stock Expense				(16,296)								(16,296)

Other Comprehensive Loss								(5,059)				(5,059)
Balance as of December 31, 2019	329,880,645	1,729,292		7,087,768		4,177,048		(65,059)		(299,055)		12,629,994
Net Income						1,212,686						1,212,686
Dividends on Common Shares - $2.27 Per Share						(767,500)						(767,500)
Dividends on Preferred Stock						(7,519)						(7,519)
Issuance of Common Shares - $5 par value	11,960,000	59,800		889,860								949,660
Long-Term Incentive Plan Activity				7,890								7,890
Issuance of Treasury Shares	1,113,378			50,812						21,076		71,888
Capital Stock Expense				(20,667)								(20,667)
Adoption of Accounting Standards Update 2016-13						(1,514)						(1,514)
Other Comprehensive Loss								(11,352)				(11,352)
Balance as of December 31, 2020	342,954,023	1,789,092		8,015,663		4,613,201		(76,411)		(277,979)		14,063,566
Net Income						1,228,046						1,228,046
Dividends on Common Shares - $2.41 Per Share						(828,337)						(828,337)
Dividends on Preferred Stock						(7,519)						(7,519)

Long-Term Incentive Plan Activity				3,537								3,537
Issuance of Treasury Shares	986,656			49,913						18,451		68,364

Issuance of Treasury Shares for Acquisition of New England Service Company	462,517			29,401						8,650		38,051

Other Comprehensive Income								34,136				34,136
Balance as of December 31, 2021	344,403,196	$	1,789,092	$	8,098,514	$	5,005,391	$	(42,275)	$	(250,878)	$	14,599,844

Common Shares
Capital
Surplus,
Paid In
Retained Earnings Accumulated Other Comprehensive Loss Treasury Stock Total Common Shareholders' Equity
(Thousands of Dollars, Except Share Information) Shares Amount
Balance as of January 1, 2017 316,885,808
$ 1,669,392
$ 6,250,224
$ 3,175,171
$ (65,282 ) $ (317,771 ) $ 10,711,734
Net Income

995,515
995,515
Dividends on Common Shares - $1.90 Per Share

(602,083 ) (602,083 )
Dividends on Preferred Stock

(7,519 ) (7,519 )
Long-Term Incentive Plan Activity

(10,834 ) (10,834 )
Other Changes in Shareholders' Equity

550

550
Other Comprehensive Loss

(1,121 ) (1,121 )
Balance as of December 31, 2017 316,885,808
1,669,392
6,239,940
3,561,084
(66,403 ) (317,771 ) 11,086,242
Net Income

1,040,519
1,040,519
Dividends on Common Shares - $2.02 Per Share

(640,110 ) (640,110 )
Dividends on Preferred Stock

(7,519 ) (7,519 )
Long-Term Incentive Plan Activity

(543 ) (543 )
Other Changes in Shareholders' Equity

1,825

1,825
Other Comprehensive Income

6,403
6,403
Balance as of December 31, 2018 316,885,808
1,669,392
6,241,222
3,953,974
(60,000 ) (317,771 ) 11,486,817
Net Income

916,572
916,572
Dividends on Common Shares - $2.14 Per Share

(685,979 ) (685,979 )
Dividends on Preferred Stock

(7,519 ) (7,519 )
Issuance of Common Shares - $5 par value 11,980,000
59,900
808,650
868,550
Long-Term Incentive Plan Activity 3,434
3,434
Issuance of Treasury Shares 1,014,837

50,758
18,716 69,474
Capital Stock Expense (16,296 ) (16,296 )
Other Comprehensive Loss

(5,059 ) (5,059 )
Balance as of December 31, 2019 329,880,645
$ 1,729,292
$ 7,087,768
$ 4,177,048
$ (65,059 ) $ (299,055 ) $ 12,629,994

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

EVERSOURCE ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended December 31,										For the Years Ended December 31,
(Thousands of Dollars)	2019			2018			2017			(Thousands of Dollars)	2021		2020		2019

Operating Activities:										Operating Activities:
Net Income	$	916,572		$	1,040,519		$	995,515		Net Income	$	1,228,046	$	1,212,686	$	916,572
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:										Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation	885,278			819,930			773,802			Depreciation	1,103,008		981,380		885,278
Deferred Income Taxes	209,812			174,812			491,630			Deferred Income Taxes	347,056		257,154		209,812
Uncollectible Expense	63,446			61,337			44,453			Uncollectible Expense	60,886		53,461		63,446
Pension, SERP and PBOP Expense, Net	22,000			5,498			22,454
Pension, SERP and PBOP (Income)/Expense, Net										Pension, SERP and PBOP (Income)/Expense, Net	(14,693)		12,888		22,000
Pension and PBOP Contributions	(121,782		)	(194,947		)	(242,800		)	Pension and PBOP Contributions	(182,344)		(111,524)		(121,782)
Regulatory (Under)/Over Recoveries, Net	(124,870		)	34,920			(47,935		)
Regulatory Underrecoveries, Net										Regulatory Underrecoveries, Net	(314,211)		(516,411)		(124,870)
Reserve at CL&P related to PURA Settlement Agreement and Storm Performance Penalty										Reserve at CL&P related to PURA Settlement Agreement and Storm Performance Penalty	81,274		—		—
Amortization	195,380			252,026			89,986			Amortization	231,965		177,679		195,380
Payments Related to CYAPC's DOE Pre-1983 Spent Nuclear Fuel Obligation	(29,000		)	(145,000		)	—			Payments Related to CYAPC's DOE Pre-1983 Spent Nuclear Fuel Obligation	—		—		(29,000)
Proceeds from DOE Spent Nuclear Fuel Litigation	68,840			—			—			Proceeds from DOE Spent Nuclear Fuel Litigation	—		—		68,840
Impairment of Northern Pass Transmission	239,644			—			—			Impairment of Northern Pass Transmission	—		—		239,644
Cost of Removal Expenditures										Cost of Removal Expenditures	(242,130)		(148,332)		(153,477)
Other	(196,087		)	(111,225		)	(204,421		)	Other	(64,640)		(25,957)		(42,610)
Changes in Current Assets and Liabilities:										Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(98,716		)	(141,433		)	(117,155		)	Receivables and Unbilled Revenues, Net	(135,505)		(351,843)		(98,716)
Fuel, Materials, Supplies and REC Inventory	(8,074		)	(831		)	(9,223		)	Fuel, Materials, Supplies and REC Inventory	(1,859)		(15,404)		(8,074)
Taxes Receivable/Accrued, Net	(16,129		)	(67,770		)	52,284			Taxes Receivable/Accrued, Net	(110,621)		43,819		(16,129)
Accounts Payable	14,866			24,481			56,067			Accounts Payable	(29,201)		122,567		14,866
Other Current Assets and Liabilities, Net	(11,603		)	78,226			91,545			Other Current Assets and Liabilities, Net	5,569		(9,591)		(11,603)
Net Cash Flows Provided by Operating Activities	2,009,577			1,830,543			1,996,202			Net Cash Flows Provided by Operating Activities	1,962,600		1,682,572		2,009,577

Investing Activities:										Investing Activities:
Investments in Property, Plant and Equipment	(2,911,489		)	(2,569,936		)	(2,348,105		)	Investments in Property, Plant and Equipment	(3,175,080)		(2,942,996)		(2,911,489)
Proceeds from Sales of Marketable Securities	566,592			900,749			832,903			Proceeds from Sales of Marketable Securities	447,893		434,124		566,592
Proceeds from Sales of Marketable Securities Used to Pay Pre-1983 Spent Nuclear Fuel Obligation	—			145,000			—

Purchases of Marketable Securities	(537,258		)	(908,387		)	(810,507		)	Purchases of Marketable Securities	(414,980)		(401,823)		(537,258)
Acquisition of Aquarion	—			—			(877,652		)
Acquisition of Assets of Columbia Gas of Massachusetts, Net of Restricted Cash										Acquisition of Assets of Columbia Gas of Massachusetts, Net of Restricted Cash	—		(1,113,252)		—
Investments in Unconsolidated Affiliates, Net	(416,337		)	(205,150		)	(32,634		)	Investments in Unconsolidated Affiliates, Net	(327,385)		(239,673)		(416,337)
Proceeds from the Sale of PSNH Generation Assets	—			193,924			—
Proceeds from the Sale of Hingham Water System										Proceeds from the Sale of Hingham Water System	—		110,536		—

Other Investing Activities	24,204			6,754			5,479			Other Investing Activities	22,178		23,809		24,204
Net Cash Flows Used in Investing Activities	(3,274,288		)	(2,437,046		)	(3,230,516		)	Net Cash Flows Used in Investing Activities	(3,447,374)		(4,129,275)		(3,274,288)

Financing Activities:										Financing Activities:
Issuance of Common Shares, Net of Issuance Costs	852,254			—			—			Issuance of Common Shares, Net of Issuance Costs	—		928,992		852,254
Cash Dividends on Common Shares	(663,239		)	(640,110		)	(602,083		)	Cash Dividends on Common Shares	(805,439)		(744,665)		(663,239)
Cash Dividends on Preferred Stock	(7,519		)	(7,519		)	(7,519		)	Cash Dividends on Preferred Stock	(7,519)		(7,519)		(7,519)
Increase/(Decrease) in Notes Payable	325,370			(379,310		)	72,810
(Repayments)/Issuance of Rate Reduction Bonds	(52,332		)	635,663			—
Increase in Notes Payable										Increase in Notes Payable	256,125		13,955		325,370
Repayment of Rate Reduction Bonds										Repayment of Rate Reduction Bonds	(43,210)		(43,210)		(52,332)
Issuance of Long-Term Debt	1,520,000			2,200,000			2,500,000			Issuance of Long-Term Debt	3,230,000		2,760,000		1,520,000
Retirement of Long-Term Debt	(801,078		)	(1,050,330		)	(745,000		)	Retirement of Long-Term Debt	(1,142,500)		(327,236)		(801,078)
Other Financing Activities	(1,006		)	(28,457		)	(4,754		)	Other Financing Activities	(46,625)		14,273		(1,006)
Net Cash Flows Provided by Financing Activities	1,172,450			729,937			1,213,454			Net Cash Flows Provided by Financing Activities	1,440,832		2,594,590		1,172,450
Net (Decrease)/Increase in Cash and Restricted Cash	(92,261		)	123,434			(20,860		)	Net (Decrease)/Increase in Cash and Restricted Cash	(43,942)		147,887		(92,261)
Cash and Restricted Cash - Beginning of Year	209,324			85,890			106,750			Cash and Restricted Cash - Beginning of Year	264,950		117,063		209,324
Cash and Restricted Cash - End of Year	$	117,063		$	209,324		$	85,890		Cash and Restricted Cash - End of Year	$	221,008	$	264,950	$	117,063

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

~~Company~~Management’s Report on Internal Controls Over Financial Reporting

The Connecticut Light and Power Company

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

Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, ~~2019.~~2021.

February 16, 2022

~~February 26, 2020~~

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of The Connecticut Light and Power Company:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of The Connecticut Light and Power Company (the “Company”) as of December 31, ~~2019~~2021 and ~~2018,~~2020, the related statements of income, comprehensive income, common stockholder’s equity, and cash flows, for each of the three years in the period ended December 31, ~~2019,~~2021, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2019~~2021 and ~~2018,~~2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2019,~~2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

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

Critical Audit Matter Description

The Company is subject to rate regulation by the Federal Energy Regulatory Commission and the state public utility authority in Connecticut (the “Commissions”). The rate regulation by these Commissions is based on cost recovery. The Company’s financial statements reflect the effects of the rate-making process. The rates charged to the customers are designed to collect the Company’s cost to provide service, plus a return on investment.

The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. The Company must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. The Company bases its conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

The Company uses judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on the Company’s financial statements. Management believes it is probable that the Company will recover its investment in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Company’s operations, or if management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made.

Accounting for the economics of rate-regulation impacts multiple financial statement line items and disclosures, such as regulated property, plant, and equipment, regulatory assets and liabilities, operating revenues, depreciation expense and amortization of regulatory assets. While management has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve full recovery of such costs or full recovery of all amounts invested in the Company and a reasonable return on that investment. We identified the impact of rate-regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impact of future regulatory orders on the financial statements. Management judgments include assessing the probability of recovery in future rates of incurred costs and of a refund to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments requires specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

How the Critical Audit Matter Was Addressed in the Audit

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

• We read relevant regulatory orders issued by the Commissions for the Company, including orders associated with the Tropical Storm Isaias Response Investigation and associated settlement agreement. We also read orders issued by the Commissions for 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.

• 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, including amounts related to Tropical Storm Isaias restoration costs and associated regulatory proceedings, 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 ~~26, 2020~~16, 2022

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

THE CONNECTICUT LIGHT AND POWER COMPANY

BALANCE SHEETS


	As of December 31,					As of December 31,
(Thousands of Dollars)	2019		2018		(Thousands of Dollars)	2021		2020

ASSETS					ASSETS
Current Assets:					Current Assets:
Cash	$	—	$	87,721	Cash	$	55,804	$	90,801
Receivables, Net	400,927		397,026
Receivables, Net (net of allowance for uncollectible accounts of $181,319 and $157,447 as of December 31, 2021 and 2020, respectively)					Receivables, Net (net of allowance for uncollectible accounts of $181,319 and $157,447 as of December 31, 2021 and 2020, respectively)	447,774		459,214
Accounts Receivable from Affiliated Companies	24,577		23,082		Accounts Receivable from Affiliated Companies	43,944		17,486
Unbilled Revenues	56,465		56,971		Unbilled Revenues	56,787		57,407
Materials and Supplies	50,700		44,529		Materials and Supplies	60,264		57,924
Regulatory Assets	178,607		125,155		Regulatory Assets	371,609		345,622
Prepayments and Other Current Assets	73,184		60,279		Prepayments and Other Current Assets	120,257		83,950
Total Current Assets	784,460		794,763		Total Current Assets	1,156,439		1,112,404

Property, Plant and Equipment, Net	9,625,765		8,909,701		Property, Plant and Equipment, Net	10,803,543		10,234,556

Deferred Debits and Other Assets:					Deferred Debits and Other Assets:
Regulatory Assets	1,557,261		1,505,488		Regulatory Assets	1,713,161		1,866,152
Other Long-Term Assets	217,705		199,767		Other Long-Term Assets	276,513		242,862
Total Deferred Debits and Other Assets	1,774,966		1,705,255		Total Deferred Debits and Other Assets	1,989,674		2,109,014

Total Assets	$	12,185,191	$	11,409,719	Total Assets	$	13,949,656	$	13,455,974

LIABILITIES AND CAPITALIZATION					LIABILITIES AND CAPITALIZATION
Current Liabilities:					Current Liabilities:
Notes Payable to Eversource Parent	$	63,800	$	—
Long-Term Debt – Current Portion	—		250,000

Accounts Payable	374,698		324,983		Accounts Payable	$	533,454	$	451,240
Accounts Payable to Affiliated Companies	97,793		26,452		Accounts Payable to Affiliated Companies	132,578		51,118
Obligations to Third Party Suppliers	56,952		56,248		Obligations to Third Party Suppliers	43,183		49,967
Regulatory Liabilities	82,763		109,614		Regulatory Liabilities	266,489		137,166
Derivative Liabilities	67,804		55,058		Derivative Liabilities	73,528		68,767
Other Current Liabilities	132,339		161,088		Other Current Liabilities	98,772		102,060
Total Current Liabilities	876,149		983,443		Total Current Liabilities	1,148,004		860,318

Deferred Credits and Other Liabilities:					Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	1,244,551		1,166,784		Accumulated Deferred Income Taxes	1,562,102		1,408,343
Regulatory Liabilities	1,164,991		1,122,157		Regulatory Liabilities	1,193,259		1,204,942
Derivative Liabilities	338,594		379,536		Derivative Liabilities	235,387		294,535
Accrued Pension, SERP and PBOP	391,159		282,771		Accrued Pension, SERP and PBOP	26,820		478,325
Other Long-Term Liabilities	147,586		155,495		Other Long-Term Liabilities	153,004		133,690
Total Deferred Credits and Other Liabilities	3,286,881		3,106,743		Total Deferred Credits and Other Liabilities	3,170,572		3,519,835

Long-Term Debt	3,518,136		3,004,016		Long-Term Debt	4,215,379		3,914,835

Preferred Stock Not Subject to Mandatory Redemption	116,200		116,200		Preferred Stock Not Subject to Mandatory Redemption	116,200		116,200

Common Stockholder's Equity:					Common Stockholder's Equity:
Common Stock	60,352		60,352		Common Stock	60,352		60,352
Capital Surplus, Paid In	2,535,765		2,410,765		Capital Surplus, Paid In	3,010,765		2,810,765
Retained Earnings	1,791,392		1,727,899		Retained Earnings	2,228,133		2,173,367
Accumulated Other Comprehensive Income	316		301		Accumulated Other Comprehensive Income	251		302
Common Stockholder's Equity	4,387,825		4,199,317		Common Stockholder's Equity	5,299,501		5,044,786

Commitments and Contingencies (Note 13)					Commitments and Contingencies (Note 13)	0		0

Total Liabilities and Capitalization	$	12,185,191	$	11,409,719	Total Liabilities and Capitalization	$	13,949,656	$	13,455,974

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

THE CONNECTICUT LIGHT AND POWER COMPANY

STATEMENTS OF INCOME


	For the Years Ended December 31,								For the Years Ended December 31,
(Thousands of Dollars)	2019		��	2018		2017		(Thousands of Dollars)	2021		2020		2019

Operating Revenues	$	3,232,551		$	3,096,174	$	2,887,359	Operating Revenues	$	3,637,412	$	3,547,527	$	3,232,551

Operating Expenses:								Operating Expenses:
Purchased Power and Transmission	1,188,202			1,095,187		930,780		Purchased Power and Transmission	1,392,969		1,369,196		1,188,202
Operations and Maintenance	549,167			506,448		502,107		Operations and Maintenance	644,175		572,897		549,167
Depreciation	301,188			278,557		249,352		Depreciation	338,915		320,709		301,188
Amortization of Regulatory Assets, Net	51,621			129,021		83,166		Amortization of Regulatory Assets, Net	99,009		58,412		51,621
Energy Efficiency Programs	118,235			93,977		114,713		Energy Efficiency Programs	129,564		141,453		118,235
Taxes Other Than Income Taxes	342,489			357,147		323,887		Taxes Other Than Income Taxes	363,862		344,451		342,489
Total Operating Expenses	2,550,902			2,460,337		2,204,005		Total Operating Expenses	2,968,494		2,807,118		2,550,902
Operating Income	681,649			635,837		683,354		Operating Income	668,918		740,409		681,649
Interest Expense	151,357			151,727		142,973		Interest Expense	166,107		153,547		151,357
Other Income, Net	17,531			22,663		22,991		Other Income, Net	30,187		20,774		17,531
Income Before Income Tax Expense	547,823			506,773		563,372		Income Before Income Tax Expense	532,998		607,636		547,823
Income Tax Expense	136,971			129,056		186,646		Income Tax Expense	131,273		149,702		136,971
Net Income	$	410,852		$	377,717	$	376,726	Net Income	$	401,725	$	457,934	$	410,852

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

STATEMENTS OF COMPREHENSIVE INCOME


	For the Years Ended December 31,
(Thousands of Dollars)	2021		2020		2019

Net Income	$	401,725	$	457,934	$	410,852
Other Comprehensive (Loss)/Income, Net of Tax:
Qualified Cash Flow Hedging Instruments	(26)		(26)		(26)
Changes in Unrealized (Losses)/Gains on Marketable Securities	(25)		12		41
Other Comprehensive (Loss)/Income, Net of Tax	(51)		(14)		15
Comprehensive Income	$	401,674	$	457,920	$	410,867

For the Years Ended December 31,
(Thousands of Dollars) 2019 2018 2017

Net Income $ 410,852
$ 377,717
$ 376,726
Other Comprehensive Income, Net of Tax:
Qualified Cash Flow Hedging Instruments (26 ) 51
334
Changes in Unrealized Gains/(Losses) on Marketable Securities 41
(19 ) (12 )
Other Comprehensive Income, Net of Tax 15
32
322
Comprehensive Income $ 410,867
$ 377,749
$ 377,048

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

THE CONNECTICUT LIGHT AND POWER COMPANY

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY


	Common Stock			Capital Surplus, Paid In			Retained Earnings				Accumulated Other Comprehensive (Loss)/Income				Total Common Stockholder's Equity					Common Stock						Capital Surplus, Paid In			Retained Earnings			Accumulated Other Comprehensive Income			Total Common Stockholder's Equity
(Thousands of Dollars, Except Stock Information)	Stock	Amount				(Thousands of Dollars, Except Stock Information)				Stock								Amount
Balance as of January 1, 2017	6,035,205	$	60,352			$		2,110,714					$	1,299,374					$	(53	)	$	3,470,387
Net Income							376,726								376,726
Dividends on Preferred Stock							(5,559		)						(5,559		)
Dividends on Common Stock							(254,800		)						(254,800		)
Capital Stock Expenses, Net				51											51
Other Comprehensive Income											322				322
Balance as of December 31, 2017	6,035,205	60,352		2,110,765			1,415,741				269				3,587,127
Net Income							377,717								377,717
Dividends on Preferred Stock							(5,559		)						(5,559		)
Dividends on Common Stock							(60,000		)						(60,000		)
Capital Contributions from Eversource Parent				300,000											300,000
Other Comprehensive Income											32				32
Balance as of December 31, 2018	6,035,205	60,352		2,410,765			1,727,899				301				4,199,317
Balance as of January 1, 2019																		Balance as of January 1, 2019		6,035,205				$	60,352		$	2,410,765		$	1,727,899		$	301		$	4,199,317
Net Income							410,852								410,852			Net Income											410,852						410,852
Dividends on Preferred Stock							(5,559		)						(5,559		)	Dividends on Preferred Stock											(5,559)						(5,559)
Dividends on Common Stock							(341,800		)						(341,800		)	Dividends on Common Stock											(341,800)						(341,800)
Capital Contributions from Eversource Parent				125,000											125,000			Capital Contributions from Eversource Parent								125,000									125,000
Other Comprehensive Income											15				15			Other Comprehensive Income														15			15
Balance as of December 31, 2019	6,035,205	$	60,352	$	2,535,765		$	1,791,392			$	316			$	4,387,825		Balance as of December 31, 2019		6,035,205				60,352		2,535,765			1,791,392			316			4,387,825
Net Income																		Net Income											457,934						457,934
Dividends on Preferred Stock																		Dividends on Preferred Stock											(5,559)						(5,559)
Dividends on Common Stock																		Dividends on Common Stock											(69,500)						(69,500)
Capital Contributions from Eversource Parent																		Capital Contributions from Eversource Parent								275,000									275,000
Adoption of Accounting Standards Update 2016-13																		Adoption of Accounting Standards Update 2016-13											(900)						(900)
Other Comprehensive Loss																		Other Comprehensive Loss														(14)			(14)
Balance as of December 31, 2020																		Balance as of December 31, 2020		6,035,205				60,352		2,810,765			2,173,367			302			5,044,786
Net Income																		Net Income											401,725						401,725
Dividends on Preferred Stock																		Dividends on Preferred Stock											(5,559)						(5,559)
Dividends on Common Stock																		Dividends on Common Stock											(341,400)						(341,400)
Capital Contributions from Eversource Parent																		Capital Contributions from Eversource Parent								200,000									200,000

Other Comprehensive Loss																		Other Comprehensive Loss														(51)			(51)
Balance as of December 31, 2021																		Balance as of December 31, 2021		6,035,205				$	60,352	$	3,010,765		$	2,228,133		$	251		$	5,299,501

Named Executive Officer
2018 - 2020
Performance Share Grant
2019 - 2021
Performance Share Grant
James J. Judge 48,912
46,249
Philip J. Lembo 10,682
10,103
Werner J. Schweiger 10,845
10,103
Gregory B. Butler 8,410
8,328
Joseph R. Nolan, Jr. 7,737
7,623

Results of the ~~2017 -~~ 2019 – 2021 Performance Share Program

The ~~2017 -~~ 2019 ~~Program, which used the same criteria used in the 2019 -~~– 2021 Program ~~described above,~~ was completed on December 31, ~~2019.~~2021. The actual performance level achieved under the Program was a three-year average adjusted EPS growth of ~~5.3~~5.9 percent and a three-year total shareholder return at the 87th percentile, which, when interpolated in accordance with the criteria established by the Committee, ~~in 2017~~ resulted in vesting performance share units at ~~150~~156 percent of target. 2019, 2020 and 2021 non-GAAP earnings per share, ~~which exclude the NPT impairment charge,~~as described in Exhibit A to this Item 11, were the basis for performance level ~~assessment.~~assessment determined by the Committee at its February 2020, 2021 and 2022 meetings. At its February ~~5, 2020~~2, 2022 meeting, the Committee confirmed that the actual results achieved were calculated in accordance with established performance criteria. The number of Performance Shares awarded to the Named Executive Officers were approved as set forth in the table below.



~~2017~~2019 – ~~2019~~2021 Long-Term Incentive Program Performance Share Awards
Named Executive Officer		Performance Share Award
~~James J. Judge~~		~~79,305~~
~~Philip J. Lembo~~	~~18,931~~
~~Werner J. Schweiger~~	~~19,232~~
~~Gregory B. Butler~~	~~14,875~~
Joseph R. Nolan, Jr.	~~13,015~~12,918
Philip J. Lembo		17,120
Werner J. Schweiger		17,120
Gregory B. Butler		14,112
Christine M. Carmody		11,399
James J. Judge		78,372

~~The 2020 - 2022 and 2021 - 2023 Performance Share Programs~~

The Compensation Committee determined that for the 2020 - 2022 Program adjustments to the measurement criteria would be put into place increasing the level of performance required to reach a target (100 percent) grant award and adding additional performance levels for which no award of shares would be made. The Committee also determined that the 2021 - 2023 Performance Share Program will change such that 75 percent of the long-term incentive opportunity will consist of Performance Shares and 25 percent will consist of RSUs.

Restricted Share Units (RSUs)

General

Each RSU granted under the long-term incentive program entitles the holder to receive one ~~Eversource~~ common share at the time of vesting. All RSUs granted under the long-term incentive program vest in equal annual installments over three years. RSU holders are eligible to receive reinvested dividend units on outstanding RSUs held by them to the same extent that dividends are declared and paid on Eversource common shares. Reinvested dividend equivalents are accounted for as additional RSUs that accrue and are distributed with the common shares issued upon vesting of the underlying RSUs. Common shares, including any additional common shares in respect of reinvested dividend equivalents, are not issued for any RSUs that do not vest.

The Committee determined RSU grants for each Eversource executive officer participating in the long-term incentive program. RSU grants are based on a percentage of annualized base salary at the time of the grant. In ~~2019,~~2021, the percentage used for each ~~executive officer~~Eversource Named Executive Officer was based on ~~the executive officer's~~their position in Eversource and ranged from 4045 percent to ~~238~~120 percent of base salary. The Committee reserves the right to increase or decrease the RSU grant from target for each executive officer under special circumstances. The Committee and all other independent members of the Eversource Board determined the RSU grants for ~~Eversource's~~its Chief Executive ~~Officer.~~Officer and the Executive Chairman. Based on input from ~~the~~Eversource’s Chief Executive Officer, the Committee determined the RSU grants for each of the other executive officers, including ~~the other~~Eversource’s Named Executive Officers.

All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from a percent of salary into ~~Eversource~~ common share equivalents by dividing the value of each grant by the average closing price for Eversource common shares over the ten trading days prior to the date of the grant. RSU grants at 100 percent of target were approved as set forth in the table below.


	RSUs Granted
Named Executive Officer	2019	2020	2021 (1)
Joseph R. Nolan, Jr.	7,623	7,616	3,944
Philip J. Lembo	10,103	8,635	4,472
Werner J. Schweiger	10,103	9,235	4,782
Gregory B. Butler	8,328	6,575	3,404
Christine M. Carmody (2)	—	—	2,749
James J. Judge	46,249	35,849	18,566

RSUs Granted
Named Executive Officer 2017 2018 2019
James J. Judge 48,259
48,912
46,249
Philip J. Lembo 11,520
10,682
10,103
Werner J. Schweiger 11,703
10,845
10,103
Gregory B. Butler 9,052
8,410
8,328
Joseph R. Nolan, Jr. 7,920
7,737
7,616
(1) Reflects change for 2021 to 75 percent Performance Shares/25 percent RSUs.

(2) Ms. Carmody was not a Named Executive Officer in 2019 or 2020.

Clawbacks

If ~~Eversource's~~Eversource’s earnings were to be restated as a result of noncompliance with accounting rules caused by fraud or misconduct, or if a plan participant engages in a willful material violation of ~~Eversource's~~the Eversource Code of Business Conduct or material corporate policy, or the breach of a material covenant in an employment agreement, as determined by the Eversource Board of Trustees, the participant will be required by ~~the Eversource~~Eversource’s 2018 Incentive Plan to reimburse Eversource for incentive compensation awards received by them for that year.

163

No Hedging and No Pledging Policy

Eversource has a long-standing policy prohibiting the purchase of any financial instruments or otherwise entering into transactions designed to have the effect of hedging or offsetting any decrease in the value of ~~Eversource~~its common shares or other ~~Eversource~~ equity securities of Eversource or its subsidiaries by ~~Eversource~~its Trustees and executives, including exchange-traded options to purchase or sell securities of Eversource ~~securities~~ (so-called ~~"puts"~~“puts” and ~~"calls"~~“calls”) or financial instruments that are designed to hedge or offset any decrease in the market value of securities of Eversource ~~securities~~ (including, but not limited to, prepaid variable forward contracts, equity swaps, collars and exchange funds). This policy also prohibits short sales, the holding of any Eversource common shares in a margin account, borrowing shares, selling future securities that establish a position that increases in value as the value of ~~Eversource common shares~~Eversource’s stock decreases, or pledging ~~Eversource's~~Eversource’s common shares. The policy applies to Trustees and executives but not to non-executives and does not apply to broad-based index funds or similar transactions.

Share Ownership Guidelines and Retention Requirements

The Committee has approved share ownership guidelines to further emphasize the importance of share ownership by Eversource officers. As indicated in the table below, the guidelines call for ~~Eversource's~~Eversource’s Chief Executive Officer and the Executive Chairman to own common shares equal to six times base salary, executive vice presidents to own a number of common shares equal to three times base salary, senior vice presidents to own common shares equal to two times base salary, and all other officers to own a number of common shares equal to one to one and ~~one half~~one-half times base salary. Officers and Eversource Trustees may only transact in Eversource Energy common shares during approved trading windows and are subject to continuing compliance with these share ownership guidelines.



Executive Officer			Base Salary Multiple
Chief Executive ~~Officer~~Officer/Executive Chairman			6
Executive Vice Presidents			3
Operating Company Presidents / Senior Vice Presidents			2
Vice Presidents			1 – 1.5

Eversource requires that its officers attain these ownership levels within five ~~years.~~years after promotion. All ~~Eversource~~of Eversource’s officers, including ~~Eversource's~~Eversource’s Named Executive Officers, have either satisfied ~~the~~these share ownership guidelines or are expected to satisfy them within the applicable timeframe. Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs satisfy the ~~guideline requirements to hold 100 percent of the net shares.~~ownership requirements. Unvested performance shares do not count toward satisfying the ownership guidelines. In addition to ~~the~~these share ownership guidelines noted above, all Eversource officers must hold ~~all~~ the net shares awarded under ~~Eversource's~~Eversource’s incentive compensation plan until the share ownership guidelines have been met.

Other Benefits

Retirement Benefits

Eversource provides a qualified defined benefit pension program for certain officers, which is a final average pay program subject to tax code limits. Because of such limits, Eversource also ~~maintain~~maintains a supplemental non-qualified pension program. Benefits are based on base salary and certain incentive payments, which is consistent with the goal of providing a retirement benefit that replaces a percentage of pre-retirement income. The supplemental program compensates for benefits barred by tax code limits, and generally provides (together with the qualified pension program) benefits equal to approximately 60 percent of pre-retirement compensation (subject to certain reductions) for Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan,~~Judge and Ms. Carmody, and approximately 50 percent of such compensation for Mr. Butler. The supplemental program ~~has been~~was discontinued in 2012 for ~~newly-elected~~newly elected officers.

For certain participants, the benefits payable under the Supplemental Non-Qualified Pension Program differ from those described above. The program benefit payable to Mr. Schweiger is fully vested and is further reduced by benefits he is entitled to receive under previous ~~employers'~~employers’ retirement plans.

Also see the narrative accompanying the ~~"Pension Benefits"~~“Pension Benefits” table and accompanying notes for more detail on the above program.

~~Mr. Judge's Pension Benefit~~

As an employee for more than 40 years, Mr. Judge's employee benefits include a pension benefit. Mr. Judge was elected to the position of President and Chief Executive Officer in 2016, such that 2017 was the first year that he served in his new position at the higher CEO compensation level. Since then there have been substantial increases over the past three years in the actuarial, formula-based present values of his pension benefit. These increases are disclosed in the Change in Pension Value and Non-Qualified Deferred Earnings column of the Summary Compensation Table. The methodology that is used to calculate the change in pension value is based upon applicable accounting rules and is influenced up or down by external values, such as assumptions regarding life expectancy and changes in the discount rate determined each year. These variables are functions of factors that do not relate to Eversource and executive performance, are outside the control of the Committee, and may or may not impact the amounts that will actually be paid, as such variables and assumptions may change from time to time. The calculation of Pension Value is very sensitive to interest rate levels. Recent very low interest rates have resulted in a very low discount rate and is a major reason for the large increase in Mr. Judge's Change in Pension Value. The accounting-based increase for Mr. Judge, while

representing a substantial portion of his 2017, 2018 and 2019 total compensation disclosed in the SEC Total column of the Summary Compensation Table, resulted in no actual 2017 to 2019 W-2 earnings for him.

401(k) Benefits

Eversource offers a qualified 401(k) program for all employees, including executives, subject to tax code limits. After applying these limits, the program provides a match of 50 percent of the first 8eight percent of eligible base salary, up to a maximum of ~~$11,200~~$11,600 per year for Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan.~~Judge and Ms. Carmody. For Mr. Butler, the program provides a match of 100 percent of the first 3three percent of eligible base salary, up to a maximum of ~~$8,400~~$8,770 per year.

164

Deferred Compensation

Eversource offers a non-qualified deferred compensation program for its executives. In ~~2019,~~2021, the program allowed deferral of up to 100 percent of base salary, annual incentives and long-term incentive awards. The program allows participants to select investment measures for deferrals based on an array of deemed investment options (including certain mutual funds and publicly traded securities).

See the Non-Qualified Deferred Compensation Table and accompanying notes for additional details on the above program.

Perquisites

Eversource provides executives with limited financial planning benefits, vehicle leasing and access to tickets to sporting events. The current level of perquisites does not factor into decisions on total compensation.

Contractual Agreements

Eversource currently maintains contractual agreements with all of its Named Executive Officers that provide for potential compensation in the event of certain terminations, including termination following a Change in Control. ~~Eversource believes these~~These agreements ~~are necessary~~were made to attract and retain high quality executives and to ensure executive focus on ~~Eversource~~Eversource’s business during the period leading up to a potential Change in ~~Control.~~Control, though Eversource has not entered into a Change in Control or employment agreement with any executive since 2010. The agreements are ~~"double-trigger"~~“double-trigger” agreements that provide executives with compensation in the event of a Change in Control followed by termination of employment due to one or more of the events set forth in the agreements, while still providing an incentive to remain employed with Eversource for the transition period that follows.

Under the agreements, certain compensation is generally payable if, during the applicable change in control period, the executive is involuntarily terminated (other than for cause) or terminates employment for ~~"good~~“good reason."” These agreements are described more fully in the ~~tables~~Tables following this CD&A under ~~"Payments~~“Payments Upon Termination.~~" Eversource has not entered into a Change in Control agreement with any executive since 2010.~~”

Tax and Accounting Considerations

Section 162(m) of the Internal Revenue Code precludes a public ~~corporation~~company from taking an income tax deduction in any one year for compensation in excess of $1 million payable to its ~~Named Executive Officers~~named executive officers who are employed on the last day of the fiscal year, unless certain specific performance goals are satisfied. Until January 1, 2018, there was an exception to the $1 million limitation for performance-based compensation meeting certain requirements. This exception was repealed, effective for taxable years beginning after December 31, 2017 and the limitation on deductibility generally was expanded to include all Named Executive Officers. As a result, compensation paid to the Named Executive Officers in excess of $1 million per officer will not be deductible unless it qualifies for transition relief applicable to certain arrangements in place as of and not modified after November 2, 2017.

The Committee believes that the availability of a tax deduction for forms of compensation should be one of many factors taken into consideration of providing market-based compensation to attract and retain highly qualified executives. The Committee believes it is in ~~Eversource's~~Eversource’s best interests to retain discretion to make compensation awards, whether or not deductible.

Eversource has adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 718, Compensation-Stock ~~Compensation~~.Compensation. In general, Eversource and the Committee do not consider accounting considerations in structuring compensation arrangements.

Equity Grant Practices

Equity awards noted in the compensation tables are made annually at the February meeting of the Compensation Committee (subject to further approval by all of the independent members of ~~Eversource's~~the Eversource Board of Trustees of ~~Eversource's~~its Chief Executive ~~Officer's award)~~Officer’s and its Executive Chairman’s awards) when the Committee also determines base salary, annual incentive opportunities, long-term incentive compensation ~~targets,~~grants, and annual and long-term performance plan awards. The date of this meeting is chosen at least a year in advance, and therefore awards are not coordinated with the release of material non-public information.

165

SUMMARY COMPENSATION TABLE

The table below summarizes the total compensation paid or earned by CL~~&P's~~&P’s principal executive officer (Mr. ~~Judge)~~Nolan), CL&P’s principal financial officer (Mr. Lembo) ~~and~~, the three other most highly compensated executive officers in ~~2019,~~2021, and Mr. Judge, who served as Chief Executive Officer of Eversource Energy and Chairman of the Board of CL&P during a portion of 2021, determined in accordance with the applicable SEC disclosure rules (collectively, the Named Executive Officers). As explained in the tables and footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on their behalf ~~of the Named Executive Officers~~ for the fiscal year ended December 31, ~~2019~~2021 in accordance with such rules. All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Executive Officer were paid for all services rendered to ~~Eversource Energy~~the Company and its subsidiaries, including CL&P, in all capacities.

Name and
Principal Position
Year Salary
Stock
Awards ⁽¹⁾

Non-Equity
Incentive Plan ⁽²⁾

Change in
Pension Value
and Non-
Qualified Deferred Earnings ⁽³⁾

All Other
Compen-
sation ⁽⁴⁾
SEC Total
Adjusted
SEC Total ⁽⁵⁾
James J. Judge 2019 $ 1,319,232
$ 6,676,043
$ 3,000,000
$ 8,784,256
$ 26,557
$ 19,806,088
$ 11,021,832
Chairman, President and Chief Executive Officer of Eversource Energy; Chairman of CL&P 2018 1,277,078
5,632,217
2,430,000
5,560,877
25,209
14,925,381
9,364,504
2017 1,230,694
5,504,904
2,285,000
6,869,854
25,009
15,915,461
9,045,607
Philip J. Lembo 2019 680,579
1,458,368
1,000,000
1,318,800
20,390
4,478,137
3,159,337
Executive Vice President and Chief Financial Officer of Eversource Energy and CL&P 2018 648,271
1,230,032
765,000
1,535,216
21,685
4,200,204
2,664,988
2017 613,847
1,314,086
700,000
1,246,325
21,485
3,895,743
2,649,418
Werner J. Schweiger 2019 692,694
1,458,368
1,050,000
2,218,536
21,846
5,441,444
3,222,908
Executive Vice President and Chief Operating Officer of Eversource Energy and CL&P 2018 658,271
1,248,802
815,000
538,978
53,896
3,314,947
2,775,969
2017 634,078
1,334,961
775,000
1,225,581
21,418
3,991,038
2,765,457
Gregory B. Butler 2019 643,270
1,202,147
740,000
2,948,208
15,518
5,549,143
2,600,935
Executive Vice President and General Counsel of Eversource Energy and CL&P 2018 618,271
968,412
645,000
634,394
15,143
2,881,220
2,246,826
2017 597,886
1,032,562
625,000
1,670,745
15,361
3,941,554
2,270,809
Joseph R. Nolan, Jr. 2019 589,616
1,100,380
774,000
3,283,296
20,388
5,767,680
2,484,384
Executive Vice President-Strategy, Customer and Corporate Relations of Eversource Energy and Eversource Service 2018 561,540
890,916
720,000
1,193,350
56,084
3,421,890
2,228,540
2017 515,578
903,434
680,000
1,486,025
16,076
3,601,113
2,115,088


~~(1)~~	~~Reflects the aggregate grant date fair value of restricted share units (RSUs) and performance shares granted in each fiscal year, calculated in accordance with FASB ASC Topic 718.~~


Name and Principal Position	Year	Salary		Stock Awards (4)		Non-Equity Incentive Plan (5)		Change in Pension Value and Non- Qualified Deferred Earnings (6)		All Other Compen- sation (7)		SEC Total		Adjusted SEC Total (8)
Joseph R. Nolan, Jr. (1)	2021	$	1,004,424	$	1,441,650	$	2,250,000	$	1,705,782	$	65,222	$	6,467,078	$	4,761,296
President and Chief Executive Officer of Eversource Energy; Chairman of CL&P	2020	630,962		1,419,699		850,000		2,134,658		18,921		5,054,240		2,919,582
	2019	589,616		1,100,380		774,000		3,283,296		20,388		5,767,680		2,484,384
Philip J. Lembo	2021	720,001		1,634,650		1,050,000		713,766		20,685		4,139,102		3,425,336
Executive Vice President and Chief Financial Officer of Eversource Energy and CL&P	2020	718,846		1,609,650		950,000		1,248,852		21,985		4,549,333		3,300,481
	2019	680,579		1,458,368		1,000,000		1,318,800		20,390		4,478,137		3,159,337
Werner J. Schweiger	2021	770,001		1,748,151		1,000,000		852,718		19,989		4,390,859		3,538,141
Executive Vice President and Chief Operating Officer of Eversource Energy and Chief Executive Officer of CL&P	2020	765,885		1,721,496		950,000		2,698,083		20,657		6,156,121		3,458,038
	2019	692,694		1,458,368		1,050,000		2,218,536		21,846		5,441,444		3,222,908
Gregory B. Butler	2021	670,002		1,244,544		700,000		465,628		11,656		3,091,830		2,626,202
Executive Vice President and General Counsel of Eversource Energy and CL&P	2020	670,292		1,225,646		700,000		1,637,907		15,839		4,249,684		2,611,777
	2019	643,270		1,202,147		740,000		2,948,208		15,518		5,549,143		2,600,935
Christine M. Carmody (2)	2021	541,001		1,005,122		650,000		645,323		19,983		2,861,429		2,216,106
Executive Vice President-Human Resources and Info Technology of Eversource Energy	2020	—		—		—		—		—		—		—
	2019	—		—		—		—		—		—		—
James J. Judge (3)	2021	1,128,078		6,786,337		2,246,000		—		60,526		10,220,941		10,220,941
Executive Chairman of Eversource Energy	2020	1,371,615		6,682,612		2,750,000		3,742,215		28,834		14,575,276		10,833,061
	2019	1,319,232		6,676,043		3,000,000		8,784,256		26,557		19,806,088		11,021,832

(1) Mr. Nolan was elected President and Chief Executive Officer of Eversource Energy on April 7, 2021, effective as of the May 5, 2021 Eversource Board of Trustees meeting. He has served as Chairman of the Board and a director of CL&P since May 5, 2021. Mr. Nolan previously served as Executive Vice President – Strategy, Customer and Corporate Relations of Eversource Energy.

(2) Ms. Carmody was not a Named Executive Officer in 2019 and 2020.

(3) Mr. Judge transitioned to Executive Chairman of the Board of Eversource Energy effective as of the May 5, 2021 Eversource Board of Trustees meeting. He previously served as President and Chief Executive Officer of Eversource Energy and Chairman of the Board of CL&P.

(4) RSUs were granted to each Named Executive Officer in ~~2019~~2021 as long-term compensation, which vest in equal annual installments over three years. ~~In 2019, each~~Each of the Named Executive Officers was also granted performance shares as long-term incentive compensation. These performance shares will vest based on the extent to which the ~~two~~ performance conditions described in the CD&A are achieved as of December 31, ~~2021.~~2023. The grant date fair values for the performance shares, assuming achievement of the highest level of both performance conditions, are as follows: Mr. ~~Judge: $5,080,453;~~Nolan: $1,609,034; Mr. Lembo: ~~$1,109,815;~~$1,824,442; Mr. Schweiger: ~~$1,109,815;~~$1,915,185; Mr. Butler: ~~$914,831;~~$1,389,138; Ms. Carmody: $1,121,918 and Mr. ~~Nolan: $837,387.~~Judge: $7,574,235.

Holders of RSUs and performance shares are eligible to receive dividend equivalent units on outstanding awards to the same extent that dividends are declared and paid on Eversource common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with those common shares that are issued upon vesting of the underlying RSUs and performance shares. No dividends are paid unless and until the underlying shares vest.


~~(2)~~	Includes payments to the Named Executive Officers under the 2019 Annual Incentive Program: Mr. Judge: $3,000,000; Mr. Lembo: $1,000,000; Mr. Schweiger: $1,050,000; Mr. Butler: $740,000; and Mr. Nolan: $774,000.

~~(3)~~

Includes the actuarial increase in the present value from December 31, 2018 to December 31, 2019 of the Named Executive Officers' accumulated benefits under all of the defined benefit pension programs and agreements, determined using interest rate and mortality rate assumptions consistent with those appearing in the footnotes to the Annual Report on Form 10-K for the fiscal year ended December 31, 2019. The Named Executive Officer may not be fully vested in such amounts. More information on this topic is set forth in the Pension Benefits table. There were no above-market earnings in deferred compensation value during 2019, as the terms of the Deferred Compensation Plan provide for market-based investments, including Eversource common shares. Mr. Judge was elected to the position of President and Chief Executive Officer of Eversource Energy in 2016, such that 2017 was the first year that he served in his more highly compensated position. This has resulted in substantial increases in the actuarial present value of his pension benefits. These accounting-based increases, while representing for Mr. Judge a substantial portion of his 2017 - 2019 total compensation disclosed in the SEC Total above, resulted in no actual W-2 earnings for him for these years.

~~(4)~~

Includes matching contributions allocated by Eversource to the accounts of Named Executive Officers under the 401k Plan as follows: $11,200 for each of Messrs. Judge, Lembo and Schweiger and Nolan, and $8,400 for Mr. Butler. For Mr. Judge, the value shown includes financial planning services valued at $5,000 and $10,357paid by Eversource for a company-leased vehicle. For Mr. Schweiger, the value shown includes financial planning services valued at $5,000 and $5,646 paid by Eversource representing the value in 2019 of a company-owned vehicle provided to Mr. Schweiger. None of the other Named Executive Officers received perquisites valued in the aggregate in excess of $10,000.

(5) Includes payments to the Named Executive Officers under the 2021 Annual Incentive Program: Mr. Nolan: $2,250,000; Mr. Lembo: $1,050,000; Mr. Schweiger: $1,000,000; Mr. Butler: $700,000; Ms. Carmody: $650,000 and Mr. Judge: $2,246,000.

~~(5)~~

The amounts in the Adjusted SEC Total column reflect an adjustment to the total compensation reported in the column marked SEC Total. The Adjusted SEC Total subtracts the actuarial change in pension value disclosed in the column titled "Change in Pension Value and Non-Qualified Deferred Earnings" as further described in footnote 4 above in order to reflect compensation earned during the year by the executive without consideration of pension benefit impacts. The amounts in this column differ substantially from, and are not a substitute for, the amounts noted in the SEC Total.

(6) Includes the actuarial increase in the present value from December 31, 2020 to December 31, 2021 of the Named Executive Officers’ accumulated benefits under all of our defined benefit pension programs and agreements, determined using interest rate and mortality rate assumptions consistent with those appearing in the footnotes to our Annual Report on Form 10-K for the fiscal year ended December 31, 2021. The Named Executive Officer may not be fully vested in such amounts. More information on this topic is set forth in the Pension Benefits table. There were no above-market earnings in deferred

166

compensation value during 2021, as the terms of the Deferred Compensation Plan provide for market-based investments, including Eversource common shares.

(7) Includes matching contributions allocated by us to the accounts of Named Executive Officers under the 401k Plan as follows: $11,600 for each of Messrs. Nolan, Lembo, Schweiger, and Judge and Ms. Carmody, and $8,700 for Mr. Butler. For Mr. Nolan, the value shown includes financial planning services valued at $5,500, $4,085, representing the value in 2021 of a company-owned vehicle provided to Mr. Nolan, and $44,036 for home security systems provided in accordance with Eversource’s security protocols. For Mr. Judge, the value shown includes financial planning services valued at $5,500, $7,982, representing the value in 2021 of a company-owned vehicle provided to Mr. Judge, and $35,444 for the installation of home wi-fi and related equipment in accordance with the Eversource’s cybersecurity protocols. None of the other Named Executive Officers received perquisites valued in the aggregate in excess of $10,000.

(8) The amounts in the Adjusted SEC Total column reflect an adjustment to the total compensation reported in the column marked SEC Total. The Adjusted SEC Total subtracts the actuarial change in pension value disclosed in the column titled “Change in Pension Value and Non-Qualified Deferred Earnings” as further described in footnote 6 above in order to reflect compensation earned during the year by the executive without consideration of pension benefit impacts. The amounts in this column differ substantially from, and are not a substitute for, the amounts noted in the SEC Total.

GRANTS OF PLAN-BASED AWARDS DURING ~~2019~~

2021

The Grants of Plan-Based Awards ~~table~~Table below provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, ~~2019.~~2021. The table also discloses the underlying equity awards and the grant date for equity-based awards. Eversource has not granted any stock options since 2002.


														All Other Stock Awards: Number of Shares of Stock or Units (#) (2)		Grant Date Fair Value of Stock and Option Awards ($) (3)
		Estimated Future Payouts Under Non-Equity Incentive Plan Awards						Estimated Future Payouts Under Equity Incentive Plan Awards (1)
	Grant Date	Threshold ($)		Target ($)		Maximum ($)		Threshold ($)		Target (#)		Maximum (#)
Name
Joseph R. Nolan, Jr.
Annual Incentive (4)	2/8/21	$	660,000	$	1,320,000	$	2,640,000	$	—	$	—	$	—	$	—	$	—
Long-Term Incentive (5)	2/8/21	—		—		—		—		11,832		23,664		3,944		1,441,650
Philip J. Lembo
Annual Incentive (4)	2/8/21	288,000		576,000		1,152,000		—		—		—		—		—
Long-Term Incentive (5)	2/8/21	—		—		—		—		13,416		26,832		4,472		1,634,650
Werner J. Schweiger
Annual Incentive (4)	2/8/21	308,000		616,000		1,232,000		—		—		—		—		—
Long-Term Incentive (5)	2/8/21	—		—		—		—		14,348		28,696		4,782		1,748,151
Gregory B. Butler
Annual Incentive (4)	2/8/21	234,500		469,000		938,000		—		—		—		—		—
Long-Term Incentive (5)	2/8/21	—		—		—		—		10,215		20,430		3,404		1,244,544
Christine M. Carmody
Annual Incentive (4)	2/8/21	189,500		379,000		758,000		—		—		—		—		—
Long-Term Incentive (5)	2/8/21	—		—		—		—		8,250		16,500		2,749		1,005,122
James J. Judge
Annual Incentive (4)	2/8/21	702,000		1,404,000		2,808,000		—		—		—		—		—
Long-Term Incentive (5)	2/8/21	—		—		—		—		55,697		111,394		18,566		6,786,337

(1) Reflects the number of performance shares granted to each of the Named Executive Officers on February 8, 2021 under the 2021 – 2023 Long-Term Incentive Program. Performance shares were granted subject to a three-year Performance Period that ends on December 31, 2023. At the end of the Performance Period, Eversource common shares will be awarded based on actual performance results as a percentage of target, subject to reduction for applicable payroll withholding taxes. Holders of performance shares are eligible to receive dividend equivalent units on outstanding performance shares awarded to them to the same extent that dividends are declared and paid on our common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the number of common shares underlying the performance shares that are actually awarded. No dividends are paid unless and until the underlying shares vest. The Annual Incentive Program did not include an equity component.

(2) Reflects the number of RSUs granted to each of the Named Executive Officers on February 8, 2021 under the 2021 – 2023 Long-Term Incentive Program. RSUs vest in equal installments on February 8, 2022, 2023 and 2024. Eversource common shares are distributed with respect to vested RSUs on a one-for-one basis following vesting, after reduction for applicable payroll withholding taxes. Holders of RSUs are eligible to receive dividend equivalent units on outstanding RSUs awarded to them to the same extent that dividends are declared and paid on our common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with those common shares actually distributed in respect of the underlying RSUs. No dividends are paid unless and until the underlying shares vest.

(3) Reflects the grant date fair value, determined in accordance with FASB ASC Topic 718, of RSUs and performance shares granted to the Named Executive Officers on February 8, 2021 under the 2021 – 2023 Long-Term Incentive Program.

(4) The threshold payment under the Annual Incentive Program is 50 percent of target. The actual payments in 2021 for performance in 2021 are set forth in the Non-Equity Incentive Plan column of the Summary Compensation Table.

167

All Other
Stock Awards:
Number of
Shares
of Stock
or Units
(#) ⁽²⁾
Grant
Date Fair
Value of
Stock and
Option Awards
($) ⁽³⁾

Estimated Future Payouts Under
Non-Equity Incentive Plan Awards

Estimated Future Payouts Under
Equity Incentive Plan Awards ⁽¹⁾
Grant Date
Threshold
($)
Target
($)
Maximum
($)

Threshold
($)
Target
(#)
Maximum
(#)
Name
James J. Judge
Annual Incentive⁽⁴⁾
02/06/19 $ 798,000
$ 1,596,000
$ 3,192,000
$ —
—
—
—
$ —
Long-Term Incentive⁽⁵⁾
02/06/19 —
—
—
—
46,249
92,498
46,249
6,676,043
Philip J. Lembo
Annual Incentive ⁽⁴⁾
02/06/19 259,000
518,000
1,036,000
—
—
—
—
—
Long-Term Incentive ⁽⁵⁾
02/06/19 —
—
—
—
10,103
20,206
10,103
1,458,368
Werner J. Schweiger
Annual Incentive ⁽⁴⁾
02/06/19 272,000
544,000
1,088,000
—
—
—
—
—
Long-Term Incentive ⁽⁵⁾
02/06/19 —
—
—
—
10,103
20,206
10,103
1,458,368
Gregory B. Butler
Annual Incentive ⁽⁴⁾
02/06/19 211,500
423,000
846,000
—
—
—
—
—
Long-Term Incentive⁽⁵⁾
02/06/19 —
—
—
—
8,328
16,656
8,328
1,202,147
Joseph R. Nolan, Jr.
Annual Incentive ⁽⁴⁾
02/06/19 193,500
387,000
774,000
—
—
—
—
—
Long-Term Incentive⁽⁵⁾
02/06/19 —
—
—
—
7,623
15,246
7,623
1,100,380

~~(1)~~

Reflects the number of performance shares granted to each of the Named Executive Officers on February 6, 2019 under the 2019 - 2021 Long-Term Incentive Program. Performance shares were granted subject to a three-year Performance Period that ends on December 31, 2021. At the end of the Performance Period, Eversource common shares will be awarded based on actual performance results as a percentage of target, subject to reduction for applicable payroll withholding taxes. Holders of performance shares are eligible to receive dividend equivalent units on outstanding performance shares awarded to them to the same extent that dividends are declared and paid on Eversource common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the number of common shares underlying the performance shares that are actually awarded. The Annual Incentive Program did not include an equity component.

~~(2)~~

Reflects the number of RSUs granted to each of the Named Executive Officers on February 6, 2019 under the 2019 - 2021 Long-Term Incentive Program. RSUs vest in equal installments on February 6, 2020, 2021 and 2022. Eversource common shares will be distributed with respect to vested RSUs on a one-for-one basis following vesting, after reduction for applicable payroll withholding taxes. Holders of RSUs are eligible to receive dividend equivalent units on outstanding RSUs awarded to them to the same extent that dividends are declared and paid on Eversource common shares. Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with those common shares actually distributed in respect of the underlying RSUs.


~~(3)~~	Reflects the grant date fair value, determined in accordance with FASB ASC Topic 718, of RSUs and performance shares granted to the Named Executive Officers on February 6, 2019 under the 2019 - 2021 Long-Term Incentive Program.


~~(4)~~	The threshold payment under the Annual Incentive Program is 50% of target. The actual payments in 2020 for performance in 2019 are set forth in the Non-Equity Incentive Plan column of the Summary Compensation Table.


~~(5)~~	~~Reflects the range of potential payouts, if any, pursuant to performance share awards under the 2019 - 2021 Long-Term Incentive Program, as described in the CD&A.~~

(5) Reflects the range of potential payouts, if any, pursuant to performance share awards under the 2021 – 2023 Long-Term Incentive Program, as described in the CD&A.

OUTSTANDING EQUITY GRANTS AT DECEMBER 31, ~~2019~~2021

The following table sets forth RSU and performance share grants outstanding at the end of the fiscal year ended December 31, ~~2019~~2021 for each of the Named Executive Officers. There are no outstanding options.


	Stock Awards (1)
	Number of Shares or Units of Stock That Have Not Vested (#) (2)	Market Value of Shares or Units of Stock That Have Not Vested ($) (3)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (4)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (5)
Name
Joseph R. Nolan, Jr.	12,186	$	28,505	139,057	$	2,593,391
Philip J. Lembo	14,346	1,305,186		33,906	3,084,761
Werner J. Schweiger	15,088	1,372,677		35,499	3,229,707
Gregory B. Butler	11,152	1,014,649		26,507	2,411,585
Christine M. Carmody	9,007	819,483		21,409	1,947,763
James J. Judge	61,116	5,560,302		145,440	13,232,101

Stock Awards ⁽¹⁾

Number of Shares or
Units of Stock That
Have Not Vested
(#)⁽²⁾
Market Value of Shares or
Units of Stock That
Have Not Vested
($) ⁽³⁾
Equity Incentive
Plan Awards:
Number of Unearned
Shares, Units or Other Rights That Have Not
Vested
(#) ⁽⁴⁾
Equity Incentive
Plan Awards:
Market or Payout Value of
Unearned Shares, Units or
Other Rights That Have Not Vested
($)⁽⁵⁾
Name
James J. Judge 99,770
$ 8,487,360
152,329
$ 12,958,613
Philip J. Lembo 22,150
1,884,309
34,344
2,921,677
Werner J. Schweiger 22,332
1,899,750
34,718
2,953,457
Gregory B. Butler 17,817
1,515,696
27,404
2,331,273
Joseph R. Nolan, Jr. 16,202
1,378,286
24,725
2,103,355

(1) Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.


~~(1)~~	~~Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.~~

(2) A total of 71,079 unvested RSUs vested on February 15, 2022 (Mr. Nolan: 6,796; Lembo: 8,234; Mr. Schweiger: 8,553; Mr. Butler: 6,500; Ms. Carmody: 5,249; and Mr. Judge: 35,747). A total of 38,809 unvested RSUs will vest on February 15, 2023 (Mr. Nolan: 4,037; Mr. Lembo: 4,578, Mr. Schweiger: 4,895; Mr. Butler: 3,485, Ms. Carmody: 2,813; and Mr. Judge: 19,001). A total of 13,005 unvested RSUs will vest on February 15, 2023 (Mr. Nolan: 1,353; Mr. Lembo: 1,534; Mr. Schweiger: 1,640; Mr. Butler: 1,168; Ms. Carmody: 943 and Mr. Judge: 6,367).

~~(2)~~

A total of 91,173 unvested RSUs will vest on February 6, 2020 (Mr. Judge: 50,777; Mr. Lembo: 11,447; Mr. Schweiger: 11,572; Mr. Butler: 9,135; and Mr. Nolan: 8,242). A total of 58,874 unvested RSUs will vest on February 8, 2021 (Mr. Judge: 33,153; Mr. Lembo: 7,242, Mr. Schweiger: 7,299; Mr. Butler: 5,830; and Mr. Nolan: 5,350). A total of 28,223 unvested RSUs will vest on February 7, 2022 (Mr. Judge: 15,840; Mr. Lembo: 3,460; Mr. Schweiger: 3,460; Mr. Butler: 2,852; and Mr. Nolan: 2,611).

(3) The market value of RSUs is determined by multiplying the number of RSUs by $90.98, the closing price of Eversource Energy common shares on December 31, 2021, the last trading day of the year.


~~(3)~~	~~The market value of RSUs is determined by multiplying the number of RSUs by $85.07, the closing price of Eversource Energy common shares on December 31, 2019, the last trading day of the year.~~

(4) Reflects the target payout level for performance shares granted under the 2019 – 2021 Program, the 2020 – 2022 Program and the 2021 – 2023 Program.


~~(4)~~	~~Reflects the target payout level for performance shares granted under the 2017 - 2019 Program, the 2018 - 2020 Program and the 2019 - 2021 Program.~~

The performance period for the ~~2017 -~~ 2019 – 2021 Program ended on December 31, ~~2019.~~2021. Awards under that program are set forth in the CD&A under the ~~"Results~~“Results of the ~~2017 -~~ 2019 – 2021 Performance Share Program."”

The performance share ~~award~~awards for ~~2018 -~~ 2020 – 2022 Program and the ~~2019 -~~ 2021 – 2023 Program will be based on actual performance results as a percentage of target, subject to reduction for applicable payroll withholding taxes. As described more fully under ~~"Performance Shares"~~“Performance Shares” in the CD&A and footnote (1) to the Grants of Plan-Based Awards table, performance shares will vest following a three-year performance period based on the extent to which the two performance conditions are achieved. Under the ~~2018 -~~ 2020 – 2022 Program, a total of 91,949 unearned performance shares (including accrued dividend equivalents) will vest based on the extent to which the two performance conditions described in the CD&A are achieved as of December 31, 2020, assuming achievement of these conditions at a target level of performance: Mr. Judge: 51,941; Mr. Lembo: 11,344; Mr. Schweiger: 11,517; Mr. Butler: 8,931; and Mr. Nolan: 8,216. Under the 2019 - 2021 Program, a total of 84,666 unearned77,413 performance shares (including accrued dividend equivalents) will vest based on the extent to which the two performance conditions described in the CD&A are achieved as of December 31, 2021. Assuming achievement of these conditions at a target level of performance, the amount of the awards would be as follows: Mr. ~~Judge: 47,518;~~Nolan: 8,052; Mr. Lembo: ~~10,380;~~9,129; Mr. Schweiger: ~~10,380;~~9,764, Mr. Butler: ~~8,556;~~6,952; Ms. Carmody: 5,614 and Mr. Judge: 37,902. Under the 2021 – 2023 Program, a total of 117,030 performance shares (including accrued dividend equivalents) will vest based on the extent to which the two performance conditions described in the CD&A are achieved as of December 31, 2023. Assuming achievement of these conditions at a target level of performance, the amount of the awards would be as follows: Mr. Nolan: ~~7,832.~~12,172; Mr. Lembo: 13,802; Mr. Schweiger: 14,761; Mr. Butler: 10,509; Ms. Carmody: 8,487; and Mr. Butler: 10,509. No dividends are paid unless and until the underlying shares vest.


~~(5)~~	The market value is determined by multiplying the number of performance shares in the adjacent column by $85.07, the closing price of Eversource Energy common shares on December 31, 2019, the last trading day of the year.

(5) The market value is determined by multiplying the number of performance shares in the adjacent column by $90.98, the closing price of Eversource Energy common shares on December 31, 2021, the last trading day of the year.

168

OPTION EXERCISES AND STOCK VESTED IN ~~2019~~2021

The following table reports amounts realized on equity compensation during the fiscal year ended December 31, ~~2019.~~2021. The Stock Awards columns report the vesting of RSU and performance share grants to the Named Executive Officers in ~~2019.~~2021. There were no options exercised as Eversource has not granted options since 2002.


	Stock Awards
	Number of Shares Acquired on Vesting (#) (1)	Value Realized on Vesting (2)
Name
Joseph R. Nolan, Jr.	21,278	$	1,746,677
Philip J. Lembo	28,587	2,344,154
Werner J. Schweiger	29,129	2,388,932
Gregory B. Butler	23,370	1,919,091
Christine M. Carmody	18,366	1,506,058
James J. Judge	129,625	10,625,440

Stock Awards

Number of Shares Acquired on Vesting (#) ⁽¹⁾
Value Realized
on Vesting ⁽²⁾
Name
James J. Judge 50,820
$ 3,564,592
Philip J. Lembo 10,359
726,490
Werner J. Schweiger 24,432
1,714,758
Gregory B. Butler 17,028
1,195,032
Joseph R. Nolan, Jr. 11,866
832,598


~~(1)~~	(1) Includes RSUs and performance shares granted to the Named Executive Officers under the long-term incentive programs, including dividend reinvestment, as follows:


Name	2018 Program	2019 Program	2020 Program
Joseph R. Nolan, Jr.	15,987	2,683	2,608
Philip J. Lembo	22,073	3,556	2,958
Werner J. Schweiger	22,409	3,556	3,163
Gregory B. Butler	17,378	2,931	3,060
Christine M. Carmody	14,180	2,367	1,819
James J. Judge	101,067	16,278	12,280

Name 2016 Program 2017 Program 2018 Program 2019 Program
James J. Judge 16,816
17,152
16,852
—
Philip J. Lembo 2,584
4,095
3,680
—
Werner J. Schweiger 16,536
4,160
3,736
—
Gregory B. Butler 10,914
3,217
2,897
—
Joseph R. Nolan, Jr. 6,308
2,892
2,666
—

In all cases, the distribution of common shares isare reduced by that number of shares valued in an amount sufficient to satisfy payroll tax withholding obligations.

~~(2)~~

Values realized on vesting of RSUs granted under the 2016 - 2018, 2017 - 2019 and 2018 - 2020 Programs were based on $70.10 per share, the closing price of Eversource Energy common shares on February 14, 2019. Values realized on vesting of performance shares granted under the 2016 - 2018 Program were based on $70.27 per share, the closing price of Eversource Energy common shares on February 20, 2019.

(2) Values realized on vesting of RSUs granted under the 2018 – 2020, 2019 – 2021 and 2020 – 2022 Programs were based on $85.17 per share, the closing price of Eversource Energy common shares on February 12, 2021. Values realized on vesting of performance shares granted under the 2018 – 2020 Program were based on $80.19 per share, the closing price of Eversource Energy common shares on February 23, 2021.

PENSION BENEFITS IN ~~2019~~2021

The Pension Benefits Table shows the estimated present value of accumulated retirement benefits payable to each Named Executive Officer upon retirement based on the assumptions described below. The table distinguishes between benefits available under the qualified pension plan program (QP), the pension equity plan program (PEP), the supplemental pension program (SERP), and ~~any additional benefits available under contractual agreements.~~the supplemental pension (Excess). See the narrative above in the CD&A under the captions ~~"Summary Compensation Table Versus Realized Pay Comparison - James J. Judge-Eversource CEO," "Other~~“Other Benefits -– Retirement ~~Benefits"~~Benefits” and ~~"Contractual Agreements"~~“Contractual Agreements” for ~~more detail~~additional information on benefits under these plans and agreements.

The values shown in the Pension Benefits Table for Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan~~Judge and Ms. Carmody were calculated as of December 31, ~~2019,~~2021 based on benefit payments in the form of a lump sum. For Mr. Butler, a payment of benefits was assumed in the form of a contingent annuitant option. Such earned pension program benefit value could otherwise have changed because of the reduction in mortality factors and potentially rising interest rates.

The values shown in this Table for the Named Executive Officers were based on benefit payments on the actual ages or the earliest possible ages for retirement with unreduced ~~benefits:~~benefits for the Named Executive Officers: Mr. Nolan: age 62, Mr. Lembo: age 62, Mr. Schweiger: age 55, Mr. Butler: age 62, Ms. Carmody: age 62 and Mr. Judge: age ~~60; Mr. Lembo: age 62; Mr. Schweiger: age 55; Mr. Butler: age 62; and Mr. Nolan: age 62.~~60.

In addition, benefits were determined under the qualified pension program using tax code limits in effect on December 31, ~~2019.~~2021. For Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan,~~Judge and Ms. Carmody, the values shown reflect actual ~~2019~~2021 salary and annual incentives earned in ~~2018~~2020 but paid in ~~2019~~2021 (per applicable supplemental program rules). For Mr. Butler, the values shown reflect actual ~~2019~~2021 salary and annual incentives earned in ~~2019~~2021 but paid in ~~2020~~2022 (per applicable supplemental program rules).

~~Eversource determined the~~The present value of benefits at retirement age were determined using the discount rate within a range of ~~3.04%~~2.83 percent to ~~3.21%~~2.89 percent under ACS 715-30 pension accounting for the ~~2019~~2021 fiscal year end measurement as of December 31, ~~2019.~~2021. This present value assumes no pre-retirement mortality, turnover or disability. However, for the postretirement period beginning at retirement age, the ~~2019~~2021 IRS lump sum mortality table was used for Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan.~~Judge and Ms. Carmody. The RP2014 Employee Table Projected Generationally with Scale ~~MP2019~~MP2020 was used for Mr. Butler. This new mortality table (as published by the Society of Actuaries in 2014) and projection scale were used by the Eversource Pension Plan for year-end ~~2019~~2021 financial disclosure. Additional assumptions appear in the footnotes to ~~the~~this Annual Report on Form ~~10-K for the fiscal year ended December 31, 2019.~~

~~Pension Benefits~~10‑K.

169


Pension Benefits							Pension Benefits
		Number of Years Credited Service (#)	Present Value of Accumulated Benefit		During Last Fiscal Year				Number of Years Credited Service (#)	Present Value of Accumulated Benefit		During Last Fiscal Year
Name	Plan Name						Name	Plan Name
James J. Judge	Retirement Plan	42.33	$	2,913,187	$	—
Joseph R. Nolan, Jr.							Joseph R. Nolan, Jr.	Retirement Plan (QP)	36.42	$	1,111,454	$	—
	Supplemental Plan	20.00	14,755,642		—			Supplemental Plan (PEP)	36.42	5,094,488		—
	Supplemental Plan	42.33	15,719,167		—			Supplemental Plan (SERP)	20.00	7,603,886		—
Philip J. Lembo	Retirement Plan	10.75	1,336,500		—		Philip J. Lembo	Retirement Plan (QP)	38.17	1,473,491		—
								Supplemental Plan (PEP)	38.17	6,859,909		—
	Supplemental Plan	10.75	5,208,302		—			Supplemental Plan (SERP)	12.00	174,020		—
Werner J. Schweiger	Retirement Plan	17.83	599,033		—		Werner J. Schweiger	Retirement Plan (QP)	19.83	706,316		—
	Supplemental Plan	17.83	2,512,305		—			Supplemental Plan (Excess)	19.83	3,461,360		—
	Supplemental Plan	17.00	8,131,823		—			Supplemental Plan (SERP)	19.00	10,626,286		—
Gregory B. Butler	Retirement Plan	23.00	1,425,654		—		Gregory B. Butler	Retirement Plan (QP)	25.00	1,802,836		—
	Supplemental Plan	23.00	5,674,956		—			Supplemental Plan (Excess)	25.00	7,875,673		—
	Target	23.00	4,558,338		—			Supplemental Plan (Excess)	25.00	6,229,794		—
Joseph R. Nolan, Jr.	Retirement Plan	20.33	1,017,250		—
Christine M. Carmody							Christine M. Carmody	Retirement Plan (QP)	18.25	630,388		—
	Supplemental Plan	20.33	3,477,146		—			Supplemental Plan (Excess)	18.25	1,896,324		—
	Supplemental Plan	20.00	5,474,992		—			Supplemental Plan (SERP)	15.00	5,108,103		—
James J. Judge							James J. Judge	Retirement Plan (QP)	44.33	3,054,717		—
								Supplemental Plan (Excess)	44.33	17,735,283		—
								Supplemental Plan (SERP)	20.00	15,388,563		—

NONQUALIFIED DEFERRED COMPENSATION IN ~~2019~~

2021

The following table reports amounts contributed in ~~2019,~~2021, together with aggregate earnings on contributions and withdrawals or distributions on contributions in ~~2019,~~2021, under ~~Eversource's~~the Eversource deferred compensation program, along with aggregate balances on contributions. See the narrative above in the CD&A under the caption ~~"Other~~“Other Benefits - Deferred ~~Compensation"~~Compensation” for more detail on ~~the~~our non-qualified deferred compensation program.

Executive
Contributions
in Last FY
Registrant
Contributions
in Last FY
Aggregate
Earnings in
in Last FY
Aggregate
Withdrawals/
Distributions
Aggregate
Balance at
Last FYE ⁽¹⁾
Name
James J. Judge $ —
$ —
$ 2,066,717
$ —
$ 8,110,416
Philip J. Lembo —
—
306,112
—
1,615,523
Werner J. Schweiger —
—
3,615,557
—
19,806,849
Gregory B. Butler —
—
6,309
—
27,503
Joseph R. Nolan, Jr. —
—
1,677,324
—
6,693,619

~~(1)~~

Includes the total market value of deferred compensation program balances at December 31, 2019, plus the value of vested RSUs or other awards for which the distribution of common shares is currently deferred, based on $85.07, the closing price of Eversource common shares on December 31, 2019, the last trading day of the year. The aggregate balances reflect a significant level of earnings on previously earned and deferred compensation.


	Executive Contributions in Last FY		Registrant Contributions in Last FY		Aggregate Earnings in in Last FY		Aggregate Withdrawals/ Distributions		Aggregate Balance at Last FYE (1)
Name
Joseph R. Nolan, Jr.	$	—	$	—	$	986,034	$	—	$	8,205,292
Philip J. Lembo	—		—		242,688		—		2,086,943
Werner J. Schweiger	—		—		3,199,325		—		26,305,514
Gregory B. Butler	—		—		2,476		—		31,877
Christine M. Carmody	—		—		251,156		—		1,689,205
James J. Judge	—		—		730,217		—		9,226,321

(1) Includes the total market value of deferred compensation program balances at December 31, 2021, plus the value of vested RSUs or other awards for which the distribution of common shares is currently deferred, based on $90.98, the closing price of Eversource Energy common shares on December 31, 2021, the last trading day of the year. The aggregate balances reflect a significant level of earnings on previously earned and deferred compensation.

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL

The discussion and tables below show compensation payable to each Named Executive Officer who is still an employee of Eversource, in the event of: (i) voluntary termination; (ii) involuntary not-for-cause termination; (iii) termination in the event of death or disability; and (iv) termination following a change in control. No amounts are payable in the event of a termination for cause. The amounts shown assume that each termination was effective as of December 31, ~~2019,~~2021, the last business day of the fiscal year.

Generally, a ~~"change~~“change in ~~control"~~control” means a change in ownership or control effected through (i) the acquisition of 30 percent or more of the combined voting power of common shares or other voting securities (20 percent for Mr. Butler, excluding certain defined transactions); (ii) the acquisition of more than 50 percent of ~~Eversource~~our common shares, excluding certain defined transactions (for Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan)~~Judge and Ms. Carmody); (iii) a change in the majority of the Eversource Board of Trustees, unless approved by a majority of the incumbent Trustees; (iv) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50 percent of the voting power of the resulting business entity (excluding in certain cases defined transactions); and (v) complete liquidation or dissolution of Eversource, or a sale or disposition of all or substantially all of the assets of Eversource other than, for Mr. Butler, to an entity with respect to which following completion of the transaction more than 50 percent of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.

170

In the event of a change in control, the Named Executive Officers are generally entitled to receive compensation and benefits following either involuntary termination of employment without ~~"cause"~~“cause” or voluntary termination of employment for ~~"good reason"~~“good reason” within the applicable period (generally two years following a change in control). The Compensation Committee believes that termination for good reason is conceptually the same as termination ~~"without cause"~~“without cause” and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance. Termination for ~~"cause"~~“cause” generally means termination due to a felony or certain other convictions; fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to Eversource property; gross misconduct or gross negligence in the course of employment or gross neglect of duties harmful to Eversource; or a material breach of obligations under the

agreement. ~~"Good reason"~~“Good reason” for termination generally exists after assignment of duties inconsistent with ~~executive's~~executive’s position, a material reduction in compensation or benefits, a transfer more than 50 miles from the ~~executive's~~executive’s pre-change in control principal business location (or for Messrs. ~~Judge,~~Nolan, Lembo, Schweiger and ~~Nolan,~~Judge and Ms. Carmody, an involuntary transfer outside the ~~Greater~~greater Boston ~~Metropolitan Area)~~metropolitan area), or requiring business travel to a substantially greater extent than required prior to the change in control.

The summaries above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and plans, copies of which have been filed as exhibits to this Annual Report on Form ~~10-K for the year ended December 31, 2019.~~10-K.

Payments Upon Termination

Regardless of the manner in which the employment of a Named Executive Officer terminates, the executive is entitled to receive certain amounts earned during the ~~executive's~~executive’s term of employment. Such amounts include:

•Vested RSUs and certain other vested awards;

•Amounts contributed and any vested matching contributions under the deferred compensation program;

•Pay for unused vacation; and

•Amounts accrued and vested under the pension/supplemental and 401k programs (except in the event of a termination for cause under the supplemental program).

The following table describes additional compensation payable to the Named Executive Officers in the event of voluntary termination, involuntary termination not for cause, termination in the event of death or disability and termination following a change in control. No benefits are provided in the event of termination for cause. See the section above captioned ~~"Pension~~“Pension Benefits in ~~2019"~~2021” for information about the pension program, supplemental program and other benefits, and the section captioned ~~"Nonqualified~~“Nonqualified Deferred Compensation in ~~2019."~~2021.”

171

POST-EMPLOYMENT COMPENSATION PAYMENTS UPON TERMINATION


Name	Type of Payments	Voluntary Termination		Involuntary Termination Not for Cause		Termination Upon Death or Disability		Termination Following a Change in Control
Joseph R. Nolan, Jr.	Annual Incentives (1)	$	—	$	—	$	—	$	1,320,000
	Performance Shares (2)	1,609,655		1,609,655		1,609,655		2,593,391
	RSUs (3)	568,869		568,869		568,869		1,108,723
	Special Retirement Benefit (4)	—		—		—		23,885,917
	Health and Welfare Benefits (5)	—		—		—		94,206
	Perquisites (6)	—		—		—		16,500
	Excise Tax and Gross-ups (7)	—		—		—		12,367,402
	Separation Payment for Liquidated Damages (8)	—		—		—		5,922,000
	Total	$	2,178,524	$	2,178,524	$	2,178,524	$	47,308,139
Philip J. Lembo	Annual Incentives (1)	$	—	$	—	$	—	$	576,000
	Performance Shares (2)	1,554,967		1,554,967		1,554,967		1,829,065
	RSUs (3)	689,217		689,217		689,217		1,305,186
	Special Retirement Benefit (4)	—		—		—		2,252,534
	Health and Welfare Benefits (5)	—		—		—		47,100
	Perquisites (6)	—		—		—		11,000
	Separation Payment for Liquidated Damages (8)	—		—		—		3,340,000
	Total	$	2,244,184	$	2,244,184	$	2,244,184	$	9,360,885
Werner J. Schweiger	Annual Incentives (1)	$	—	$	—	$	—	$	616,000
	Performance Shares (2)	2,036,802		2,036,802		2,036,802		3,229,707
	RSUs (3)	715,871		715,871		715,871		1,372,677
	Special Retirement Benefit (4)	—		—		—		2,014,920
	Health and Welfare Benefits (5)	—		—		—		76,694
	Perquisites (6)	—		—		—		16,500
	Separation Payment for Liquidated Damages (8)	—		—		—		5,160,000
	Total	$	2,752,673	$	2,752,673	$	2,752,673	$	12,486,498
Gregory B. Butler	Annual Incentives (1)	$	—	$	—	$	—	$	469,000
	Performance Shares (2)	1,562,295		1,562,295		1,562,295		2,411,585
	RSUs (3)	544,029		544,029		544,029		1,014,649
	Health and Welfare Benefits (5)	—		25,470		—		38,205
	Perquisites (6)	—		10,000		—		16,500
	Separation Payment for Liquidated Damages (8)	—		1,139,000		—		1,139,000
	Separation Payment for Non-Compete Agreement (9)	—		1,139,000		—		2,278,000
	Total	$	2,106,324	$	4,419,794	$	2,106,324	$	7,366,939
Christine M. Carmody	Annual Incentives (1)	$	—	$	—	$	—	$	379,000
	Performance Shares (2)	1,261,852		1,261,852		1,261,852		1,947,763
	RSUs (3)	439,450		439,450		439,450		819,483
	Health and Welfare Benefits (5)	—		—		—		8,864
	Perquisites (6)	—		—		—		11,000
	Separation Payment for Liquidated Damages (8)	—		—		—		3,486,340
	Total	$	1,701,302	$	1,701,302	$	1,701,302	$	6,652,450
James J. Judge	Annual Incentives (1)	$	—	$	—	$	—	$	1,404,000
	Performance Shares (2)	8,601,402		8,601,402		8,601,402		13,232,101
	RSUs (3)	2,992,104		2,992,104		2,992,104		5,560,302
	Health and Welfare Benefits (5)	—		—		—		103,951
	Perquisites (6)	—		—		—		16,500
	Excise Tax and Gross-Ups (7)	—		—		—		657,823
	Separation Payment for Liquidated Damages (8)	—		—		—		11,250,000
	Total	$	11,593,506	$	11,593,506	$	11,593,506	$	32,224,677

(1) For Termination Following a Change in Control: Represents target 2021 annual incentive awards as described in the Grants of Plan Based Awards Table.

(2) For Voluntary Termination and Involuntary Termination Not For Cause, and Termination Upon Death or Disability: Represents 100 percent of the performance share awards under the 2019 – 2021 Long-Term Incentive Program, 67 percent of the performance share awards under the 2020 – 2022 Long-Term Incentive Program, and 33 percent of the performance share awards under the 2021 – 2023 Long-Term Incentive Program. The values were calculated by multiplying the number of RSUs by $90.98, the closing price of Eversource common shares on December 31, 2021, the last trading day of the year. For Termination Following a Change in Control: Represents 100 percent of the performance share awards under each of the three Programs noted in the previous two sentences.

(3) For Voluntary Termination and Involuntary Termination Not For Cause, and Termination Upon Death or Disability: Represents values of RSUs granted under our long-term incentive programs that, at year-end 2021, were unvested under applicable vesting schedules. Under these programs, RSUs vest pro rata

172

Name Type of Payments Voluntary Termination
Involuntary Termination
Not for Cause
Termination Upon Death or Disability
Termination Following a
Change in Control
James J. Judge
Annual Incentives ⁽¹⁾
$ —
$ —
$ —
$ 1,596,000

Performance Shares ⁽²⁾
8,792,108
8,792,108
8,792,108
12,958,613

RSUs ⁽³⁾
3,974,005
3,974,005
3,974,005
8,487,360

Special Retirement Benefit ⁽⁴⁾
—
—
—
6,997,917

Health and Welfare Benefits ⁽⁵⁾
—
—
—
96,289

Perquisites ⁽⁶⁾
—
—
—
15,000

Excise Tax and Gross-ups ⁽⁷⁾
—
—
—
10,506,837

Separation Payment for Liquidated Damages ⁽⁸⁾
—
—
—
11,280,000
Total $ 12,766,113
$ 12,766,113
$ 12,766,113
$ 51,938,016
Philip J. Lembo
Annual Incentives ⁽¹⁾
$ —
$ —
$ —
$ 518,000

Performance Shares ⁽²⁾
2,011,593
2,011,593
2,011,593
2,921,677

RSUs ⁽³⁾
895,955
895,955
895,955
1,884,309

Special Retirement Benefit ⁽⁴⁾
—
—
—
2,345,917

Health and Welfare Benefits ⁽⁵⁾
—
—
—
42,810

Perquisites ⁽⁶⁾
—
—
—
10,000

Separation Payment for Liquidated Damages ⁽⁸⁾
—
—
—
2,910,000
Total $ 2,907,548
$ 2,907,548
$ 2,907,548
$ 10,632,713
Werner J. Schweiger
Annual Incentives ⁽¹⁾
$ —
$ —
$ —
$ 544,000

Performance Shares ⁽²⁾
2,038,514
2,038,514
2,038,514
2,953,457

RSUs ⁽³⁾
905,673
905,673
905,673
1,899,750

Special Retirement Benefit ⁽⁴⁾
—
—
—
6,046,821

Health and Welfare Benefits ⁽⁵⁾
—
—
—
80,083

Perquisites ⁽⁶⁾
—
—
—
15,000

Separation Payment for Liquidated Damages ⁽⁸⁾
—
—
—
1,954,855
Total $ 2,944,187
$ 2,944,187
$ 2,944,187
$ 13,493,966
Gregory B. Butler
Annual Incentives ⁽¹⁾
$ —
$ —
$ —
$ 423,000

Performance Shares ⁽²⁾
1,592,867
1,592,867
1,592,867
2,331,273

RSUs ⁽³⁾
714,953
714,953
714,953
1,515,696

Special Retirement Benefit ⁽⁴⁾
¯
5,572,153
¯
5,572,153

Health and Welfare Benefits ⁽⁵⁾
¯
22,404
¯
33,607

Perquisites ⁽⁶⁾
¯
10,000
¯
15,000

Excise Tax and Gross-Ups ⁽⁷⁾
¯
2,818,443
¯
2,818,443

Separation Payment for Liquidated Damages ⁽⁸⁾
¯
1,073,000
¯
1,073,000

Separation Payment for Non-Compete Agreement ⁽⁹⁾
¯
1,073,000
¯
2,146,000
Total $ 2,307,820
$ 12,876,820
$ 2,307,820
$ 15,928,172
Joseph R. Nolan, Jr.
Annual Incentives ⁽¹⁾
$ —
$ —
$ —
$ 387,000

Performance Shares ⁽²⁾
1,426,297
1,426,297
1,426,297
2,103,355

RSUs ⁽³⁾
645,029
645,029
645,029
1,378,286

Special Retirement Benefit ⁽⁴⁾
—
—
—
3,571,439

Health and Welfare Benefits ⁽⁵⁾
—
—
—
87,254

Perquisites ⁽⁶⁾
—
—
—
15,000

Excise Tax and Gross-ups ⁽⁷⁾
—
—
—
2,774,844

Separation Payment for Liquidated Damages ⁽⁸⁾
—
—
—
3,945,000
Total $ 2,071,326
$ 2,071,326
$ 2,071,326
$ 14,262,178


~~(1)~~	~~For Termination Following a Change in Control: Represents target 2019 annual incentive awards as described in the Grants of Plan Based Awards Table.~~

~~(2)~~

For Voluntary Termination and Involuntary Termination Not for Cause and Termination Upon Death or Disability: Represents 100 percent of the performance share awards under the 2017 - 2019 Long-Term Incentive Program, 67 percent of the performance share awards under the 2018 - 2020 Long-Term Incentive Program and 33 percent of the performance share awards under the 2019 -based on credited service years and age at termination, and time worked during the vesting period. For all, the values were calculated by multiplying the number of RSUs by $90.08, the closing price of Eversource common shares on December 31, 2021, Long-Term Incentive Program. For all of the Named Executive Officers, the values were calculated by multiplying the number of RSUs by $85.07, the closing price of Eversource common shares on December 31, 2019, the last trading day of the year. ~~For Termination Following a Change in Control: Represents 100 percent of the performance share awards under each of the three programs noted in the previous two sentences.~~

~~(3)~~

For Voluntary Termination and Involuntary Termination Not for Cause and Termination Upon Death or Disability, represents values of RSUs granted under long-term incentive programs that, at year-end 2019, were unvested under applicable vesting schedules. Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period. For all, the values were calculated by multiplying the number of RSUs by $85.07, the closing price of Eversource common shares on December 31, 2019, the last trading day of the year.

For Termination Following a Change in Control: Represents values of all RSUs granted under our long-term incentive programs that, at year-end ~~2019,~~2021, were unvested under applicable vesting schedules, all of which vest in full.

~~(4)~~

The amount noted in the Involuntary Termination, Not for Cause column, represents for Mr. Butler actuarial present values at year-end 2019 of amounts payable (two years of service) solely under an employment agreement upon termination, which are in addition to amounts due under the pension plan. For Termination Following a Change in Control: represents actuarial present values at year-end 2019 of amounts payable solely under employment agreements upon termination (which are in addition to amounts due under the pension program). For Messrs. Judge, Schweiger, Butler and Nolan, pension benefits were calculated by adding three years of service (two years for Mr. Lembo). A lump sum of this benefit value is payable to Messrs. Judge, Lembo and Schweiger. Pension amounts shown in the table are present values at year-end 2019 of benefits payable upon termination as described with respect to the Pension Benefits Table above.

(4) For Termination Following a Change in Control: Represents actuarial present values at year-end 2021 of amounts payable solely under employment agreements upon termination (which are in addition to amounts due under the pension program). For Messrs. Nolan and Schweiger, pension benefits were calculated by adding three years of service (two years for Mr. Lembo). A lump sum of this benefit value is payable to Messrs. Nolan, Lembo and Schweiger. Pension amounts shown in the table are present values at year-end 2021 of benefits payable upon termination as described with respect to the Pension Benefits Table above.

~~(5)~~

The amount noted in the Involuntary Termination, Not for Cause column, represents for Mr. Butler the value of two years' employer contributions toward active health, long-term disability, and life insurance benefits, plus a payment to offset any taxes thereon. For Termination Following a Change in Control: represents estimated cost to Eversource at year-end 2019 (estimated by consultants) of providing post-employment health and welfare benefits beyond those available to non-executives upon involuntary termination. The amounts shown in the table for Messrs. Judge, Schweiger and Nolan represent the value of three years (two years for Mr. Lembo) continued health and welfare plan participation. The amounts shown in the table for Mr. Butler represent the value of three years' employer contributions toward active health, long-term disability, and life insurance benefits, plus a payment to offset any taxes on the value of these benefits, less the value of one year of retiree health coverage at retiree rates.

(5) The amount noted in the Involuntary Termination, Not for Cause: Represents for Mr. Butler the value of two years’ employer contributions toward active health, long-term disability, and life insurance benefits, plus a payment to offset any taxes thereon. For Termination Following a Change in Control: represents estimated Company cost at year-end 2020 (estimated by our consultants) of providing post-employment health and welfare benefits beyond those available to non-executives upon involuntary termination. The amounts shown in the table for Messrs. Nolan, Schweiger and Judge represent the value of three years (two years for Mr. Lembo and Ms. Carmody) continued health and welfare plan participation. The amounts shown in the table for Mr. Butler represent the value of three years’ employer contributions toward active health, long-term disability, and life insurance benefits, plus a payment to offset any taxes on the value of these benefits, less the value of one year of retiree health coverage at retiree rates.


~~(6)~~	The amount noted in the Involuntary Termination, Not for Cause column, represents for Mr. Butler the cost of reimbursing Mr. Butler for two years financial planning and tax preparation fees. For Termination Following a Change in Control, represents the cost to Eversource of reimbursing for financial planning and tax preparation fees for three years (two years for Mr. Lembo).

(6) The amount for Involuntary Termination, Not for Cause: Represents Company cost of reimbursing Mr. Butler for two years of financial planning and tax preparation fees. For Termination Following a Change in Control: Represents Company cost of reimbursing Messrs. Nolan, Schweiger, Butler and Judge for three years (two years for Mr. Lembo and Ms. Carmody) of financial planning and tax preparation fees.

~~(7)~~

For Termination Following a Change in Control, represents payments made to offset costs associated with certain excise taxes under Section 280G of the Internal Revenue Code. Executives may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a Termination Following a Change in Control that exceed specified Internal Revenue Service limits. Contractual agreements with the above executives provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on the Section 280G excise tax rate of 20 percent, the statutory federal income tax withholding rate of 35 percent, the applicable state income tax rate, and the Medicare tax rate of 1.45 percent.

(7) For Termination Following a Change in Control: Represents payments made to offset costs associated with certain excise taxes under Section 280G of the Internal Revenue Code. Executives may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a Termination Following a Change in Control that exceed specified Internal Revenue Service limits. Contractual agreements with the above executives provide for a grossed-up reimbursement of these excise taxes. The amounts in the table are based on the Section 280G excise tax rate of 20 percent, the statutory federal income tax withholding rate of 35 percent, the applicable state income tax rate, and the Medicare tax rate of 1.45 percent.

~~(8)~~

For Involuntary Termination, Not for Cause, represents for Mr. Butler a severance payment (two-times the sum of base salary plus relevant annual incentive award) in addition to any non-compete agreement payment described above. For Termination Following a Change in Control, represents severance payments in addition to any non-compete agreement payments described in the prior note. For Messrs. Judge, Schweiger and Nolan, this payment equals three-times the sum of base salary plus relevant annual incentive award (two-times the sum for Messrs. Lembo and Butler). These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

(8) For Involuntary Termination, Not for Cause: Represents for Mr. Butler a severance payment (two-times the sum of base salary plus relevant annual incentive award) in addition to any non-compete agreement payment described above. For Termination Following a Change in Control: Represents severance payments in addition to any non-compete agreement payments described in the prior note. For Messrs. Nolan, Schweiger and Judge and Ms. Carmody, this payment equals three-times the sum of base salary plus relevant annual incentive award (two-times the sum for Messrs. Lembo and Butler). Pursuant to Ms. Carmody’s agreement, the lump sum severance payment and payment of the value of three additional years of service under the SERP as provided under the agreement are limited to 2.99 times the sum of her most recent annual base salary and annual bonus during the period prior to the date of termination. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

~~(9)~~

For Involuntary Termination, Not for Cause and Termination Following a Change in Control, represents payments made under agreements or Eversource programs to Mr. Butler as consideration for agreement not to compete with Eversource following termination of employment, equal to the sum of base salary plus relevant annual incentive award. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

(9) For Involuntary Termination, Not For Cause and Termination Following a Change in Control: Represents payments made under agreements or Eversource programs to Mr. Butler as consideration for agreement not to compete with Eversource following termination of employment, equal to the sum of base salary plus relevant annual incentive award. These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

PAY RATIO

Eversource's ~~CEO~~Chief Executive Officer to median employee pay ratio is calculated pursuant to the requirements of Item 402(u) of Regulation S-K. Eversource identifies a new median employee each year. For 2021, Eversource identified the median employee by reviewing the ~~2019~~2021 total cash compensation of all full-time employees, excluding ~~Eversource's CEO,~~our Chief Executive Officer, who were employed by Eversource and its subsidiaries on December 31, ~~2019.~~2021. In Eversource's assessment of median employee compensation, pay was annualized for those employees who commenced work during ~~2019.~~2021. Otherwise, no assumptions, adjustments, or estimates were made with respect to total cash compensation, and the compensation for any full-time employees who were not employed by Eversource at the end of ~~2019~~2021 was not annualized. Eversource believes the use of total cash compensation for all employees is a consistently applied compensation measure, as Eversource does not widely distribute annual equity awards to employees.

After identifying the median employee based on total cash compensation, Eversource calculated the annual total compensation for such employee using the same methodology ~~it uses~~used for its Named Executive Officers as set forth in the ~~2019~~2021 Summary Compensation Table.

Mr. ~~Judge~~Nolan had ~~2019~~2021 annual total compensation of ~~$19,806,088,~~$6,467,078, as reflected in the Summary Compensation Table. ~~Eversource's~~Eversource’s median ~~employee's~~employee’s annual total compensation for ~~2019~~2021 was ~~$133,899. Eversource's 2019 CEO~~$133,297. Eversource’s 2021 Chief Executive Officer to median employee pay ratio is ~~148~~49 to 1.

EXHIBIT A

Adjusted Earnings (Non-GAAP)

We use Adjusted Earnings (non-GAAP) and its per share impact as our principal financial measure of operating performance because management believes it best reflects our baseline operating performance and provides additional and useful information in analyzing historical and future performance of our business and for planning and forecasting of future periods.

Adjusted Earnings (non-GAAP) is defined as Net Income Attributable to Common Shareholders excluding the following adjustments: (1) charges in 2021 at CL&P related to a settlement agreement that included credits to customers and funding of various customer assistance initiatives and a storm performance penalty imposed on CL&P by PURA, (2) Columbia Gas acquisition and transition costs in 2021 and 2020, and (3) an

173

impairment charge for our Northern Pass Transmission project in 2019. We believe the impacts of the CL&P settlement agreement and the storm performance penalty imposed on CL&P by PURA, Columbia Gas acquisition and transition costs, and the impairment charge for our Northern Pass Transmission project are not indicative of our ongoing costs and performance.

With respect to the 2021 EPS performance goal, the Compensation Committee discussed this goal at length at both its December 2021 and February 2022 meetings. The Committee first noted 2021 adjusted earnings to be $3.86 per share, a 6% growth over 2020, substantially above the average industry growth of 4.8%. Following those discussions, the Compensation Committee determined that it would assess the earnings per share goal based on Adjusted Earnings. The Compensation Committee considered the fact that the PURA storm related settlement and the integration costs of the complex Columbia Gas asset acquisition, which were for 2021 the two costs excluded in the calculation of Adjusted Earnings, were appropriate to be excluded and in the best interests of customers and shareholders. The PURA settlement adjustment to earnings was part of a comprehensive resolution of several important issues which was seen by the investment community as a positive outcome for all stakeholders, both for 2021 and the longer term. The integration of Columbia Gas was the culmination of a timely significant strategic opportunity for the Company and its customers, completed in an accelerated timeframe, under budget, with constructive regulatory outcomes. Please also see Item 7 of this Form 10-K.

This non-GAAP financial measure should not be considered as an alternative to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as indicators of operating performance.


Adjusted Earnings and EPS Reconciliation
	For the Years Ended December 31,
	2021				2020				2019
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Common Shareholders (GAAP)	$	1,220.5	$	3.54	$	1,205.2	$	3.55	$	909.1	$	2.81
Adjustments (after-tax) to reconcile to Adjusted Earnings:
CL&P Settlement Impacts	86.1		0.25		—		—		—		—
Acquisition and Transition Costs	23.6		0.07		32.1		0.09		—		—
Impairment of Northern Pass Transmission	—		—		—		—		204.4		0.64
Adjusted Earnings (Non-GAAP)	$	1,330.2	$	3.86	$	1,237.3	$	3.64	$	1,113.5	$	3.45

174

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 ~~26, 2020.~~25, 2022.

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

COMMON SHARE OWNERSHIP OF DIRECTORS AND MANAGEMENT

Eversource Energy owns 100 percent of the outstanding common stock of CL&P. The table below shows the number of Eversource Energy common shares beneficially owned as of February ~~18, 2020,~~3, 2022, by each of CL&P's directors and each Named Executive Officer of CL&P, as well as the number of Eversource Energy common shares beneficially owned by all of CL&P's directors and executive officers as a group. The table also includes information about restricted share units and deferred shares credited to the accounts of CL&P's directors and executive officers under certain compensation and benefit plans. No equity securities of CL&P are owned by any of the Trustees, directors or executive officers of Eversource Energy or CL&P. The address for the shareholders listed below is c/o Eversource Energy, Prudential Center, 800 Boylston Street, Boston, Massachusetts 02199 for Messrs. Judge, Lembo, Nolan and Schweiger; c/o Eversource Energy, 56 Prospect Street, Hartford, Connecticut 06103-2818 for Mr. Butler.

Name of Beneficial Owner

Amount and Nature of Beneficial Ownership (1)(2)(3)

Percent of Class

Joseph R. Nolan, Jr., Chairman, Director of CL&P

138,851

Philip J. Lembo, Executive Vice President and Chief Financial Officer, Director of CL&P

90,414

(4)

Werner J. Schweiger, Chief Executive Officer, Director of CL&P

221,604

(5)

Gregory B. Butler, Executive Vice President and General Counsel, Director of CL&P

93,793

Christine M. Carmody, Executive Vice President-Human Resources and Information Technology of Eversource Energy

61,495

All directors and executive officers as a group (8 persons)

675,022

(6)

* Less than 1 percent of Eversource Energy common shares outstanding.

1. The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as noted below.

2. Includes restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power, and phantom shares held by executive officers who participate in a deferred compensation plan as follows: Mr. Nolan: 93,053 shares; Mr. Lembo: 19,049 shares; Mr. Schweiger: 103,276 shares; Mr. Butler: 14,985 shares; and Ms. Carmody: 12,103 shares.

3. Includes shares held as units in the 401(k) Plan invested in the Eversource Energy Common Shares Fund over which the holder has sole voting and investment power as follows: Mr. Nolan: 20,647 shares; Mr. Lembo: 292 shares; Mr. Schweiger: 409 shares; Mr. Butler: 6,771 shares; and Ms. Carmody: 5,209 shares.

4. Includes 573 shares held by Mr. Lembo in a custodial account and 125 shares held in a charitable trust over which Mr. Lembo has sole voting and investment power.

5. Includes 2,321 shares held in a trust of which Mr. Schweiger is the trustee and beneficiary; 437 shares in a trust of which Mr. Schweiger’s spouse is the trustee and beneficiary; 992 shares held by Mr. Schweiger’s spouse in a custodial account for grandchild #1; and 175 shares held by Mr. Schweiger’s spouse in a custodial account for grandchild #2.

6. Includes 276,219 unissued shares (see Note 2) and 35,007 shares held as units in the 401(k) Plan (see Note 3).

175



~~Name of Beneficial Owner~~	~~Amount and Nature of Beneficial Ownership~~^(1)(2)(3)		~~Percent of Class~~
~~James J. Judge, Chairman of CL&P~~	~~312,760~~		*
~~Philip J. Lembo, Executive Vice President and Chief Financial Officer, Director of CL&P~~	~~63,017~~	⁽⁴⁾	*
~~Werner J. Schweiger, Chief Executive Officer, Director of CL&P~~	~~253,158~~	⁽⁵⁾	*
~~Gregory B. Butler, Executive Vice President and General Counsel, Director of CL&P~~	~~95,143~~		*
~~Joseph R. Nolan, Jr., Executive Vice President-Strategy, Customer and Corporate Relations of Eversource Service~~	~~111,473~~		*
~~All directors and executive officers as a group (7 persons)~~	~~912,459~~	⁽⁶⁾	*


*	~~Less than 1 percent of Eversource Energy common shares outstanding.~~


1.	~~The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as noted below.~~

Includes restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power, and phantom shares held by executive officers who participate in a deferred compensation plan as follows: Mr. Judge: 178,116 shares; Mr. Lembo: 19,337; Mr. Schweiger: 159,819 shares; Mr. Butler: 15,495 shares; and Mr. Nolan: 74,763 shares.


3.	Includes shares held as units in the 401(k) Plan invested in the Eversource Energy Common Shares Fund over which the holder has sole voting and investment power as follows: Mr. Judge: 27,135 shares; Mr. Lembo: 122 shares; Mr. Schweiger: 691 shares; Mr. Butler: 6,291 shares; and Mr. Nolan: 19,366 shares.


4.	~~Includes 542 shares held by Mr. Lembo in a custodial account and 125 shares held in a charitable trust over which Mr. Lembo has sole voting and investment power.~~


5.	Includes 4,596 shares held in a trust of which Mr. Schweiger is the trustee and beneficiary; 437 shares in a trust of which Mr. Schweiger’s spouse is the trustee and beneficiary; and 433 shares held by Mr. Schweiger’s spouse in a custodial account.


6.	~~Includes 468,709 unissued shares (see Note 2) and 58,471 shares held as units in the 401(k) Plan (see Note 3).~~

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, ~~2019,~~2021, in accordance with the rules of the SEC:


Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	Weighted-average exercise price of outstanding options, warrants and rights (2)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (1))
Equity compensation plans approved by security holders	1,059,130	$—	2,430,716
Equity compensation plans not approved by security holders (3)	—	—	—
Total	1,059,130	—	2,430,716

Plan Category
Number of securities to be issued upon exercise of outstanding options, warrants and rights ⁽¹⁾
Weighted-average exercise price of outstanding options, warrants and rights ⁽²⁾
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column ⁽¹⁾)
Equity compensation plans approved by security holders 1,261,070 $— 3,302,526
Equity compensation plans not approved by security holders ⁽³⁾
— — —
Total 1,261,070 $— 3,302,526

(1) Includes 594,623 common shares for distribution in respect of restricted share units, and 464,507 performance shares issuable at target, all pursuant to the terms of our Incentive Plan.


~~(1)~~	~~Includes 774,163common shares for distribution in respect of restricted share units, and 486,907performance shares issuable at target, all pursuant to the terms of our Incentive Plan.~~


~~(2)~~	(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 or the former shareholders of NSTAR.~~

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

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 ~~26, 2020.~~25, 2022.

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

Eversource Energy's Code of Ethics for Senior Financial Officers applies to the Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) of Eversource Energy, CL&P and certain other Eversource Energy subsidiaries. Under the Code, one's position as a Senior Financial Officer in the company may not be used to improperly benefit such officer or his or her family or friends. Under the Code, specific activities that may be considered conflicts of interest include, but are not limited to, directly or indirectly acquiring or retaining a significant financial interest in an organization that is a customer, vendor or competitor, or that seeks to do business with the company; serving, without proper safeguards, as an officer or director of, or working or rendering services for an organization that is a customer, vendor or competitor, or that seeks to do business with the company. Waivers of the provisions of the Code of Ethics for Trustees, executive officers or directors must be approved by Eversource Energy's Board of Trustees. Any such waivers will be disclosed pursuant to legal requirements.

Eversource Energy's Code of Conduct, which applies to all Trustees, directors, officers and employees of Eversource Energy and its subsidiaries, including CL&P, contains a Conflict of Interest Policy that requires all such individuals to disclose any potential conflicts of interest. Such individuals are expected to discuss their particular situations with management to ensure appropriate steps are in place to avoid a conflict of interest. All disclosures must be reviewed and approved by management to ensure a particular situation does not adversely impact the individual's primary job and role.

Eversource Energy's Related Persons Transactions Policy is administered by the Corporate Governance Committee of Eversource Energy's Board of Trustees. The Policy generally defines a "Related Persons Transaction" as any transaction or series of transactions in which (i) Eversource Energy or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any "Related Persons" has a direct or indirect material interest. A "Related Persons" is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5 percent of Eversource Energy's total outstanding shares, and any immediate family member of any such person. Management submits to the Corporate Governance Committee for consideration any Related Persons Transaction into which Eversource Energy or a subsidiary proposes to enter. The Corporate Governance Committee recommends to the Eversource Energy Board of Trustees for approval only those transactions that are in Eversource Energy's best interests. If management causes the company to enter into a Related Persons Transaction prior to approval by the Corporate Governance Committee, the transaction will be subject to ratification by the Eversource Energy Board of Trustees. If the Eversource Energy Board of Trustees determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.

The directors of CL&P are employees of CL&P and/or other subsidiaries of Eversource Energy, and thus are not considered independent.

176

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 ~~26, 2020.~~25, 2022.

CL&P, NSTAR ELECTRIC and PSNH

Pre-Approval of Services Provided by Principal Auditors

None of CL&P, NSTAR Electric and PSNH is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, NSTAR Electric and PSNH obtain audit services from the independent auditor engaged by the Audit Committee of Eversource Energy's Board of Trustees. Eversource Energy's Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the Eversource Energy Audit Committee Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the Eversource Energy Audit Committee at the next regularly scheduled meeting of the Committee.

The following relates to fees and services for the entire Eversource Energy system, including Eversource Energy, CL&P, NSTAR Electric and PSNH.

Fees Billed By Principal Independent Registered Public Accounting Firm

The aggregate fees ~~including out of pocket expense reimbursements,~~ billed to the Company and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the Deloitte Entities), for the years ended December 31, ~~2019~~2021 and ~~2018~~2020 totaled ~~$5,641,614~~$6,013,205 and ~~$5,076,922,~~$5,296,414, respectively. In addition, affiliates of Deloitte & Touche LLP as noted below provide other accounting services to the Company. ~~Fees~~


Audit and Non-Audit Fees	2021		2020
Audit Fees (1)	$	4,883,791	$	4,562,000
Audit Related Fees (2)	918,500		732,500
Tax Fees (3)	20,000		—
All Other Fees (4)	190,914		1,914
TOTAL	$	6,013,205	$	5,296,414

(1) Audit fees in 2021 and 2020 consisted of ~~the following:~~

~~1. Audit Fees~~

~~The aggregate~~ fees ~~billed~~related to the Company and its subsidiaries by Deloitte & Touche LLP for audit services rendered for the years ended December 31, 2019 and 2018 totaled $4,743,400 and $4,464,500, respectively. The audit fees were incurred for audits of ~~consolidated~~ financial statements of Eversource Energy and its subsidiaries in the Annual Report on Form 10-K, reviews of financial statements ~~included~~ in the Combined Quarterly ~~Reports~~reports on Form 10-Q of Eversource Energy and its subsidiaries, consultations with management, regulatory and ~~other costs. The fees also included~~compliance filings, out of pocket expense reimbursements, and audits of internal controls over financial reporting as of December 31, ~~2019~~2021 and ~~2018.~~

~~2. Audit-Related Fees~~

~~The aggregate~~2020. Audit fees ~~billed~~in 2021 also related to the ~~Company and its subsidiaries by~~audits of pension plan financial statements in connection with the ~~Deloitte Entities for audit-related services rendered for the years ended December 31, 2019 and 2018 totaled $851,300 and $547,500, respectively. The audit-related fees~~acquisition of CMA.

(2) Audit Related Fees were incurred for procedures performed in the ordinary course of business in support of certain regulatory filings, comfort letters, consents, and other costs related to registration statements and ~~financings.~~

~~3. Tax Fees~~

~~The aggregate fees billed to the Company and its subsidiaries by the Deloitte Entities for tax services rendered~~financials for the years ended December 31, ~~2019~~2021 and ~~2018 totaled $45,000 and $7,500, respectively.~~ 2020.

(3) The tax service fees for the period ended December 31, 2021 were incurred for procedures performed in the ordinary course of business in support of certain federal ~~rulings~~rules in ~~2019~~2021. There were no tax fees rendered and ~~certain employee benefit plan federal filings in 2018.~~

~~4. All Other Fees~~

~~The aggregate~~no tax fees billed ~~to the Company and its subsidiaries by the Deloitte Entities for services, other than the services described above,~~ for the ~~years~~year ended December 31, ~~2019~~2020.

(4) All Other Fees for the periods ended December 31, 2021 and ~~2018 totaled $1,914 and $57,422, respectively. These fees~~2020 were for aan annual license for access to an accounting standards research ~~tool in 2019 and 2018, and~~tool. All Other Fees for the ~~review of benefit payment calculations in 2018.~~period ended December 31, 2021 also included an advisory benchmarking project related to operations at a newly acquired business.

The Audit Committee pre-approves all auditing services and permitted audit-related or other services (including the fees and terms thereof) to be performed for us by our independent registered public accounting firm, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such ~~subcommittee~~subcommittees to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. During ~~2019,~~2021, all services described above were pre-approved by the Audit Committee or its Chair.

The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects.

177



			UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
			FORM	10-K

☒
	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, ~~2019~~2021
			or
☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the transition period from ____________ to ____________



			Yes			No
			☒			☐



			Yes			No
			☐			☒



			Yes			No
			☒			☐



			Yes			No
			☒			☐



	Yes	No
Eversource Energy	☐	☒
The Connecticut Light and Power Company	☐	☒
NSTAR Electric Company	☐	☒
Public Service Company of New Hampshire	☐	☒



Company - Class of Stock	Outstanding as of January 31, ~~2020~~2022
Eversource Energy Common Shares, $5.00 par value	~~329,952,663~~344,439,905	shares

The Connecticut Light and Power Company Common Stock, $10.00 par value	6,035,205	shares

NSTAR Electric Company Common Stock, $1.00 par value	200	shares

Public Service Company of New Hampshire Common Stock, $1.00 par value	301	shares



Current or former Eversource Energy companies, segments or investments:
Eversource, ES or the Company		Eversource Energy and subsidiaries
Eversource parent or ES parent		Eversource Energy, a public utility holding company
ES parent and other companies		ES parent and other companies are comprised of Eversource parent, Eversource Service, ~~Eversource Water Ventures, Inc. (parent company of Aquarion),~~ and other subsidiaries, which primarily includes our unregulated businesses, HWP Company, The Rocky River Realty Company (a real estate subsidiary), the consolidated operations of CYAPC and YAEC, and Eversource parent's equity ownership interests that are not consolidated
CL&P		The Connecticut Light and Power Company
NSTAR Electric		NSTAR Electric Company
PSNH		Public Service Company of New Hampshire
PSNH Funding		PSNH Funding LLC 3, a bankruptcy remote, special purpose, wholly-owned subsidiary of PSNH
NSTAR Gas		NSTAR Gas Company
EGMA		Eversource Gas Company of Massachusetts
Yankee Gas		Yankee Gas Services Company
Aquarion		~~Eversource~~ Aquarion ~~Holdings, Inc.~~Company and its subsidiaries
NPT		Northern Pass Transmission LLC
Northern Pass		The ~~HVDC~~high-voltage direct current (HVDC) and associated alternating-current transmission line project from Canada into New Hampshire
HEEC		Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric
Eversource Service		Eversource Energy Service Company
~~Bay State Wind~~North East Offshore		~~Bay State Wind~~North East Offshore, LLC, an offshore wind business being developed jointly by Eversource and Denmark-based Ørsted ~~which holds the Sunrise Wind project~~
~~North East Offshore~~CYAPC		~~North East Offshore, LLC, an offshore wind business holding company being developed jointly by Eversource and Denmark-based Ørsted, which holds the Revolution Wind and South Fork Wind projects~~
~~CYAPC~~	Connecticut Yankee Atomic Power Company
MYAPC		Maine Yankee Atomic Power Company
YAEC		Yankee Atomic Electric Company
Yankee Companies		CYAPC, YAEC and MYAPC
Regulated companies		The Eversource regulated companies are comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric and PSNH, the natural gas distribution businesses of Yankee Gas, ~~and~~ NSTAR Gas ~~NPT, Aquarion,~~and EGMA, Aquarion’s water distribution businesses, and the solar power facilities of NSTAR Electric
~~Regulators:~~			Regulators and Government Agencies:
~~DEEP~~BOEM		U.S. Bureau of Ocean Energy Management
DEEP		Connecticut Department of Energy and Environmental Protection
DOE		U.S. Department of Energy
DOER		Massachusetts Department of Energy Resources
DPU		Massachusetts Department of Public Utilities
EPA		U.S. Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
ISO-NE		ISO New England, Inc., the New England Independent System Operator
MA DEP		Massachusetts Department of Environmental Protection
NHPUC		New Hampshire Public Utilities Commission
PURA		Connecticut Public Utilities Regulatory Authority
SEC		U.S. Securities and Exchange Commission
~~SJC~~			~~Supreme Judicial Court of Massachusetts~~
Other Terms and Abbreviations:
ADIT		Accumulated Deferred Income Taxes
AFUDC		Allowance For Funds Used During Construction
AOCI		Accumulated Other Comprehensive Income
ARO		Asset Retirement Obligation
Bcf		Billion cubic feet
~~C&LM~~CfD		~~Conservation and Load Management~~
~~CfD~~	Contract for Differences
~~CTA~~CWIP		~~Competitive Transition Assessment~~
~~CWIP~~	Construction Work in Progress
EDC		Electric distribution company
EDIT		Excess Deferred Income Taxes
EPS		Earnings Per Share
ERISA		Employee Retirement Income Security Act of 1974
ESOP		Employee Stock Ownership Plan



~~ESOP~~		~~Employee Stock Ownership Plan~~
Eversource ~~2018~~2020 Form 10-K	The Eversource Energy and Subsidiaries ~~2018~~2020 combined Annual Report on Form 10-K as filed with the SEC
Fitch		Fitch Ratings
FMCC		Federally Mandated Congestion Charge
~~FTR~~GAAP		~~Financial Transmission Rights~~
~~GAAP~~	Accounting principles generally accepted in the United States of America
~~GSC~~GWh		~~Generation Service Charge~~Gigawatt-Hours
~~GSRP~~IPP		~~Greater Springfield Reliability Project~~
~~GWh~~	~~Gigawatt-Hours~~
HQ	~~Hydro-Québec, a corporation wholly-owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada~~
~~HVDC~~	~~High-voltage direct current~~
~~Hydro Renewable Energy~~	~~Hydro Renewable Energy, Inc., a wholly-owned subsidiary of Hydro-Québec~~
~~IPP~~	Independent Power Producers
ISO-NE Tariff		ISO-NE FERC Transmission, Markets and Services Tariff
kV		Kilovolt
kVa		Kilovolt-ampere
kW		Kilowatt (equal to one thousand watts)
~~LBR~~LNG		~~Lost Base Revenue~~
~~LNG~~	Liquefied natural gas
LRS		Supplier of last resort service
MG		Million gallons
MGP		Manufactured Gas Plant
MMBtu		One million British thermal units
MMcf		Million cubic feet
Moody's		Moody's Investors Services, Inc.
MW		Megawatt
MWh		Megawatt-Hours
~~NEEWS~~NETOs		~~New England East-West Solution~~
~~NETOs~~	New England Transmission Owners (including Eversource, National Grid and Avangrid)
OCI		Other Comprehensive Income/(Loss)
PAM		Pension and PBOP Rate Adjustment Mechanism
PBOP		Postretirement Benefits Other Than Pension
PBOP Plan		Postretirement Benefits Other Than Pension Plan
Pension Plan		Single uniform noncontributory defined benefit retirement plan
PPA		Power purchase agreement
RECs		Renewable Energy Certificates
Regulatory ROE		The average cost of capital method for calculating the return on equity related to the distribution business segment excluding the wholesale transmission segment
ROE		Return on Equity
RRBs		Rate Reduction Bonds or Rate Reduction Certificates
RSUs		Restricted share units
S&P		Standard & Poor's Financial Services LLC
~~SBC~~SERP		~~Systems Benefits Charge~~
~~SCRC~~	~~Stranded Cost Recovery Charge~~
~~SERP~~	Supplemental Executive Retirement Plans and non-qualified defined benefit retirement plans
SS		Standard service
~~TCAM~~UI		~~Transmission Cost Adjustment Mechanism~~
~~TSA~~	~~Transmission Service Agreement~~
UI	The United Illuminating Company
VIE		Variable Interest Entity



		Page
PART I
Item 1.	Business	2
Item 1A.	Risk Factors	1416
Item 1B.	Unresolved Staff Comments	1821
Item 2.	Properties	1921
Item 3.	Legal Proceedings	2124
Item 4.	Mine Safety Disclosures	2224
	Information About Our Executive Officers	24
~~PART II~~
PART II
Item 5.	Market for the Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2225
Item 6.	~~Selected Consolidated Financial Data~~Removed and Reserved	2326
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2527
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	4856
Item 8.	Financial Statements and Supplementary Data	4958
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~123~~140
Item 9A.	Controls and Procedures	~~123~~140
Item 9B.	Other Information	~~123~~140

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~124~~141
Item 11.	Executive Compensation	~~125~~142
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~154~~175
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~155~~176
Item 14.	Principal Accountant Fees and Services	~~156~~177

PART IV
Item 15.	Exhibits and Financial Statement Schedules	~~158~~178
Item 16.	Form 10-K Summary	~~158~~178
Signatures		E-~~E-9~~9



December 31,
	2014	2015	2016	2017	2018	2019
Eversource Energy	$100	$99	$110	$130	$138	$186
EEI Index	$100	$96	$113	$126	$131	$164
S&P 500	$100	$101	$114	$138	$132	$174



(Millions of Dollars)	Issue Date	Issuance/(Repayment)			Maturity Date	Use of Proceeds for Issuance/ Repayment Information
CL&P:
4.00% 2018 Series A First Mortgage Bonds ⁽¹⁾	April 2019	$	300.0		April 2048	Paid short-term borrowings that were used to pay long-term debt that matured on February 1, 2019 and fund capital expenditures and working capital
3.20% 2017 Series A First Mortgage Bonds ⁽²⁾	September 2019	200.0			March 2027	Paid short-term borrowings and fund capital expenditures and working capital
5.50% 2009 Series A First Mortgage Bonds	February 2009	(250.0		)	February 2019	Paid at maturity on February 1, 2019
NSTAR Electric:
3.25% 2019 Debentures	May 2019	400.0			May 2029	Paid short-term borrowings that were used to fund investments in eligible green expenditures
PSNH:
3.60% 2019 Series T First Mortgage Bonds	June 2019	300.0			July 2049	Paid long-term debt that matured in December 2019, paid short-term borrowings and fund capital expenditures and working capital
4.50% 2009 Series P First Mortgage Bonds	December 2009	(150.0		)	December 2019	Paid at maturity on December 1, 2019
Other:
Eversource Parent 4.50% Debentures	November 2009	(350.0		)	November 2019	Paid at maturity on November 15, 2019
Eversource Parent 3.45% Series P Senior Notes	January 2020	350.0			January 2050	Paid short-term borrowings
NSTAR Gas 3.74% Series Q First Mortgage Bonds	July 2019	75.0			August 2049	Paid short-term borrowings and fund capital expenditures and working capital
Yankee Gas 2.23% Series P First Mortgage Bonds	September 2019	100.0			October 2024	Paid short-term borrowings and for general corporate purposes
Yankee Gas 3.30% Series Q First Mortgage Bonds	September 2019	100.0			October 2049	Paid short-term borrowings and for general corporate purposes
Yankee Gas 5.26% Series H First Mortgage Bonds	November 2004	(50.0		)	November 2019	Paid at maturity on November 1, 2019
Aquarion 3.54% Senior Notes	December 2019	45.0			December 2049	Paid short-term borrowings



	Total Provision for Uncollectible Accounts				Provision for Uncollectible Hardship Accounts
	As of December 31,				As of December 31,
(Millions of Dollars)	2019		2018		2019		2018
Eversource	$	224.8	$	212.7	$	143.3	$	131.5
CL&P	97.3		88.0		80.1		71.9
NSTAR Electric	75.4		74.5		43.9		42.5
PSNH	10.5		11.1		—		—


Eversource	For the Years Ended December 31,
(Millions of Dollars, except percentages)	2021			2020			2019
Borrowed Funds	$	18.4		$	23.7		$	25.6
Equity Funds	37.3			42.0			45.0
Total AFUDC	$	55.7		$	65.7		$	70.6
Average AFUDC Rate	4.2		%	5.0		%	5.4		%


Eversource (Millions of Dollars)	As of and For the Years Ended December 31,
	2021		2020		2019
Cash Paid During the Year for:
Interest, Net of Amounts Capitalized	$	568.7	$	518.0	$	532.4
Income Taxes	121.6		48.9		56.0
Non-Cash Investing Activities:
Plant Additions Included in Accounts Payable (As of)	467.9		367.2		379.4


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


(Percent)	2021		2020		2019
Eversource	3.1	%	3.0	%	3.0	%
CL&P	2.8	%	2.8	%	2.8	%
NSTAR Electric	2.8	%	2.8	%	2.8	%
PSNH	3.1	%	2.8	%	2.8	%


	As of December 31, 2021
(Years)	Eversource	CL&P	NSTAR Electric	PSNH
Distribution - Electric	33.4	35.3	33.1	29.7
Distribution - Natural Gas	39.5	—	—	—
Transmission - Electric	40.2	36.5	45.1	40.8
Distribution - Water	38.5	—	—	—
Solar	24.2	—	24.2	—
Other (1)	11.2	—	—	—



	As of December 31, 2019
(Years)	Eversource	CL&P	NSTAR Electric	PSNH
Distribution - Electric	34.3	35.3	33.7	33.2
Distribution - Natural Gas	43.2	—	—	—
Transmission - Electric	40.4	36.8	44.9	42.1
Distribution - Water	33.5	—	—	—
Solar	24.2	—	24.2	—
Other ⁽¹⁾	11.2	—	—	—


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


⁽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.


CL&P (Millions of Dollars)	For the Years Ended December 31,						CL&P (Millions of Dollars)	For the Years Ended December 31,
	2019			2018				2021		2020
Derivatives, Net:							Derivatives, Net:
Fair Value as of Beginning of Period	$	(356.5	)	$	(362.3	)	Fair Value as of Beginning of Period	$	(293.1)	$	(329.2)
Net Realized/Unrealized Losses Included in Regulatory Assets	(15.0		)	(32.0		)	Net Realized/Unrealized Losses Included in Regulatory Assets	(8.5)		(17.9)
Settlements	42.3			37.8			Settlements	52.4		54.0
Fair Value as of End of Period	$	(329.2	)	$	(356.5	)	Fair Value as of End of Period	$	(249.2)	$	(293.1)


Eversource (Millions of Dollars)	Amortized Cost		Fair Value

Less than one year (1)	$	32.2	$	32.2
One to five years	60.5		61.4
Six to ten years	35.7		36.8
Greater than ten years	86.1		89.0
Total Debt Securities	$	214.5	$	219.4


⁽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.


			Investment Balance as of December 31,
(Millions of Dollars)	Ownership Interest		2021		2020
Offshore Wind Business - North East Offshore	50	%	$	1,213.6	$	887.1
Natural Gas Pipeline - Algonquin Gas Transmission, LLC	15	%	121.9		125.2
Renewable Energy Investment Fund	90	%	76.5		71.6
Other	various		24.3		23.2
Total Investments in Unconsolidated Affiliates			$	1,436.3	$	1,107.1


NSTAR Electric (Millions of Dollars)	As of December 31,
	2021		2020
Debentures:
5.750% due 2036	$	200.0	$	200.0
5.500% due 2040	300.0		300.0
2.375% due 2022	400.0		400.0
4.400% due 2044	300.0		300.0
3.250% due 2025	250.0		250.0
2.700% due 2026	250.0		250.0
3.200% due 2027	700.0		700.0
3.250% due 2029	400.0		400.0
3.950% due 2030	400.0		400.0
3.100% due 2051	300.0		—
1.950% due 2031	300.0		—
Total Debentures	3,800.0		3,200.0
Notes:
5.900% Senior Notes Series B due 2034	50.0		50.0
6.700% Senior Notes Series D due 2037	40.0		40.0
3.500% Senior Notes Series F due 2021	—		250.0
3.880% Senior Notes Series G due 2023	80.0		80.0
2.750% Senior Notes Series H due 2026	50.0		50.0
Total Notes	220.0		470.0
Less Amounts due Within One Year	(400.0)		(250.0)
Unamortized Premiums and Discounts, Net	(11.2)		(6.8)
Unamortized Debt Issuance Costs	(23.4)		(20.0)
NSTAR Electric Long-Term Debt	$	3,585.4	$	3,393.2


PSNH (Millions of Dollars)	As of December 31,
	2021		2020
First Mortgage Bonds:
5.600% Series M due 2035	$	50.0	$	50.0
4.050% Series Q due 2021	—		122.0
3.200% Series R due 2021	—		160.0
3.500% Series S due 2023	325.0		325.0
3.600% Series T due 2049	300.0		300.0
2.400% Series U due 2050	150.0		150.0
2.200% Series V due 2031	350.0		—
Total First Mortgage Bonds	1,175.0		1,107.0
Less Amounts due Within One Year	—		(282.0)
Unamortized Premiums and Discounts, Net	(2.6)		(1.5)
Unamortized Debt Issuance Costs	(8.6)		(6.4)
PSNH Long-Term Debt	$	1,163.8	$	817.1


OTHER (Millions of Dollars)	As of December 31,
	2021		2020
Yankee Gas - First Mortgage Bonds: 1.380% - 8.480% due 2022 - 2051	$	765.0	$	640.0
NSTAR Gas - First Mortgage Bonds: 2.250% - 7.110% due 2025 - 2051	580.0		500.0
EGMA - First Mortgage Bonds: 2.110% - 2.920% due 2031 - 2051	550.0		—
Aquarion - Senior Notes 4.000% due 2024	360.0		360.0
Aquarion - Unsecured Notes 0% - 6.430% due 2023 - 2051	394.9		335.2
Aquarion - Secured Debt 1.296% - 9.290% due 2022 - 2044	39.6		35.9
Eversource Parent - Senior Notes 0.300% - 4.250% due 2022 - 2050	6,100.0		5,550.0
Pre-1983 Spent Nuclear Fuel Obligation (CYAPC)	11.7		11.7
Fair Value Adjustment (1)	43.8		74.7
Less Fair Value Adjustment - Current Portion (1)	(17.7)		(31.0)
Less Amounts due in One Year	(775.4)		(490.2)

Unamortized Premiums and Discounts, Net	43.4		46.5
Unamortized Debt Issuance Costs	(36.3)		(32.0)
Total Other Long-Term Debt	$	8,059.0	$	7,000.8

Total Eversource Long-Term Debt	$	17,023.6	$	15,125.9


⁽¹⁾	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.


(Millions of Dollars) PSNH Income Statements:	For the Years Ended December 31,
	2021		2020		2019
Amortization of RRB Principal (included in Amortization of Regulatory Assets, Net)	$	43.2	$	43.2	$	43.0
Interest Expense on RRB Principal (included in Interest Expense)	18.4		19.7		21.1



(Millions of Dollars) Income Statement:	For the Year Ended December 31, 2019		For the Year Ended December 31, 2018
Amortization of RRB Principal (included in Amortization of Regulatory Assets, Net)	$	43.0	$	27.3
Interest Expense on RRB Principal (included in Interest Expense)	21.1		14.4


	Pension and SERP
	As of December 31,
	2021								2020
(Millions of Dollars)	Eversource		CL&P		NSTAR Electric		PSNH		Eversource		CL&P		NSTAR Electric		PSNH
Change in Benefit Obligation:
Benefit Obligation as of Beginning of Year	$	(7,045.3)	$	(1,477.3)	$	(1,517.9)	$	(748.7)	$	(6,321.7)	$	(1,331.3)	$	(1,397.3)	$	(692.6)
Service Cost	(85.8)		(23.0)		(15.8)		(8.9)		(76.2)		(21.8)		(15.4)		(8.2)
Interest Cost	(130.0)		(27.3)		(26.8)		(14.5)		(177.8)		(37.3)		(38.6)		(19.4)
Actuarial Gain/(Loss)	177.1		127.8		20.8		14.7		(658.2)		(152.3)		(139.5)		(62.1)
Benefits Paid - Pension	309.5		64.6		68.7		34.7		279.3		63.6		59.4		33.5
Benefits Paid - Lump Sum	34.7		—		15.6		—		23.4		—		13.1		—
Benefits Paid - SERP	10.1		0.3		0.2		0.4		7.3		0.3		0.2		0.4
Employee Transfers	—		4.0		6.8		1.3		—		1.5		0.2		(0.3)
Increase due to acquisition of CMA	—		—		—		—		(121.4)		—		—		—
Benefit Obligation as of End of Year	$	(6,729.7)	$	(1,330.9)	$	(1,448.4)	$	(721.0)	$	(7,045.3)	$	(1,477.3)	$	(1,517.9)	$	(748.7)
Change in Pension Plan Assets:
Fair Value of Pension Plan Assets as of Beginning of Year	$	5,409.2	$	1,043.1	$	1,345.1	$	593.7	$	4,968.6	$	986.2	$	1,288.8	$	551.6
Employer Contributions	180.0		98.9		30.0		—		109.6		23.2		0.7		19.5
Actual Return on Pension Plan Assets	1,250.5		250.4		312.0		136.9		512.3		98.8		128.3		55.8
Benefits Paid - Pension	(309.5)		(64.6)		(68.7)		(34.7)		(279.3)		(63.6)		(59.4)		(33.5)
Benefits Paid - Lump Sum	(34.7)		—		(15.6)		—		(23.4)		—		(13.1)		—
Employee Transfers	—		(4.0)		(6.8)		(1.3)		—		(1.5)		(0.2)		0.3
Increase due to acquisition of CMA	—		—		—		—		121.4		—		—		—
Fair Value of Pension Plan Assets as of End of Year	$	6,495.5	$	1,323.8	$	1,596.0	$	694.6	$	5,409.2	$	1,043.1	$	1,345.1	$	593.7
Funded Status as of December 31st	$	(234.2)	$	(7.1)	$	147.6	$	(26.4)	$	(1,636.1)	$	(434.2)	$	(172.8)	$	(155.0)


	Pension and SERP								PBOP
	For the Year Ended December 31, 2021								For the Year Ended December 31, 2021
(Millions of Dollars)	Eversource		CL&P		NSTAR Electric		PSNH		Eversource		CL&P		NSTAR Electric		PSNH
Service Cost	$	85.8	$	23.0	$	15.8	$	8.9	$	13.5	$	2.3	$	2.4	$	1.2
Interest Cost	130.0		27.3		26.8		14.5		17.4		3.2		4.4		1.8
Expected Return on Plan Assets	(437.5)		(86.8)		(108.1)		(47.5)		(79.1)		(10.3)		(36.9)		(6.1)
Actuarial Loss	243.9		45.5		61.6		20.7		8.9		1.8		2.4		0.7
Prior Service Cost/(Credit)	1.4		—		0.3		—		(21.2)		1.1		(17.0)		0.4
Total Net Periodic Benefit Plan Expense/(Income)	$	23.6	$	9.0	$	(3.6)	$	(3.4)	$	(60.5)	$	(1.9)	$	(44.7)	$	(2.0)
Intercompany Expense/(Income) Allocations	N/A		$	8.0	$	8.8	$	2.7	N/A		$	(1.6)	$	(1.9)	$	(0.6)



	Pension and SERP												PBOP
	For the Year Ended December 31, 2017												For the Year Ended December 31, 2017
(Millions of Dollars)	Eversource			CL&P			NSTAR Electric			PSNH			Eversource			CL&P			NSTAR Electric			PSNH
Service Cost	$	71.3		$	18.5		$	15.5		$	9.7		$	9.5		$	1.9		$	1.7		$	1.3
Interest Cost	188.0			41.6			42.7			21.2			27.1			5.3			8.7			3.0
Expected Return on Plan Assets	(334.1		)	(71.7		)	(87.6		)	(40.0		)	(63.7		)	(9.7		)	(28.6		)	(5.5		)
Actuarial Loss	135.2			27.7			41.1			11.6			9.1			1.0			3.4			0.6
Prior Service Cost/(Credit)	4.5			1.5			0.6			0.5			(21.6		)	1.1			(17.0		)	0.6
Total Net Periodic Benefit Expense/(Income)	$	64.9		$	17.6		$	12.3		$	3.0		$	(39.6	)	$	(0.4	)	$	(31.8	)	$	—
Intercompany Allocations	N/A			$	9.8		$	9.1		$	3.3		N/A			$	(0.7	)	$	(1.1	)	$	(0.5	)


	Regulatory Assets as of December 31,				AOCI as of December 31,
(Millions of Dollars)	2021		2020		2021		2020
Pension and SERP
Actuarial Loss	$	1,427.3	$	2,620.2	$	66.3	$	107.4
Prior Service Cost	5.3		6.6		0.6		0.7
PBOP
Actuarial Loss	$	45.0	$	235.0	$	3.5	$	7.9
Prior Service (Credit)/Cost	(130.1)		(151.2)		1.0		0.9