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,

~~acts of war or terrorism, physical attacks or grid disturbances that may damage and disrupt our transmission and distribution systems,~~

~~ability or inability to commence and complete our major strategic development projects and opportunities,~~

~~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 related to our current or future business model,~~

~~increased conservation measures of customers and development of alternative energy sources,~~

~~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,

• 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 levels or timing of capital expenditures,

• changes in laws, regulations or regulatory policy, including compliance with environmental laws and regulations,

• changes in accounting standards and financial reporting regulations,

• actions of rating agencies, and

• other presently unknown or unforeseen factors.

Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.

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

EVERSOURCE ENERGY AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

PART I

Item 1.Business

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

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

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

•NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of eastern and western Massachusetts and owns solar power facilities;

•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. ~~On December 4, 2017, Eversource acquired Eversource Aquarion Holdings, Inc. and its subsidiaries (formerly known as Macquarie Utilities Inc).~~

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, ~~2018,~~2021, CL&P furnished retail franchise electric service to approximately ~~1.25~~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 approximately $1.1 billion, effective May 1, 2018 and May 1, 2019, and $1.2 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 described below.

•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.

~~An SBC,~~•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 charge, comprised of both a statutory rate and~~ Conservation Adjustment Mechanism (CAM) charge established to implement cost-effective energy conservation programs and market transformation initiatives. The ~~conservation~~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.

As required by regulation, CL&P ~~jointly~~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, ~~entered into the following contracts~~ whereby CL&P is responsible for 80 percent and UI ~~will share~~for 20 percent ~~and~~of the net costs or benefits. CL~~&P will share 80 percent~~&P's portion of the costs and benefits ~~(CL&P's portion~~ of these ~~costs are either recovered from,~~contracts will be paid by, or refunded to, ~~customers through the FMCC):~~CL&P's customers.

Four capacity CfDs (totaling approximately 787 MW of capacity) with three electric generation units and one demand response project, which extend through 2026 and have terms of up to 15 years beginning in 2009. The capacity CfDs obligate both CL&P and UI to make or receive payments on a monthly basis to or from the project and generation owners based on the difference between a contractually set capacity price and the capacity market prices that the project and generation owners receive in the ISO-NE capacity markets.

Three peaker CfDs (totaling approximately 500 MW of peaking capacity) with three peaking generation units. The three peaker CfDs pay the generation owners the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years beginning in 2008 (including costs of plant operation and the prices that the generation owners receive for capacity and other products in the ISO-NE markets).

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. For further information, see "Regulatory Developments~~2018, and ~~Rate Matters - Connecticut"~~incremental step adjustments effective May 1, 2019 and May 1, 2020.

CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel (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 ~~accompanying Item 7,~~ ~~Management's Discussion~~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 ~~Analysis of Financial Condition~~not to other rate mechanisms such as the retail rate components, rate reconciling mechanisms, formula rates and ~~Results of Operations.~~

~~Sources and Availability of Electric Power Supply~~

~~As noted above, CL&P~~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 2018, CL&P supplied approximately 45 percent of its customer load at SS or LRS rates while the other 55 percent of its customer load had migrated to competitive energy suppliers. In termscost recovery mechanism outside of the ~~total number of CL&P customers, this equates~~base distribution rates with regard to ~~28 percent being on competitive supply, while 72 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 2019. For the second half of 2019, 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 2020 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 2019 and intends~~that requires electric utilities to ~~purchase 100 percent of full requirements for the remainder of 2019.~~

~~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, 2018, NSTAR Electric furnished retail franchise electric service to approximately 1.47 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 used to supply customers and purchases its energy requirements from competitive energy suppliers.

In December 2016, the DPU approved NSTAR Electric's application to develop 62 MW of new solar power facilities in addition to the 8 MW of existing solar power facilities. Currently, NSTAR Electric owns 58 MW of solar power facilities on sites in Massachusetts that were completed from 2010 through 2018. We expect the remaining 4 MW of new facilities to be completed in 2019. Similar to NSTAR Electric’s current practice on the existing 58 MW of solar power facilities, we expect that NSTAR Electric will sell energy from the new facilities into the ISO-NE market. We estimate our investment in these new facilities will be approximately $170 million.

~~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.

~~base distribution amounts are adjusted for inflation and filed for approval by the DPU on an annual basis, until the next~~last rate case. ~~The baseline distribution delivery service revenue requirement approved by the DPU for 2019 is $988 million.~~

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, 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 required by regulation, NSTAR Electric, along with two other Massachusetts electric utilities, signed long-term commitments to purchase a combined estimated generating capacity of approximately 101 MW of wind and solar power from one wind farm in New York (28 MW), and nine solar projects in Connecticut, Maine, New Hampshire and Rhode Island (73 MW), over 20 years. One solar project began operating in January 2019, and the other eight solar projects are scheduled to begin operating in late 2019. In addition, the one wind farm in New York is scheduled to begin operating by year end 2020.

~~Distribution Rate Case:~~ NSTAR Electric's distribution rates were established in a 2017 DPU-approved rate case with rates effective February 1, 2018. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

~~Service Quality Metrics:~~ NSTAR Electric is subject to service quality ("SQ") metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. NSTAR Electric will not be required to pay a SQ charge for its 2018 performance as the company achieved results at or above target for all of its SQ metrics in 2018.

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)~~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 48approximately 30 percentof its residential and 23 percent of its small commercial and industrial ~~("C&I")~~(C&I) customers twice per year for twelve-month terms. NSTAR Electric enters into supply contracts for basic service for 1813 percentof its large C&I customers every three months.

During ~~2018,~~2021, NSTAR Electric supplied approximately 5517 percent of its ~~residential customer load, 33 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, ~~2018,~~2021, PSNH furnished retail franchise electric service to approximately ~~519,000~~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, 2018, 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 2018, approximately 24 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.

~~PSNH~~Distribution Rate Case: PSNH’s distribution rates were established in a December 2020 NHPUC-approved 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~~agreement, with rates effective January 1, 2021. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and ~~increased funding via rates, of PSNH's reliability enhancement program.~~

~~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, at which time the Company classified these assets as held for sale.

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 adjustedAugust 1, 2022, 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. 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. For further information on the securitized RRB issuance, see "Liquidity - Rate Reduction Bonds" in the accompanying Item 7, ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

Sources and Availability of Electric Power Supply

~~From January 1, 2018 through March 31, 2018, approximately 24 percent~~PSNH does not own any generation assets and as approved by the NHPUC, purchases energy supply from a variety of ~~PSNH's default~~competitive suppliers for its energy service load was met through its own generation and approximately 18 percent was met through long-term power supply provided pursuant to orders of the NHPUC. The remaining 58 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market. Included in the 58 percent are PSNH's obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market. Beginning on April 1, 2018, 100 percent of PSNH’s default energy service load was met through purchases of energy requirements from competitive sourcescustomers through requests for proposals issued ~~periodically, consistent with NHPUC regulations.~~

~~PSNH no longer owns any generation assets and enters into supply contracts for energy service~~ twice per year, for six-month terms, for 76approximately 82 percent of its residential and small ~~commercial and industrial ("~~C~~&I")~~&I customers and for 1517 percent of its large C&I customers.

During ~~2018,~~2021, PSNH supplied approximately 4247 percent of its customer load at default energy service rates while the other 5853 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 ~~refunded~~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 ~~have been~~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")~~(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 Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases.

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

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

Transmission Projects

During ~~2018,~~2021, we were involved in the planning, development and construction of a series of electric transmission projects ~~including the Greater Hartford Central Connecticut projects ("GHCC") and the Greater Boston Reliability Solutions,~~ that ~~will be built within the next three years and that will~~ enhance system reliability and improve capacity. We were also involved in the planning and development of the Seacoast Reliability Project, for which the New Hampshire Site Evaluation Committee ("NHSEC") indicated its unanimous approval of the projectFor more information on ~~December 10, 2018, and subsequently issued its written decision on January 31, 2019. This project is scheduled to be completed by the end of 2019.~~

In March 2018, the NHSEC issued a written decision denying Northern Pass’ siting application after which the Massachusetts EDCs terminated the selection of, and subsequent contract negotiations with, Northern Pass under the Massachusetts Clean Energy RFP. On April 27, 2018, NPT filed a motion for rehearing with the NHSEC and on July 12, 2018, the NHSEC issued its written decision denying Northern Pass’ motion for rehearing. On August 10, 2018, NPT filed an appeal to the New Hampshire Supreme Court, alleging that the NHSEC failed to follow applicable law in its review of the project. On October 12, 2018, the New Hampshire Supreme Court accepted this appeal. Subsequently, the NHSEC transmitted the record of its proceedings to the New Hampshire Supreme Court on December 11, 2018. Briefing of the appeal began on February 4, 2019. The New Hampshire Supreme Court has not set a date for oral argument. NPT intends to continue to pursue NHSEC approval to construct this project. Consistent with Eversource’s and HQ’s long-term relationship to bring clean energy into New England, Eversource and HQ remain committed to Northern Pass and the many benefits this project will bring to our customers and the region. For further information,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.

~~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 2018, our estimated transmission rate base was approximately $6.7 billion, including approximately $3.0 billion at CL&P, $2.7 billion at NSTAR Electric, and $920 million 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 ~~296,000~~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 ~~237,000~~249,000 customers in 7274 cities and towns in Connecticut covering ~~2,187~~2,632 square miles. Total throughput (sales and transportation) in ~~2018~~2021 was approximately ~~70.1~~66.9 Bcf for NSTAR Gas, 53.4 Bcf for EGMA, and ~~58.6~~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.

NSTAR Gas, EGMA and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. All NSTAR Gas and EGMA retail customers have the ability to choose to purchase gas from third party marketers under the Massachusetts Retail Choice program. In the past year in Massachusetts, Retail Choice represented only approximately one percent of the total residential load, while Retail Choice represented approximately 59 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 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 ~~Hopkinton LNG Corp.~~ facilities ~~in Hopkinton, Massachusetts~~ consisting of aan 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.~~gas and 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. 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, ~~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.

Rates

NSTAR Gas and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. While all NSTAR Gas customers have the ability to choose to transport natural gas, in the past year, transportation represented only about two percent of the total residential load, while transportation represented about 56 percent of the total commercial and industrial load. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers. NSTAR Gas offers firm transportation service to all customers who purchase natural gas from sources other than NSTAR Gas while Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase natural gas from sources other than Yankee Gas. NSTAR Gas offers 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 and Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.

~~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")~~(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")~~(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 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.

Conservation Adjustment Mechanism ~~("CAM")~~(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 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 2018~~their 2021 performance as iteach achieved results at or above target for all of ~~its~~their SQ metrics in ~~2018.~~2021.

Distribution Rate Cases:

NSTAR Gas: NSTAR Gas distribution rates were ~~set~~established in ~~its 2015 DPU approved~~an October 2020 DPU-approved rate ~~case.~~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 two distribution rate increases, the two rate base reset provisions, and potential adjustments for qualifying exogenous events, EGMA agreed not to file for an increase or redesign of distribution base rates effective prior to November 1, 2028.

Yankee Gas: Yankee Gas distribution rates were ~~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 agreement PURA 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. For further information on the 2018 Yankee Gas settlement agreement, see "Regulatory Developments~~January 1, 2020 and ~~Rate Matters - Connecticut" in the accompanying Item 7,~~ ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~March 1, 2021.

Natural Gas Replacement ~~and Expansion~~

Massachusetts: ~~On July 7, 2014,~~Pursuant to Massachusetts enacted "An Act Relative to Natural Gas Leaks". This act established a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure. The program enabled companies, including NSTAR Gas, to better manage the scheduling and costs of replacement. The act also called for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.

Inlegislation, in October of each year, ~~pursuant to the act,~~ NSTAR Gas ~~files the Gas System Enhancement Program ("GSEP")~~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.

In October 2020, the DPU opened Docket “DPU 20-80 The Future of Gas” to examine the role of Massachusetts natural gas local distribution companies (LDCs) in helping to meet the state’s 2050 climate goals. The DPU will consider new policies and structures that would protect ratepayers as Massachusetts works to decarbonize the building sector, potentially recasting the role of LDCs in Massachusetts, which may require significant changes to the LDCs planning processes and business models. At this time, Eversource cannot predict the ultimate outcome of this proceeding and the resulting impact to its natural gas businesses, however the Company does not believe there is any indication of an inability to recover costs or risk of impairment of our natural gas assets at this time.

Connecticut: ~~In 2013, in accordance with Connecticut law and regulations, the~~Yankee Gas' December 2018 PURA approved ~~a comprehensive joint natural gas infrastructure expansion plan (the "Expansion Plan") filed by~~rate case settlement agreement included an accelerated pipeline replacement cost recovery program. The Gas System Improvement (GSI) rate recovers accelerated pipeline replacement as well as other capital investment through an annual reconciliation. Yankee Gas 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 has received approval from PURA forfiles its 2014, 2015 and 2016 System Expansion Reconciliations as of November 2017. Yankee Gas filed its 2017 System Expansion Reconciliation in March 2018 and is awaiting PURA review. Yankee Gas intends to file its 2018 System Expansion ReconciliationGSI reconciliation annually on March ~~15, 2019.~~1st for rates effective April 1st.

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 ~~described below,~~ 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 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 ~~and Acushnet, MA.~~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 ~~participation~~ in ~~planned~~order to meet the long-term firm customer requirements in a reliable manner, a combination of pipeline, storage, and ~~anticipated pipeline and storage expansion projects~~non-pipeline solutions will be ~~required in order for it to meet current and future sales growth opportunities.~~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 ~~228,000~~226,000 residential, commercial, industrial, municipal and fire protection and other customers, in 5968 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, ~~2018,~~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 $177.9 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) charge, which is applied between rate case proceedings and seeks recovery of allowed costs associated with ~~WICA-eligible capital~~eligible infrastructure improvement projects placed in-service. The WICA is updated semi-annually in Connecticut and annually in New Hampshire. In Connecticut, an annual WICA reconciliation mechanism reconciles earned WICA revenue to the approved WICA revenue with any differences refunded to, or recovered from, customers.

In Massachusetts, treatment plant surcharges, which are a series of three surcharges in Massachusetts (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 9899 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

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

The offshore leases include a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode Island and a separate, adjacent 300 square-mile ocean lease located ~~in a 300-square-mile area of the Atlantic Ocean~~ approximately 25 miles south of the coast of ~~Massachusetts~~Massachusetts. In aggregate, these ocean lease sites jointly-owned by Eversource and ~~has the ultimate potential to generate~~Ørsted could eventually develop at least ~~2,000~~4,000 MW of clean, renewable ~~energy. Eversource and Ørsted each hold a 50 percent ownership interest in Bay State Wind. Bay State Wind has previously submitted proposals, and expects to participate in future solicitations, for~~ offshore wind ~~in Connecticut, Massachusetts, New York and Rhode Island based on each state's clean energy requirements.~~energy.

On February 8, 2019, Eversource and Ørsted entered into a 50-50 partnership for key offshore wind assets in the Northeast. Eversource paid approximately $225 million for a 50 percent interest in Ørsted’s Revolution Wind and South Fork Wind power projects, as well as the 257-square-mile tract off the coasts of Massachusetts and Rhode Island. Revolution Wind is a ~~700~~704 MW offshore wind power project located approximately 15 miles south of the Rhode Island coast, and South Fork Wind is ~~approximately~~ a 130 MW offshore wind power project located approximately 35 miles east of Long Island. ~~Subject to permitting, finalized power purchase agreements, where applicable, further development, and final investment decisions by Ørsted and Eversource, Revolution~~Sunrise Wind is ~~expected~~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 ~~be commissioned~~federal permitting through BOEM, and engineering, state siting and permitting in ~~2023~~New York, Rhode Island and ~~South Fork Wind is expected by the end of 2022.~~

Massachusetts. For more information on these projects, see "Business Development and Capital Expenditures – Offshore Wind ~~Projects"~~Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

~~NATURAL GAS TRANSMISSION PROJECT~~

Access Northeast is 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"). Eversource owns a 40 percent interest in the project, which is accounted for as an equity method investment. 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. For more information, see "Business Development and Capital Expenditures – Natural Gas Transmission Project" 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 ~~$12.75~~$18.14 billion from ~~2019~~2022 through ~~2023,~~2026, of which we expect ~~$8.06~~$7.02 billion to be in our electric ~~and~~distribution segment, $4.53 billion to be in our natural gas distribution ~~segments, $3.35~~segment, $4.60 billion to be in our electric transmission segment and ~~$0.62~~$0.89 billion to be in our water distribution segment. We also project to invest ~~$0.72~~$1.10 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to ~~NPT or~~our offshore wind ~~projects.~~ 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, 2018, $801.1 million of Eversource's~~ long-term debt ~~including $350.0 million, $250.0 million, $150.0 million, $50.0 million~~agreements, see "Liquidity" in the accompanying Item 7, Management's Discussion and ~~$1.1 million for Eversource parent, CL&P, PSNH, Yankee 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 ~~generation~~nuclear power facilities and are now engaged in the long-term storage of their spent nuclear fuel. The Yankee Companies ~~have completed collection of their decommissioning and closure~~fund these costs through ~~the~~litigation proceeds received from ~~the spent nuclear fuel litigation against~~ the DOE and, ~~have refunded amounts~~ to ~~their member companies. These proceeds were used by~~ the ~~Yankee Companies to offset the decommissioning and closure cost amounts due from their member companies or to decrease 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, ~~and several other New England utilities. The decommissioning rates charged by the Yankee Companies have been reduced to zero. CL&P, NSTAR Electric and PSNH can~~in turn recover these costs from ~~or refund proceeds to,~~ 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")~~(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 2018, the total RPS obligation was 18.7 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 ~~2018,~~2021, the total RPS obligation was 2530.5 percentand will ultimately reach 3848.0 percent in ~~2020.~~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 ~~2018,~~2021, the ~~requirement was 23.365~~RPS and Clean Energy Standard (CES) requirements were 49.26 percent, and will ultimately reach ~~37.75~~57.30 percent in ~~2020.~~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, ~~2018,~~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 ~~$64.7~~$115.4 million, representing 6061 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 ~~$50.1~~$105.6 million of the total ~~$64.7~~$115.4 million as of December 31, ~~2018.~~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")~~(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 by the use of designs that can be implemented without additional cost or at~~lines.

HUMAN CAPITAL

Eversource is committed to delivering reliable energy and superior customer service; expanding energy options for our region; environmental stewardship; a ~~modest cost.~~safe, diverse and fairly-compensated workforce; and community service and leadership. Our employees are critical to achieving this mission. We ~~do not believe that other capital expenditures~~recognize our employees are ~~appropriate to minimize unsubstantiated risks.~~

~~Global Climate Change and Greenhouse Gas Emission Issues~~

~~Global climate change and greenhouse gas emission issues have received an increased focus from state governments~~our most valuable asset and the ~~federal government. The EPA initiated~~importance of attracting, retaining, growing and developing our employees. Leaders at all levels strive to create a ~~rulemaking addressing greenhouse gas emissions~~workplace where our employees are engaged, advocate for the customer, work collaboratively, raise ideas for improvement and focus on ~~December 7, 2009, issued~~delivering a ~~finding that concluded that greenhouse gas emissions are "air pollution" that endangers public health~~superior customer experience. We build employee engagement through continuous communication, developing talent, fostering teamwork and ~~welfare~~creating a diverse, equitable and should be regulated. The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including volume of gas supplied to large customers and fugitive emissions of SF6 gas and methane.inclusive workplace.

We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns. Such concerns could potentially lead to additional rules and regulations that impact how we operate our general utility business. These could include federal "cap and trade" laws, carbon taxes, and fuel and energy taxes. We expect that any costs of these rules and regulations would be recovered from customers.

~~EMPLOYEES~~

As of December 31, ~~2018,~~2021, Eversource Energy employed a total of ~~7,998~~9,227 employees, excluding temporary employees, of which ~~1,307~~1,382 were employed by CL&P, ~~1,618~~1,599 were employed by NSTAR Electric, and ~~736~~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 5051 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 ~~nine~~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 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 ~~significant~~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 ~~distribution~~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 ~~devote~~deploy substantial ~~resources~~technologies to ~~network~~system and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or ~~misuse~~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 to deter cyberattacks. These safeguards may not always be effective due to the evolving nature of cyberattacks. We maintain ~~limited~~ cyber insurance to cover damages and defense costs related to breaches of networks or operational ~~technology.~~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.

~~Acts of war or terrorism, both threatened and actual, or physical attacks could adversely affect our ability to operate our systems and could adversely affect our financial results and liquidity.~~

Acts of war or terrorism, both threatened and actual, or actual physical attacks that damage our transmission and distribution systems or other assets could negatively impact our ability to transmit or distribute energy, distribute water, 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 blackout due to grid disturbances or disruptions on a neighboring interconnected system. If our assets were physically damaged and were not recovered in a timely manner, it could result in a loss of service to customers and a significant decrease in revenues.

Any such acts of war or terrorism, physical attacks or grid disturbances could result in 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.

~~Strategic development 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 New England region related to the construction of electric transmission facilities, off-shore wind electric generation facilities, interconnections to generating resources and other investment opportunities. The development of these activities involve numerous risks. Various factors could result in increased costs or result in delays or cancellation of these projects. Risks include regulatory approval processes, new legislation, 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 strategic partners. Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.

As a result of legislative and regulatory changes, the states in which we provide service have implemented new selection procedures for new major electric transmission, natural gas pipeline, off-shore wind and other clean energy facilities. These procedures require the review of competing projects and permit the selection of only those projects that are expected to provide the greatest benefit to customers. If the projects in which we have invested 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 operations and cash flows.

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

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.

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 reasonable operating and capital costs and a reasonable ROE, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Each of these companies prepares and submits periodic rate filings with their respective regulatory commissions for review and approval. As a result of a catastrophic event not involving Eversource, regulators and legislators could impose additional requirements resulting in additional costs to the Company.

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.

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.

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 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, the recovery for which is subject to approval by regulators.

Climate change creates physical and financial risks. 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 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, hurricanes 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.

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, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; 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, conservation measures 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. Customers' increased use of energy efficiency measures, distributed generation and energy storage technology could result in lower demand. Similarly, mandatory water conservation imposed by regulators due to drought conditions could result in lower demand for water. Reduced demand for electricity due to energy efficiency measures and the use of distributed generation, and reduced demand for water due to mandatory or voluntary conservation efforts, to the extent not substantially offset through ratemaking or decoupling mechanisms, could have a material adverse effect on our financial condition, 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 and~~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 ~~limited privacy protection liability~~cyber insurance to cover ~~limited~~ 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 ~~card~~ 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.~~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.

~~Contamination of our water supplies, the failure of dams on reservoirs providing water to our customers,~~Business and Operational Risks:

Strategic development opportunities associated with offshore wind or ~~requirements to repair, upgrade~~investment opportunities in electric transmission or ~~dismantle any of these dams,~~clean-energy opportunities may ~~disrupt our ability to distribute water to our customers~~not be successful, and ~~result in substantial additional costs,~~projects may not commence operation as scheduled or within budget, or be completed, which could ~~adversely affect~~have a material adverse effect on our ~~financial condition,~~business prospects.

We are pursuing broader strategic development investment opportunities that will benefit the Northeast region related to the development, construction and ~~results~~operation of ~~operations.~~

~~Our water supplies, including water provided to our customers,~~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 ~~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 abilityexpected to provide ~~water~~the greatest benefit to customers. Accordingly, our ~~customers until~~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 ~~facilities and a sufficient amount of water in our reservoirs can be restored. A failure of a dam~~industry, future legislative or regulatory actions that could result in ~~personal injuries~~these projects not being probable of entering the construction phase, economic events or factors,

environmental and ~~downstream property damage for which we may be liable. The failure~~community concerns, design and siting issues, difficulties in obtaining required rights of ~~a dam would also adversely affect~~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 ~~supply water~~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 ~~sufficient quantities~~offshore wind projects, any changes to ~~our customers. Any losses~~tax laws impacting Eversource’s ability to monetize tax attributes associated with these projects, or ~~liabilities incurred due to a failure~~the cancellation of one of our dams may not be covered by existing insurance, may exceed such insurance coverage limits, or may not be recoverable in rates. Any such losses may make it difficult for us to obtain insurance at acceptable rates inany projects, as well as the ~~future, and may~~other risk factors described above, could have a material adverse effect on our financial ~~condition,~~position, results of operations, and cash ~~flows.~~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 ~~goodwill is valued~~contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and ~~recorded~~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 ~~an amount that, if impaired~~a reasonable price across all business lines. We also continue to pursue enhancements to standardize our systems and ~~written down,~~processes. If any difficulties in the global supply chain cycle or operation of these systems were to occur, they could adversely affect our ~~future operating~~ results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.

Our transmission and ~~total capitalization.~~

~~We have a significant amount of goodwill on our consolidated balance sheet,~~distribution systems may not operate as expected, and could require unplanned expenditures, which as of December 31, 2018, 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~~cash flows.

~~Eversource Energy and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.~~

~~Because utility companies, including our electric,~~the delivery of electricity, natural gas and ~~water utility subsidiaries, have large customer bases, they are subject~~water; increased capital expenditure requirements, including those due to ~~adverse publicity focused on the reliability of their distribution services~~environmental regulation; catastrophic events such as fires, explosions, a solar event, an electromagnetic event, or other similar occurrences; extreme weather conditions beyond equipment and ~~the speed with which they are able to respond to electric outages, natural gas leaks~~plant design capacity; human error; global supply chain disruptions; and ~~similar interruptions caused by storm~~potential claims for property damage or ~~other unanticipated events. Adverse publicity~~personal injuries beyond the scope of ~~this nature could harm~~our insurance coverage. Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the ~~reputations~~in-service date for one or more of ~~Eversource Energy and its subsidiaries; may make state legislatures, utility commissions and other~~these projects is delayed due to economic events or factors, or regulatory authorities less likely to view them in a favorable light; and may cause them 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~~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 requirements. The imposition of any of the foregoing could have a material adverse effect on the business, financial position, results of operations and cash flows of Eversource Energy and each of its utility subsidiaries.

~~Limits on our access to and~~unplanned increases in ~~the cost of capital may adversely impact our ability~~operation and maintenance costs. The inability to ~~execute our business plan.~~

~~We use short-term debt and the long-term capital markets as~~recover a significant ~~source~~amount 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~~such costs 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.

~~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 who owe us money, have contracted to supply us with energy or other commodities or services, or who 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.

~~Costs of compliance with environmental laws and regulations 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~~ - ~~Other Regulatory~~New technology and ~~Environmental Matters, included~~alternative energy sources could adversely affect our operations and financial results.

Advances in ~~this Annual Report on Form 10-K.~~

~~Market performance or changes~~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 ~~assumptions~~loss of market share and customers, and may require us to make significant ~~contributions~~expenditures 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.remain competitive. 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~~technology, including micro-grids and advances in energy or ~~regulation,~~battery storage, could also alter the channels through which electric customers buy or utilize energy, which could reduce our revenues or increase ~~the amount~~our expenses. Economic downturns or periods 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 and amount of future financings and negatively affect our financial position, results of operations and cash flows. For further information, see Note 10A, "Employee Benefits - Pensions and Postretirement Benefits Other Than Pension,"high energy supply costs typically can lead to the ~~financial statements.~~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, or 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:

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 neighboring interconnected system. Similarly, our natural gas distribution system is connected to transmission pipelines, not owned by Eversource. If there was an attack on the transmission pipelines, it could impact our ability to deliver natural gas. If our assets were physically damaged and were not recovered in a timely manner, it could result in a loss of service to customers, a significant decrease in revenues, significant expense to repair system damage, costs associated with governmental actions in response to such attacks, and liability claims, all of which could have a material adverse impact on our financial position, results of operations and cash flows. We maintain property and liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. In addition, physical attacks against third-party providers could have a similar effect on the operation of our systems.

Regulatory, Legislative and Compliance Risks:

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

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

be adjusted, subject to refund or disallowed, including cost recovery mechanisms. The ultimate outcome and timing of regulatory rate proceedings 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.

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

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 and water utility subsidiaries, have large customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events, including those related to climate change. Adverse publicity of this nature could harm our reputation and the reputation of our subsidiaries; may make state legislatures, utility commissions and other regulatory authorities less likely to view us in a favorable light; and may cause us to be subject to less favorable legislative and regulatory outcomes, legal claims or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements.

Addressing any adverse publicity, regulatory scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of our business, on the morale and performance of our employees and on our relationships with respective regulators, customers and counterparties. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on our financial position, results of operations and cash flows.

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

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

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

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.

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. ~~Additionally, the~~

~~subsidiary companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from Eversource parent.~~ Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent, or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource parent's ability to pay interest, dividends and its own debt obligations would be restricted.

Item 1B. Unresolved Staff Comments

We do not have any unresolved SEC staff comments.

Item 2. Properties

Transmission and Distribution System

As of December 31, ~~2018,~~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	495	74	Number of substations owned	181	21	173	32	124	22
Transformer capacity (in kVa)	43,632,000	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)	40,542	3,949	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)	17,453	405
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
174
34
140
20
Transformer capacity (in kVa) 21,752,000
3,633,000
17,568,000
7,465,000
4,312,000
5,051,000
Overhead lines (in circuit miles) 16,930
1,675
11,413
1,233
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) 6,673
137
8,814
267
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 627,046
290,640
170,964
165,442
Aggregate capacity (in kVa) 36,601,452
15,855,590
14,157,211
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 13, "Generation Asset Sale," in the accompanying Item 8, ~~Financial Statements and Supplementary Data~~ ~~for further information.~~

As of December 31, ~~2018,~~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 20 2010 - 2018 58,100

** 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, ~~2018,~~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, ~~199~~207 district regulator stations, and approximately ~~3,398~~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, ~~2018,~~2021, NSTAR Gas and EGMA owned ~~21 active gate stations, 164 district regulator stations,~~1.0 and ~~approximately 3,299~~2.36 miles of intrastate transmission natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, MA (0.5 Bcf of natural gas). In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, MA (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.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, ~~2018,~~2021, Aquarion owned and operated sources of water supply with a combined yield of approximately ~~131~~127 million gallons per day; ~~3,625~~3,573 miles of transmission and distribution mains; 109 surface water treatment plants; 3129 dams; and ~~107~~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.

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.

~~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.

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, 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 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

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

~~DOE Phase I Damages~~ ~~- In 1998, the Yankee Companies filed separate 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 begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms~~business. For information regarding material lawsuits and 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 ("DOE Phase I Damages"). Phase I covered damages for the years 1998 through 2002. Following multiple appeals and cross-appeals in December 2012, the judgment awarding $39.6 million, $38.3 million and $81.7 millionCombined Notes to ~~CYAPC, YAEC and MYAPC, respectively, became final.~~Financial Statements.

In ~~January 2013, the proceeds from the DOE Phase I Damages Claim were received by the Yankee Companies and transferred to each Yankee Company's respective decommissioning trust.~~

In June 2013, FERC approved CYAPC, YAEC and MYAPC to reduce rates in their wholesale power contracts through the application of the DOE proceeds for the benefit of customers. Changes to the terms of the wholesale power contracts became effective on July 1, 2013. In accordance with the FERC order, CL&P, NSTAR Electric and PSNH began receiving the benefit of the DOE proceeds, and the benefits have been passed on to customers.

On September 17, 2014, in accordance with the MYAPC refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric and PSNH, in the amount of $3.2 million, $1.9 million and $1.4 million, respectively.

~~DOE Phase II Damages~~ - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years 2001 through 2008 for CYAPC and YAEC and from 2002 through 2008 for MYAPC ("DOE Phase II Damages"). In November 2013, the court issued a final judgment awarding $126.3 million, $73.3 million, and $35.8 million to CYAPC, YAEC and MYAPC, respectively. On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.

In March and April 2014, CYAPC, YAEC and MYAPC received payment of $126.3 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds and made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order. The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric and PSNH, for the benefit of their respective customers, on June 1, 2014. Refunds to CL&P's, NSTAR Electric's and PSNH's customers for these DOE proceeds began in the third quarter of 2014 and all refunds under these proceedings have been disbursed.

~~DOE Phase III Damages -~~ In August 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012 ("DOE Phase III"). The DOE Phase III trial concluded on July 1, 2015, followed by a post-trial briefing that concluded on October 4, 2015. On March 25, 2016, the court issued its decision and awarded CYAPC, YAEC and MYAPC damages of $32.6 million, $19.6 million and $24.6 million, respectively. In total, the Yankee Companies were awarded $76.8 million of the $77.9 million in damages sought in the DOE Phase III. The decision became final on July 18, 2016, and the Yankee Companies received the awards from the DOE on October 14, 2016. The Yankee Companies received FERC approval of their proposed distribution of certain amounts of the awarded damages proceeds to member companies, including CL&P, NSTAR Electric and PSNH, which CYAPC and MYAPC made in December 2016. MYAPC also refunded $56.5 million from its spent nuclear fuel trust, a portion of which was also refunded to the Eversource utility subsidiaries. In total, Eversource received $26.1 million, of which CL&P, NSTAR Electric and PSNH received $13.6 million, $8.6 million and $3.9 million, respectively. These amounts have been refunded to the customers of the respective Eversource utility subsidiaries.

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

Claims seeking monetary damages totaling approximately $100 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, which is the vast majority of the damages being sought. The DOE Phase IV trial for the remaining amount of damages is expected to begin in 2019.

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 ~~proceedings involving~~ 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 ~~OF THE REGISTRANT~~

The following ~~table~~ sets forth the executive officers of Eversource Energy as of February ~~26, 2019.~~16, 2022. All of ~~the Company's~~Eversource Energy’s officers serve terms of one year and until their successors ~~are~~ elected and ~~qualified:~~

qualified.

Name

Age

Title

James J. Judge

6366

Executive Chairman of the Board

Joseph R. Nolan, Jr.

President and Chief Executive Officer

Philip J. Lembo

6366

Executive Vice President and Chief Financial Officer

Gregory B. Butler

6164

Executive Vice President and General Counsel

Christine M. Carmody

5659

Executive Vice President-Human Resources and Information Technology

~~Joseph R. Nolan, Jr.~~Penelope M. Conner

5558

Executive Vice President-Customer Experience and ~~Corporate Relations~~Energy Strategy

~~Leon J. Olivier~~James W. Hunt, III

7150

Executive Vice ~~President-Enterprise Energy Strategy~~President-Corporate Relations and ~~Business Development~~Sustainability and Secretary

Werner J. Schweiger

5962

Executive Vice President and Chief Operating Officer

Jay S. Buth

4952

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 ~~since~~from May 3, ~~2017; as a Trustee of Eversource Energy~~2017 until May 5, 2021, and as Chairman of CL&P, NSTAR Electric and PSNH since May 4, 2016; and as Chairman, President and Chief Executive Officer of Eversource Service and Chairman of NSTAR Gas and Yankee Gas since May 9, 2016. Mr. Judge has served as a Director of CL&P, PSNH, Yankee Gas and Eversource Service since April 10, 2012; of NSTAR Electric and NSTAR Gas since September 27, 1999; and of Eversource Aquarion Holdings, Inc. Previously, Mr. Judge served as President and Chief Executive Officer of Eversource Energy from May 4, 2016 until May 3, ~~2017;~~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~~President-Customer and ~~Chief Financial Officer~~Corporate Relations of Eversource Energy ~~CL&P, NSTAR Electric~~from August 8, 2016 to February 5, 2020. Based on his experience described above, Mr. Nolan has the skills and PSNH from April 10, 2012 until May 4, 2016; of NSTAR Gas, Yankee Gas and Eversource Service from April 10, 2012 until May 9, 2016. Mr. Judge has served as Chairman of the Board of Eversource Energy Foundation, Inc. since May 9, 2016; and as a Director since April 10, 2012. He previously served as Treasurer of Eversource Energy Foundation, Inc. from April 10, 2012 until May 9, 2016. He has servedqualifications necessary to serve as a Trustee of ~~the NSTAR Foundation since December 12, 1995.~~Eversource Energy.

Philip J. Lembo. Mr. Lembo has served as ~~Executive Vice President and~~ Chief Financial Officer of Eversource Energy since May ~~3, 2017; and of CL&P, NSTAR Electric, NSTAR Gas, PSNH, Yankee Gas and Eversource Service since March 31, 2017. Mr. Lembo has served as a Director of CL&P, NSTAR Electric and PSNH since May~~ 4, 2016; of NSTAR Gas, Yankee Gas and Eversource Service since May 9, 2016; and of Eversource Aquarion Holdings, Inc. Mr. Lembo previously served as Executive Vice President, Chief Financial Officer and Treasurer of Eversource Energy from August 8, 2016 until May 3, 2017; of CL&P, NSTAR Electric, PSNH, NSTAR Gas, Yankee Gas and Eversource Service from August 8, 2016 until March 31, 2017; as Senior Vice President, Chief Financial Officer and Treasurer of Eversource Energy, CL&P, NSTAR Electric and PSNH from May 4, 2016 until August 8, 2016; and of NSTAR Gas, Yankee Gas and Eversource Service from May 9, 2016 until August 8, 2016; as Vice President and Treasurer of Eversource Energy, CL&P and PSNH from April 10, 2012 until May 4, 2016; and of Yankee Gas and Eversource Service from April 10, 2012 until May 9, 2016. Mr. Lembo served as Vice President and Treasurer of NSTAR Electric and NSTAR Gas from

~~March 29, 2006 until May 4, 2016. Mr. Lembo has served as a Director of Eversource Energy Foundation, Inc. since May 9,~~ 2016. He previously served as Treasurer of Eversource Energy ~~Foundation, Inc.~~ from April 10, 2012 until May ~~9, 2016 until March 31,~~3, 2017. HeMr. Lembo has served as ~~a Trustee~~Executive Vice President of ~~the NSTAR Foundation~~Eversource Energy since ~~May 9,~~August 8, 2016.

Gregory B. Butler. Mr. Butler has served as ~~Executive Vice President and~~ General Counsel of Eversource Energy ~~CL&P, NSTAR Electric, NSTAR Gas, PSNH, Yankee Gas and~~since May 1, 2001. He has served as Executive Vice President of Eversource ~~Service~~Energy since August 8, 2016. Mr. Butler has served as a Director of NSTAR Electric and NSTAR Gas since April 10, 2012; of Eversource Service since November 27, 2012; of CL&P, PSNH and Yankee Gas since April 22, 2009; and of Eversource Aquarion Holdings, Inc. Mr. Butler previously served as Senior Vice President and General Counsel of Eversource Energy from May 1, 2014 until August 8, 2016; of NSTAR Electric and NSTAR Gas from April 10, 2012 until August 8, 2016; of CL&P, PSNH, Yankee Gas and Eversource Service from March 9, 2006 until August 8, 2016; and as Senior Vice President, General Counsel and Secretary of Eversource Energy from April 10, 2012 until May 1, 2014. He has served as a Director of Eversource Energy Foundation, Inc. since December 1, 2002. He has been a Trustee of the NSTAR Foundation since April 10, 2012.

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

Penelope M. Conner. Ms. Carmody has served as a Director of Eversource Service since November 27, 2012. Previously Ms. Carmody served as Senior Vice President-Human Resources of Eversource Energy from May 4, 2016 until August 8, 2016; of Eversource Service from April 10, 2012 until August 8, 2016; as Senior Vice President-Human Resources of CL&P, PSNH and Yankee Gas from November 27, 2012 until September 29, 2014; of NSTAR Electric and NSTAR Gas from August 1, 2008 until September 29, 2014; and as a Director of CL&P, PSNH and Yankee Gas from April 10, 2012 until September 29, 2014; and of NSTAR Electric and NSTAR Gas from November 27, 2012 until September 29, 2014. Ms. Carmody has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012. She has served as a Trustee of the NSTAR Foundation since August 1, 2008.

~~Joseph R. Nolan, Jr.~~ ~~Mr. Nolan~~Conner has served as Executive Vice President-Customer Experience and ~~Corporate Relations~~Energy Strategy of Eversource Energy ~~and Eversource Service~~ since ~~August 8, 2016. Mr. Nolan has served as a Director of Eversource Service since November 27, 2012.~~May 5, 2021. Previously, ~~Mr. Nolan~~Ms. Conner served as Senior Vice ~~President-Corporate Relations of Eversource Energy from May 4, 2016 until August 8, 2016;~~President and Chief Customer Officer of Eversource Service from ~~April 10, 2012 to August 8, 2016; of NSTAR Electric and NSTAR Gas from April 10, 2012~~March 2, 2013 until ~~September 29, 2014; and of CL&P, PSNH and Yankee Gas from November 27, 2012 until September 29, 2014.~~ May 5, 2021.

James W. Hunt, III. Mr. Nolan previously served as a Director of CL&P, PSNH and Yankee Gas from April 10, 2012 until September 29, 2014; and of NSTAR Electric and NSTAR Gas from November 27, 2012 until September 29, 2014. Mr. Nolan has served as a Director of Eversource Energy Foundation, Inc. since April 10, 2012, and as Executive Director of Eversource Energy Foundation, Inc. since October 15, 2013. He has served as a Trustee of the NSTAR Foundation since October 1, 2000.

~~Leon J. Olivier. Mr. Olivier~~Hunt has served as Executive Vice ~~President-Enterprise Energy Strategy~~President-Corporate Relations and ~~Business Development~~Sustainability of Eversource Energy since ~~September 2, 2014;~~May 5, 2021 and ~~of Eversource Service since August 11, 2014. Mr. Olivier has served~~ as ~~a Director of Eversource Service since January 17, 2005. Mr. Olivier previously served as Executive Vice President and Chief Operating Officer~~Secretary of Eversource Energy ~~from May 13, 2008 until September 2, 2014;~~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 ~~13, 2008 until August 11, 2008;~~5, 2021 and as Senior Vice President-Regulatory Affairs and Chief ~~Executive~~Communications Officer of ~~NSTAR Electric and NSTAR Gas~~Eversource Service from ~~April 10, 2012~~October 3, 2016 until August 11, 2014; of CL&P, PSNH and Yankee Gas from January 15, 2007 until August 11, 2014; as a Director of NSTAR Electric and NSTAR Gas from November 27, 2012 until September 29, 2014; of PSNH and Yankee Gas from JanuaryDecember 17, 2005 until September 29, 2014; and of CL&P from September 10, 2001 until September 29, 2014. He has served as a Director of Eversource Energy Foundation, Inc. since April 1, 2006. Mr. Olivier has served as a Trustee of the NSTAR Foundation since April 10, 2012.2019.

Werner J. Schweiger. Mr. Schweiger has served as Executive Vice President and Chief Operating Officer of Eversource Energy since September 2, ~~2014; of Eversource Service since August 11, 2014; and as Chief Executive Officer of CL&P, NSTAR Electric, NSTAR Gas, PSNH and Yankee Gas since August 11,~~ 2014. Mr. Schweiger has served as a Director of Eversource Service, NSTAR Gas and Yankee Gas since September 29, 2014; and of CL&P, PSNH and NSTAR Electric since May 28, 2013. He previously served as President of CL&P from June 2, 2015 until June 27, 2016; as President of NSTAR Gas and Yankee Gas from September 29, 2014 until November 10, 2014; as President-Electric Distribution of Eversource Service from January 16, 2013 until August 11, 2014; as President of NSTAR Electric from April 10, 2012 until January 16, 2013; and as a Director of NSTAR Electric from November 27, 2012 until January 16, 2013. Mr. Schweiger has served as a Director of Eversource Energy Foundation, Inc. since September 29, 2014. He has served as a Trustee of the NSTAR Foundation since September 29, 2014.

Jay S. Buth. Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of Eversource Energy ~~CL&P, NSTAR Electric, NSTAR Gas, PSNH, Yankee Gas and Eversource Service~~ 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, ~~2019,~~2022, there were ~~35,874~~31,020 registered common shareholders of our company on record. As of the same date, there were a total of ~~316,981,088~~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 ~~2013~~2016 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period ~~2013~~2016 through ~~2018,~~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,
2013 2014 2015 2016 2017 2018
Eversource Energy $100 $130 $129 $144 $170 $180
EEI Index $100 $129 $124 $145 $163 $169
S&P 500 $100 $114 $115 $129 $157 $150

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 ~~shares awarded under the company's incentive plan and dividend reinvestment plan and~~ 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, 2018 95,834
$ 61.32
—
—
November 1 - November 30, 2018 2,248
64.62
—
—
December 1 - December 31, 2018 180,526
64.42
—
—
Total 278,608
$ 63.36
—
—

Item 6. ~~Selected Consolidated Financial Data~~Removed and Reserved

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

(Thousands of Dollars, except percentages and
common share information)
2018 2017 2016 2015 2014
Balance Sheet Data:
Property, Plant and Equipment, Net $ 25,610,428
$ 23,617,463
$ 21,350,510
$ 19,892,441
$ 18,647,041
Total Assets 38,241,256
36,220,386
32,053,173
30,580,309
29,740,387
Common Shareholders' Equity 11,486,817
11,086,242
10,711,734
10,352,215
9,976,815
Noncontrolling Interest - Preferred Stock of Subsidiaries 155,570
155,570
155,568
155,568
155,568
Long-Term Debt ^(a)
13,086,062
12,325,520
9,603,237
9,034,457
8,851,600
Obligations Under Capital Leases^(a)
10,735
9,898
8,924
8,222
9,434
Income Statement Data:

Operating Revenues $ 8,448,201
$ 7,751,952
$ 7,639,129
$ 7,954,827
$ 7,741,856
Net Income $ 1,040,519
$ 995,515
$ 949,821
$ 886,004
$ 827,065
Net Income Attributable to Noncontrolling Interests 7,519
7,519
7,519
7,519
7,519
Net Income Attributable to Common Shareholders $ 1,033,000
$ 987,996
$ 942,302
$ 878,485
$ 819,546
Common Share Data:

Net Income Attributable to Common Shareholders:

Basic Earnings Per Common Share $ 3.25
$ 3.11
$ 2.97
$ 2.77
$ 2.59
Diluted Earnings Per Common Share $ 3.25
$ 3.11
$ 2.96
$ 2.76
$ 2.58
Dividends Declared Per Common Share $ 2.02
$ 1.90
$ 1.78
$ 1.67
$ 1.57
Market Price - Closing (end of year) ^(b)
$ 65.04
$ 63.18
$ 55.23
$ 51.07
$ 53.52
Book Value Per Common Share (end of year) $ 36.25
$ 34.98
$ 33.80
$ 32.64
$ 31.47
Tangible Book Value Per Common Share (end of year) ^(c)
$ 22.27
$ 21.00
$ 22.70
$ 21.54
$ 20.37
Rate of Return Earned on Average Common Equity (%) ^(d)
9.2
9.1
9.0
8.7
8.4
Market-to-Book Ratio (end of year) ^(e)
1.8
1.8
1.6
1.6
1.7

CL&P Selected Financial Data (Unaudited)
(Thousands of Dollars) 2018 2017 2016 2015 2014
Balance Sheet Data:

Property, Plant and Equipment, Net $ 8,909,701
$ 8,271,030
$ 7,632,392
$ 7,156,809
$ 6,809,664
Total Assets 11,409,719
10,630,246
10,035,044
9,592,957
9,344,400
Common Stockholder's Equity 4,199,317
3,587,127
3,470,387
3,140,717
2,936,767
Preferred Stock Not Subject to Mandatory Redemption 116,200
116,200
116,200
116,200
116,200
Long-Term Debt ^(a)
3,254,016
3,059,135
2,766,010
2,763,682
2,841,951
Obligations Under Capital Leases^(a)
4,465
5,711
6,767
7,624
8,439
Income Statement Data:

Operating Revenues 3,096,174
2,887,359
2,805,955
2,802,675
2,692,582
Net Income 377,717
376,726
334,254
299,360
287,754
Common Stock Data:

Cash Dividends on Common Stock 60,000
254,800
199,599
196,000
171,200

^(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.

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 2021 compared to fiscal year 2020 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2019 items and of fiscal year 2020 compared to fiscal year 2019, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2020 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 non-GAAP financial measures referencing our 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 PURA and our 2021 and 2020 earnings and EPS excluding certain acquisition and transition costs.

We use ~~this~~these non-GAAP financial ~~measure~~measures to evaluate and provide details of earnings results by ~~business.~~business and to more fully compare and explain our 2021 and 2020 results without including these items. This information is among the primary indicators we use as a basis for evaluating performance and planning and forecasting of future periods. We believe the impacts of the 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 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 byof our business. ~~This~~These non-GAAP financial ~~measure~~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, 2018 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 ~~$1.03~~$1.22 billion, or ~~$3.25~~$3.54 per share, in ~~2018,~~2021, compared with ~~$988.0 million,~~$1.21 billion, or ~~$3.11~~$3.55 per share, in ~~2017.~~ 2020.

•Our 2021 results include after-tax costs recorded within the electric distribution segment ~~earned $455.4~~resulting from a PURA-approved CL&P settlement agreement and an after-tax charge at CL&P for a PURA assessment as a result of 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 ~~$1.44~~$0.32 per share in ~~2018, compared with $497.4~~2021. Our 2020 results include after-tax acquisition and transition costs of $32.1 million, or ~~$1.57~~$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 ~~2017. Our electric transmission segment earned $427.2 million,~~2021, compared with $1.24 billion, or ~~$1.34~~$3.64 per share, in 2018, compared with $391.9 million, or $1.23 per share, in 2017. Our natural gas distribution segment earned $93.2 million, or $0.29 per share, in 2018, compared with $74.6 million, or $0.23 per share, in 2017. Our water distribution segment earned $30.9 million, or $0.10 per share, in 2018, compared with a net loss of $1.2 million in 2017.2020.

~~Eversource parent and other companies earned $26.3 million, or $0.08 per share, in 2018, compared with $25.3 million, or $0.08 per share, in 2017.~~

•We currently project ~~2019 earnings~~2022 non-GAAP earning guidance of between ~~$3.40~~$4.00 per share and ~~$3.50~~$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 ~~$1.78~~$1.96 billion in ~~2018,~~2021, compared with ~~$2.00~~$1.68 billion in ~~2017.~~2020. Investments in property, plant and equipment totaled ~~$2.52~~$3.18 billion in ~~2018~~2021 and ~~$2.35~~$2.94 billion in ~~2017.~~ 2020.

•Cash ~~and cash equivalents~~ totaled ~~$108.1~~$66.8 million as of December 31, ~~2018,~~2021, compared with ~~$38.2~~$106.6 million as of December 31, ~~2017.~~

2020. Our available borrowing capacity under our commercial paper programs totaled $1.14 billion as of December 31, 2021. In ~~2018,~~2021, we issued ~~$2.20~~$3.23 billion of new long-term debt ~~consisting of $1.55 billion at Eversource parent, $500 million at CL&P, $50 million at Yankee Gas,~~ and $100 million at NSTAR Gas. Proceeds from these new issuances were used primarily to repay short-term borrowings and repay long-term debt at maturity. In 2018, PSNH issued $635.7 million of securitized RRBs. In 2018, we repaid ~~at maturity, $1.05~~$1.14 billion of ~~previously~~long-term debt.

•In 2021, we issued ~~long-term debt, consisting of $450 million at Eversource parent, $300 million at CL&P, $199.3 million at PSNH and $100 million at Yankee Gas.~~

~~In 2018, we paid cash~~ dividends ~~of $640.1 million, or $2.02~~totaling $2.41 per common share, compared with ~~$602.1 million, or $1.90~~dividends of $2.27 per common share in ~~2017.~~ 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 ~~6, 2019,~~2, 2022, our Board of Trustees approved a common share dividend payment of ~~$0.535~~$0.6375 per share, payable on March ~~29, 2019~~31, 2022 to shareholders of record as of March 5, 2019. The 2019 dividend represents an increase of 5.9 percent over the dividend paid in December 2018, and is the equivalent to dividends on common shares of approximately $678 million on an annual basis.

3, 2022.

•We project to make capital expenditures of ~~$12.75~~$18.14 billion from ~~2019~~2022 through ~~2023,~~2026, of which we expect ~~$8.06~~$7.02 billion to be in our electric ~~and~~distribution segment, $4.53 billion to be in our natural gas distribution ~~segments, $3.35~~segment, $4.60 billion to be in our electric transmission segment, and ~~$0.62~~$0.89 billion to be in our water distribution segment. We also project to invest ~~$0.72~~$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 NPT or~~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.

In December 2018, CYAPC paid $145 million to the DOE to partially settle its pre-1983 spent nuclear fuel obligation, which is classified as long-term debt on Eversource's consolidated balance sheet. CYAPC funded this payment from proceedsStrategic and Regulatory Items:

•On January 18, 2022, South Fork Wind received BOEM’s final approval of its ~~spent nuclear fuel trust,~~Construction and Operations Plan (COP), following BOEM’s November 2021 issuance of the Record of Decision, which ~~is classified~~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 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 in a fund to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages, as ~~marketable securities on Eversource's consolidated balance sheet. Eversource consolidates CYAPC because CL&P's, NSTAR Electric's~~approved by the PURA. In exchange for the $75 million of customer credits and ~~PSNH's combined ownership and voting interests in CYAPC is 63 percent.~~assistance, PURA’s interim rate reduction docket was resolved without findings. As a result of ~~consolidating CYAPC, CYAPC's payment~~the settlement agreement, neither the 90 basis point reduction to CL&P’s return on equity introduced in PURA’s storm-related decision issued April 28, 2021, nor the 45 basis point reduction to CL&P’s return on equity included in PURA’s decision issued September 14, 2021 in the interim rate reduction docket, will be implemented. Additionally, CL&P agreed to withdraw its pending appeals related to the ~~DOE is included~~$28.6 million storm performance penalty imposed in ~~operating cash flows on Eversource's 2018 consolidated statement of cash flows.~~

~~Strategic, Legislative, Regulatory, Policy~~PURA’s April 28, 2021 and ~~Other Items:~~

On February 8, 2019, Eversource and Ørsted entered into a 50-50 partnership for key offshore wind assets in the Northeast. Eversource paid approximately $225 million for a 50 percent interest in Ørsted’s Revolution Wind and South Fork Wind power projects, as well as the 257-square-mile tract off the coasts of Massachusetts and Rhode Island. Revolution Wind is a 700 MW offshore wind power project located approximately 15 miles southJuly 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 Rhode Island coast, and South Fork Wind is approximately a 130 MW offshore wind power project located 35 miles east of Long Island. Subject to permitting, finalized power purchase agreements, where applicable, further development, and final investment decisions by Ørsted and Eversource, Revolution Wind is expected to be commissioned in 2023 and South Fork Wind is expected by the end of 2022.

~~On December 12, 2018, PURA approved the Yankee Gas distribution rate case~~October 1, 2021 settlement agreement ~~which included, among other things, rate increases of $1.4 million, $15.8~~and the Storm Isaias penalty imposed by PURA totaled $103.6 million, and ~~$13.0~~the after-tax earnings impact was $86.1 million, ~~for rate years beginning November 15, 2018, January 1, 2020, and January 1, 2021, respectively. As a result of this decision, we recognized an $11.7 million pre-tax benefit to earnings~~or $0.25 per share, in ~~2018 ($4.0 million at the natural gas distribution segment and $7.7 million at Eversource Parent and Other Companies).~~2021.

Earnings Overview

Consolidated: Below is a summary of our earnings by business, which also reconciles the non-GAAP financial ~~measure~~measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP ~~measure~~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,
2018
2017 ⁽¹⁾
2016
(Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share
Net Income Attributable to Common Shareholders (GAAP) $ 1,033.0
$ 3.25
$ 988.0
$ 3.11
$ 942.3
$ 2.96
Regulated Companies $ 1,006.7
$ 3.17
$ 962.7
$ 3.03
$ 911.3
$ 2.86
Eversource Parent and Other Companies 26.3
0.08
25.3
0.08
31.0
0.10
Net Income Attributable to Common Shareholders (GAAP) $ 1,033.0
$ 3.25
$ 988.0
$ 3.11
$ 942.3
$ 2.96

Regulated Companies: Our regulated companies comprise the electric distribution, ~~(including NSTAR Electric's solar power facilities and PSNH's generation facilities prior to sale in 2018),~~ 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,
2018
2017 ⁽¹⁾
2016
(Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share
Electric Distribution $ 455.4
$ 1.44
$ 497.4
$ 1.57
$ 462.8
$ 1.46
Electric Transmission 427.2
1.34
391.9
1.23
370.8
1.16
Natural Gas Distribution 93.2
0.29
74.6
0.23
77.7
0.24
Water Distribution 30.9
0.10
(1.2 ) —
N/A
N/A
Net Income - Regulated Companies $ 1,006.7
$ 3.17
$ 962.7
$ 3.03
$ 911.3
$ 2.86

⁽¹⁾ ~~Our water distribution business was determined~~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 beearnings for customer credits provided to customers over a ~~reportable segment beginning in 2018.~~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 ~~2017 segment information has been recast~~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 ~~conform~~customer bills and a $0.2 million fine to the ~~current year presentation.~~ 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 decreased ~~$42.0~~$73.9 million in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to ~~lower generation~~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 ~~$29.7~~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 settlement agreement and 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 ~~resulting~~effective January 1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020, and higher earnings from ~~the sales of its thermal and hydroelectric generation assets in 2018, higher depreciation expense,~~CL&P's capital tracker mechanism due to increased electric system improvements. Those earnings increases were partially offset by higher operations and maintenance expense driven by higher ~~interest~~employee-related expenses and higher vegetation management costs, higher depreciation expense, higher property tax expense, and higher ~~property and other tax~~interest expense. The earnings decrease was partially offset by higher non-service income from our benefit plans, the impact of the CL&P base distribution rate increase effective May 1, 2018, and the recognition of carrying charges on PSNH storm costs approved for recovery. Earnings were also favorably impacted by lower income tax expense, net of lower distribution revenues resulting from the Tax Cuts and Jobs Act.

Our electric transmission segment earnings increased ~~$35.3~~$42.1 million in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure, partially offset by a reduction in the benefits from tax reform as compared to 2017 and approximately $6 million (after-tax) in tax-related regulatory assets that we concluded were not recoverable from customers.infrastructure.

Our natural gas distribution segment earnings increased ~~$18.6~~$70.7 million in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to anthe incremental impact of EGMA earnings of $43.0 million. Additionally, the earnings increase ~~in sales volumes~~was due to base distribution rate increases at NSTAR Gas effective November 1, 2021 and ~~demand revenues driven by colder January, April, October~~2020 and ~~November weather in Connecticut in 2018, as compared to the same periods in 2017, as well as growth in new customer base, and an earnings benefit resulting from the~~at Yankee Gas ~~rate case settlement approved by PURA~~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 ~~December 2018. Earnings were also favorably impacted by lower income tax expense, net of lower distribution revenues resulting from the Tax Cuts and Jobs Act.~~natural gas infrastructure. The earnings increase ~~in earnings~~ was partially offset by higher ~~operations and maintenance~~depreciation expense, higher property tax expense and higher ~~depreciation~~interest expense. ~~Effective November 15, 2018, fluctuations~~

Our water distribution segment earnings decreased $4.4 million in ~~Connecticut natural gas sales volumes no longer impact earnings~~2021, as compared to 2020, due primarily to the absence in 2021 of an after-tax gain of $3.5 million and lower revenues both as a result of ~~a decoupled rate structure at Yankee Gas approved in~~ the ~~2018 rate case settlement.~~

~~Our 2018 and 2017 water distribution segment results reflect the earnings~~sale of the ~~Aquarion~~ water ~~distribution business, which was acquired on December 4, 2017.~~system and treatment plant in Hingham, Massachusetts in July 2020.

Eversource Parent and Other Companies:Eversource parent and other companies ~~earned $26.3~~had an increased loss of $19.2 million in ~~2018,~~2021, as compared ~~with $25.3 million in 2017. Earnings were positively impacted by~~to 2020, due primarily to a ~~lower~~higher effective tax rate ~~due in part to an $18 million aggregate after-tax benefit resulting from both federal~~ and ~~Connecticut tax law changes, unrealized gains on our investment in a renewable energy fund, and an income tax benefit associated with our investments.~~higher employee-related costs. The ~~increase in earnings~~higher loss was partially offset by a ~~pre-tax $32.9~~decrease of $7.0 million ~~($26 million after-tax) other-than-temporary impairment to our equity method investment~~ in ~~the Access Northeast project, higher interest expense,~~acquisition and transition costs of EGMA recorded at Eversource parent and a lower earnings benefit in 2018, as compared to 2017, related to the allowed recovery of certain previously expensed merger-related costs in distribution rates. For further information on the impairment of our Access Northeast project, see "Business Development and Capital Expenditures - Natural Gas Transmission Project" in this ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

~~Electric, Natural Gas and Water Sales Volumes:~~ 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~~higher return at ~~PSNH and natural gas sales volumes at Yankee Gas prior to November 15, 2018 impacted earnings ("Traditional" in the table below). For CL&P, NSTAR Electric (effective February 1, 2018~~Eversource Service as a result of increased investments in property, plant and equipment.

Impact of COVID-19

COVID-19 has adversely affected customers, workers and the U.S. economy. We provide a ~~DPU-approved rate case decision), Yankee Gas (effective November 15, 2018 as a result~~critical service to our customers and have taken extensive measures to maintain its safety and reliability. We continue to address the impacts of ~~a PURA-approved rate case settlement)~~the COVID-19 pandemic and ~~NSTAR Gas, fluctuations in retail sales volumes do~~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 ~~earnings due~~ to ~~their respective regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled"~~us in the ~~table below). These distribution revenues are decoupled from their customer sales volumes, which breaks~~future will vary, and depend on the ~~relationship between sales volumes~~duration, scope and ~~revenues recognized. Fluctuations in water sales volumes largely do not impact earnings as our Connecticut water distribution business is also decoupled.~~

A 2016 DPU-approved energy efficiency plan at NSTAR Electric authorized recovery of LBR in its eastern Massachusetts service territory until LBR was covered under a decoupled rate structure, which occurred on February 1, 2018. NSTAR Electric recognized LBR of $7.0 million in 2018, compared to $73.7 million in 2017, and no longer has an LBR recovery mechanism effective February 1, 2018.

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, for the years ended December 31, 2018 and 2017, is as follows:

Electric Firm Natural Gas Water
Sales Volumes (GWh) Percentage
Increase Sales Volumes (MMcf) Percentage
Increase/(Decrease) Sales Volumes (MG) Percentage
Increase/(Decrease)
2018
2017 ⁽¹⁾
2018
2017⁽²⁾
2018
2017 ⁽³⁾

Traditional 9,790
9,465
3.4 % 44,715
39,455

13.3 % 2,252
2,202
2.3 %
Decoupled and Special Contracts ⁽⁴⁾
43,591
42,781
1.9 % 61,242
61,571
(0.5 )% 21,479
22,565
(4.8 )%
Total Sales Volumes 53,381
52,246
2.2 % 105,957
101,026
4.9 % 23,731
24,767
(4.2 )%

⁽¹⁾

In 2017 and in the month of January 2018, NSTAR Electric operated under two different rate structures (traditional and decoupled) based on its service territory geography. Effective February 1, 2018, NSTAR Electric operated entirely under a decoupled rate structure. The 2017 sales volumes for NSTAR Electric have been recast to present February through December 2017 as decoupled, to conform to the current year presentation.


⁽²⁾	In 2017 and until November 14, 2018, Yankee Gas operated under a traditional rate structure. Effective November 15, 2018, Yankee Gas operated under a decoupled rate structure. The 2017 sales volumes for Yankee Gas have been recast to present November 15th through December 2017 as decoupled, to conform to the current year presentation.


⁽³⁾	~~Eversource acquired its water distribution business on December 4, 2017. Full 2017 sales volumes have been presented for comparative purposes.~~


⁽⁴⁾	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.

Traditional retail electric sales volumes were higher in 2018, as compared to 2017, due primarily to warmer summer weather in 2018 and colder weather in January 2018 at NSTAR Electric (prior to its decoupled rate structure). Cooling degree days in 2018 were 25.8 percent higher in New Hampshire, as compared to 2017. Heating degree days in January of 2018 were 21.7 percent higher in the Boston metropolitan area, as compared to January 2017.

~~Our firm natural gas sales volumes are subject to many~~severity of the ~~same influences~~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 ~~retail electric sales volumes. In addition, they have benefited from~~businesses primarily relate to collectability of customer ~~growth in our natural gas distribution segment. Traditional firm natural gas sales volumes were higher in 2018, as compared to 2017, due primarily to colder January, April, October~~receivables and ~~November weather in 2018. Heating degree days in January through November 2018 were 9.1 percent higher in Connecticut, as compared to the same period in 2017.~~customer payment plans and increased expenses for cleaning and supplies for personal protective equipment.

~~Liquidity~~

~~Cash and cash equivalents totaled $108.1 million as~~As of December 31, ~~2018, compared with $38.2~~2021, our allowance for uncollectible customer receivable balance of $417.4 million, as of ~~December 31, 2017.~~

~~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 and Yankee Gas~~the extent those costs are also parties to a five-year $1.45 billion revolving credit facility. Effective December 10, 2018, the revolving credit facility's termination date was extended for one additional year to December 8, 2023. 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 10, 2018, the revolving credit facility's termination date was extended for one additional year to December 8, 2023. 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) 2018 2017 2018 2017 2018 2017
Eversource Parent Commercial Paper Program $ 631.5
$ 979.3
$ 818.5
$ 470.7
2.77 % 1.86 %
NSTAR Electric Commercial Paper Program 278.5
234.0
371.5
416.0
2.50 % 1.55 %

There were no borrowings outstanding on either the Eversource parent or NSTAR Electric revolving credit facilities as of December 31, 2018 or 2017. Eversource's water distribution segment has a $100.0 million revolving credit facility, which expires on August 19, 2019, and there were no amounts outstanding as of December 31, 2018 and $76.0 million outstanding as of December 31, 2017.

Amounts outstanding under the commercial paper programs and revolving credit facility 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 issuances~~order, PSNH removed its $0.6 million deferral of net incremental COVID-19 costs in 2021. In New Hampshire, the moratorium on ~~January 8, 2018,~~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, $201.2 million of commercial paper borrowings under~~evaluation performed, for the ~~Eversource parent commercial paper program were reclassified as Long-Term Debt as of~~year ended December 31, ~~2017.~~

~~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. In addition, growth in Eversource's key business initiatives requires cash infusion to those subsidiaries. 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, ~~2018, 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 ~~PSNH~~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 ~~$57.0 million.~~ the impact of 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 uncollectible expense that impacts earnings, facilities and fleet cleaning, sanitizing costs and supplies for personal protective equipment, net of cost savings and benefits under the CARES Act. In 2021, we deferred $15.8 million of 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, ~~2017, 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, ~~of $69.5 million to CL&P~~ and ~~$262.9 million to PSNH. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent~~existing cash, and are ~~classified in current liabilities on the respective subsidiary's balance sheets.~~

~~Long-Term Debt:The following table summarizes~~used to fund their liquidity and capital requirements. Eversource’s regulated companies typically maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. Short-term borrowings are also used as a bridge to long-term debt ~~issuances and repayments:~~

(Millions of Dollars) Issue Date Issuances/(Repayments) Maturity Date Use of Proceeds for Issuances/
Repayment Information
CL&P:
4.00% 2018 Series A First Mortgage Bonds March 2018 $ 500.0
April 2048 Repaid long-term debt that matured in 2018 and repaid short-term borrowings
5.65% 2008 Series A First Mortgage Bonds May 2008 (300.0 ) May 2018 Repaid at maturity on May 1, 2018
PSNH:
6.00% 2008 Series O First Mortgage Bonds May 2008 (110.0 ) May 2018 Repaid at maturity on May 1, 2018
2001 Series A Pollution Control Revenue Bonds December 2001 (89.3 ) May 2021 Redeemed on November 28, 2018 at a redemption price of $89.3 million
Other:
Eversource Parent 2.50% Series I Senior Notes ⁽¹⁾
January 2018 200.0
March 2021 Repaid short-term borrowings
Eversource Parent 3.30% Series M Senior Notes January 2018 450.0
January 2028 Repaid long-term debt that matured in 2018
Eversource Parent 3.80% Series N Senior Notes December 2018 400.0
December 2023 Repaid short-term borrowings
Eversource Parent 4.25% Series O Senior Notes December 2018 500.0
April 2029 Repaid short-term borrowings
Eversource Parent 1.60% Series G Senior Notes January 2015 (150.0 ) January 2018 Repaid at maturity on January 15, 2018
Eversource Parent 1.45% Series E Senior Notes May 2013 (300.0 ) May 2018 Repaid at maturity on May 1, 2018
Yankee Gas 4.13% Series O First Mortgage Bonds September 2018 50.0
October 2048 Repaid long-term debt that matured in 2018
Yankee Gas 6.90% Series J First Mortgage Bonds October 2008 (100.0 ) October 2018 Repaid at maturity on October 1, 2018
NSTAR Gas 4.09% Series P First Mortgage Bonds September 2018 100.0
October 2048 Repaid short-term borrowings

⁽¹⁾ ~~These notes are part~~financings. The levels of short-term borrowing may vary significantly over the course of the ~~same series issued by Eversource parent~~year due to the impact of fluctuations in ~~March 2016. The aggregate outstanding principal amount of these notes is now $450 million.~~

~~Rate Reduction Bonds:~~ PSNH Funding LLC 3 (PSNH Funding) is a bankruptcy remote, special purpose, wholly-owned, consolidated subsidiary of PSNH. PSNH Funding was formed solely to issue RRBs to finance PSNH’s unrecovered remaining costs associated with the divestiture of its generation assets.

On May 8, 2018, PSNH Funding issued $635.7 million of securitized RRBs in multiple tranches with a weighted average interest rate of 3.66 percent, and final maturity dates ranging from 2026 to 2035. The RRBs are expected to be repaid by February 1, 2033. RRB payments consist of principal and interest and will be paid semi-annually, beginning on February 1, 2019. The RRBs were issued 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.~~

~~Cash Flows:~~ ~~Cash flows provided by operating activities totaled $1.78 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,~~from operations, dividends paid, capital contributions received 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, as described below. 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.

CYAPC is obligated to pay the DOE for the costs to dispose of spent nuclear fuel and high-level radioactive waste generated from its nuclear fuel facility prior to April 7, 1983. Eversource consolidates CYAPC because CL&P's, NSTAR Electric's and PSNH's combined ownership and voting interests in CYAPC is 63 percent. CYAPC's obligation to the DOE is classified as long-term debt on Eversource's consolidated balance sheet. In December 2018, CYAPC paid $145 million to the DOE to partially settle its pre-1983 spent nuclear fuel obligation. CYAPC funded this payment from proceeds of its spent nuclear fuel trust, which is classified as marketable securities on Eversource's consolidated balance sheet. As a result of consolidating CYAPC, Eversource has reflected CYAPC's payment to the DOE within operating cash flows on its 2018 consolidated statement of cash flows.financings.

In 2018, we paid cash dividends of $640.1 million, or $2.02 per common share, compared with $602.1 million, or $1.90 per common share, in 2017. Our quarterly common share dividend payment was $0.505 per share in 2018, as compared to $0.475 per common share in 2017. On February 6, 2019, our Board of Trustees approved a common share dividend payment of $0.535 per share, payable on March 29, 2019 to shareholders of record as of March 5, 2019. The 2019 dividend represents an increase of 5.9 percent over the dividend paid in December 2018, and is the equivalent to dividends on common shares of approximately $678 million on an annual basis.

~~In 2018, CL&P, NSTAR Electric and PSNH paid $60.0 million, $228.0 million and $150.0 million, respectively, in common stock dividends to Eversource parent.~~

Beginning in 2019, Eversource began using treasury stock to fund the payment of shares awarded under the company's incentive plan and dividend reinvestment plan and matching contributions under the Eversource 401k Plan.

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 2018, investments for Eversource, CL&P, NSTAR Electric and PSNH were $2.52 billion, $864.1 million, $725.8 million and $277.3 million, respectively.

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 $2.52 billion in cash capital spend in 2018.~~period. In addition, ~~growth~~Eversource’s investments in ~~Eversource's key~~its offshore wind business ~~initiatives in 2018 required cash contributions of $205.2 million, which~~ are recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by ~~$1.82~~$2.58 billion, ~~$188.7 million, $430.8~~$537.0 million, and ~~$158.6~~$165.0 million at Eversource, ~~CL&P,~~ NSTAR Electric and PSNH, respectively, as of December 31, ~~2018.~~2021.

As of December 31, ~~2018, $801.1 million~~2021, $1.18 billion of Eversource's long-term debt, including ~~$350.0~~$750.0 million ~~$250.0 million, $150.0 million, $50.0 million and $1.1 million for~~at Eversource parent, ~~CL&P, PSNH,~~$400.0 million at NSTAR Electric, $20.0 million at Yankee Gas, and $5.4 million at Aquarion, ~~respectively,~~ will mature within the next 12 months. Included in the current portion of long-term debt is $36.2 million related to fair value adjustments from our 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 ~~the~~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 ~~Ratings:~~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 ~~12, 2019, S~~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, ~~changed~~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 ~~outlook~~statements of cash flows do not include amounts incurred on ~~all its credit ratings~~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 ~~stable~~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 ~~negative.~~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

Negative

BBB+

~~Positive~~Stable

CL&P

A3A

Stable

A+A3

Negative

A-

~~Stable~~Negative

NSTAR Electric

A2A

~~Positive~~Stable

A+A1

~~Negative~~Stable

Stable

PSNH

A3A

Stable

A+A3

~~Negative~~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

A Baa1

Negative

BBB+

~~Positive~~Stable

CL&P

A1A+

Stable

~~AA-~~ A1

Negative

A+

~~Stable~~Negative

NSTAR Electric

A2A

~~Positive~~Stable

A+ A1

~~Negative~~Stable

A+

Stable

PSNH

A1A+

Stable

~~AA-~~ A1

~~Negative~~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 ~~$2.86~~$3.54 billion in ~~2018, $2.52~~2021, $3.06 billion in ~~2017,~~2020, and ~~$2.21~~$3.06 billion in ~~2016.~~2019. These amounts included ~~$184.6~~$238.0 million in ~~2018, $165.9~~2021, $239.1 million in ~~2017,~~2020, and ~~$137.7~~$239.0 million in ~~2016~~2019 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

Electric Transmission Business: Our consolidated electric transmission business capital expenditures increased by ~~$91.1~~$151.7 million in ~~2018,~~2021, as compared to ~~2017.~~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) 2018 2017 2016
CL&P $ 465.5
$ 431.5
$ 338.3
NSTAR Electric 334.3
301.9
398.7
PSNH 194.2
155.6
119.0
NPT 29.4
43.3
40.9
Total Electric Transmission Segment $ 1,023.4
$ 932.3
$ 896.9

~~Northern Pass: Northern Pass is Eversource's planned 1,090 MW HVDC~~Our transmission ~~line that will interconnect from~~projects are designed to improve the ~~Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.~~

~~Northern Pass has achieved several key milestones, including receiving the following major permits:~~

~~National Energy Board of Canada permit issued, which authorizes the construction~~reliability of the ~~transmission line that will connect with Northern Pass at~~electric grid, meet customer demand for power, strengthen the ~~Québec-New Hampshire border on March 6, 2018;~~

~~NHPUC approval on February 12, 2018 for the proposed lease of certain land and easement rights from PSNH to NPT, concluding that the lease is in the public interest;~~

U.S. Forest Service Record of Decision on January 5, 2018, which allows NPT to install approximately 11 miles of underground transmission lines along existing roads through the White Mountain National Forest;

~~Province of Québec permit granted to HQ on December 21, 2017 to construct the hydroelectric transmission line that will connect at the border of New Hampshire;~~

~~DOE Record of Decision and Presidential Permit on November 16, 2017, which will allow construction of transmission facilities at the Québec-New Hampshire border; and~~

DOE final Environmental Impact Statement issued on August 10, 2017, which concluded that the proposed Northern Pass route is the preferred alternative, providing substantial benefits with only minimal impacts.

The following permits remain outstanding: the NHSEC Certificate of Site and Facility approving construction of the project in New Hampshire, the U.S. Forest Service Special Use Permit, as authorized by the January 5, 2018 Record of Decision, and the Army Corps of Engineers Permit allowing the discharge of dredging material or other fill into wetlandselectric grid's resilience against extreme weather and other ~~waters under Section 404 of the Clean Water Act~~safety and ~~Section 10 of the River~~security threats, and ~~Harbors Act.~~

~~On January 25, 2018, Northern Pass was selected~~increase access to clean power generation from ~~the 46 proposal packages submitted~~renewable sources, such as ~~the winning bidder in the~~solar and offshore wind. In Connecticut, Massachusetts clean energy request for proposal ("RFP"), which successfully positioned Northern Pass to provide a firm delivery of hydropower to Massachusetts. On February 1, 2018, the NHSEC voted to deny Northern Pass’ siting application. On March 28, 2018, the Massachusetts EDCs, in coordination with the DOER and an independent evaluator, notified Northern Pass that the EDCs had terminated its selection and all contract negotiations.

On March 30, 2018, the NHSEC released its written decision confirming its denial. On April 27, 2018, NPT filed a motion for rehearing with the NHSEC, and on July 12, 2018, the NHSEC issued its written decision denying Northern Pass’ motion for rehearing. On August 10, 2018, NPT filed an appeal to the New Hampshire Supreme Court, alleging that the NHSEC failed to follow applicable law in its review of the project. On October 12, 2018, the New Hampshire Supreme Court accepted this appeal. Subsequently, the NHSEC transmitted the record of its proceedings to the New Hampshire Supreme Court on December 11, 2018. Briefing of the appeal began on February 4, 2019. The New Hampshire Supreme Court has not set a date for oral argument. NPT intends to continue to pursue NHSEC approval to construct this project.

The March 2018 NHSEC decision denying Northern Pass' siting application caused us to review the recoverability of our Northern Pass project costs in the first quarter of 2018. In this recoverability review, we estimated undiscounted expected project cash flows and compared the result to our estimated project costs to determine whether the recorded amount was recoverable. Our undiscounted cash flows were substantially in excess of our estimated project costs. We completed this analysis and concluded that our project costs were recoverable as of March 31, 2018, based on our expectation that the Northern Pass project remains probable of being placed in service.

Consistent with Eversource’s and HQ’s long-term relationship to bring clean energy into New England, Eversource and HQ remain committed to Northern Pass and the many benefits this project will bring to our customers and the region. If, as a result of future events and changes in circumstances, a new recoverability review were to conclude that our project costs are not recoverable, then we would reduce Northern Pass' project costs to the estimated fair value, which could result in most of our $307 million of capitalized project costs being impaired. Such an impairment could have a material adverse effect on our financial position and results of operations.

~~Greater Boston Reliability Solution:~~ ~~In February 2015, ISO-NE selected the Greater Boston~~ and New Hampshire, ~~Solution (the "Solution"), proposed by Eversource~~our transmission projects include transmission line upgrades, the installation of new transmission lines, and ~~National Grid, to satisfy the requirements identified~~substation enhancements.

Our transmission projects in ~~the Greater Boston study. The Solution consists of a portfolio of~~Massachusetts include electric transmission upgrades in ~~southern New Hampshire and northern Massachusetts and continuing into~~ the greater Boston metropolitan area, of which 28 upgrades are in Eversource's service territory. The NHSEC issued its written order approving the New Hampshire upgrades on October 4, 2016. All the New Hampshire upgrades, including the Merrimack Valley Reliability Project, have been completed and placed in

~~service. We are currently pursuing the necessary regulatory and siting application approvals in Massachusetts. To date, we have received approval for five~~area. Two of these ~~projects from~~upgrades, the ~~Massachusetts Energy Facilities Siting Board~~Mystic-Woburn and ~~anticipate approval of two additional projects in~~ the ~~second quarter of 2019. Construction has also begun on numerous smaller projects, several of which have been placed in service. Most upgrades are expected to be completed by the end of 2019. Two~~Wakefield-Woburn reliability projects, are ~~expected to be in service by the end of 2020~~under construction and another project by mid-2021. We estimate our portion of the investment in the Solution will be approximately $560 million, of which $357.3 million has been spent and capitalized through December 31, 2018.

~~GHCC: The Greater Hartford Central Connecticut ("GHCC") projects, which have been approved by ISO-NE, consist of 27 projects with an expected investment of approximately $350 million that~~ are expected to be placed in service ~~through 2019. As~~by the second quarter of December 31, 2018, 23 projects have been placed in service, and four projects are in active construction. As of December 31, 2018, CL&P had spent and capitalized $232.0 million in costs associated with GHCC.

~~Seacoast Reliability Project: On April 12, 2016, PSNH filed a siting application with~~2023. The last remaining upgrade, the ~~NHSEC for the Seacoast~~Sudbury-Hudson Reliability Project, a 13-mile, 115kV transmission line within several New Hampshire communities, which proposes to use a combination of overhead, underground and underwater line design to help meet the growing demand for electricityreceived siting approval, however one appeal remains pending with expected resolution in the ~~Seacoast region. On December 10, 2018,~~first quarter of 2022. We 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 ~~NHSEC indicated its unanimous approval~~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 ~~the project, and subsequently issued its written decision~~approximately $140 million on January 31, 2019. This project is scheduled to be completed by the end of 2019. We estimate the investment in this project to be approximately $84 million, of which PSNH had spent and capitalized $31.2 million in costs through December 31, 2018.these transmission upgrades.

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
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 Generation —
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 Generation —
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

2016
Basic Business $ 179.8
$ 146.0
$ 70.0
$ 395.8
$ 70.7
N/A
$ 466.5
Aging Infrastructure 144.7
105.7
84.7
335.1
155.9
N/A
491.0
Load Growth and Other 48.6
89.2
17.3
155.1
44.2
N/A
199.3
Total Distribution 373.1
340.9
172.0
886.0
270.8
N/A
1,156.8
Generation —
—
17.5
17.5
—
N/A
17.5
Total $ 373.1
$ 340.9
$ 189.5
$ 903.5
$ 270.8
N/A
$ 1,174.3


⁽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.

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 ~~2019~~2022 through ~~2023,~~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) 2019 2020 2021 2022 2023
2019 - 2023
Total
CL&P Transmission $ 392
$ 179
$ 148
$ 135
$ 124
$ 978
NSTAR Electric Transmission 431
434
309
293
244
1,711
PSNH Transmission 164
133
116
120
123
656
Total Electric Transmission
$ 987
$ 746
$ 573
$ 548
$ 491
$ 3,345
Electric Distribution $ 1,217
$ 1,131
$ 1,132
$ 1,143
$ 1,109
$ 5,732
Natural Gas Distribution 459
473
439
483
476
2,330
Total Electric and Natural Gas Distribution
$ 1,676
$ 1,604
$ 1,571
$ 1,626
$ 1,585
$ 8,062
Water Distribution $ 109
$ 112
$ 126
$ 133
$ 143
$ 623
Information Technology and All Other $ 199
$ 137
$ 131
$ 128
$ 127
$ 722
Total $ 2,971
$ 2,599
$ 2,401
$ 2,435
$ 2,346
$ 12,752

The projections do not include investments related to ~~NPT or~~ 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 ~~Projects:~~

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

The offshore leases include a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode Island and a separate, adjacent 300-square-mile ocean lease located ~~in a 300-square-mile area of the Atlantic Ocean~~ approximately 25 miles south of the coast of Massachusetts and has the ultimate potential to generate at least 2,000 MW of clean, renewable energy. Eversource and Ørsted each hold a 50 percent ownership interest in Bay State Wind. Bay State Wind expects to participate, or has submitted proposals, in the following opportunities for future solicitations for offshore wind based on each state's clean energy requirements:

The New York State Energy Research and Development Authority ("NYSERDA") issued an RFP for 800 MW in November 2018. NYSERDA has the authority to award more than 800 MW in the first solicitation if sufficient attractive offers are received. On February 14, 2019, Bay State Wind submitted proposals, called Sunrise Wind, in response to the RFP. Contracts are expected to be awarded in 2019.

~~Massachusetts’ second offshore wind RFP for 400 MW to 800 MW is expected to be issued no later than mid-2019.~~

~~Bay State Wind previously participated in certain other New England RFPs during 2018, but was not selected.~~

~~Revolution Wind and South Fork Wind:~~ On February 8, 2019, Eversource and Ørsted entered into a 50-50 partnership for key offshore wind assets in the Northeast. Eversource paid approximately $225 million for a 50 percent interest in Ørsted’s Revolution Wind and South Fork Wind power projects, as well as the 257-square-mile tract off the coasts of Massachusetts and Rhode Island, owned by North East Offshore LLC. Ørsted acquired all three assets in November 2018 as part of its Deepwater Wind transaction.

~~This transaction builds upon the Eversource and Ørsted Bay State Wind partnership, which is on a separate 300-square-mile~~Massachusetts. In aggregate, these ocean ~~tract adjacent to the North East Offshore area. Together, the Bay State Wind and the North East Offshore~~ lease sites ~~jointly owned~~jointly-owned by Eversource and Ørsted could eventually ~~host~~develop at least 4,000 MW of clean, renewable offshore ~~wind.~~ wind energy.

The ~~two companies~~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

(1) The contractual capacity increased from 880 MWs to 924 MWs, as allowed under the original agreement with NYSERDA.

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

As of December 31, 2021 and 2020, Eversource's total equity investment balance in its offshore wind business was $1.21 billion and $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, and capitalized interest.

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

Federal Siting and Permitting Process:The federal siting and permitting process for each of our offshore wind projects commence with the filing of a Construction and Operations Plan (COP) application with BOEM.The first major milestone in the BOEM review process is an issuance of a Notice of Intent (NOI) to complete an Environmental Impact Statement (EIS). BOEM then provides a final review schedule for the project’s COP approval. BOEM conducts environmental and technical reviews of the COP. The EIS assesses the environmental, social, and economic impacts of constructing the project and recommends measures to minimize impacts. The Final EIS will ~~jointly manage permitting~~inform BOEM in deciding whether to approve the project or to approve with modifications and BOEM will then issue its Record of Decision. BOEM issues its final approval of the COP following the Record of Decision.

South Fork Wind filed its COP application with BOEM in 2018 and 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 and in August 2021, BOEM released its 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 received BOEM’s final approval of its COP. The COP approval outlines the project’s one nautical mile turbine spacing, the requirements on the construction methodology for ~~upcoming projects~~all work occurring in federal ocean waters, and ~~will honor all planned local investments~~mitigation measures to protect marine habitats and ~~agreements entered prior to this partnership.~~species.

Revolution Wind and Sunrise Wind filed their COP applications with BOEM in 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 ~~700 MW offshore wind power~~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, 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 ~~located approximately 15 miles south~~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 ~~coast, that~~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 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 East Hampton, New York will ~~deliver power~~be the first to ~~Rhode Island (400 MW)~~begin. Offshore installation, including the project’s monopile foundations, 11-megawatt wind turbines, and ~~Connecticut (300 MW).~~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 ~~a 130 MW~~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 ~~power project, located 35 miles east of Long Island,~~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 ~~will interconnect into eastern Long Island where it will deliver power to households under a long-term power purchase agreement with~~ the ~~Long Island Power Authority. Subject to permitting, finalized power purchase agreements, where applicable, further development,~~three projects are completed and ~~final investment decisions by Ørsted and Eversource, Revolution Wind is expected to be commissioned in 2023 and South Fork Wind is expected~~are in-service by the end of ~~2022.~~2025, as planned.

~~Natural Gas Transmission Project:~~ Access Northeast is 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"). Eversource owns a 40 percent interest in the project, which is accounted for as an equity method investment.

In 2015 and 2016, AGT sought to secure long-term natural gas pipeline capacity contracts with EDCs in Massachusetts, Connecticut, New Hampshire, Maine, and Rhode Island. Subsequently, in 2016, the Massachusetts Supreme Judicial Court and the NHPUC each ruled that state statutes precluded the state regulatory agencies from approving those contracts in Massachusetts and New Hampshire, respectively. The New Hampshire Supreme Court overruled the NHPUC decision in May 2018. Legislative changes are needed in Massachusetts to allow the DPU to approve natural gas pipeline capacity contracts. No such changes have occurred during any legislative session to date.

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. As a result of these events, compounded by the failure to secure Massachusetts legislation to date, we believe there is significant uncertainty around the future timing of, and ability to secure, needed legislative change affecting the natural gas industry and pipeline expansion, which may significantly delay the completion of the Access Northeast project.

Eversource identified the September 2018 natural gas series of explosions, compounded by the adverse legislative environment, as negative evidence that indicated potential impairment. 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. 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.

FERC Regulatory Matters

~~FERC Transmission Rate Settlement:~~ On December 28, 2015, FERC initiated a proceeding to review the New England transmission owners' (NETOs) regional and local transmission rates due to a lack of transparency. The FERC also found that the formula rates generally lacked 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 includes, among other things, a new formula rate template, effective on January 1, 2020, 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 November 5, 2018, the Settlement Administrative Law Judge reported the contested settlement to the FERC. The NETOs are awaiting an order from the FERC.

FERC ROE Complaints: Four separate complaints ~~have been~~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")~~(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")~~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, ~~2018.~~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, ~~2018.~~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. ~~The parties to these proceedings were directed to submit briefs on this new proposed framework and how they would apply the proposed framework in each of the four complaint proceedings.~~ 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 ~~providing~~provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results. ~~Reply briefs will be filed on March 8, 2019.~~

The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those ~~preliminary~~illustrative calculations indicated that for the first complaint period, for the NETOs, ~~that~~which FERC concludes are of average financial risk, ~~(1) a preliminary range of presumptively just and reasonable base ROEs is 9.60 percent to 10.99 percent; (2) the pre-existing base ROE of 11.14 percent is therefore unjust and unreasonable; (3)~~ the preliminary just and reasonable base ROE is 10.41 ~~percent;~~percent and ~~(4)~~ the preliminary incentive cap on total ROE is 13.08 percent.

If the results of ~~these~~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.

~~Although the order provided illustrative calculations, FERC stated that these calculations are merely preliminary. The FERC's~~ These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC ~~order, as changes~~order.

On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC ~~are possible as a result of the parties' arguments and calculations~~ in the briefing process. Until FERC issues a final decision on each of these four complaints, there is significant uncertainty, and at this time, the Company cannot reasonably estimate a range of gain or loss for any of the four complaint proceedings. Theits October 16, 2018 order to determine the NETOs' base ROEs in its four pending cases. FERC ~~order or~~Opinion Nos. 569-A and 569-B are currently under appeal with the ~~January 11, 2019 briefs did not provide a~~Court.

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

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

~~The average impact~~A change of a 10 basis ~~point change~~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~~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 ~~affect Eversource's~~impact Eversource’s future annual after-tax earnings by approximately ~~$3 million.~~$5 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

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

FERC Notice of Inquiry and Proposed Rulemaking on Transmission Incentives: On March 21, 2019, FERC issued an NOI seeking comments on FERC's policies for implementing electric transmission incentives. On June 26, 2019, Eversource filed comments requesting that FERC retain policies that have been effective in encouraging new transmission investment and remain flexible enough to attract investment in new and emerging transmission technologies. Eversource filed reply comments on August 26, 2019. On March 20, 2020, FERC issued a ~~separate~~ Notice of Proposed Rulemaking ~~addressing accounting~~(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 ~~issues related to ADIT changes resulting~~base) on Eversource’s after-tax earnings is approximately $17 million. The Supplemental NOPR contemplates an effective date 30 days from the ~~act. After issuance~~final order.

At this time, Eversource cannot predict the ultimate outcome of ~~a final rule by FERC, Eversource expects to file a compliance filing~~these proceedings, including possible appellate review, and ~~after acceptance by FERC, begin~~ the ~~refund of any EDIT through local and regional~~resulting impact on its transmission ~~service rates.~~incentives.

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

In New Hampshire, ~~PSNH~~PSNH's distribution rates were established in a December 2020 NHPUC-approved rate case settlement approved by the NHPUC in 2010. Prior to the expiration of that settlement, the NHPUC approved the continuation of those rates, and increased funding via rates, of PSNH's reliability enhancement program.agreement. Aquarion rates were established in a 2013 NHPUC-approved rate case, further revised in 2016.On December 18, 2020, Aquarion filed an application with the NHPUC for a permanent increase in base rates and a decision by the NHPUC 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, ~~such~~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,~~ restructuring and stranded ~~costs resulting from deregulation,~~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 capital tracking mechanisms, and carrying charges that are billed in rates to ~~customers.~~customers, which do impact earnings.

~~U.S. Federal Corporate Income Taxes:~~ OnExcess ADIT Amortization: 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 $2.9 billion and included in regulatory liabilities as of December 31, 2018.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 to customers and resulting amortization of the EDIT regulatory liabilities results in lower revenues (for the amortization of the EDIT and the tax gross up portion) and lower income tax expense (for the amortization of EDIT and lower current tax benefits from the tax gross up portion) on the statement of 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 to customers reflect the lower federal tax rate. As of December 31, 2018,~~other economic development rates. A procedural schedule for this ~~liability, net of amounts refunded to customers, was $24.6 million.~~

~~Eversource's regulated companies are in the process of, or will, refund the decrease in the income tax rate based on orders issued by applicable state regulatory commissions. A summary~~part of the ~~timing of refunds related to~~proceeding has not yet been set by the ~~change in the tax rate is as follows:~~PURA.



~~Eversource Utility and Jurisdiction~~	~~EDIT Refund Timing~~	~~Effective Date of~~ ~~New Tax Rate~~ ~~Reflected in Rates~~	~~January 1, 2018 Change in Tax Rate~~ ~~Prior to Effective Date of New Rates~~
~~Connecticut~~
~~CL&P~~	~~Refunds will be incorporated into May 1, 2019 distribution rate change~~	~~May 1, 2018~~	~~January 1, 2018 through April 30, 2018 fully refunded to customers as of December 31, 2018~~
~~Yankee Gas~~	~~Refunds began to be reflected in rates effective November 15, 2018~~	~~November 15, 2018~~	~~January 1, 2018 through November 14, 2018 began to be refunded to customers, beginning November 15, 2018~~
~~Massachusetts~~
~~NSTAR Electric~~	~~Refunds began to be reflected in rates effective January 1, 2019~~	~~February 1, 2018~~	~~Refunds not required for the period January 1, 2018 to~~ ~~January 31, 2018~~
~~NSTAR Gas~~	~~Refunds began to be reflected in rates effective February 1, 2019~~	~~July 1, 2018~~	~~Refunds not required for the period January 1, 2018 to June 30, 2018~~
~~New Hampshire~~
~~PSNH~~	~~Refunds will be addressed as part of the next distribution rate case filing~~ ~~Refunds for EDIT related to PSNH's divested generation assets began to be reflected in rates effective August 1, 2018~~	~~No later than~~ ~~July 1, 2019 for distribution~~	~~January 1, 2018 through effective date of next distribution rate change will be refunded to customers~~
~~Transmission~~
~~CL&P, NSTAR Electric and PSNH~~	~~Refunds will be made based on expected guidance from FERC~~	~~January 1, 2018~~	~~Effective January 1, 2018 for local transmission service, and effective June 1, 2018 for regional transmission service, rates reflected the reduced federal corporate income tax rate~~

For further information on filings with regulatory commissions and the impact to customer rates, see "Connecticut," "Massachusetts," and "New Hampshire" sections below and "FERC Regulatory Matters - U.S. Federal Corporate Income Taxes" in this ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

~~Connecticut:~~

CL&P ~~Rate Case Settlement:~~Settlement Agreement: On ~~April 18, 2018, PURA approved the distribution rate case~~October 1, 2021, CL&P entered into a settlement agreement ~~that was reached by CL&P,~~with the ~~Prosecutorial Unit of PURA, and the~~DEEP, Office of Consumer Counsel ~~("OCC") on December 15, 2017, as amended on March 23, 2018. The distribution rate case settlement agreement included, among other things, rate increases~~(OCC), Office of ~~$64.3 million, $31.1 million,~~the Attorney General (AG) and ~~$29.2 million, effective May 1, 2018, 2019, and 2020, respectively; an authorized~~the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory ROE of 9.25 percent; 53 percent common equity in CL&P's capital structure; and a new capital tracker, effective July 1, 2018, for core capital additions in excess of $270 million per rate year and for capital additions for system resiliency and grid modernization. The new capital tracker also included a provision to return to customers the impact of a lower federal corporate income tax rate from the Tax Cuts and Jobs Act from January through April 2018, offsetproceedings initiated by the impacts of rate base growth since the previous rate case for the same period. In addition, the base distribution rates charged to customers were adjusted to reflect the prospective impacts of a lower federal income tax rate resulting from the Tax Cuts and Jobs Act. Amounts related to the EDIT liabilities will be incorporated as refunds to customers in May 1, 2019 base distribution rates. The settlement agreement also incorporated $18.6 million of rate base recovery for catastrophic storms occurring after December 31, 2016, subject to a storm filing. On November 16, 2018, CL&P filed for recovery of $153 million of storm costs incurred from 2017 through 2018, with recovery incorporated into the May 1, 2019 distribution rate change. The storm filing is pending PURA approval.

~~Yankee Gas Rate Case Settlement: On December 12, 2018,~~PURA. PURA approved the ~~distribution rate case~~ settlement agreement ~~that was reached~~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 carrying arrearages, as approved by ~~Yankee Gas, the prosecutorial division of~~ the PURA, ~~and~~with the ~~OCC~~objective of disbursing the funds prior to April 30, 2022. CL&P recorded a current regulatory liability of $75 million on September 21, 2018. The distribution rate case settlement agreement included, among other things, rate increases of $1.4 million, $15.8 million and $13.0 million, for rate years beginning November 15, 2018, January 1, 2020, and January 1, 2021, respectively, and for 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 coststhe balance sheet 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 agreement 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. In addition, Yankee Gas was 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 were effective January 1, 2019, the provisions of the settlement agreement, ~~took effect November 15, 2018.~~with a $65 million pre-tax charge as a reduction to Operating Revenues associated with the customer credits and a $10 million charge to Operations and Maintenance expense associated with the customer assistance fund on the year ended December 31, 2021 statement of income.

In exchange for the $75 million of customer credits and assistance, PURA’s interim rate reduction docket was resolved without findings. As a result of the settlement agreement, neither the 90 basis point reduction to CL&P’s return on equity introduced in PURA’s storm-related decision issued April 28, 2021, nor the 45 basis point reduction to CL&P’s return on equity included in PURA’s decision issued September 14, 2021 in the interim rate reduction docket, will be implemented.

CL&P has also agreed to freeze its current base distribution rates, subject to the customer credits described above, until no earlier than January 1, 2024. The rate freeze applies only to base distribution rates (including storm costs) and not to other rate mechanisms such as the retail rate components, rate reconciling mechanisms, formula rates and any other adjustment mechanisms. The rate freeze also does not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings, either currently pending or that may be initiated during the rate freeze period, that may place additional obligations on CL&P. The approval of the settlement agreement satisfies the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case.

As part of the settlement agreement, CL&P agreed to withdraw with prejudice its pending appeals of PURA’s decisions dated April 28, 2021 and July 14, 2021 related to Storm Isaias and agreed to waive its right to file an appeal and seek a judicial stay of the September 14, 2021 decision in the interim rate reduction docket. The settlement agreement assures that CL&P will have the opportunity to petition for and demonstrate the 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 a final decision in which it adjusted the timing of 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 GSC, BFMCC, NBFMCC, SBC, CTA, ESI and base distribution rates, but resulted in changes to the 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.

CL&P Impact of 2021 Rate Changes (Excluding Supply Rates): On June 1, 2021, CL&P implemented an ~~$11.7 million pre-tax benefit to earnings in 2018 ($4.0 million at the natural gas distribution segment primarily~~overall rate increase of $0.00411 per kWh for ~~DIMP costs allowed for recovery, and $7.7 million at Eversource Parent and Other Companies~~residential customers. The rate increase included delivery rate changes for the ~~allowed recovery~~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 ~~previously expensed merger-related costs).~~the June 1, 2021 rate changes equated to an increase of $2.88 on monthly customer bills.

~~Clean Energy RFP:~~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 ~~28, 2018, under Public Act 17-3, "An Act Concerning Zero Carbon Solicitation and Procurement,"~~1, 2021, CL&P adjusted its rates for the ~~DEEP selected~~$65 million of customer credits resulting from the ~~Millstone nuclear power generation facility, alongside smaller generation facilities, as~~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 ~~winner~~impact of the ~~zero-carbon electricity-generating resource.~~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 ~~directed~~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 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 ~~DEEP to enter into~~the PURA. As required, the plan includes a ~~ten-year contract with Millstone for approximately 9 million MWh annually. DEEP requested negotiations among all parties conclude~~full deployment of advanced metering functionality and a composite business case in support of the Advanced Metering Infrastructure plan. A procedural schedule in this proceeding has not been issued by ~~March 31, 2019.~~the 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 ~~Decision:~~ On November 30, 2017, the DPU issued its decision in the NSTAR Electric distribution rate case, which approved an annual distribution rate increase of $37 million, with rates effective February 1, 2018.: On January ~~3, 2018,~~14, 2022, NSTAR Electric filed ~~a motion to reflect a revenue requirement reduction~~an application with the DPU for approval of ~~$56~~an $89 million ~~due to the decrease~~increase in ~~the federal corporate income tax rate, as part of the Tax Cuts and Jobs Act, resulting in an annual net decrease in~~base distribution rates, ~~of $19 million. NSTAR Electric’s~~with new rates took effect on February 1, 2018, following approval of NSTAR Electric’s compliance filing on February 2, 2018. The DPU also approved, in part, NSTAR Electric's request for recalculation, resulting in an increase of $3.5 million in the approved revenue requirement,anticipated to be effective March 1, 2018. In addition to its decision regarding rates, the DPU approved an authorized regulatory ROE of 10 percent, the establishment of a revenue decoupling rate mechanism for the portion of the NSTAR Electric business that did not previously have a decoupling mechanism, and the implementation of an inflation-based adjustment mechanism with a five-year stay-out until 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 ~~Electric~~Gas submitted its first annual Performance Based Rate Adjustment ~~(PBRA)~~ filing on September ~~19, 2018~~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 ~~$31.9~~$13.6 million increase to base distribution rates on ~~December 27, 2018 for effect~~October 29, 2021, effective November 1, 2021. For EGMA, the DPU approved a $13 million increase to base distribution rates on October 28, 2021, effective November 1, 2021.

New Hampshire:

PSNH Distribution Rates:In connection with an October 9, 2020 settlement agreement, the NHPUC approved a permanent rate increase of $45.0 million effective January 1, ~~2019.~~2021. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant additions in calendar years 2019, 2020 and 2021, respectively. On December 23, 2020, the NHPUC approved the first step adjustment for 2019 plant in service to recover a revenue requirement of $10.6 million, effective January 1, 2021. On July 30, 2021, the NHPUC approved the second step adjustment for 2020 plant in service to recover a revenue requirement of $11.0 million, subject to reconciliation after completion of an audit, with rates effective August 1, 2021.

~~NSTAR Electric Grid Modernization Plan~~:COVID Regulatory Docket: On ~~May 10, 2018,~~July 7, 2021, the ~~DPU~~NHPUC issued an order approving a grid modernization plan for NSTAR Electric. In the order, the DPU pre-authorized $133 million in grid-facing investments over three years, adopted a regulatory review construct for pre-authorization of grid modernization investments, and allowed targeted costto New Hampshire utilities that concluded that recovery of ~~eligible~~ incremental grid-modernization capital and operations and maintenance expenses. The pre-authorized $133 million is in addition to $100 million associated with energy storage and electric vehicle infrastructure previously approved by the DPU in the November 30, 2017 order issued in the NSTAR Electric distribution rate case.

~~U.S. Federal Corporate Income Taxes~~: The DPU opened an investigation into the impact of the Tax Cuts and Jobs Act on Massachusetts regulated utilities. On June 29, 2018, the DPU issued a decision ordering NSTAR Gas to lower rates effective July 1, 2018 by an annualized $7.3 million. For NSTAR Electric, lower rates due to the reduction in the federal corporate income tax rate were effective February 1, 2018.

A second phase of the investigation addressed the EDIT issue and any potential refunds for the periods January 1, 2018 to the effective dates of the rate changes that have occurred. On December 21, 2018, the DPU issued a decision ordering Massachusetts regulated utilities to refund the distribution related EDIT to customers through a new reconciling factor ("Tax Act Credit Factor"). The order also required these companies to include any EDIT that relates to existing reconciling tracking mechanisms to be refunded within those individual mechanisms. The DPU approved compliance filings for NSTAR Electric on December 27, 2018 and for NSTAR Gas on January 18, 2019 for the Tax Act Credit Factor to be included in rates effective January 1, 2019 for NSTAR Electric and effective February 1, 2019 for NSTAR Gas. Additionally, the December 21, 2018 DPU order indicated that the DPU will not require a revision to base rates for any potential refunds for the periods January 1, 2018 to the effective dates of the rate changes. Therefore, as of December 31, 2018, a reserve was not recorded for the reduction in the federal corporate income tax rate in customer billings from January 1, 2018 to the dates of the rate changes at NSTAR Electric (February 1, 2018) and NSTAR Gas (July 1, 2018).

~~Eversource and NSTAR Electric Boston Harbor Civil Action~~: On July 15, 2016, the United States Attorney on behalf of the United States Army Corps of Engineers filed a civil action in the United States District Court for the District of Massachusetts under provisions of the Rivers and Harbors Act of 1899 and the Clean Water Act against NSTAR Electric, Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric ("HEEC"), and the Massachusetts Water Resources Authority (together with NSTAR Electric and HEEC, the "Defendants"). The action alleged that the Defendants failed to comply with certain permitting requirementsbad debt or waived late fees related to the ~~placement~~COVID-19 pandemic would be addressed in the context of the ~~HEEC-owned electric distribution cable beneath Boston Harbor. The action sought an order~~utility’s next rate case when related costs, to ~~compel HEEC to comply with cable depth requirements~~the extent those costs remain relevant under test year based rate-setting, would be considered in the United States Army Corps of Engineers' permit or alternatively to remove the electric distribution cable and cease unauthorized work in U.S. waterways. The action also sought civil penalties and other costs.

~~The parties reached a settlement pursuant to which HEEC agreed to install a new 115kV distribution cable across Boston Harbor to Deer Island, utilizing a different route, and remove portions~~context of the ~~existing cable. Upon the installation~~utility’s full revenue requirement and ~~completion~~overall rate of the new cable and the removal of the portions of the existing cable, all issues surrounding the current permit from the United States Army Corps of Engineers are expected to be resolved, and such litigation is expected to be dismissed with prejudice.

In 2017, as a result of the settlement, NSTAR Electric expensed $4.9 million (pre-tax) of previously incurred capitalized costs associated with engineering work performed on the existing cable that will no longer be used. In addition, NSTAR Electric agreed to provide a rate base credit of $17.5 million to the Massachusetts Water Resources Authority for the new cable. This negotiated credit resulted in the initial $17.5 million of construction costs on the new cable being expensed as incurred, all of which was fully expensed in 2018. Construction of the new cable is underway and is expected to be completed in 2019.

~~New Hampshire:~~

~~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, at which time the Company classified these assets as held for sale.

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 adjusted to reflect working capital adjustments, closing date adjustments 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.

On May 8, 2018, PSNH Funding issued $635.7 million of securitized RRBs pursuant to a finance order issued by the NHPUC to recover remaining costs resulting from the divestiture of PSNH’s 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. For further information on the securitized RRB issuance, see "Liquidity - Rate Reduction Bonds" in this ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

~~U.S. Federal Corporate Income Taxes:On September 27, 2018, the NHPUC issued a decision on the impact of the U.S. federal corporate income tax rate reduction from the Tax Cuts and Jobs Act.~~return. The NHPUC concluded that ~~the tax law change qualified as an exogenous event, as defined in the 2015 Public Service Company of~~ New Hampshire ~~Restructuring and Rate Stabilization Agreement, and that the benefit of incurring the lower federal income tax expense~~utilities would not be ~~passed back~~permitted to customers with carrying charges. The next PSNH distribution rate case shall address the impacts of EDIT, the lower federal income tax rate, and the overcollection of the lower income tax rate from January 1, 2018 to the rate adjustment effective date of July 1, 2019, or earlier if a rate case is filed for rates effective prior to July 1, 2019. As of December 31, 2018, PSNH has recorded a reserve of $12.6 million to reflect the difference between the 35 percent federal corporate income tax rate included in rates charged to customers and the 21 percent federal corporate income tax rate, effective January 1, 2018. The EDIT balance related to PSNH's divested generation assets has been included as a component of the securitization of the stranded generation assets and has started to be refunded to customers via the Stranded Cost Recovery Charge effective August 1, 2018.

~~2011 through 2013 Storm Costs:~~On September 17, 2018, the NHPUC approved the recovery of $49 million, plus carrying charges, in storm costs incurred from August 2011 through March 2013 and the transfer of funding from PSNH’s major storm reserve to offset those costs. The costs of these storms (excluding the equity return component of the carrying charges) were deferred as regulatory assets, and the funding reserve collected from customers was accrued asestablish a regulatory ~~liability. The storm cost deferral is separate from the major storm funding reserve that is being collected from customers.~~asset for these items. As a result of the ~~duration~~order, in the second quarter of ~~time between incurring storm costs in August 2011 through March 2013 and final approval from~~2021, PSNH removed its $0.6 million deferral of net incremental COVID-19 costs.

Energy Efficiency Plan: On November 12, 2021, the NHPUC ~~in 2018, PSNH recognized $8.7 million (pre-tax) for~~issued an order rejecting the ~~equity return component~~proposed 2021 through 2023 energy efficiency plan and significantly reduced funding and operational functions of the ~~carrying charges, which~~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 performance incentives beginning in 2022. PSNH sought rehearing of 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 ~~been collected from customers, within Other Income, Net on our statement~~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 four Supreme Court appeals filed, it is likely that at least some of ~~income in 2018. Storm costs incurred from December 2013 through April 2016 have been audited by~~the provisions of the NHPUC ~~staff and are pending NHPUC approval. As of December 31, 2018, the pre-tax equity return component of the carrying charges related to storms incurred after March 2013 was $7.9 million, which~~order will be ~~recognized to earnings upon NHPUC approval~~undone. At this time, PSNH cannot predict the ultimate outcome of ~~those storm costs.~~this order, and the resulting impact on its financial statements.

~~Reliability Enhancement Program:~~ On December 28, 2018, the NHPUC approved PSNH’s extension of the Reliability Enhancement Program for 2019. The extension included cost recovery associated with vegetation management costs. The vegetation management spending, which is consistent with prior years’ spending, will be deferred and offset against amounts due to customers as a result of federal income tax reform.

Legislative and Policy Matters

~~New Hampshire:~~ Federal: On ~~January 11, 2018,~~November 5, 2021, Congress passed the ~~New Hampshire Supreme Court issued~~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 ~~decision~~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 ~~affirmed~~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 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 ~~lower court's October 2016 decision that the Town~~risks of ~~Bow, New Hampshire 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 ~~2012 and 2013 property tax years. As a result of this decision, PSNH received $7.4 million in property tax refunds and interest in 2018.~~70 MWs previously constructed at NSTAR Electric.

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~~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 ~~earnings~~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, ~~2018,~~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 ~~2019~~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 ~~2018~~ 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, ~~2018,~~2021, the discount rates used to determine the funded status were within a range of ~~4.22~~2.8 percent to ~~4.45~~3.0 percent for the Pension and SERP Plans, and within a range of ~~4.38~~2.91 percent to ~~4.41~~2.92 percent for the PBOP Plans. As of December 31, ~~2017,~~2020, the discount rates used were within a range of ~~3.43~~2.4 percent to ~~3.75~~2.7 percent for the Pension and SERP Plans, and within a range of ~~3.55~~2.5 percent to ~~3.70~~2.6 percent for the PBOP Plans. The increase in the discount rates used to calculate the funded status resulted in a decrease to the Pension and PBOP Plans' liability of ~~approximately $465~~$286.8 million and ~~$88~~$29.8 million, respectively, as of December 31, ~~2018.~~ 2021.

The Company uses the spot rate methodology for the service and interest cost components of Pension, SERP and PBOP expense ~~for the Eversource plans~~ 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 ~~2018~~2021 expense were within a range of ~~3.85~~1.5 percent to ~~4.62~~3.0 percent for the Pension and SERP Plans, and within a range of ~~3.28~~1.8 percent to ~~3.94~~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 ~~2018,~~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, ~~2018~~2021 and ~~2017,~~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~~to 4.0 percent.

Health Care Cost: The Eversource Service ~~plans and 4 percent for the Aquarion plans.~~

~~Health Care Cost: In August 2016, we amended the Eversource~~ PBOP Plan ~~to standardize benefit design and make benefit changes. As a result, this plan~~ is ~~no longer~~not subject to health care cost trends. ~~The Aquarion PBOP Plan is still subject to heath care cost trends. For~~As of December 31, 2021, for the Aquarion PBOP Plan, the health care trend rate for pre-65 retirees is ~~a range of 3.5 percent to 6.75~~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 ~~$39.6~~$23.6 million, ~~$64.9~~$56.9 million and ~~$71.9~~$63.7 million for the years ended December 31, ~~2018, 2017~~2021, 2020 and ~~2016,~~2019, respectively. For the PBOP Plans, there was net periodic PBOP income of ~~$45.0~~$60.5 million, ~~$39.6~~$51.6 million and ~~$17.9~~$41.5 million for the years ended December 31, ~~2018~~, ~~2017~~2021, 2020 and ~~2016,~~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 ~~2019~~2022 for the Pension and SERP Plans will be approximately ~~$72~~$177 million and income in ~~2019~~2022 for the PBOP Plans will be approximately ~~$38~~$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 ~~$185.6~~$180.0 million to the Pension Plans in ~~2018.~~2021. We currently estimate contributing ~~approximately $112~~between $100 million to $175 million to the Pension Plans in ~~2019.~~

~~For~~2022, however, there is no minimum funding requirement for our Pension Plans for 2022, and therefore the ~~PBOP Plans, it~~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 ~~2018.~~2021. We currently estimate contributing ~~$11~~$2.4 million to the PBOP Plans in ~~2019.~~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 2018 2017 2018 2017
Lower expected long-term rate of return $ 23.7
$ 20.4
$ 4.5
$ 4.1
Lower discount rate 25.5 19.7 2.9 3.6
Higher compensation rate 6.8 9.3 N/A N/A

Goodwill: We recorded goodwill on our balance sheet associated with previous mergers and ~~acquisitions. On December 4, 2017, we completed the acquisition~~acquisitions, all of ~~Aquarion, resulting in the addition of $0.9~~which totaled $4.48 billion ~~of goodwill. As~~as of December 31, ~~2018, a total of $4.4 billion of goodwill is recorded on our balance sheet.~~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 ~~was created upon completion of~~includes the ~~acquisition of~~ Aquarion ~~and includes the~~ water utility businesses. As of December 31, ~~2018,~~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, ~~2018~~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 ~~2018~~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 ~~strategic, infrastructure and~~ other ~~investments,~~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.

~~Access Northeast: Eversource recorded~~Equity Method Investments: Investments in affiliates where we have the ability to exercise significant influence, but not control, over an ~~other-than-temporary impairment of $32.9 million within Other Income, Net on our statement of income in 2018, related to Access Northeast,~~investee are initially recognized as an equity method ~~investment. In September 2018, a series~~investment at cost. Any differences between the cost of ~~non-Eversource natural gas explosions~~an investment and the amount of underlying equity in ~~eastern Massachusetts resulted in widespread property~~net assets of an investee are considered basis differences and ~~system damage, personal injuries, and a fatality. Eversource identified~~are determined based upon 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 considerationestimated fair values of the ~~severity~~investee's identifiable assets and ~~duration~~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 ~~any decline~~the PPAs, and equity method goodwill that is not amortized. Capitalized interest associated with our offshore wind equity method investment is included in the investment balance.

Equity method investments are assessed for impairment when conditions exist that indicate that the fair value of ~~our~~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 ~~project, and involved~~investment. Impairment evaluations involve a significant ~~management~~degree of 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~~identifying circumstances 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. For further information, see Note 1K, "Investments," to the financial statements.

NPT: In March 2018, the New Hampshire Site Evaluation Committee ("NHSEC") issued a written decision denying Northern Pass’ siting application after which the Massachusetts EDCs terminated the selection of, and subsequent contract negotiations with, Northern Pass under the Massachusetts Clean Energy RFP. The March 2018 NHSEC decision denying Northern Pass' siting application caused us to review the recoverability of our Northern Pass project costs in the first quarter of 2018. In this recoverability review, we estimated undiscounted expected project cash flows and compared the result to our estimated project costs to determine whether the recorded amount was recoverable. Our undiscounted cash flows were substantially in excess of our estimated project costs. We completed this analysis and concluded that our project costs were recoverable as of March 31, 2018, based on our expectation that the Northern Pass project remains probable of being placed in service. If as a result of future events and changes in circumstances a new recoverability review were to conclude that our project costs are not recoverable, then we would reduce Northern Pass' project costs to the estimated fair value, which could result in most of our $307 million of capitalized project costs being impaired. Suchindicate an impairment ~~could have a material adverse effect on our financial position~~may exist and ~~results~~developing an estimate of ~~operations.~~

As of December 31, 2018, we did not identify any other impairment indicators for our long-lived assets. If events or changes in circumstances indicate the carrying value of a long-lived asset may not be recoverable, we would perform an impairment analysis. An impairment analysis would consist of two steps: first, the estimated undiscounted future cash flows attributable to the asset would be compared with the carrying value of the asset, and second, if the carrying value is greater than the undiscounted future cash flows, an impairment charge would be recognized equal to the amount by which the carrying value of the asset exceeds its estimated fair value.flows.

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 from 35 percent~~matters may result in favorable or unfavorable impacts to ~~21 percent effective January 1, 2018. For~~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 ~~regulated companies, the most significant changes are (1) the benefit of incurring a lower federal income~~intent and ability to implement tax ~~expense and (2) the reduction in ADIT liabilities (now excess ADIT or EDIT), which are estimated~~planning strategies, if necessary, to ~~be approximately $2.9 billion and included in regulatory liabilities as of December 31, 2018. The refund of these regulatory liabilities to customers will generally be made over the same period~~realize deferred tax assets. We also assess negative evidence, such as the ~~remaining useful lives~~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 ~~underlying assets that gave rise to the ADIT liabilities.~~

~~We have completed our evaluation~~reversal of the impacts of the act as of December 31, 2018. The ultimate outcome was not materially different from the provisional estimates recorded as of December 31, 2017. While we have recorded the impacts of the act based on interpretation of the provisions as enacted, it istaxable temporary differences, expected ~~the U.S. Department of Treasury and the IRS will issue additional interpretative guidance in the~~ future ~~that could result in changes to previously finalized provisions. At this time, some of the states in which we do business have issued guidance regarding the act~~taxable income, and the impact ~~was~~of tax planning strategies.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, not ~~material. Amortization~~realizing expected tax planning strategy amounts, as well as results of ~~the EDIT liabilities began in 2018 at our PSNH~~audits and ~~Yankee Gas subsidiaries. The total amortization for 2018 was $4.4 million and $0.6 million for PSNH and Yankee Gas, respectively.~~examinations of filed tax returns by taxing authorities.

Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Increases to estimates of environmental liabilities could have an adverse impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which we may have potential liability. Estimates are based on the expected remediation plan. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost ~~estimates 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,~~Plans. Fair value measurements are also incorporated into the accounting for goodwill, long-lived assets, equity method investments, and ~~to nonfinancial assets such as goodwill~~AROs, and ~~AROs. This~~in the valuation of the acquisition of CMA in 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, 2018, is summarized annually through 2023 and thereafter as follows:~~

Eversource
(Millions of Dollars) 2019 2020 2021 2022 2023 Thereafter Total
Long-term debt maturities ^(a)
$ 801.1
$ 296.1
$ 1,033.5
$ 1,188.9
$ 1,665.2
$ 7,977.7
$ 12,962.5
Rate reduction bond maturities 52.3
43.2
43.2
43.2
43.2
410.6
635.7
Estimated interest payments on existing debt ^(b)
498.0
459.5
440.7
406.4
373.4
3,526.1
5,704.1
Capital leases^(c)
3.4
3.4
2.9
1.5
0.7
13.9
25.8
Operating leases^(d)
11.5
9.8
8.7
7.2
4.7
32.7
74.6
Funding of pension obligations ^{(d) (e)}
112.0
—
—
—
—
—
112.0
Funding of PBOP obligations ^{(d) (e)}
11.0
—
—
—
—
—
11.0
Estimated future annual long-term contractual costs ^(f)
609.2
607.9
528.7
494.1
461.7
2,905.9
5,607.5
Total ^(g)
$ 2,098.5
$ 1,419.9
$ 2,057.7
$ 2,141.3
$ 2,548.9
$ 14,866.9
$ 25,133.2

CL&P
(Millions of Dollars) 2019 2020 2021 2022 2023 Thereafter Total
Long-term debt maturities ^(a)
$ 250.0
$ —
$ —
$ —
$ 400.0
$ 2,615.3
$ 3,265.3
Estimated interest payments on existing debt ^(b)
141.7
134.8
134.8
134.8
129.8
1,843.0
2,518.9
Capital leases ^(c)
2.0
2.0
1.5
—
—
—
5.5
Operating leases^(d)
1.5
1.4
1.2
1.1
0.5
0.2
5.9
Funding of pension obligations ^{(d) (e)}
44.0
—
—
—
—
—
44.0
Estimated future annual long-term contractual costs ^(f)
179.9
205.2
197.2
195.7
200.4
959.7
1,938.1
Total ^(g)
$ 619.1
$ 343.4
$ 334.7
$ 331.6
$ 730.7
$ 5,418.2
$ 7,777.7


~~(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 capital lease obligations include interest.~~


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


~~(e)~~	These amounts represent expected pension and PBOP contributions for 2019. 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 6, "Asset Retirement Obligations," Note 7, "Short-Term Debt," Note 8, "Long-Term Debt," Note 9, "Rate Reduction Bonds and Variable Interest Entities," Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," Note 12, "Commitments and Contingencies," and Note 14, "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, ~~2018~~2021 and ~~2017~~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) 2018 2017 Increase/(Decrease)
Operating Revenues $ 8,448.2
$ 7,752.0
$ 696.2
Operating Expenses:

Purchased Power, Fuel and Transmission 3,139.0
2,535.3
603.7
Operations and Maintenance 1,335.2
1,307.0
28.2
Depreciation 819.9
773.8
46.1
Amortization 252.0
90.0
162.0
Energy Efficiency Programs 472.4
480.8
(8.4 )
Taxes Other Than Income Taxes 729.8
676.8
53.0
Total Operating Expenses 6,748.3
5,863.7
884.6
Operating Income 1,699.9
1,888.3
(188.4 )
Interest Expense 498.8
421.8
77.0
Other Income, Net 128.4
107.9
20.5
Income Before Income Tax Expense 1,329.5
1,574.4
(244.9 )
Income Tax Expense 289.0
578.9
(289.9 )
Net Income 1,040.5
995.5
45.0
Net Income Attributable to Noncontrolling Interests 7.5
7.5
—
Net Income Attributable to Common Shareholders $ 1,033.0
$ 988.0
$ 45.0

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, ~~in MMcf,~~ and our water MG sales volumes, and percentage changes, ~~for the years ended December 31, 2018 and 2017,~~ 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
Increase Sales Volumes (MMcf) Percentage
Increase/(Decrease) Sales Volumes (MG) Percentage
Increase/(Decrease)
2018
2017 ⁽¹⁾
2018
2017⁽²⁾
2018
2017 ⁽³⁾

Traditional 9,790
9,465
3.4 % 44,715
39,455
13.3 % 2,252
2,202
2.3 %
Decoupled and Special Contracts ⁽⁴⁾
43,591
42,781
1.9 % 61,242
61,571
(0.5 )% 21,479
22,565
(4.8 )%
Total Sales Volumes 53,381
52,246
2.2 % 105,957
101,026
4.9 % 23,731
24,767
(4.2 )%

(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⁾	In 2017 and until November 14, 2018, Yankee Gas operated under a traditional rate structure. Effective November 15, 2018, Yankee Gas operated under a decoupled rate structure. The 2017 sales volumes for Yankee Gas have been recast to present November 15th through December 2017 as decoupled, to conform to the current year presentation.

(2) Eversource acquired CMA's natural gas distribution assets on October 9, 2020. Prior year sales volumes have been presented for comparative purposes.


⁽³⁾	~~Eversource acquired its water distribution business on December 4, 2017. Full 2017 sales volumes have been presented for comparative purposes.~~


⁽⁴⁾	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 ~~and natural gas sales volumes at Yankee Gas prior to November 15, 2018 impacted~~impact earnings ("Traditional" in the table above). For CL&P, NSTAR Electric, ~~(effective February 1, 2018 as a result of a DPU-approved rate case decision),~~NSTAR Gas, EGMA, Yankee Gas, ~~(effective November 15, 2018 as a result of a PURA-approved rate case settlement)~~ 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 decoupled.~~

Operating Revenues: Operating Revenues by segment ~~increased/(decreased)~~increased in ~~2018,~~2021, as compared to ~~2017,~~2020, as ~~follows (the variance in electric distribution revenues reflects intercompany transmission billings in both periods):~~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 $ 405.6
Natural Gas Distribution 74.9
Electric Transmission (15.4 )
Water Distribution 196.1
Other 5.3
Eliminations 29.7
Total Operating Revenues $ 696.2

Electric and Natural Gas (excluding EGMA) Distribution Revenues:

Base Distribution Revenues:

•Base electric distribution revenues ~~decreased $49.3~~increased $28.8 million in 2021, as compared to 2020, due primarily to ~~lower~~the impact of base distribution ~~rates~~rate increases at NSTAR Electric ~~as per~~effective January 1, 2021, at PSNH effective January 1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020. These increases were partially offset by a base distribution rate decrease at CL&P implemented June 1, 2021. The decrease in the ~~DPU-approved~~CL&P base distribution rate ~~case decision that became effective February~~on June 1, ~~2018. NSTAR Electric's rates were adjusted~~2021 was due primarily to ~~reflect~~ the ~~new lower federal corporate income tax rate and~~completion of the ~~movement~~recovery of certain ~~costs from~~storm cost amortization and therefore the base ~~distribution rates to fully-reconciled cost tracking mechanisms (most of which~~rate decrease did not impact ~~earnings). The decrease~~earnings.

•Base natural gas distribution revenues increased $62.8 million in ~~revenues was partially offset by CL&P's~~2021, as compared to 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 provisions of the base distribution rate increase were effective 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 ~~PURA-approved rate case~~ 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 ~~became effective May~~is currently being credited to customers on electric bills beginning on September 1, ~~2018 (a portion~~2021 over a one-year period. CL&P recorded these reserves as a current regulatory liability and a reduction to Operating Revenues. As of ~~which did~~December 31, 2021, the remaining reserve that has not ~~impact earnings),~~yet been issued as customer credits and ~~an increase~~not yet reflected in ~~non-decoupled sales volumes primarily driven by colder weather in January 2018 at NSTAR Electric (prior to its decoupled rate structure)~~rates totaled $71.1 million. For further information, see "Regulatory Developments and ~~warmer summer weather in 2018 at PSNH. Effective February 1, 2018, NSTAR Electric operated entirely under a decoupled rate structure.~~

~~Electric distribution revenues also decreased $28.9 million due to the liability established to reflect the difference between the 35 percent federal corporate income tax rate~~Rate Matters - Connecticut" included in ~~rates charged to customers~~this Management’s Discussion and the 21 percent federal corporate income tax rate, effective January 1, 2018 as a result of the Tax Cuts and Jobs Act. Effective February 1, 2018 for NSTAR Electric and May 1, 2018 for CL&P, rates charged to customers have been adjusted to reflect the new federal corporate income tax rate. PSNH will refund the overcollection in rates from January 1, 2018 to customers in a future period.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, ~~have~~recovery of these costs has no impact on earnings. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for ~~NSTAR Electric,~~the Massachusetts utilities, pension and PBOP benefits, ~~and~~ net metering for distributed ~~generation. In addition, tracked revenues include certain incentives earned~~generation, and carrying charges that are billed in rates to customers. Tracked retail electric distribution revenues increased as a result of an increase in electric energy supply costs ($219.1 million), an increase in stranded cost recovery revenues ($80.5 million), an increase in retail electric transmission charges ($39.3 million), and an increase in other distribution tracking mechanisms ($84.0 million).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, which increased $48.7 million.~~

~~Natural Gas Distribution Revenues~~:

Base natural gas distribution revenues increased $17.8 million due primarily to an increase in sales volumes and demand revenues driven by colder January, April, October and November weather in Connecticut in 2018, as well as growth in new customer base. Effective November 15, 2018, fluctuations in Connecticut sales volumes no longer impact earnings as a result of a decoupled rate structure at Yankee Gas approved in the 2018 rate case settlement.

Natural gas distribution revenues decreased $8.3 million due to the liability established to reflect the difference between the 35 percent federal corporate income tax rate included in rates charged to customers and the 21 percent federal corporate income tax rate, effective January 1, 2018 as a result of the Tax Cuts and Jobs Act. Effective July 1, 2018 for NSTAR Gas and November 15, 2018 for Yankee Gas, rates charged to customers have been adjusted to reflect the new federal corporate income tax rate.

Tracked natural gas distribution revenues increased as a result of an increase in natural gas supply costs ($42.8 million), an increase in energy efficiency program revenues ($7.9 million), and an increase in wholesale sales of natural gas to third party marketers, ~~($14.6 million).~~and the sale of RECs to various counterparties.

~~Water Distribution:~~ ~~Water~~Tracked distribution revenues increased/(decreased) in 2021, as compared to 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.

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 ~~$196.1~~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.

EGMA Natural Gas Distribution Revenues: The incremental impact of EGMA increased total operating revenues at the natural gas distribution segment by $431.5 million ~~for the year ended December 31, 2018~~in 2021, as compared to 2020.

Electric Transmission Revenues: Electric transmission revenues increased $98.5 million in 2021, as compared to 2020, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure.

Other Revenues and Eliminations: Other revenues primarily include the ~~acquisition~~revenues of ~~Aquarion on December 4, 2017.~~

~~Electric Transmission Revenues:~~ ~~The electric transmission segment revenues decreased by $15.4 million due primarily to lower revenue requirements~~Eversource's service company, most of which are eliminated in consolidation. Eliminations are also primarily related to the ~~lower federal corporate income tax rate that was reflected in 2018~~Eversource electric transmission revenues ~~partially offset by an increase related~~that are derived from ISO-NE regional transmission charges to ~~ongoing investments~~the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in ~~our transmission infrastructure.~~rates charged to their customers.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas ~~and water,~~ 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 in ~~2018,~~2021, as compared to ~~2017,~~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
Electric Distribution $ 436.9
Natural Gas Distribution 48.8
Transmission 73.6
Water Distribution 1.6
Eliminations 42.8
Total Purchased Power, Fuel and Transmission $ 603.7

The ~~variance in electric distribution reflects intercompany transmission charges in both periods. The increase~~decrease in purchased power expense at the electric distribution business in ~~2018,~~2021, as compared to ~~2017,~~2020, was driven primarily by ~~higher prices associated with~~lower expense related to the procurement of energy ~~supply. As a result of~~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 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 in 2018.~~ 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 to~~of $145.0 million, as well as higher average prices and higher average supply-related sales volumes.

The increase in transmission costs in ~~2018,~~2021, as compared to ~~2017,~~2020, was primarily the result of an increase in costs billed by ISO-NE that support regional grid ~~investment~~investments and an increase inresulting from the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. This was partially offset by 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 in ~~2018,~~2021, as compared to ~~2017,~~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 $ 8.5
Bad debt expense 11.2
HEEC Boston Harbor distribution cable costs (12.5 )
Storm restoration costs (6.3 )
Other non-tracked operations and maintenance 13.0
Total Base Electric Distribution (Non-Tracked Costs) 13.9
Base Natural Gas Distribution (Non-Tracked Costs) - Increase due primarily to higher employee-related expenses of $4.5 million and higher bad debt expense of $4.3 million 9.8
Water Distribution - Increase of Aquarion operations and maintenance expenses due to acquisition on December 4, 2017 73.3
Tracked Costs (Electric Distribution, Electric Transmission and Natural Gas Distribution) - Decrease due primarily to lower PSNH generation operations expenses of $53.3 million due to the 2018 sales of thermal and hydroelectric generation assets and lower transmission expenses of $18.5 million (83.3 )
Other and eliminations:
Absence of merger-related costs allowed for recovery through NSTAR Electric distribution rates as a result of the 2017 DPU distribution rate case decision (absence of 2017 earnings benefit) 30.5
Merger-related costs allowed for recovery through Yankee Gas distribution rates as a result of the 2018 PURA distribution rate case settlement agreement (earnings benefit) (7.7 )
Eversource Parent and Other Companies - other operations and maintenance 0.8
Eliminations (9.1 )
Total Operations and Maintenance $ 28.2

Depreciation expense increased in ~~2018,~~2021, as compared to ~~2017,~~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. ~~Partially offsetting these increases was lower depreciation expense at PSNH as a result of the sale of the thermal and hydroelectric generation assets in 2018.~~

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. Amortization increased in 2018, as~~revenues compared to ~~2017, due primarily to~~ the ~~deferral of energy supply and energy-related~~actual costs ~~which can fluctuate from period to period based on the timing of costs incurred and the related rate changes to recover these costs.~~incurred. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. ~~In addition,~~Amortization expense also includes the ~~increase includes~~ amortization of ~~PSNH's securitized regulatory asset~~certain costs as those costs are collected in rates.

Amortization increased in 2021, as compared to 2020, due primarily to the deferral adjustment of ~~$27.3 million~~energy supply, energy-related 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 was partially offset by a decrease in storm amortization expense at CL&P related to the ~~2018 RRB issuance.~~completion of the amortization period of certain storm costs deferred assets.

Energy Efficiency Programs expense ~~decreased~~increased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to ~~a State~~the incremental impact of ~~Connecticut policy change requiring CL&P to remit 2018~~EGMA energy efficiency ~~funds~~program costs of $48.0 million. The increase was also due to the ~~State~~deferral adjustment at NSTAR Electric, which reflects the actual costs of ~~Connecticut, which totaled $46.8 million in 2018, as~~energy efficiency programs compared to ~~$25.4 million in 2017. These costs were collected from CL&P's~~the amounts billed to customers, and ~~remitted to~~ the ~~State~~timing of ~~Connecticut; as such we have classified these amounts as Taxes Other than Income Taxes.~~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. Partially offsetting this decrease was an increase in allowed distribution revenue at PSNH that funded a higher level of expenditures, and higher spending for our natural gas energy efficiency programs.

Taxes Other Than Income Taxes expense increased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to ~~a State of Connecticut policy change requiring CL&P to remit 2018 energy efficiency funds to the State of Connecticut (which totaled $46.8 million~~an increase in 2018, as compared to $25.4 million in 2017), as well as higher property taxes due to higher utility plant in service balances and higher gross earnings taxes (the costs of which are tracked). Partially offsetting these increases was the absence of property taxes as a result of higher utility plant balances, the ~~sale~~incremental impact of EGMA property and other taxes of $23.5 million, higher Connecticut gross earnings taxes, and the ~~PSNH thermal and hydroelectric generation assets~~absence in ~~2018, and~~2021 of a ~~2018 refund~~benefit at NSTAR Gas in 2020 relating to the resolution of disputed property taxes for prior ~~years at PSNH.~~years.

Interest Expense increased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to an increase in interest on long-term debt ~~($30.7 million)~~ as a result of new debt issuances ~~the addition of Aquarion interest expense in 2018~~ ($~~23.0 million), interest expense on the 2018 PSNH RRB issuance ($14.4~~29.5 million), an increase in interest expense on regulatory deferrals ($12.2 million), the absence in 2021 of a benefit at NSTAR Gas in 2020 relating to the resolution of disputed property taxes and interest thereon for prior years ($5.7 million), and higher amortization of debt discounts and premiums, net ($0.8 million), partially offset by a decrease in interest on notes payable ($~~11.2~~3.4 million), a decrease in RRB interest expense ($1.3 million), and an increase in regulatory deferrals, which increased interest expense ($7.1 million) driven primarily by the absence in 2018 of a benefit to interest expense at NSTAR Electric due to the 2017 DPU distribution rate case decision regarding carrying charges for past storms. Partially offsetting these increases was an increase incapitalized AFUDC related to debt funds and other capitalized interest ($~~7.2~~1.1 million).

Other Income, Net increased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to an increase related to ~~Pension,~~pension, SERP and PBOP non-service income components ($~~30.9~~40.0 million) and an increase in interest income primarily from regulatory deferrals ($20.8 million), ~~higher~~partially offset by lower AFUDC related to equity funds ($~~9.6~~4.7 million)~~, the recognition of $8.7 million of the equity return component of carrying charges related to storms incurred from August 2011 through March 2013 at PSNH recorded~~ and investment losses in interest income, and gains on the sale of property ($5.1 million). Partially offsetting these increases was a decrease in equity in earnings of unconsolidated affiliates related to Eversource's equity method investments ($23.6 million), which was driven by a $32.9 million other-than-temporary impairment to our equity method investment in the Access Northeast project, partially offset by increased unrealized gains on our investment in a renewable energy fund. Other Income, Net was further decreased by investment loss in 20182021 compared to investment income in ~~2017~~2020 driven by market volatility ($~~11.5~~1.3 million) ~~primarily related to unrealized losses on equity marketable securities.~~.

Income Tax Expense decreased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to the ~~new federal tax law enacted December 22, 2017,~~absence of the ~~Tax Cuts and Jobs Act, reducing~~sale of the ~~federal corporate income tax rate from 35 percent to 21 percent and lower pre-tax earnings~~Hingham water system ($265.2 million), further reduced by state taxes ($3.6 million), which includes a valuation allowance against state tax credits. Income tax expense further decreased by the write-off of Access Northeast ($6.912.5 million), an ~~aggregate benefit relating to both federal tax reform impacts on~~increase in amortization of EDIT ($20.4 million), the ~~tax return compared to the provision estimate and remeasurement of~~CL&P settlement agreement ($17.5 million), a ~~tax reserve ($18 million), and partially offset by~~decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~3.8~~0.6 million), and a decrease in valuation allowance ($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 benefits ($2.6 million), and a lower return to provision adjustment ($4.6 million).

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, ~~2018~~2021 and ~~2017~~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) 2018 2017 Increase/(Decrease) 2018 2017 Increase/(Decrease) 2018 2017 Increase/(Decrease)
Operating Revenues $ 3,096.2
$ 2,887.4
$ 208.8
$ 3,112.9
$ 2,980.6
$ 132.3
$ 1,047.6
$ 981.6
$ 66.0
Operating Expenses:

Purchased Power, Fuel and Transmission 1,095.2
930.8
164.4
1,257.1
1,025.4
231.7
370.2
237.5
132.7
Operations and Maintenance 506.4
502.2
4.2
462.1
482.9
(20.8 ) 210.5
263.1
(52.6 )
Depreciation 278.6
249.4
29.2
276.4
274.0
2.4
92.1
128.2
(36.1 )
Amortization of Regulatory Assets/
(Liabilities), Net
129.0
83.2
45.8
46.7
33.8
12.9
81.0
(16.6 ) 97.6
Energy Efficiency Programs 94.0
114.7
(20.7 ) 292.3
294.1
(1.8 ) 20.1
13.8
6.3
Taxes Other Than Income Taxes 357.2
323.8
33.4
194.2
182.0
12.2
77.3
89.7
(12.4 )
Total Operating Expenses 2,460.4
2,204.1
256.3
2,528.8
2,292.2
236.6
851.2
715.7
135.5
Operating Income 635.8
683.3
(47.5 ) 584.1
688.4
(104.3 ) 196.4
265.9
(69.5 )
Interest Expense 151.7
143.0
8.7
105.2
105.7
(0.5 ) 60.6
51.0
9.6
Other Income, Net 22.7
23.0
(0.3 ) 53.1
34.1
19.0
27.7
9.8
17.9
Income Before Income Tax Expense 506.8
563.3
(56.5 ) 532.0
616.8
(84.8 ) 163.5
224.7
(61.2 )
Income Tax Expense 129.1
186.6
(57.5 ) 148.9
242.1
(93.2 ) 47.6
88.7
(41.1 )
Net Income $ 377.7
$ 376.7
$ 1.0
$ 383.1
$ 374.7
$ 8.4
$ 115.9
$ 136.0
$ (20.1 )

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,
	2018	2017	Increase	Percent			2021	2020	Increase	Percentage Increase
CL&P	21,467	20,950	517	2.5	%	CL&P	20,501	20,113	388	1.9	%
NSTAR Electric	23,999	23,538	461	2.0	%	NSTAR Electric	22,727	22,418	309	1.4	%
PSNH	7,915	7,758	157	2.0	%	PSNH	7,782	7,675	107	1.4	%

Fluctuations in retail electric sales volumes at PSNH impact earnings. For CL&P and NSTAR Electric, ~~(effective February 1, 2018, as a result of the DPU-approved rate case decision),~~ 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 $89.9 million at CL&P, $115.3 million at NSTAR Electric, and $98.1 million at PSNH in ~~2018,~~2021, as compared to ~~2017, as follows:~~2020.

(Millions of Dollars) CL&P NSTAR Electric PSNH
Operating Revenues $ 208.8
$ 132.3
$ 66.0

Base Distribution Revenues:

•CL&P's distribution revenues decreased $12.0 million due primarily to the base distribution rate 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 ~~$25.4~~due to the impact of a base distribution rate increase effective May 1, 2020.

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

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

NSTAR Electric's distribution revenues decreased $79.3 million due primarily to lower base distribution rates at NSTAR Electric, as per the DPU-approved rate case decision that became effective February 1, 2018. NSTAR Electric's rates were adjusted to reflect the new lower federal corporate income tax rate and the movement of certain costs from base distribution rates to fully-reconciled cost tracking mechanisms (most of which did not impact earnings). The decrease in revenues was partially offset by an increase in January 2018 sales volumes, as compared2021 to January ~~2017, primarily driven by the colder weather. Effective February~~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, ~~2018, NSTAR Electric operated entirely under~~2021 over a ~~decoupled rate structure, and changes in sales volumes no longer impact earnings.~~

~~PSNH's base distribution revenues increased $4.6 million primarily~~one-year period. CL&P recorded these reserves as a ~~result~~current regulatory liability and a reduction to Operating Revenues. As of ~~an increase~~December 31, 2021, the remaining reserve that has not yet been issued as customer credits and not yet reflected in ~~sales volumes in 2018, partially offset by a rate change due to the completion of the full recovery of certain costs in revenues. The rate change did not impact earnings.~~

~~Distribution revenues decreased $16.6 million at CL&P~~rates totaled $71.1 million. For further information, see "Regulatory Developments and ~~$12.3 million at PSNH due to the liability established to reflect the difference between the 35 percent federal corporate income tax rate~~Rate Matters - Connecticut" included in ~~rates charged to customers~~this Management’s Discussion and the 21 percent federal corporate income tax rate, effective January 1, 2018 as a result of the Tax Cuts and Jobs Act. Effective February 1, 2018 for NSTAR Electric and May 1, 2018 for CL&P, rates charged to customers have been adjusted to reflect the new federal corporate income tax rate. PSNH will refund the overcollection in rates from January 1, 2018 to customers in a future period.Analysis.

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, ~~have~~recovery of these costs has no impact on earnings. Revenues from certain of these

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

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

procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost

recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, net metering for distributed generation, and restructuring and stranded cost recovery revenues (including securitized RRB charges). In addition, tracked revenues include certain incentives earned and carrying charges that are billed in rates to customers.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.

Tracked revenues increased/(decreased) in ~~2018,~~2021, as compared to ~~2017,~~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 ⁽¹⁾
$ 172.8
$ 100.7
$ (54.4 )
Retail transmission (26.7 ) 75.1
(9.1 )
Stranded cost recovery 3.4
(21.5 ) 98.6
Other distribution tracking mechanisms 17.0
58.5
8.5

Wholesale Market Sales Revenue 24.4
(4.0 ) 28.3

⁽¹⁾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 ~~includes the absence~~was driven primarily by higher average supply-related sales volumes, partially offset by lower average prices. Fluctuations in ~~2018 of~~retail transmission revenues are driven by the recovery of ~~generation rate base return~~the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges. For further information, see "Purchased Power and Transmission Expense" below.

The increase in wholesale market sales revenue was due primarily to 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. The increase in wholesale market sales revenues at CL&P, NSTAR Electric and PSNH was also driven by higher proceeds from a one-year sale of ~~its thermal~~transmission rights, effective June 2021, under CL&P’s, NSTAR Electric’s and ~~hydroelectric generation assets in 2018.~~PSNH’s Hydro-Quebec transmission support agreements. Proceeds from these sales are credited back to customers.

Transmission Revenues: Transmission revenues ~~decreased $6.4 million and $15.3~~increased $42.6 million at CL&P, ~~and~~$30.1 million at NSTAR Electric ~~respectively,~~and $25.8 million at PSNH in 2021, as compared to 2020, due primarily to ~~lower revenue requirements~~a higher transmission rate base as a result of our continued investment in our transmission infrastructure.

Eliminations: Eliminations are primarily related to the ~~lower federal corporate income tax rate that was reflected in 2018~~Eversource electric transmission revenues ~~partially offset~~that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers. The impact of eliminations decreased revenues by ~~an increase related to ongoing investments in our transmission infrastructure. Transmission revenues increased $6.3~~$27.8 million at CL&P, $29.1 million at NSTAR Electric and $29.5 million at PSNH ~~due~~in 2021, as compared to ~~an increase related to ongoing investments in our transmission infrastructure, partially offset by the reduction in the federal corporate income tax rate.~~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 ~~2018,~~2021, as compared to ~~2017,~~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 $ 162.9
$ 141.1
$ 132.9
Transmission Costs (3.7 ) 75.7
1.6
Eliminations 5.2
14.9
(1.8 )
Total Purchased Power, Fuel and Transmission $ 164.4
$ 231.7
$ 132.7

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.~~suppliers and the cost of energy purchase contracts, as required by regulation.

•The increase at CL&P was due primarily to ~~an increase~~higher long-term contractual energy-related costs that are recovered in the ~~price and volume~~NBFMCC mechanism, partially offset by lower expense related to the procurement of ~~power procured on behalf of our customers.~~energy supply resulting from lower average prices.

•The ~~increase~~decrease at NSTAR Electric was due primarily to ~~an increase in~~lower expense related to the ~~price~~procurement of ~~power procured on behalf of our customers.~~energy supply resulting from lower average supply-related sales volumes, partially offset by higher net metering costs.

•The ~~increase~~decrease 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 tracking mechanism. 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 purchased power in place of its self-generation output in 2018.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 ~~a result of~~to an increase in costs billed by ISO-NE that support regional grid investments. This was partially offset by a decrease inresulting 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 Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network. ~~This~~

•The increase in transmission costs at NSTAR Electric and PSNH was ~~partially offset~~due primarily to an increase in costs billed by ISO-NE, an increase resulting from the retail transmission cost deferral, and an increase in costs billed by ISO-NE that support regional grid ~~investment.~~

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

Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense ~~increased/(decreased)~~increased in ~~2018,~~2021, as compared to ~~2017,~~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 $ 14.5
$ (8.3 ) $ 2.3
Bad debt expense 6.9
4.4
(0.1 )
HEEC Boston Harbor distribution cable costs —
(12.5 ) —
Storm restoration costs (7.4 ) 1.4
(0.3 )
Operations-related expenses, including vegetation management, vehicles, and outside services (excluding storm restoration costs) (3.9 ) 3.1
(0.8 )
Other non-tracked operations and maintenance 2.1
8.9
3.6
Total Base Electric Distribution (Non-Tracked Costs) 12.2
(3.0 ) 4.7
Tracked Costs:
Decrease of PSNH generation operations expenses due to the 2018 sales of thermal and hydroelectric generation assets —
—
(53.3 )
Transmission expenses (7.4 ) (12.0 ) 0.9
Other tracked operations and maintenance (0.6 ) (5.8 ) (4.9 )
Total Tracked Costs (8.0 ) (17.8 ) (57.3 )
Total Operations and Maintenance $ 4.2
$ (20.8 ) $ (52.6 )

Depreciation ~~increased/(decreased) at~~ expense increased in 2021, as compared to 2020, for CL&P, NSTAR Electric and PSNH ~~in 2018, as compared to 2017,~~ due ~~primarily to the following:~~

~~The increase at CL&P was due primarily~~ to higher net plant in service ~~balances and the implementation of~~balances. The increase at PSNH was also due to new depreciation rates effective ~~with~~January 1, 2021 resulting from the ~~CL&P~~2020 distribution rate ~~case~~ settlement agreement.

~~The increase at NSTAR Electric was due primarily to higher net plant in service balances, offset by lower distribution depreciation composite rates.~~

~~The decrease at PSNH was due primarily to the sale of the thermal and hydroelectric generation assets in 2018, partially offset by higher distribution depreciation expense.~~

Amortization of Regulatory ~~Assets/(Liabilities),~~Assets, Net expense includes the deferral of energy supply, ~~and~~ energy-related costs and other costs that are included in certain regulatory-approved ~~costs~~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/(Liabilities),~~Assets, Net ~~increased~~increased/decreased in 2021, as compared to 2020, due primarily to the following:

•The increase at CL&P ~~NSTAR Electric and PSNH in 2018, as compared to 2017,~~was 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. ~~In addition,~~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 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 ~~includes amortization of its securitized regulatory asset of $27.3 million related~~was due to the ~~2018 RRB issuance. Energy supply~~deferral adjustment of energy-related and ~~energy-related~~other tracked costs, which ~~are~~can fluctuate from period to period based on the ~~primary drivers~~timing of ~~amortization, are recovered from customers in rates~~costs incurred and ~~have no impact on earnings.~~ related rate changes to recover these costs.

Energy Efficiency Programs expenseincludes costs ~~for~~of various state energy policy initiatives and expanded energy efficiency programs ~~the majority of which~~that are recovered from customers in rates, ~~and~~most of which have no impact on earnings. Energy Efficiency Programs expenseincreased/~~(decreased)~~decreased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to the following:

•The decrease at CL&P was due ~~primarily~~ to ~~a State~~the deferral adjustment, which reflects actual costs of ~~Connecticut policy change requiring CL&P to remit 2018~~ energy efficiency ~~funds~~programs compared to the ~~State~~estimated amounts billed to customers, and the timing of ~~Connecticut (which totaled $46.8 million in 2018, as~~the recovery of energy efficiency costs.

•The increases at NSTAR Electric and PSNH were due to the deferral adjustment, which reflects actual costs of energy efficiency programs compared to ~~$25.4 million in 2017). These costs were collected from CL&P's~~the estimated amounts billed to customers, and ~~remitted to~~ the ~~State~~timing of ~~Connecticut; as such we have classified this amount as Taxes Other than Income Taxes.~~the recovery of energy efficiency costs.

~~The increase at PSNH was primarily due to an increase in allowed distribution revenue that funded a higher level of expenditures.~~

Taxes Other Than Income Taxes ~~increased/(decreased)~~increased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to the following:

•The increase at CL&P was ~~due primarily~~related to a State of Connecticut policy change requiring CL&P to remit 2018 energy efficiency funds to the State of Connecticut (which totaled $46.8 million in 2018, as compared to $25.4 million in 2017), as well as higher ~~property taxes due to higher utility plant balances and higher gross earnings taxes (the costs of which are tracked).~~

~~The increase at NSTAR Electric was due primarily to higher property taxes due to higher utility plant balances.~~

~~The decrease at PSNH was due primarily to the absence of~~ property taxes as a result of ~~the sales of its thermal~~a higher utility plant balance and ~~hydroelectric generation assets in 2018,~~higher gross earnings taxes.

•The increases at NSTAR Electric and ~~a 2018 refund of disputed property taxes for prior years from the Town of Bow, New Hampshire, partially offset by~~PSNH were due to higher property taxes ~~due to~~as a result of higher utility ~~distribution~~ plant balances.

Interest Expense ~~increased~~ increased/decreased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to the following:

•The increase at CL&P was due primarily to higher interest on long-term debt ~~as a result of new debt issuances~~ ($~~6.7~~5.4 million) ~~and~~, an increase in interest expense on regulatory deferrals ~~which increased interest expense~~ ($~~3.8~~3.7 million), ~~partially offset by an increase~~a decrease in AFUDC related to debt funds ($~~1.2~~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 ~~increase~~decrease at PSNH was due primarily to a decrease in RRB interest ~~on the 2018 RRB issuance~~expense ($~~14.4~~1.3 million), ~~partially offset by~~lower amortization of debt discounts and premiums, net ($0.7 million), and lower interest on long-term debt ($~~6.4~~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 ($0.4 million).

Other Income, Net increased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to the following:

•The increase at ~~NSTAR Electric~~CL&P was due primarily to an increase related to pension, SERP and PBOP non-service income components ($~~16.8~~11.4 million), higher interest income ($3.9 million), and ~~higher~~an increase in investment income ($0.2 million), partially offset by a decrease in AFUDC related to equity funds ($~~5.4~~6.1 million)~~, partially offset by investment loss in 2018 compared to investment income in 2017 ($3.1 million), primarily related to officer's life insurance policies.~~.

•The increase at ~~PSNH~~NSTAR Electric was due primarily to ~~the recognition of $8.7 million of the equity return component of the carrying charges related to storms incurred from August 2011 through March 2013 recorded in~~higher interest income ~~a gain on the sale of property~~ ($~~4.4~~12.5 million)~~, interest income primarily related to the 2018 refund of disputed property taxes for prior years ($2.6 million),~~ and an increase related to pension, SERP and PBOP non-service income components ($~~4.0~~10.9 million), partially offset by a decrease in AFUDC related to equity funds ($1.1 million).

•The increase at PSNH was due primarily to an increase related to pension, SERP and PBOP non-service income components ($3.3 million), partially offset by a decrease in AFUDC related to equity funds ($2.6 million).

Income Tax Expense increased/decreased in ~~2018,~~2021, as compared to ~~2017,~~2020, due primarily to the following:

•The decrease at CL&P was due primarily to the ~~new federal tax law enacted December 22, 2017, the Tax Cuts and Jobs Act, reducing the federal corporate income tax rate from 35 percent to 21 percent and lower pre-tax earnings~~CL&P settlement agreement ($~~90.8~~17.5 million), ~~partially offset by state taxes ($3.4 million), which includes an increase~~a decrease in a valuation allowance ~~of $2.5 million. Income tax expense increased by return to provision items~~ ($~~10.9~~17.0 million), ~~federal tax effect of state reserves~~ and ~~credits ($10.6 million) and by~~a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~8.4~~9.8 million), partially offset by 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 benefits ($0.8 million).

•The decrease at NSTAR Electric was due primarily to ~~the reduction~~an increase in ~~the federal corporate income tax rate and lower pre-tax earnings~~amortization of EDIT ($~~104.2~~22.8 million), partially offset by ~~return to provision items~~higher pre-tax earnings ($~~1.2~~3.2 million), higher state taxes ($~~2.8~~1.4 million), ~~and~~an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~7.0~~0.8 million), and lower share-based payment excess tax benefits ($0.9 million).

•The ~~decrease~~increase at PSNH was due primarily to ~~the reduction~~a decrease in ~~the federal corporate income tax rate and lower~~amortization of EDIT ($4.9 million), higher state taxes ($0.4 million), higher pre-tax earnings ($~~44.2~~2.2 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($~~1.3~~0.2 million)~~, partially offset by state taxes ($4.4 million)~~.

~~EARNINGS SUMMARY~~

CL&P's earnings increased $1.0 million in 2018, as compared to 2017, due primarily to the impact of the CL&P base distribution rate increase effective May 1, 2018, higher non-service income from our benefit plans, and an increase in transmission earnings driven by a higher transmission rate base. Earnings were also favorably impacted by lower income tax expense, net of lower distribution revenues resulting from the Tax Cuts and Jobs Act. The earnings increase was partially offset by higher depreciation expense, higher operations and maintenance expense, higher property and other tax expense, and higher interest expense.

NSTAR Electric's earnings increased $8.4 million in 2018, as compared to 2017, due primarily to an increase in transmission earnings driven by a higher transmission rate base, higher non-service income from our benefit plans, and lower distribution depreciation expense. Earnings were also favorably impacted by lower income tax expense, net of lower distribution revenues resulting from the Tax Cuts and Jobs Act. The earnings increase was partially offset by higher property tax expense and higher interest expense.

PSNH's earnings decreased $20.1 million in 2018, as compared to 2017, due primarily to lower generation earnings of $29.7 million as a result of thermal and hydroelectric generation asset sales in 2018, higher operations and maintenance expense, and higher distribution depreciation expense. The earnings decrease was partially offset by an increase in transmission earnings driven by a higher transmission rate base, the recognition of carrying charges on storm costs approved for recovery, a gain on the sale of property, lower property tax expense due to the 2018 refund of disputed property taxes for prior tax years, and higher sales volumes. Earnings were also favorably impacted by lower income tax expense, net of lower distribution revenues resulting from the Tax Cuts and Jobs Act.

~~LIQUIDITY~~

~~Cash Flows:~~ CL&P had cash flows provided by operating activities of $588.1 million in 2018, as compared to $806.3 million in 2017. The decrease in operating cash flows was due primarily to cash payments made in 2018 for storm restoration costs of approximately $142 million, an increase in Pension contributions of $38.7 million, and the timing of collections and payments related to our working capital items, including accounts receivable and accounts payable. Partially offsetting these unfavorable impacts was an increase related to the timing of cash collected for regulatory tracking mechanisms.

NSTAR Electric had cash flows provided by operating activities of $780.5 million in 2018, as compared to $639.3 million in 2017. The increase in operating cash flows was due primarily to the timing of cash collected for regulatory tracking mechanisms, a decrease of $29.0 million in Pension and PBOP contributions, and the timing of payments related to our working capital items, including accounts receivable and accounts payable. Partially offsetting these favorable impacts were cash payments made for storm restoration costs of approximately $90 million, and income tax payments of $120.0 million made in 2018, compared to income tax payments of $95.5 million made in 2017.

PSNH had cash flows provided by operating activities of $213.3 million in 2018, as compared to $300.9 million in 2017. The decrease in operating cash flows was due primarily to the absence of generation operations as a result of the generation asset sales in 2018, and the timing of payments of our working capital items, including accounts payable.

~~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~~.

~~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, 2017 and 2016 included in this Annual Report on Form 10-K:

For the Years Ended December 31,
(Millions of Dollars) 2017 2016 Increase/(Decrease)
Operating Revenues $ 7,752.0
$ 7,639.1
$ 112.9
Operating Expenses:

Purchased Power, Fuel and Transmission 2,535.3
2,500.8
34.5
Operations and Maintenance 1,307.0
1,342.1
(35.1 )
Depreciation 773.8
715.5
58.3
Amortization of Regulatory Assets, Net 90.0
71.7
18.3
Energy Efficiency Programs 480.8
533.7
(52.9 )
Taxes Other Than Income Taxes 676.8
634.0
42.8
Total Operating Expenses 5,863.7
5,797.8
65.9
Operating Income 1,888.3
1,841.3
47.0
Interest Expense 421.8
401.0
20.8
Other Income, Net 107.9
64.5
43.4
Income Before Income Tax Expense 1,574.4
1,504.8
69.6
Income Tax Expense 578.9
555.0
23.9
Net Income 995.5
949.8
45.7
Net Income Attributable to Noncontrolling Interests 7.5
7.5
—
Net Income Attributable to Common Shareholders $ 988.0
$ 942.3
$ 45.7

~~Operating Revenues~~

~~A summary of our Operating Revenues by segment was as follows:~~

For the Years Ended December 31,
(Millions of Dollars) 2017 2016 Increase/(Decrease)
Electric Distribution $ 5,542.9
$ 5,594.3
$ (51.4 )
Natural Gas Distribution 947.3
857.7
89.6
Electric Transmission 1,301.7
1,210.0
91.7
Other and Eliminations (39.9 ) (22.9 ) (17.0 )
Total Operating Revenues $ 7,752.0
$ 7,639.1
$ 112.9

~~A summary of our retail electric GWh sales volumes and our firm natural gas sales volumes in MMcf and percentage changes was as follows:~~

Electric Firm Natural Gas
For the Years Ended December 31, For the Years Ended December 31,

2017 ⁽¹⁾
2016 Decrease Percent
2017 ⁽¹⁾
2016 Increase Percent
Traditional 27,855
28,479
(624 ) (2.2 )% 46,957
45,314
1,643
3.6 %
Decoupled and
Natural Gas Special Contracts
24,391
25,163
(772 ) (3.1 )% 54,069
52,728
1,341
2.5 %
Total Sales Volumes 52,246
53,642
(1,396 ) (2.6 )% 101,026
98,042
2,984
3.0 %


⁽¹⁾	~~The 2017 sales volumes have not been recast in this presentation for comparability between the prior years.~~

Fluctuations in sales volumes at certain of the electric and natural gas utilities impact earnings ("Traditional" in the table above). Fluctuations in CL&P's, NSTAR Electric's (for a portion of its sales volumes as of December 31, 2017) and NSTAR Gas' sales volumes do not impact the level of base distribution revenue realized or earnings due to the commission-approved revenue decoupling mechanisms ("Decoupled and Natural Gas Special Contracts" in the table above). The revenue decoupling mechanisms permit recovery of a base amount of distribution revenues and breaks the relationship between sales volumes and revenues recognized. Effective February 1, 2018, all of NSTAR Electric's distribution revenues were decoupled as a result of the DPU-approved rate case decision.

Operating Revenues, which primarily consist of base electric and natural gas distribution revenues and tracked revenues further described below, increased by $112.9 million in 2017, as compared to 2016.

~~Base electric and natural gas distribution revenues~~: Base electric distribution segment revenues, excluding LBR, decreased $12.3 million in 2017, as compared to 2016, due primarily to a decrease in sales volumes driven by the mild summer weather in 2017 at our non-decoupled electric companies. LBR increased $13.0 million in 2017, as compared to 2016. Effective February 1, 2018, NSTAR Electric no longer has an LBR recovery mechanism. Base natural gas distribution revenues increased $2.9 million in 2017, as compared to 2016. The impact of higher firm natural gas sales volumes, which was driven by colder winter weather in the fourth quarter of 2017, was partially offset by lower demand revenues in Connecticut driven by lower peak usage in 2017, as compared to 2016.

~~Tracked distribution revenues:~~ Tracked revenues consist of certain costs that are recovered from customers in rates through regulatory commission-approved cost tracking mechanisms and therefore, have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs for our electric and natural gas customers, retail transmission charges, energy efficiency program costs, net metering for distributed generation and restructuring and stranded cost recovery revenues. In addition, certain tracked revenues include incentives earned and carrying charges that are billed in rates to customers.

Tracked natural gas distribution segment revenues increased as a result of an increase in natural gas supply costs ($68.7 million) and an increase in energy efficiency program revenues ($18.1 million). Tracked electric distribution revenues decreased as a result of a decrease in electric energy supply costs ($21.7 million), driven by decreased average retail prices and lower sales volumes, a decrease in retail electric transmission charges ($14.8 million), a decrease in transition and stranded cost recovery revenues ($46.2 million), a decrease in pension rate adjustment mechanisms ($21.6 million), a decrease in revenues related to the timing of the sale of PSNH's RECs ($16.3 million), and a decrease in energy efficiency program revenues ($10.4 million). Partially offsetting these decreases were increases in tracked electric distribution revenues related to federally-mandated congestion charges ($30.1 million), net metering revenues ($29.8 million) and revenues related to renewable energy requirements ($41.9 million).

~~Electric transmission revenues:~~ The electric transmission segment revenues increased by $91.7 million due primarily to the recovery of higher revenue requirements associated with ongoing investments in our transmission infrastructure.

~~Other:~~ Other revenues decreased due primarily to the sale of Eversource's unregulated telecommunication business on December 31, 2016 ($20.0 million), partially offset by the addition of Aquarion revenues due to the acquisition on December 4, 2017 ($15.9 million).

~~Purchased Power, Fuel and Transmission~~ expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These energy supply 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 in 2017, as compared to 2016, due primarily to the following:

(Millions of Dollars) (Decrease)/Increase
Electric Distribution $ (68.9 )
Natural Gas Distribution 59.5
Transmission 43.9
Total Purchased Power, Fuel and Transmission $ 34.5

The decrease in purchased power expense at the electric distribution business in 2017, as compared to 2016, was driven primarily by lower prices associated with the procurement of energy supply and lower sales volumes. The increase in purchased power expense at the natural gas distribution business was due to higher average natural gas prices and higher sales volumes. The increase in transmission costs in 2017, as compared to 2016, was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment, and Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network. This was partially offset by a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

~~Operations and Maintenance~~ expense includes tracked costs and costs that are part of base electric and natural gas distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense decreased in 2017, as compared to 2016, due primarily to the following:

(Millions of Dollars) Increase/(Decrease)
Base Electric Distribution:
Employee-related expenses, including labor and benefits $ (46.8 )
Bad debt expense (14.5 )
Shared corporate costs (including computer software depreciation at Eversource Service) 24.2
HEEC Boston Harbor distribution cable costs 16.0
Other non-tracked operations and maintenance 7.4
Total Base Electric Distribution (13.7 )
Base Natural Gas Distribution 4.3
Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution):
Absence in 2017 of earnings benefit related to merger-related costs allowed for recovery through transmission rates 27.5
Other tracked operations and maintenance (4.4 )
Total Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution) 23.1
Other and eliminations:
  Merger-related costs allowed for recovery through NSTAR Electric distribution rates as a result of the November 30, 2017
    DPU distribution rate case decision (earnings benefit)
(30.5 )
Addition of Aquarion operations and maintenance expenses due to acquisition on December 4, 2017 6.9
Eversource Parent and Other Companies - other operations and maintenance 7.6
   Eliminations (32.8 )
Total Operations and Maintenance $ (35.1 )

~~Depreciation~~ ~~expense increased in 2017, as compared to 2016, due primarily to higher utility plant in service balances.~~

~~Amortization of Regulatory Assets, Net~~ expense includes the deferral of energy supply and energy-related costs included in certain regulatory-approved tracking mechanisms, and the amortization of certain costs. The deferral adjusts expense to match the corresponding revenues. Amortization of Regulatory Assets, Net increased in 2017, as compared to 2016, due primarily to the deferral of energy supply and energy-related costs which can fluctuate from period to period based on the timing of costs incurred and the related rate changes to recover these costs. Energy supply and energy-related costs at the electric and natural gas companies are recovered from customers in rates and have no impact on earnings.

~~Energy Efficiency Programs~~ expense decreased in 2017, as compared to 2016, due primarily to a State of Connecticut policy change impacting CL&P requiring the remittance of $25.4 million of 2017 energy efficiency funds to the State (resulting in these costs being classified as Taxes Other than Income Taxes), and the deferral adjustment at NSTAR Electric. The deferral adjustment reflects the actual costs of energy efficiency programs compared to the estimated amounts billed to customers. The deferral adjusts costs incurred to match energy efficiency revenue billed to customers and the timing of the recovery of energy efficiency costs. The costs for various state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.

~~Taxes Other Than Income Taxes~~ expense increased in 2017, as compared to 2016, due primarily to a State of Connecticut policy change requiring $25.4 million of 2017 CL&P energy efficiency costs to be remitted to the State of Connecticut that is included in Taxes Other than Income Taxes, an increase in property taxes as a result of higher utility plant balances, partially offset by a decrease in gross earnings taxes. Gross earnings taxes are recovered from customers in rates and have no impact on earnings.

~~Interest Expense~~ increased in 2017, as compared to 2016, due primarily to an increase in interest on long-term debt ($30.3 million) as a result of new debt issuances and an increase in interest on notes payable ($5.1 million), partially offset by a decrease in regulatory deferrals, primarily at NSTAR Electric, which decreased interest expense ($14.7 million) due primarily to the November 30, 2017 NSTAR Electric DPU distribution rate case decision which allowed for a higher rate on carrying charges for past storm costs.

~~Other Income, Net~~ increased in 2017, as compared to 2016, due primarily to increased gains on investments ($27.2 million), primarily related to Eversource's investment in a renewable energy fund, an increase related to pension, SERP and PBOP non-service income components ($11.3 million), changes in the market value related to deferred compensation plans ($8.3 million) and higher AFUDC related to equity funds ($8.2 million). Partially offsetting these favorable impacts was the absence in 2017 of a gain on the sale of an unregulated business in 2016 ($11.8 million) and lower interest income ($3.3 million).

~~Income Tax Expense~~ increased in 2017, as compared to 2016, due primarily to higher pre-tax earnings ($29.1 million), lower excess tax benefit ($16.2 million), the absence of tax credits in 2017 ($3.5 million), and the impact from federal tax rate change ($0.5 million), partially offset by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($11.4 million), the sale of an unregulated business in 2016 ($10.2 million), and lower state taxes ($3.8 million).

EARNINGS SUMMARY

~~Regulated Companies:~~ ~~Our electric distribution segment~~CL&P's earnings ~~increased $34.6~~decreased $56.2 million in ~~2017,~~2021, as compared to ~~2016,~~2020, due primarily to the settlement agreement on October 1, 2021 resulting in a ~~lower effective tax rate, lower non-tracked~~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 ~~lost base revenues at NSTAR Electric~~employee-related expenses, higher shared corporate costs, and higher ~~distribution revenues at CL&P due in part to a~~vegetation management costs, higher ~~rate base for the system resiliency program,~~depreciation expense, higher property tax expense, and higher interest expense. The earnings decrease was partially offset by higher ~~depreciation expense, lower sales volumes primarily driven by the mild summer weather in 2017, as compared to 2016 (primarily at NSTAR Electric), and higher property tax expense.~~

~~Our electric transmission segment~~ earnings increased $21.1 million in 2017, as compared to 2016, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure, partially offset by the absence in 2017 of the FERC-allowed recovery of certain previously expensed merger-related costs in 2016, and a lower benefit in the second quarter of 2017 related to the annual billing and cost reconciliation filing with the FERC.

Our natural gas distribution segment earnings decreased $3.1 million in 2017, as compared to 2016, due primarily to higher depreciation expense, lower demand revenues in Connecticut driven by lower peak usage in 2017, as compared to 2016, higher non-tracked operations and maintenance expense, and higher property tax expense, partially offset by higher sales volumes driven by colder winter weather in the fourth quarter of 2017, as compared to 2016.

~~Eversource Parent and Other Companies:~~ Eversource parent and other companies, including our water business, earned $25.3 million in 2017, compared with $31.0 million in 2016. The decrease in earnings was due primarily to a higher effective tax rate, higher interest expense and the absence in 2017 of the earnings and gain on the sale of an unregulated business in 2016. These decreases were partially offset by the 2017 DPU-allowed recovery of certain previously expensed merger-related costs in NSTAR Electric's distribution rates, and increased gains on investments recorded in 2017.

~~LIQUIDITY~~

Cash flows provided by operating activities totaled $2.0 billion in 2017, compared with $2.2 billion in 2016. The decrease in operating cash flows was due primarily to the $166.3 million net unfavorable impact as a result of the change in income tax payments made, or refunds received, in 2017 when compared to 2016. This unfavorable impact was primarily the result of the December 2015 legislation, which extended the accelerated deduction of depreciation from 2015 to 2019. The legislation resulted in a significant refund of approximately $275 million, which we received in the first quarter of 2016. Additionally, there was an increase of $84.1 million in Pension and PBOP Plan cash contributions made in 2017, as compared to 2016, a decrease of $59.8 million related to the absence in 2017 of the Yankee Companies' DOE Damages received in 2016, and the unfavorable impact related to the timing of regulatory recoveries, which were significantly impacted by NSTAR Electric’s timing of collections of purchased power and transmission costs. Partially offsetting these unfavorable impacts was the benefit related to the timing of collections and payments of our workingits capital ~~items, including accounts payable.~~

~~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, 2017 and 2016 included in this Annual Report on Form 10-K:

For the Years Ended December 31,
CL&P NSTAR Electric PSNH
(Millions of Dollars) 2017 2016 Increase/(Decrease) 2017 2016 Increase/(Decrease) 2017 2016 Increase/(Decrease)
Operating Revenues $ 2,887.4
$ 2,806.0
$ 81.4
$ 2,980.6
$ 3,041.6
$ (61.0 ) $ 981.6
$ 959.5
$ 22.1
Operating Expenses:

Purchased Power, Fuel and Transmission 930.8
919.7
11.1
1,025.4
1,084.3
(58.9 ) 237.5
210.8
26.7
Operations and Maintenance 502.2
490.8
11.4
482.9
500.4
(17.5 ) 263.1
267.1
(4.0 )
Depreciation 249.4
230.5
18.9
274.0
259.3
14.7
128.2
116.5
11.7
Amortization of Regulatory Assets/
(Liabilities), Net
83.2
38.8
44.4
33.8
34.3
(0.5 ) (16.6 ) 11.2
(27.8 )
Energy Efficiency Programs 114.7
154.0
(39.3 ) 294.1
321.8
(27.7 ) 13.8
14.2
(0.4 )
Taxes Other Than Income Taxes 323.8
299.7
24.1
182.0
177.8
4.2
89.7
82.9
6.8
Total Operating Expenses 2,204.1
2,133.5
70.6
2,292.2
2,377.9
(85.7 ) 715.7
702.7
13.0
Operating Income 683.3
672.5
10.8
688.4
663.7
24.7
265.9
256.8
9.1
Interest Expense 143.0
144.1
(1.1 ) 105.7
108.4
(2.7 ) 51.0
50.0
1.0
Other Income, Net 23.0
14.2
8.8
34.1
21.3
12.8
9.8
7.5
2.3
Income Before Income Tax Expense 563.3
542.6
20.7
616.8
576.6
40.2
224.7
214.3
10.4
Income Tax Expense 186.6
208.3
(21.7 ) 242.1
225.8
16.3
88.7
82.3
6.4
Net Income $ 376.7
$ 334.3
$ 42.4
$ 374.7
$ 350.8
$ 23.9
$ 136.0
$ 132.0
$ 4.0

~~Operating Revenues~~

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

Rate For the Years Ended December 31,
Structure 2017 2016 Decrease Percent
CL&P Decoupled 20,950
21,617
(667 ) (3.1 )%
NSTAR Electric (eastern Massachusetts) Traditional 20,097
20,619
(522 ) (2.5 )%
NSTAR Electric (western Massachusetts) Decoupled 3,441
3,546
(105 ) (3.0 )%
PSNH Traditional 7,758
7,860
(102 ) (1.3 )%

Fluctuations in retail electric sales volumes at certain of the electric utilities impact earnings ("Traditional" in the table above). For others, fluctuations in retail electric sales volumes do not impact earningstracker mechanism due to ~~their regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled" in~~increased electric system improvements, the ~~table above). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.~~

In 2017 and 2016, NSTAR Electric operated under two different rate structures based on its service territory geography. For customers that were served in eastern Massachusetts, including metropolitan Boston, Cape Cod and Martha's Vineyard, NSTAR Electric operated using traditional rates. For customers that were served in western Massachusetts, including the metropolitan Springfield region, NSTAR Electric operated using decoupled rates. Effective February 1, 2018, all of NSTAR Electric's distribution revenues were decoupled as a result of the DPU-approved rate decision. See "Regulatory Developments and Rate Matters - Massachusetts - NSTAR Electric Distribution Rate Case Decision" in this ~~Management's Discussion and Analysis of Financial Condition and Results of Operations.~~

~~CL&P and NSTAR Electric (for its western Massachusetts customer rates) reconcile their annual~~ base distribution rate ~~recovery amounts to their pre-established levels of baseline distribution delivery service revenues of $1.059 billion and $132.4 million, respectively, through December 31, 2017. Effective February~~increase effective May 1, 2018, NSTAR Electric, operating entirely under decoupled rates, will reconcile its annual base distribution rate recovery to its new baseline of $974.8 million. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period.

~~Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased/(decreased) in 2017, as compared to 2016 as follows:~~

(Millions of Dollars) CL&P NSTAR Electric PSNH
Operating Revenues $ 81.4
$ (61.0 ) $ 22.1

~~Base Distribution Revenues, with changes that impact earnings:~~

NSTAR Electric's base distribution revenues, excluding LBR, decreased $10.8 million in 2017, as compared to 2016, as a result of lower sales volumes driven by the mild summer weather in 2017. LBR increased $13.0 million in 2017, as compared to 2016. Effective February 1, 2018, NSTAR Electric no longer has an LBR mechanism.

~~PSNH's base distribution revenues decreased $1.5 million in 2017, as compared to 2016, as a result of lower sales volumes driven by the mild summer weather in 2017.~~

~~Tracked Revenues:~~ Fluctuations in the overall level of operating revenues are primarily related to tracked revenues. Tracked revenues consist of certain costs that are recovered from customers in rates through commission-approved cost tracking mechanisms and therefore have no impact on earnings. Costs recovered through cost tracking mechanisms include energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, net metering for distributed generation and restructuring and stranded cost recovery revenues. In addition, tracked revenues include certain incentives earned and carrying charges. Tracked revenues increased/(decreased) in 2017, as compared to 2016, due primarily to the following:

(Millions of Dollars) CL&P NSTAR Electric PSNH
Energy supply procurement $ 18.8
$ (50.8 ) $ 10.3
All other distribution tracking mechanisms 35.0
(33.7 ) (12.7 )

~~Transmission Revenues:~~ Transmission revenues increased by $34.2 million, $31.0 million and $26.5 million at CL&P, NSTAR Electric and PSNH, respectively, due primarily to higher revenue requirements associated with ongoing investments in our transmission infrastructure.

~~Purchased Power, Fuel and Transmission~~ expense includes costs associated with purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's customers. For PSNH, these costs also include PSNH's generation of electricity. These energy supply costs are recovered from customers in commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense increased/(decreased) in 2017, as compared to 2016, due primarily to the following:

(Millions of Dollars) CL&P NSTAR Electric PSNH
Purchased Power Costs $ (41.4 ) $ (27.9 ) $ 3.7
Transmission Costs 52.5
(31.0 ) 23.0
Total Purchased Power, Fuel and Transmission $ 11.1
$ (58.9 ) $ 26.7

~~Purchased Power Costs~~: Included in purchased power costs are the costs associated with certain energy supply tracking mechanisms and deferred energy supply costs. Energy supply tracking mechanisms recover energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to third party suppliers. In order to meet the demand of customers who have not migrated to third party suppliers, PSNH procures power through power supply contracts and spot purchases in the competitive New England wholesale power market and/or produces power through its own generation. The increase/(decrease) in purchased power costs in 2017, as compared to 2016, was due primarily to the following:

~~The decrease at CL&P was due primarily to a decrease in the price of standard offer supply associated with the GSC.~~

~~The decrease at NSTAR Electric was due primarily to lower prices associated with the procurement of energy supply, lower sales volumes and the expiration of certain purchase power agreements.~~

The increase at PSNH was due primarily to higher purchased power energy expenses that are recovered as a component of the Energy Service rate, and Regional Greenhouse Gas Initiative related expenses recovered in the SCRC.

~~Transmission Costs~~: Included in transmission costs are charges that recover 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 increase/(decrease) in transmission costs in 2017, as compared to 2016, was due primarily to the following:

The increase at CL&P was primarily the result of an increase in costs billed by ISO-NE that support regional grid investment, Local Network Service charges, which reflect the cost of transmission service, and the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

~~The decrease at NSTAR Electric was primarily the result of a decrease in the retail transmission cost deferral. This was partially offset by an increase in costs billed by ISO-NE.~~

~~The increase at PSNH was primarily the result of increases in costs billed by ISO-NE, Local Network Service charges, and the retail transmission cost deferral.~~

~~Operations and Maintenance~~ expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense increased/(decreased) in 2017, as compared to 2016, 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 $ (4.0 ) $ (36.6 ) $ (6.2 )
Bad debt expense (6.8 ) (7.5 ) (0.2 )
Shared corporate costs (including computer software depreciation at Eversource Service) 7.8
12.6
3.8
HEEC Boston Harbor distribution cable costs —
16.0
—
Other non-tracked operations and maintenance 8.8
0.6
(2.0 )
Total Base Electric Distribution (Non-Tracked Costs) 5.8
(14.9 ) (4.6 )
Tracked Costs:
Employee-related expenses, including labor and benefits 1.9
(7.5 ) (1.0 )
Other tracked operations and maintenance 3.7
4.9
1.6
Total Tracked Costs 5.6
(2.6 ) 0.6
Total Operations and Maintenance $ 11.4
$ (17.5 ) $ (4.0 )

~~Depreciation~~ ~~increased at CL&P, NSTAR Electric and PSNH in 2017, as compared to 2016, due primarily to higher utility plant in service balances.~~

~~Amortization of Regulatory Assets/(Liabilities), Net~~ expense includes the deferral of energy supply and energy-related costs and the amortization of storm and other costs. Amortization of Regulatory Assets/(Liabilities), Net increased at CL&P and decreased for both NSTAR Electric and PSNH in 2017, as compared to 2016, due primarily to the deferral adjustment of energy supply and energy-related costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The deferral adjusts expense to match the corresponding revenues. Energy supply and energy-related costs, which are the primary drivers of amortization, are recovered from customers in rates and have no impact on earnings.

~~Energy Efficiency Programs~~ ~~expenseincludes costs for various state policy initiatives and are recovered from customers in rates and have no impact on earnings. Energy Efficiency Programs expensedecreased in 2017, as compared to 2016, due primarily to the following:~~

The decrease at CL&P is due primarily to a State of Connecticut policy change requiring the remittance of $25.4 million of 2017 energy efficiency funds to the State. These amounts collected from customers were reclassified to Taxes Other than Income Taxes.

The decrease at NSTAR Electric is due to the deferral adjustment, which reflects the actual cost of energy efficiency programs compared to the estimated amounts billed to customers and the timing of the recovery of energy efficiency costs. The deferral adjusts costs to match energy efficiency revenue billed to customers.

~~Taxes Other Than Income Taxes~~ ~~increased in 2017, as compared to 2016, due primarily to the following:~~

The increase at CL&P is due primarily to a State of Connecticut policy change requiring the remittance of $25.4 million of 2017 energy efficiency funds to the State and higher utility plant balances, partially offset by a decrease in gross earnings taxes. Gross earnings taxes are recovered from customers in rates and have no impact on earnings.

The increase at NSTAR Electric is due primarily to higher property taxes resulting from disallowed costs in the November 30, 2017 NSTAR Electric DPU distribution rate case decision and higher employee-related payroll taxes, partially offset by a decrease in property tax rates in Boston.

~~The increase at PSNH is due to an increase in property taxes as a result of higher utility plant balances.~~

~~Interest Expense~~ ~~at NSTAR Electric~~decreased in 2017, as compared to 2016, due primarily to lower deferred regulatory interest expense ($14.0 million), primarily as a result of the November 30, 2017 NSTAR Electric DPU distribution rate case decision, which allowed for a higher interest rate on carrying charges for past storm costs, partially offset by an increase in interest on long-term debt ($9.6 million).

~~Other Income, Net~~ ~~increased in 2017, as compared to 2016, due primarily to the following:~~

The increase at CL&P is due to higher AFUDC related to equity funds ($5.9 million) and market value changes related to the deferred compensation plans ($6.3 million), partially offset by lower interest income ($4.4 million).

The increase at NSTAR Electric is due to an increase related to pension, SERP and PBOP non-service income components ($8.7 million), market value changes related to the deferred compensation plans ($1.6 million), an increase in amounts related to officer life insurance policies ($1.3 million) and an increase in interest income ($1.2 million).

~~The increase at PSNH is due to market value changes related to the deferred compensation plans ($1.5 million).~~

~~Income Tax Expense~~ ~~increased/(decreased) in 2017, as compared to 2016, due primarily to the following:~~

The decrease at CL&P is due primarily to the tax reform impacts on the federal tax effect of state reserves and credits ($10.7 million), items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($10.1 million), the true up of the return to provision impacts ($2.6 million), and lower state taxes ($5.5 million), partially offset by higher pre-tax earnings ($7.2 million).

The increase at NSTAR Electric is due primarily to higher pre-tax earnings ($14.5 million), higher state taxes ($2.4 million), partially offset by items that impact our tax rate as a result of flow-through items and permanent differences ($0.6 million).

The increase at PSNH is due primarily to higher pre-tax earnings ($3.6 million) and the absence of tax credits in 2017 ($3.5 million), partially offset by items that impact our tax rate as a result of flow-through items and permanent differences ($0.7 million).

~~EARNINGS SUMMARY~~

~~CL&P's earnings increased $42.4 million in 2017, as compared to 2016, due primarily to a lower effective tax rate,~~2020, an increase in transmission earnings driven by a higher transmission rate base, and ~~higher distribution revenues due~~an increase in ~~part to a higher rate base for~~ the ~~system resiliency program. These favorable earnings impacts were partially offset by higher depreciation expense, higher operations~~non-service income components of pension, SERP and ~~maintenance expense, and higher property tax expense.~~PBOP net periodic benefit plan cost.

NSTAR Electric's earnings increased ~~$23.9~~$31.6 million in ~~2017,~~2021, as compared to 2016, due primarily to higher distribution revenues related to lost base revenues, net metering and the PAM, lower operations and maintenance expense, lower interest expense as a result of the November 30, 2017 NSTAR Electric distribution rate case decision, and an increase in transmission earnings driven by a higher transmission rate base. These favorable earnings impacts were partially offset by lower sales volumes driven by the mild summer weather in 2017, higher depreciation expense, and higher property tax expense.

~~PSNH's earnings increased $4.0 million in 2017, as compared to 2016,~~2020, due primarily to an increase in transmission earnings driven by a higher transmission rate base, the base distribution rate increase effective January 1, 2021, a lower effective tax rate, and ~~lower~~the earnings 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, and higher interest expense. ~~These favorable~~

PSNH's earnings ~~impacts were~~increased $3.0 million in 2021, as compared to 2020, due primarily to the base distribution rate increases effective January 1, 2021 and August 1, 2021, an increase in transmission earnings driven by a higher transmission rate base, and the impact in 2021 of a new tracker mechanism at PSNH approved as part of the 2020 rate settlement agreement. The earnings increase was partially offset by ~~lower generation earnings,~~higher operations and maintenance expense primarily driven by higher vegetation management costs and higher employee-related expenses, higher depreciation expense, and higher property tax ~~expense, lower sales volumes driven by the mild summer weather in 2017, and a higher effective tax rate.~~expense.

LIQUIDITY

Cash Flows:CL&P had cash flows provided by operating activities of ~~$806.3~~$612.9 million in ~~2017,~~2021, as compared ~~with $812.2~~to $397.1 million in ~~2016.~~2020. The ~~decrease~~increase in operating cash flows was due primarily to ~~income tax payments of $68.8 million made in 2017, compared to the income tax refunds of $73.9 million received in 2016. Partially offsetting this decrease was~~ the timing of collections for regulatory ~~recoveries, an increase in distribution rates due to higher rate base,~~tracking mechanisms, the timing of cash collections on our accounts receivable, the timing of cash payments made on our accounts payable, and the timing of ~~collections and payments related to our~~other working capital items. These favorable impacts were partially offset by a $75.7 million increase in pension contributions made in 2021, as compared to 2020, a $38.4 million increase in cost of removal expenditures, and a $27.5 million increase in income tax payments made in 2021, as compared to 2020.

NSTAR Electric had cash flows provided by operating activities of ~~$639.3~~$700.9 million in ~~2017,~~2021, as compared to ~~$812.1~~$525.8 million in ~~2016.~~2020. The ~~decrease~~increase in operating cash flows was due primarily to ~~a decrease in regulatory recoveries, which were significantly impacted by~~ the timing of collections for regulatory tracking mechanisms, the timing of ~~purchased power and transmission costs, an increase of $53.4~~other working capital items, a $36.5 million ~~in Pension and PBOP Plan cash contributions and an increase of $29.5 million~~decrease in income tax payments made in ~~2017,~~2021, as compared to ~~2016. Also contributing to the decrease was~~2020, the timing of ~~working capital items, including~~cash collections on our accounts ~~payable~~receivable, and ~~inventory.~~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 ~~$300.9~~$336.1 million in ~~2017,~~2021, as compared to ~~$360.7~~$218.7 million in ~~2016.~~2020. The ~~decrease~~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, a $16.9 million increase in income tax payments ~~of $26.1 million~~ made in ~~2017,~~2021, as compared to ~~the income tax refunds~~2020, and an $8.7 million increase in cost of ~~$36.0 million received~~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 ~~2016~~this Management's Discussion and ~~the unfavorable impacts related to the timing~~Analysis of ~~regulatory recoveries. Partially offsetting these decreases were the timing~~Financial Condition and Results of ~~collections and payments of our working capital items, including accounts payable and inventory, and a $16.3 million decrease in Pension Plan cash contributions.~~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 ~~and directors~~ 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, ~~2018, all~~2021, approximately 98 percent of our long-term debt ~~except for $39.5 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, ~~2018,~~2021, our regulated companies ~~did not hold~~held collateral (letters of ~~credit)~~credit or cash) of $210.9 million from counterparties related to our standard service contracts. As of December 31, ~~2018,~~2021, Eversource had ~~$24.8~~$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 ~~1P,~~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
		Management’s Report on Internal Controls Over Financial Reporting
		Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
		~~Consolidated~~ Financial Statements

~~CL&P~~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

~~NSTAR Electric~~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

~~PSNH~~
	~~Company Report on Internal Controls Over Financial Reporting~~
	~~Report of Independent Registered Public Accounting Firm~~
	~~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, ~~2018.~~2021.

February ~~26, 2019~~16, 2022

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Eversource Energy:

~~Opinions~~Opinion on ~~the Financial Statements and~~ Internal Control over Financial Reporting

We have audited the ~~accompanying consolidated balance sheets~~internal control over financial reporting of Eversource Energy and subsidiaries (the “Company”) as of December 31, 2018 and 2017, 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, 2018, and the related notes and the schedules listed in the Index at Item 15 of Part IV (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2018,2021, 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 financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

~~Also, in~~ our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2018,~~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, 2021, of the Company and our report dated February 16, 2022, expressed an unqualified opinion on those financial statements.

Basis for ~~Opinions~~

Opinion

The Company’s management is responsible ~~for these financial statements,~~ 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 ~~these financial statements and an opinion on~~ the Company’s internal control over financial reporting based on our ~~audits.~~audit. We are a public accounting firm registered with the ~~Public Company Accounting Oversight Board (United States) (PCAOB)~~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~~audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the ~~audits~~audit to obtain reasonable assurance about ~~whether the financial statements are free of material misstatement, whether due to error or fraud, and~~ whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to 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. Our audit ~~of internal control over financial reporting~~ included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, ~~and~~ testing and evaluating the design and operating effectiveness of internal control based on the assessed ~~risk. Our audits also included~~risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our ~~audits provide~~audit provides a reasonable basis for our ~~opinions.~~

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 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, 2021 and 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, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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, 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 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 the Federal Energy Regulatory Commission and by their respective state public utility authorities in Connecticut, Massachusetts, or New Hampshire (the “Commissions”). The rate regulation by these Commissions is based on cost recovery. The regulated companies’ financial statements reflect the effects of the rate-making process. The rates charged to the customers of the Company’s regulated companies are designed to collect each company’s cost to provide service, plus a return on investment.

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

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

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

How the Critical Audit Matter Was Addressed in the Audit

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

• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates, a refund, or a future reduction in rates.

• We evaluated the Company’s disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements. 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, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future refund or reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

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

• We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery, refund, or future reductions in rates for regulatory assets and liabilities, 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, 2019~~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) 2018 2017

ASSETS

Current Assets:

Cash and Cash Equivalents $ 108,068
$ 38,165
Receivables, Net 994,055
925,083
Unbilled Revenues 176,285
201,361
Fuel, Materials, Supplies and Inventory 238,042
223,063
Regulatory Assets 514,779
741,868
Prepayments and Other Current Assets 260,995
138,009
Assets Held for Sale —
219,550
Total Current Assets 2,292,224
2,487,099

Property, Plant and Equipment, Net 25,610,428
23,617,463

Deferred Debits and Other Assets:

Regulatory Assets 4,631,137
4,497,447
Goodwill 4,427,266
4,427,266
Marketable Securities 417,508
585,419
Other Long-Term Assets 862,693
605,692
Total Deferred Debits and Other Assets 10,338,604
10,115,824

Total Assets $ 38,241,256
$ 36,220,386

LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable $ 910,000
$ 1,088,087
Long-Term Debt – Current Portion 837,319
549,631
Rate Reduction Bonds – Current Portion 52,332
—
Accounts Payable 1,119,995
1,085,034
Regulatory Liabilities 370,230
128,071
Other Current Liabilities 823,006
738,222
Total Current Liabilities 4,112,882
3,589,045

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes 3,506,030
3,297,518
Regulatory Liabilities 3,609,475
3,637,273
Derivative Liabilities 379,562
377,257
Accrued Pension, SERP and PBOP 962,510
1,228,091
Other Long-Term Liabilities 1,196,336
1,073,501
Total Deferred Credits and Other Liabilities 9,653,913
9,613,640

Long-Term Debt 12,248,743
11,775,889

Rate Reduction Bonds 583,331
—

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

Common Shareholders' Equity:
Common Shares 1,669,392
1,669,392
Capital Surplus, Paid In 6,241,222
6,239,940
Retained Earnings 3,953,974
3,561,084
Accumulated Other Comprehensive Loss (60,000 ) (66,403 )
Treasury Stock (317,771 ) (317,771 )
Common Shareholders' Equity 11,486,817
11,086,242

Commitments and Contingencies (Note 12)

Total Liabilities and Capitalization $ 38,241,256
$ 36,220,386

~~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,
(Thousands of Dollars, Except Share Information) 2018 2017 2016

Operating Revenues $ 8,448,201
$ 7,751,952
$ 7,639,129

Operating Expenses:
Purchased Power, Fuel and Transmission 3,138,969
2,535,271
2,500,828
Operations and Maintenance 1,335,213
1,307,052
1,342,134
Depreciation 819,930
773,802
715,466
Amortization 252,026
89,986
71,696
Energy Efficiency Programs 472,380
480,835
533,659
Taxes Other Than Income Taxes 729,753
676,757
634,072
Total Operating Expenses 6,748,271
5,863,703
5,797,855
Operating Income 1,699,930
1,888,249
1,841,274
Interest Expense 498,805
421,755
400,961
Other Income, Net 128,366
107,913
64,505
Income Before Income Tax Expense 1,329,491
1,574,407
1,504,818
Income Tax Expense 288,972
578,892
554,997
Net Income 1,040,519
995,515
949,821
Net Income Attributable to Noncontrolling Interests 7,519
7,519
7,519
Net Income Attributable to Common Shareholders $ 1,033,000
$ 987,996
$ 942,302

Basic Earnings Per Common Share $ 3.25
$ 3.11
$ 2.97

Diluted Earnings Per Common Share $ 3.25
$ 3.11
$ 2.96

Weighted Average Common Shares Outstanding:
Basic 317,370,369
317,411,097
317,650,180
Diluted 317,993,934
318,031,580
318,454,239

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

EVERSOURCE ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~COMPREHENSIVE~~ INCOME


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

Operating Revenues	$	9,863,085	$	8,904,430	$	8,526,470

Operating Expenses:
Purchased Power, Fuel and Transmission	3,372,344		2,987,840		3,040,160
Operations and Maintenance	1,739,685		1,480,252		1,363,113
Depreciation	1,103,008		981,380		885,278
Amortization	231,965		177,679		195,380
Energy Efficiency Programs	592,775		535,760		501,369
Taxes Other Than Income Taxes	829,987		752,785		711,035
Impairment of Northern Pass Transmission	—		—		239,644
Total Operating Expenses	7,869,764		6,915,696		6,935,979
Operating Income	1,993,321		1,988,734		1,590,491
Interest Expense	582,334		538,452		533,197
Other Income, Net	161,282		108,590		132,777
Income Before Income Tax Expense	1,572,269		1,558,872		1,190,071
Income Tax Expense	344,223		346,186		273,499
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 Common Shareholders	$	1,220,527	$	1,205,167	$	909,053

Basic Earnings Per Common Share	$	3.55	$	3.56	$	2.83

Diluted Earnings Per Common Share	$	3.54	$	3.55	$	2.81

Weighted Average Common Shares Outstanding:
Basic	343,972,926		338,836,147		321,416,086
Diluted	344,631,056		339,847,062		322,941,636

For the Years Ended December 31,
(Thousands of Dollars, Except Share Information) 2018 2017 2016

Net Income $ 1,040,519
$ 995,515
$ 949,821
Other Comprehensive Income/(Loss), Net of Tax:
Qualified Cash Flow Hedging Instruments 1,756
1,974
2,137
Changes in Unrealized (Losses)/Gains on Marketable Securities (547 ) (350 ) 2,294
Changes in Funded Status of Pension, SERP and PBOP Benefit Plans 5,194
(2,745 ) (2,869 )
Other Comprehensive Income/(Loss), Net of Tax 6,403
(1,121 ) 1,562
Comprehensive Income Attributable to Noncontrolling Interests (7,519 ) (7,519 ) (7,519 )
Comprehensive Income Attributable to Common Shareholders $ 1,039,403
$ 986,875
$ 943,864

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

~~EVERSOURCE ENERGY AND SUBSIDIARIES~~

CONSOLIDATED STATEMENTS OF ~~COMMON SHAREHOLDERS' EQUITY~~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

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, 2016 317,191,249
$ 1,669,313
$ 6,262,368
$ 2,797,355
$ (66,844 ) $ (309,977 ) $ 10,352,215
Net Income

949,821
949,821
Dividends on Common Shares - $1.78 Per Share

(564,486 ) (564,486 )
Dividends on Preferred Stock

(7,519 ) (7,519 )
Issuance of Common Shares, $5 Par Value 15,787
79
(5,639 ) (5,560 )
Long-Term Incentive Plan Activity

(6,056 ) (6,056 )
Increase in Treasury Shares (321,228 )

(7,794 ) (7,794 )
Other Changes in Shareholders' Equity

(449 )

(449 )
Other Comprehensive Income

1,562
1,562
Balance as of December 31, 2016 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

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

EVERSOURCE ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~

COMMON SHAREHOLDERS' EQUITY

For the Years Ended December 31,
(Thousands of Dollars) 2018 2017 2016

Operating Activities:
Net Income $ 1,040,519
$ 995,515
$ 949,821
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation 819,930
773,802
715,466
Deferred Income Taxes 174,812
491,630
466,463
Bad Debt Expense 61,337
44,453
69,466
Pension, SERP and PBOP Expense, Net 5,498
22,454
39,912
Pension and PBOP Contributions (194,947 ) (242,800 ) (158,741 )
Regulatory Over/(Under) Recoveries, Net 34,920
(47,935 ) 13,340
Amortization 252,026
89,986
71,696
(Payments)/Refunds Related to Spent Nuclear Fuel, Net (145,000 ) —
59,804
Other (111,225 ) (204,421 ) (118,195 )
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net (141,433 ) (117,155 ) (142,699 )
Fuel, Materials, Supplies and Inventory (831 ) (9,223 ) 7,755
Taxes Receivable/Accrued, Net (67,770 ) 52,284
234,543
Accounts Payable (22,084 ) 56,067
(14,126 )
Other Current Assets and Liabilities, Net 78,226
91,545
13,737
Net Cash Flows Provided by Operating Activities 1,783,978
1,996,202
2,208,242

Investing Activities:
Investments in Property, Plant and Equipment (2,523,371 ) (2,348,105 ) (1,976,867 )
Proceeds from Sales of Marketable Securities 900,749
832,903
659,338
Proceeds from Sales of Marketable Securities Used to Pay Spent Nuclear Fuel Obligation 145,000
—
—
Purchases of Marketable Securities (908,387 ) (810,507 ) (681,272 )
Acquisition of Aquarion —
(877,652 ) —
Payments to Acquire Investments (205,150 ) (32,634 ) (188,958 )
Proceeds from the Sale of PSNH Generation Assets 193,924
—
—
Other Investing Activities 6,754
5,479
36,211
Net Cash Flows Used in Investing Activities (2,390,481 ) (3,230,516 ) (2,151,548 )

Financing Activities:
Cash Dividends on Common Shares (640,110 ) (602,083 ) (564,486 )
Cash Dividends on Preferred Stock (7,519 ) (7,519 ) (7,519 )
(Decrease)/Increase in Notes Payable (379,310 ) 72,810
(12,453 )
Issuance of Rate Reduction Bonds 635,663
—
—
Issuance of Long-Term Debt 2,200,000
2,500,000
800,000
Retirements of Long-Term Debt (1,050,330 ) (745,000 ) (200,000 )
Other Financing Activities (28,457 ) (4,754 ) (33,482 )
Net Cash Flows Provided by/(Used in) Financing Activities 729,937
1,213,454
(17,940 )
Net Increase/(Decrease) in Cash, Cash Equivalents and Restricted Cash 123,434
(20,860 ) 38,754
Cash, Cash Equivalents and Restricted Cash - Beginning of Year 85,890
106,750
67,996
Cash, Cash Equivalents and Restricted Cash - End of Year $ 209,324
$ 85,890
$ 106,750


	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

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

EVERSOURCE ENERGY AND SUBSIDIARIES

~~Company~~CONSOLIDATED STATEMENTS OF CASH FLOWS


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

Operating Activities:
Net Income	$	1,228,046	$	1,212,686	$	916,572
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation	1,103,008		981,380		885,278
Deferred Income Taxes	347,056		257,154		209,812
Uncollectible Expense	60,886		53,461		63,446
Pension, SERP and PBOP (Income)/Expense, Net	(14,693)		12,888		22,000
Pension and PBOP Contributions	(182,344)		(111,524)		(121,782)
Regulatory Underrecoveries, Net	(314,211)		(516,411)		(124,870)
Reserve at CL&P related to PURA Settlement Agreement and Storm Performance Penalty	81,274		—		—
Amortization	231,965		177,679		195,380
Payments Related to CYAPC's DOE Pre-1983 Spent Nuclear Fuel Obligation	—		—		(29,000)
Proceeds from DOE Spent Nuclear Fuel Litigation	—		—		68,840
Impairment of Northern Pass Transmission	—		—		239,644
Cost of Removal Expenditures	(242,130)		(148,332)		(153,477)
Other	(64,640)		(25,957)		(42,610)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(135,505)		(351,843)		(98,716)
Fuel, Materials, Supplies and REC Inventory	(1,859)		(15,404)		(8,074)
Taxes Receivable/Accrued, Net	(110,621)		43,819		(16,129)
Accounts Payable	(29,201)		122,567		14,866
Other Current Assets and Liabilities, Net	5,569		(9,591)		(11,603)
Net Cash Flows Provided by Operating Activities	1,962,600		1,682,572		2,009,577

Investing Activities:
Investments in Property, Plant and Equipment	(3,175,080)		(2,942,996)		(2,911,489)
Proceeds from Sales of Marketable Securities	447,893		434,124		566,592

Purchases of Marketable Securities	(414,980)		(401,823)		(537,258)
Acquisition of Assets of Columbia Gas of Massachusetts, Net of Restricted Cash	—		(1,113,252)		—
Investments in Unconsolidated Affiliates, Net	(327,385)		(239,673)		(416,337)
Proceeds from the Sale of Hingham Water System	—		110,536		—

Other Investing Activities	22,178		23,809		24,204
Net Cash Flows Used in Investing Activities	(3,447,374)		(4,129,275)		(3,274,288)

Financing Activities:
Issuance of Common Shares, Net of Issuance Costs	—		928,992		852,254
Cash Dividends on Common Shares	(805,439)		(744,665)		(663,239)
Cash Dividends on Preferred Stock	(7,519)		(7,519)		(7,519)
Increase in Notes Payable	256,125		13,955		325,370
Repayment of Rate Reduction Bonds	(43,210)		(43,210)		(52,332)
Issuance of Long-Term Debt	3,230,000		2,760,000		1,520,000
Retirement of Long-Term Debt	(1,142,500)		(327,236)		(801,078)
Other Financing Activities	(46,625)		14,273		(1,006)
Net Cash Flows Provided by Financing Activities	1,440,832		2,594,590		1,172,450
Net (Decrease)/Increase in Cash and Restricted Cash	(43,942)		147,887		(92,261)
Cash and Restricted Cash - Beginning of Year	264,950		117,063		209,324
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.

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, ~~2018.~~2021.

February ~~26, 2019~~16, 2022

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, ~~2018~~2021 and ~~2017,~~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, ~~2018,~~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, ~~2018~~2021 and ~~2017,~~2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2018,~~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, 2019~~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)	2018		2017		(Thousands of Dollars)	2021		2020

ASSETS					ASSETS
Current Assets:					Current Assets:
Cash	$	87,721	$	6,028	Cash	$	55,804	$	90,801
Receivables, Net	397,026		370,676
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	23,082		28,181		Accounts Receivable from Affiliated Companies	43,944		17,486
Unbilled Revenues	56,971		54,154		Unbilled Revenues	56,787		57,407
Materials, Supplies and Inventory	44,529		48,438
Materials and Supplies					Materials and Supplies	60,264		57,924
Regulatory Assets	125,155		200,281		Regulatory Assets	371,609		345,622
Prepayments and Other Current Assets	60,279		46,926		Prepayments and Other Current Assets	120,257		83,950
Total Current Assets	794,763		754,684		Total Current Assets	1,156,439		1,112,404

Property, Plant and Equipment, Net	8,909,701		8,271,030		Property, Plant and Equipment, Net	10,803,543		10,234,556

Deferred Debits and Other Assets:					Deferred Debits and Other Assets:
Regulatory Assets	1,505,488		1,444,935		Regulatory Assets	1,713,161		1,866,152
Other Long-Term Assets	199,767		159,597		Other Long-Term Assets	276,513		242,862
Total Deferred Debits and Other Assets	1,705,255		1,604,532		Total Deferred Debits and Other Assets	1,989,674		2,109,014

Total Assets	$	11,409,719	$	10,630,246	Total Assets	$	13,949,656	$	13,455,974

LIABILITIES AND CAPITALIZATION					LIABILITIES AND CAPITALIZATION
Current Liabilities:					Current Liabilities:
Notes Payable to Eversource Parent	$	—	$	69,500
Long-Term Debt – Current Portion	250,000		300,000

Accounts Payable	324,983		367,605		Accounts Payable	$	533,454	$	451,240
Accounts Payable to Affiliated Companies	26,452		82,201		Accounts Payable to Affiliated Companies	132,578		51,118
Obligations to Third Party Suppliers	56,248		52,860		Obligations to Third Party Suppliers	43,183		49,967
Regulatory Liabilities	109,614		38,967		Regulatory Liabilities	266,489		137,166
Derivative Liabilities	55,058		54,392		Derivative Liabilities	73,528		68,767
Other Current Liabilities	161,088		127,234		Other Current Liabilities	98,772		102,060
Total Current Liabilities	983,443		1,092,759		Total Current Liabilities	1,148,004		860,318

Deferred Credits and Other Liabilities:					Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	1,166,784		1,103,367		Accumulated Deferred Income Taxes	1,562,102		1,408,343
Regulatory Liabilities	1,122,157		1,112,136		Regulatory Liabilities	1,193,259		1,204,942
Derivative Liabilities	379,536		376,918		Derivative Liabilities	235,387		294,535
Accrued Pension, SERP and PBOP	282,771		354,469		Accrued Pension, SERP and PBOP	26,820		478,325
Other Long-Term Liabilities	155,495		128,135		Other Long-Term Liabilities	153,004		133,690
Total Deferred Credits and Other Liabilities	3,106,743		3,075,025		Total Deferred Credits and Other Liabilities	3,170,572		3,519,835

Long-Term Debt	3,004,016		2,759,135		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	2,410,765		2,110,765		Capital Surplus, Paid In	3,010,765		2,810,765
Retained Earnings	1,727,899		1,415,741		Retained Earnings	2,228,133		2,173,367
Accumulated Other Comprehensive Income	301		269		Accumulated Other Comprehensive Income	251		302
Common Stockholder's Equity	4,199,317		3,587,127		Common Stockholder's Equity	5,299,501		5,044,786

Commitments and Contingencies (Note 12)

Commitments and Contingencies (Note 13)					Commitments and Contingencies (Note 13)	0		0
Total Liabilities and Capitalization	$	11,409,719	$	10,630,246	Total Liabilities and Capitalization	$	13,949,656	$	13,455,974

•Peer ~~group data.~~ Group Data.In support of executive pay decisions, ~~during 2018 and early 2019,~~ the Committee consulted with Pay Governance, which provided the Committee with a competitive assessment analysis of ~~Eversource's~~Eversource’s executive compensation levels as compared to the 2018 peer group companies listed in the table below. This peer group, which the Committee reviews annually, was chosen because these companies are ~~and continue to be~~ similar to Eversource Energy in terms of size, business model and long-term strategies. ~~The group was reduced in January 2019 upon the merger of SCANA and Dominion Energy, and it will be reviewed by the Committee again in 2019.~~

150



Alliant Energy Corporation		Dominion Energy, Inc.		Pinnacle West Capital Corporation
Ameren Corporation		DTE Energy Company		PPL Corporation
~~Ameren Corporation~~		~~Edison International~~	~~Public Service Enterprise Group, Inc.~~
American Electric Power Co., Inc.	~~Entergy Corporation~~Edison International		~~SCANA Corp. (2018)~~Public Service Enterprise Group, Inc.
CenterPoint Energy, Inc.		~~FirstEnergy Corp.~~Entergy Corporation		Sempra Energy
CMS Energy Corp.		~~NiSource Inc.~~FirstEnergy Corp.		WEC Energy Group, Inc.
Consolidated Edison, Inc.		~~PG&E Corporation~~NiSource Inc.		Xcel Energy Inc.
~~Dominion Energy, Inc.~~	~~Pinnacle West Capital Corporation~~

The Committee ~~reviews the appropriateness of the peer group periodically and~~ adjusts the target percentages of annual and long-term incentives based on the survey data and recommendations from ~~Eversource's CEO,~~the Chief Executive Officer, after discussion with the compensation consultant, to ensure that they are approximately equal to competitive median levels.

~~The Committee also determines perquisites to the extent they serve business purposes and sets supplemental benefits at levels that provide appropriate compensation opportunities to the executives.~~ The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, including data obtained from companies in the peer group.

MIX OF COMPENSATION ELEMENTS

Eversource targetsthe mix of compensation for its Chief Executive Officer and its other Named Executive Officers so that the percentages of each compensation element are approximately equal to the competitive median market mix. The mix is heavily weighted toward incentive compensation, and incentive compensation is heavily weighted toward performance-based long-term compensation. Since the most senior positions have the greatest responsibility for implementing ~~the~~Eversource’s long-term business plans and strategies, a greater proportion of total compensation is based on performance with a long-term focus.

The Committee determines the compensation for each executive based on the relative authority, duties and responsibilities of the executive. ~~Eversource's~~Eversource’s Chief Executive ~~Officer's~~Officer’s responsibilities for the strategic direction and daily operations and management of Eversource are greater than the duties and responsibilities of the other executives. As a result, ~~Eversource's~~Eversource’s Chief Executive ~~Officer's~~Officer’s compensation is higher than the

compensation of those other executives. Assisted by the compensation consultant, the Committee regularly reviews market compensation data for executive officer positions similar to those held by ~~Eversource's~~Eversource’s executives, including its Chief Executive Officer.

The following table sets forth the contribution to ~~2018~~2021 Total Direct Compensation ~~("TDC")~~(TDC) of each element of compensation at target, reflected as a percentage of TDC, for the Named Executive Officers. The percentages shown in this table are at target and therefore do not correspond to the amounts appearing in the Summary Compensation Table.


	Percentage of TDC at Target
			Long-Term Incentives
	Base Salary	Annual Incentive (1)	Performance Shares (1)
Named Executive Officer				RSUs (2)	TDC
Joseph R. Nolan, Jr.	15%	17%	51%	17%	100%
Philip J. Lembo	25%	20%	41%	14%	100%
Werner J. Schweiger	25%	20%	41%	14%	100%
Gregory B. Butler	28%	20%	39%	13%	100%
Christine M. Carmody	28%	20%	39%	13%	100%
James J. Judge	14%	18%	51%	17%	100%
NEO average, excluding CEO and Executive Chairman	26.5%	20%	40%	13.5%	100%

Percentage of TDC at Target
Long-Term Incentives
Base Salary
Annual Incentive ⁽¹⁾

Performance Shares ⁽¹⁾

Named Executive Officer
RSUs ⁽²⁾
TDC
James J. Judge 15 17 34 34 100
Philip J. Lembo 26 20 27 27 100
Werner J. Schweiger 26 20 27 27 100
Gregory B. Butler 30 20 25 25 100
Joseph R. Nolan, Jr. 30 20 25 25 100
NEO average, excluding CEO 28 20 26 26 100


~~(1)~~	(1) The annual incentive compensation element and performance shares under the ~~long-term incentive compensation element are performance-based.~~


~~(2)~~	~~Restricted Share Units (RSUs) vest over three years contingent upon continued employment.~~

~~RISK ANALYSIS OF EXECUTIVE COMPENSATION PROGRAM~~

~~The overall compensation program includes a mix of compensation elements ranging from a fixed base salary that is not at risk to annual and~~ long-term incentive compensation ~~programs intended~~element are performance-based.

(2) Restricted Share Units (RSUs) vest over three years contingent upon continued employment.

151

Changes to ~~motivate executives~~2021 Long-Term Incentive Program

In engagement sessions with Eversource shareholders, Eversource received comments relative to the 50/50 mix of RSUs and eligible employees to achieve individual and corporate performance goals that reflect an appropriate level of risk. The fundamental objective of the compensation program is to foster the continued growth and success of Eversource's business. The design and implementation of the overall compensation program provides the Committee with opportunities throughout the year to assess risks within the compensation program that may have a material effect on Eversource and its shareholders.

The Compensation Committee assesses the risks associated with the executive compensation program on an on-going basis by reviewing the various elements of incentive compensation. The annual incentive program was designed to ensure an appropriate balance between individual and corporate goals, which were deemed appropriate and supportive of Eversource's annual business plan. Similarly, thePerformance Shares in Eversource’s long-term incentive program was designed to ensure that the performance metrics were properly weighted and supportive of Eversource's strategy. The Committee reviewed the overall compensation program in the context of risks identified in the annual operating plan. The annual and long-term incentive programs were designed to include mechanisms to mitigate risk. These mechanisms include realistic goal setting and discretion with respect to actual payments, in addition to:

~~A mix of annual and long-term performance awards to provide an appropriate balance of short- and long-term risk and reward horizon;~~

A variety of performance metrics, including financial, operational, customer service, diversity and safety goals and other strategic initiatives for annual performance awards to avoid excessive focus onprogram. As a ~~single measure of performance;~~

Metrics in Eversource's long-term incentive compensation program that use earnings per share growth and relative total shareholder return, which are both robust measures of shareholder value and which reduce the risk that employees might be encouraged to pursue other objectives that increase risk or reduce financial performance;

~~The provisions of Eversource's annual and long-term incentive programs, which cap awards at 200 percent of target;~~

~~Expansive clawback provisions on incentive compensation, including clawback for material violations of the Eversource Code of Conduct; and~~

~~Stock ownership requirements for all executives, including the Named Executive Officers, and prohibitions on hedging, pledging and other derivative transactions related to Eversource common shares.~~

~~Based on these factors,~~result, the Compensation Committee revised the Performance Share Program in response to these shareholder comments to further align our compensation programs with the Committee’s pay for performance philosophy, such that 75 percent of the 2021 – 2023 Program’s long-term incentive opportunity consists of Performance Shares and ~~Eversource's Board~~25 percent consists of ~~Trustees believe the overall compensation program risks are mitigated to reduce overall compensation risk.~~RSUs.

Results of Eversource's ~~2018~~2021 Say-on-Pay ~~Vote~~. Vote. Eversource provides its shareholders with the required opportunity to cast the annual advisory vote on executive compensation (a ~~"Say-on-Pay"~~Say-on-Pay proposal).

At ~~Eversource's~~Eversource’s Annual Meeting of Shareholders held on May ~~2, 2018, 90~~5, 2021, 88.3 percent of the votes cast on the Say-on-Pay proposal were voted to approve the ~~2017~~2020 compensation of the Named Executive Officers, as described in ~~Eversource's 2018~~Eversource’s 2021 proxy statement. ~~Eversource's~~Eversource’s Say-on-Pay results, along with those of utility and general industry peers, are reviewed by the Committee annually to help assess whether Eversource shareholders continue to deem ~~the executives'~~its executives’ compensation to be appropriate. The Committee has and will continue to consider the outcome of ~~Eversource's~~Eversource’s Say-on-Pay votes when making future compensation decisions for the Named Executive Officers.

ELEMENTS OF ~~2018~~2021 COMPENSATION

Base Salary

Base salary is designed to attract and retain key executives by providing an element of total compensation at levels competitive with those of other executives employed by companies of similar size and complexity in the utility and general industries. In establishing base salary, the Compensation Committee relies on compensation data obtained from independent third-party surveys of companies and from an industry peer group to ensure that the compensation opportunities Eversource offers are capable of attracting and retaining executives with the experience and talent required to achieve its strategic objectives. Adjustments to base salaries are generally made on an annual basis except in instances of promotions.

When setting or adjusting base salaries, the Committee considers annual executive performance appraisals; market pay movement across industries (determined through market analysis); targeted market pay positioning for each executive; individual experience; strategic importance of a position; recommendations of ~~Eversource's~~the Chief Executive Officer; and internal pay equity.

Incentive Compensation

Annual incentive and long-term incentive compensation are provided under ~~Eversource's 2018~~Eversource’s Incentive ~~Plan.~~Plan, which was approved by its shareholders in 2018. The annual incentive program provides cash compensation intended to reward performance under ~~Eversource's~~Eversource’s annual operating plan. The long-term stock-based incentive program is designed to reward demonstrated performance and leadership, motivate future performance, align the interests of the executives with those of shareholders, and retain executives during the term of grants. The annual and long-term programs are designed to strike a balance between ~~Eversource's~~Eversource’s short- and long-term objectives so that the programs work in tandem.

In addition to the specific performance goals, the Committee assesses other factors, as well as the ~~executives'~~executives’ roles and individual performance and then makes annual incentive program awards at the levels and amounts disclosed in this ~~Item 11.~~CD&A.

~~2018~~

152

RISK ANALYSIS OF EXECUTIVE COMPENSATION PROGRAM

The overall compensation program includes a mix of compensation elements ranging from a fixed base salary that is not at risk to annual and long-term incentive compensation programs intended to motivate executives and other eligible employees to achieve individual and corporate performance goals that reflect an appropriate level of risk. The fundamental objective of the compensation program is to foster the continued growth and success of Eversource’s business. The design and implementation of the overall compensation program provide the Committee with opportunities throughout the year to assess risks within the compensation program that may have a material effect on Eversource and its shareholders.

The Compensation Committee assesses the risks associated with the executive compensation program on an ongoing basis by reviewing the various elements of incentive compensation. The annual incentive program is designed to ensure an appropriate balance between individual and corporate goals, which were deemed appropriate and supportive of Eversource’s annual business plan. Similarly, the long-term incentive program is designed to ensure that the performance metrics are properly weighted and supportive of Eversource’s strategy. The Committee reviewed the overall compensation program in the context of risks identified in the annual operating plan. The annual and long-term incentive programs were designed to include mechanisms to mitigate risk. These mechanisms include realistic goal setting and discretion with respect to actual payments, in addition to:

•A mix of annual and long-term performance awards to provide an appropriate balance of short- and long-term risk and reward horizon;

•A variety of performance metrics, including financial, operational, customer service, ESG, diversity, safety and strategic goals and initiatives for annual performance awards to avoid excessive focus on a single measure of performance;

•Metrics in Eversource’s long-term incentive compensation program that use earnings per share growth and relative total shareholder return, which are both robust measures of shareholder value and which reduce the risk that employees might be encouraged to pursue other objectives that increase risk or reduce financial performance;

•The provisions of Eversource’s annual and long-term incentive programs, which cap awards at 200 percent of target;

•Eversource’s expansive clawback provisions on incentive compensation, including clawback for material violations of the Eversource Code of Business Conduct; and

•Stock ownership requirements for all executives, including Eversource’s NEOs, and prohibitions on hedging, pledging and other derivative transactions related to Eversource common shares.

Based on these factors, the Compensation Committee and the Board of Trustees believe the overall compensation program risks are mitigated to reduce overall compensation risk.

2021 ANNUAL INCENTIVE PROGRAM ASSESSMENT

In early February ~~2018,~~of 2021, the Committee established the terms of the ~~2018~~2021 Annual Incentive Program. As part of the overall program, and after consulting with Pay Governance, the Committee set target award levels for each of ~~the~~Eversource’s Named Executive Officers that ranged from 6570 percent to ~~120~~125 percent of base salary.

At the February ~~2018~~2021 meeting, the Committee determined that for ~~2018~~2021 it would continue to base 70 percent of the annual incentive performance goals on ~~Eversource's~~Eversource’s overall financial performance and 30 percent of the annual performance goals on ~~Eversource's~~Eversource’s overall operational performance. The Committee also determined the specific goals that would be used to assess performance, with potential ratings on each goal ranging from 0zero percent to 200 percent of target. The Committee assigned weightings to each of ~~these specific~~the goals. For the financial component, the following goals were used: earnings per share, weighted at 60 percent, ~~dividend growth, weighted at 10 percent, and~~

advancement of strategic growth initiatives and regulatory outcomes, weighted at 30 percent, and dividend growth, weighted at 10 percent. For the operational component, the Committee used the following goals: ~~combined service reliability and restoration goals, weighted at 60 percent, and~~ combined safety ratings, gas service response, diversity promotions and hires of leadership employee positions, ~~goals~~ and ~~key~~sustainability, customer and clean energy initiatives, weighted at 4050 percent, service reliability weighted at 25 percent, and restoration of outages duration, weighted at 25 percent.

~~2018~~In establishing the individual annual performance goals, the Committee sets stretch goals for both the Financial and Operational components. Many of the goals use performance ranges, as opposed to threshold or target ranges, whereby the lower end of the performance range does not represent average or less compared to industry peers, or other similar performance benchmarks, but requires performance that exceeds industry standards, peer performance and other benchmarks in order to be met, while achievement at the higher end of the range represents superior performance. Achieving performance of these stretch goals within the particular range will therefore justify an assessment beyond target.

153

2021 Performance Goals

At the December ~~2018~~2021 meeting of the Committee, Eversource’s management provided an initial review of ~~Eversource's 2018~~its 2021 performance, followed in February ~~2019~~2022 by a full assessment of the performance goals, the additional accomplishments noted below under the caption ~~"Additional Factors"~~“Additional Factors” and the overall performance of Eversource and ~~the~~its executives. In addition to these meetings, the Committee and the Eversource Board were ~~continuously~~ provided updates during ~~2018~~2021 on corporate performance. At the February ~~6, 2019~~2, 2022 meeting, the Committee determined, based on its assessment of the financial and operational performance goals and the other factors noted above, to set the level of achievement of combined financial and operational performance goals results at ~~157~~160 percent, ~~of target,~~ reflecting the ~~overall~~ strong performance of Eversource and its executive team in executing Eversource’s Operating Plan and adapting quickly to the ~~executive team.~~constantly changing COVID-19 pandemic to keep its customers and employees safe and to maintain effective operations. In arriving at this determination, the Committee determined that the weighted financial performance goals result was ~~151~~116 percent ~~of target~~ and the weighted operational performance goals result was 171 percent of target. In particular, the Committee discussed its assessment of the Strategic Growth Initiative goal, and in determining the assessment of 150 percent of a possible 200 percent, it considered the success of Eversource in establishing itself as a leader in clean energy through the greatly expanded Ørsted offshore wind partnership; Eversource's best in industry ranking in energy efficiency; the completed construction of 62 MW in utility scale solar; and the advancement of Eversource's battery storage and electric vehicle infrastructure initiatives. Eversource's44 percent. Eversource’s Chief Executive Officer recommended to the Committee awards for ~~the~~its executives (other than ~~himself)~~himself and the Executive Chairman) based on his assessment of each ~~executive's~~executive’s individual performance towards achievement of the performance goals and the additional accomplishments of Eversource, together with each ~~executive's~~executive’s contributions to the overall performance of Eversource. The actual awards determined by the Committee were also based on the same criteria.

Financial Performance Goals Assessment

~~Eversource Energy's~~•FINANCIAL PERFORMANCE: Eversource’s non-GAAP earnings per share in ~~2018~~2021 of $3.86, which excludes the two adjustments to earnings as described in Exhibit A to this Item 11, increased by ~~4.5~~6.0 percent ~~over 2017~~when compared to non-GAAP earnings per share in 2020, and exceeded the established goal of ~~a 3.5 percent increase; 2018 earnings equaled $3.25 per share.~~$3.85. Eversource ~~accomplished~~was able to achieve this ~~by effectively managing its~~goal through effective management of the 2021 Operating Plan on a day-by-day basis, including execution of its $3.5 billion utility capital plan, and by overcoming several ~~challenges.~~challenges to plan achievement, including higher than plan O&M expenses caused primarily by the significant number and severity of storm events, higher employee-related costs, and the financial and operational impacts of the COVID-19 pandemic. Please see Exhibit A to this Item 11, which provides detailed information of GAAP and non-GAAP financial information and the Committee's determination with respect to the earnings per share goal. The Committee determined the earnings per share goal to have attained a ~~150~~160 percent performance result.

154

•DIVIDEND GROWTH: Eversource ~~Energy~~ increased its dividend to ~~$2.02~~$2.41 per share, a ~~6.3~~6.2 percent increase from the prior year, significantly above the utility industry's median dividend growth of ~~5.1~~4.7 percent for the EEI Utility Index.The Committee determined this goal to have attained a 160 percent performance result.

•STRATEGIC INITIATIVES AND REGULATORY OUTCOMES: Eversource received the approval of a comprehensive storm settlement agreement with PURA that provided for the resolution of several pending regulatory and legal proceedings and are ahead of plan on the integration of the assets acquired from Columbia Gas Company of Massachusetts. Eversource advanced the progress of Massachusetts Grid Modernization and accelerated the recovery of 2020 investments for NSTAR Gas Company. In addition, Eversource received approval to defer $15.6 million of additional storm related costs and successfully negotiated and completed the acquisition of NESC, a New England water delivery company. The Committee determined this goal to have attained a 180 percent performance result.

Operational Performance Goals Assessment

•RELIABILITY PERFORMANCE: Electric System Reliability, measured by months between interruptions, was top decile in the industry in 2021; customer power interruptions were on average 19.2 months apart. The Committee determined this goal to have attained a 165 percent performance result.

155

•RESTORATION PERFORMANCE: The average system outage duration was 69.8 minutes, which was in the top quartile of the utility industry for the fastest restoration time. The Committee determined this goal to have attained a 160 percent performance result.

•SAFETY: Eversource’s safety performance was 0.9, measured by days away, restricted or transferred (DART) per 100 workers, which continued to outperform the industry in 2021. In addition to our safety performance as measured by DART, the policies and procedures Eversource established at the onset of the pandemic were and continue to be a significant and successful part of our overall safety performance. The strong partnerships that have been developed between management and union leadership have been of great assistance in both helping Eversource’s employees stay safe throughout the pandemic and in advancing Eversource’s business initiatives, allowing for continuing overall strong company performance. Eversource employees had less than one percent of COVID occupational contact cases in 2021. The Committee determined this goal to have attained a 90 percent performance result.

156

•GAS EMERGENCY RESPONSE: On-time response to gas customer emergency calls was 98.0 percent, which continued to outperform the industry. The Committee determined this goal to have attained a 175 percent performance result.

•DIVERSITY: Eversource continued to support many programs and agencies that address racial and ethnic disparities in our customers' communities and beyond. Eversource also remains committed to developing a workforce that fully reflects the diversity of the people and communities Eversource serves. Eversource’s hiring and talent practices emphasize diversity, equity, and inclusion and encourage employees to embrace different people, perspectives, and experiences in the workplace and within its communities – regardless of their race, color, religion, national origin, ancestry, sex, gender identity, age, disability, marital status, sexual orientation, active military or veteran status. Eversource sustained its successful drive to increase workforce diversity and build a diverse talent pipeline; in 2021, 57 percent of external hires were women or people of color and 41.2 percent of external hires and internal promotions into leadership roles were women or people of color, slightly below the stretch goal of 45 percent. The Committee determined this goal to have attained a ~~155~~90 percent ~~performance.~~performance result.

•SUSTAINABILITY: Eversource’s strong environmental, social and governance performance once again received widespread recognition in 2021, which demonstrates its deep commitment to corporate social responsibility, as evidenced by the high ratings it receives from leading sustainability rating firms. In 2021, Eversource was ranked at the top of a peer group of comparably sized U.S. utilities whose ESG performance is assessed by two leading sustainability rating firms. Eversource outperformed its goal to be in the 85th percentile compared to peers with a combined end-of-year ranking of 97 percent. Eversource continues to engage with operational and business partners to advance its sustainability strategy and drive performance that addresses the evolving expectations of shareholders, customers, employees, regulators and the communities Eversource serves.

Eversource ~~Energy significantly advanced its~~took steps to mitigate climate change impacts through leading clean energy ~~leadership~~initiatives and an industry leading emissions target to achieve carbon neutrality in its operations by 2030. In 2021, Eversource made progress toward this goal by engaging employees cross-functionally through dedicated committees focused on addressing emission reduction plans across all key emission sources, engaging internal and external stakeholders and making preparations to offset the ~~expansion of~~emissions that cannot be avoided. Eversource has reduced its ~~offshore wind~~carbon footprint by 17 percent since 2018 by executing its carbon reduction initiatives associated with fleet, electric line losses, SF6 gas used in electric switchgears, energy partnership with Ørsted. Completing a project in February 2019 that commenced in 2018, the partnership purchased two projects that have contract commitments of 830 MW, along with a 257 square mile lease tract off the New England coast.efficiency and leak prone gas pipe replacements. Looking beyond its operational GHG emissions, Eversource also ~~completed construction of 62 MW of large scale solar in Massachusetts,~~worked with customers to reduce their impacts on the climate through solutions such as energy efficiency programs, enabling renewable energy interconnection, and achieved solid progress on existing grid modernization projects, including battery storage and electric vehicle infrastructure. In addition, the Committee also recognized advancements made to continue to expand solar andadvancing electric vehicle infrastructure in other jurisdictions. Eversource's appeal of the denial of the single final permit for the Northern Pass hydro power transmission project was accepted by the New Hampshire Supreme Court. The totality of these strategic accomplishments was considered by the Committee to have significantly advanced Eversource Energy's long-term strategy of being a cleanand energy ~~leader. The Committee determined this goal to have attained a 150 percent performance.~~

~~Operational Performance Goals Assessment~~

Eversource Energy's total electric system reliability performance exceeded that of its peers significantly. Average months between interruptions equaled 17.2 months, near the highest end of the performance zone established by the Committee of 15.5 to 18.5 months and in the first quartile of industry peers. System average restoration duration time equaled 77.5 minutes, within the performance zone

~~established by the Committee of 80 to 67 minutes and also exceeding peers. The Committee determined these goals to have each attained a 175 percent performance result.~~

Eversource Energy achieved the safety performance goal of between 0.5 - 0.9 DART per 1,000 employees; DART equaled 0.7 in 2018, within the established performance zone and better than peers. The Committee determined this goal to have attained a 130 percent performance result.

On-time response to gas customer emergency calls was 99.5 percent, which was at the high end of the performance zone of 99.2 percent to 99.6 percent. The Committee determined this goal to have attained a 150 percent performance result.

~~In 2018, 42 percent of new hires and promotions into leadership roles were women or people of color, substantially exceeding the goal of 37 percent.~~storage capabilities. The Committee determined this goal to have attained a 200 percent performance result.

•ELECTRIC STORM RESTORATION:Eversource ~~Energy successfully completed important efforts~~implemented a municipal information portal and storm restoration dashboards, developed an internal information desk to ~~improve~~provide real time, accurate and consistent information to municipal leaders and customers, enhanced the ~~customer experience,~~staffing plan for all emergency response plan (ERP) levels, including ~~enhanced web/digital capabilities with~~ a new ~~web-based outage map~~public safety process and ~~improved outage communications. Key customer metrics finished above target. Estimated Time to Restoration calls were well-managed 89 percent of the time, exceeding the goal of 85 percent,~~organization, and ~~digital customer engagement finished above target at 83.2 percent.~~launched an enhanced crew tracking and oversight process. In addition, Eversource ~~maintained~~stress tested its ~~best~~critical IT systems to ensure reliability during large scale events and developed strategic partnerships with regulators, legislators, first responders, media and meteorologists to better align and help reinforce our storm coordination. Eversource completed updated documentation, filed its enhanced ERP plan with PURA, and completed plan roll out across all three states that Eversource serves. These enhancements were on display during Tropical Storm Elsa and the October 2021 Nor'easter and were well received by customers, communities and other key stakeholders. While the Committee found Eversource to have substantially achieved its storm response goal, it felt that due to the importance of this goal to ensuring outstanding performance for customers, the 2021 target achievement standard for this goal category should be increased. The Committee determined this goal to have attained an 80 percent performance result.

•CLEAN ENERGY EXECUTION: Eversource successfully executed a 10-year agreement with the City of New London, Connecticut and continues to progress the New London State Pier redevelopment project, which provides its partnership access to the leading offshore wind port in ~~industry ranking~~the Northeast, and it made significant progress to advance siting and permitting of all three of its offshore wind projects at the federal and state levels. Eversource advanced the development of its electric vehicle infrastructure in ~~energy efficiency program effectiveness.~~Massachusetts and

157

Connecticut, successfully executed its first Massachusetts Grid Modernization plan, submitted the next round of investments for approval, including Advanced Metering Infrastructure, and successfully executed its $500 million Energy Efficiency (EE) Plan. In addition, Eversource filed and received Massachusetts DPU approval for its new $1 billion Massachusetts three-year EE program. The Committee determined this goal to have attained a ~~150~~125 percent performance result.

Eversource Energy achieved several constructive regulatory outcomes. These included the settlement agreement approved by the PURA for CL&P, a settlement agreement also approved by the PURA on Yankee Gas' rate review, a positive rate outcome for Aquarion Water Company of Massachusetts, and a settlement with FERC in an important docket on transparency, along with progress on the critical docket relating to return on equity for transmission assets. The Committee determined this goal to have attained a 200 percent performance result.

~~Financial~~2021 Annual Incentive Program Performance ~~Goals~~

Assessments

~~Category~~Financial Performance Goals

~~2018 Goal~~

~~Eversource Performance~~

~~Assessment~~




	UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ~~FORM 10-K~~
x	FORM	10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the ~~Fiscal Year Ended~~ fiscal year ended	December 31, ~~2018~~ or 2021
¨	or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________



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

~~1-5324~~	~~EVERSOURCE ENERGY~~ ~~(a Massachusetts voluntary association)~~ ~~300 Cadwell Drive~~ ~~Springfield, Massachusetts 01104~~ ~~Telephone: (800) 286-5000~~	~~04-2147929~~

~~0-00404~~	~~THE CONNECTICUT LIGHT AND POWER COMPANY~~ ~~(a Connecticut corporation)~~ ~~107 Selden Street~~ ~~Berlin, Connecticut 06037-1616~~ ~~Telephone: (800) 286-5000~~	~~06-0303850~~

~~1-02301~~	~~NSTAR ELECTRIC COMPANY~~ ~~(a Massachusetts corporation)~~ ~~800 Boylston Street~~ ~~Boston, Massachusetts 02199~~ ~~Telephone: (800) 286-5000~~	~~04-1278810~~

~~1-6392~~	~~PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE~~ ~~(a New Hampshire corporation)~~ ~~Energy Park~~ ~~780 North Commercial Street~~ ~~Manchester, New Hampshire 03101-1134~~ ~~Telephone: (800) 286-5000~~	~~02-0181050~~



			Yes			No
			x☒			¨☐



			Yes			No
			¨☐			x☒



			Yes			No
			x☒			¨☐



Company - Class of Stock	Outstanding as of January 31, ~~2019~~2022
Eversource Energy Common Shares, $5.00 par value	~~316,981,088~~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 ~~(formerly known as Macquarie Utilities Inc)~~
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		~~A project~~North East Offshore, LLC, an offshore wind business being developed jointly by Eversource and Denmark-based Ørsted ~~(formerly known as DONG Energy) to construct an offshore wind farm off the coast of Massachusetts~~
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:
~~Access Northeast~~ADIT		~~A project jointly owned by Eversource, Enbridge, Inc. ("Enbridge"), and National Grid plc ("National Grid") through Algonquin Gas Transmission, LLC ("AGT")~~
~~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
~~EPS~~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 ~~2017~~2020 Form 10-K	The Eversource Energy and Subsidiaries ~~2017~~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)
~~kWh~~LNG		~~Kilowatt-Hours (the basic unit of electricity energy equal to one kilowatt of power supplied for one hour)~~
~~LBR~~	~~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
~~PCRBs~~		~~Pollution Control Revenue Bonds~~
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PPA		~~Pension Protection Act~~Power purchase agreement
~~RRBs~~RECs		~~Rate Reduction Bonds~~
~~RECs~~	Renewable Energy Certificates
Regulatory ROE		The average cost of capital method for calculating the return on equity related to the distribution ~~and generation~~ business segment excluding the wholesale transmission segment
~~RNS~~ROE		~~Regional Network Service~~
~~ROE~~	Return on Equity
~~RRB~~RRBs		Rate Reduction ~~Bond~~Bonds or Rate Reduction ~~Certificate~~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	2425
Item 6.	~~Selected Consolidated Financial Data~~Removed and Reserved	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	6256
Item 8.	Financial Statements and Supplementary Data	6358
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	~~139~~140
Item 9A.	Controls and Procedures	~~139~~140
Item 9B.	Other Information	~~139~~140

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~140~~141
Item 11.	Executive Compensation	~~143~~142
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~167~~175
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~168~~176
Item 14.	Principal Accountant Fees and Services	~~169~~177

PART IV
Item 15.	Exhibits and Financial Statement Schedules	~~171~~178
Item 16.	Form 10-K Summary	~~171~~178
Signatures		E-~~E-9~~9



December 31,
	2013	2014	2015	2016	2017	2018
Eversource Energy	$100	$130	$129	$144	$170	$180
EEI Index	$100	$129	$124	$145	$163	$169
S&P 500	$100	$114	$115	$129	$157	$150



	For the Years Ended December 31,
	2018				2017 ⁽¹⁾				2016
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Common Shareholders (GAAP)	$	1,033.0	$	3.25	$	988.0	$	3.11	$	942.3	$	2.96
Regulated Companies	$	1,006.7	$	3.17	$	962.7	$	3.03	$	911.3	$	2.86
Eversource Parent and Other Companies	26.3		0.08		25.3		0.08		31.0		0.10
Net Income Attributable to Common Shareholders (GAAP)	$	1,033.0	$	3.25	$	988.0	$	3.11	$	942.3	$	2.96



(Millions of Dollars)	Issue Date	Issuances/(Repayments)			Maturity Date	Use of Proceeds for Issuances/ Repayment Information
CL&P:
4.00% 2018 Series A First Mortgage Bonds	March 2018	$	500.0		April 2048	Repaid long-term debt that matured in 2018 and repaid short-term borrowings
5.65% 2008 Series A First Mortgage Bonds	May 2008	(300.0		)	May 2018	Repaid at maturity on May 1, 2018
PSNH:
6.00% 2008 Series O First Mortgage Bonds	May 2008	(110.0		)	May 2018	Repaid at maturity on May 1, 2018
2001 Series A Pollution Control Revenue Bonds	December 2001	(89.3		)	May 2021	Redeemed on November 28, 2018 at a redemption price of $89.3 million
Other:
Eversource Parent 2.50% Series I Senior Notes ⁽¹⁾	January 2018	200.0			March 2021	Repaid short-term borrowings
Eversource Parent 3.30% Series M Senior Notes	January 2018	450.0			January 2028	Repaid long-term debt that matured in 2018
Eversource Parent 3.80% Series N Senior Notes	December 2018	400.0			December 2023	Repaid short-term borrowings
Eversource Parent 4.25% Series O Senior Notes	December 2018	500.0			April 2029	Repaid short-term borrowings
Eversource Parent 1.60% Series G Senior Notes	January 2015	(150.0		)	January 2018	Repaid at maturity on January 15, 2018
Eversource Parent 1.45% Series E Senior Notes	May 2013	(300.0		)	May 2018	Repaid at maturity on May 1, 2018
Yankee Gas 4.13% Series O First Mortgage Bonds	September 2018	50.0			October 2048	Repaid long-term debt that matured in 2018
Yankee Gas 6.90% Series J First Mortgage Bonds	October 2008	(100.0		)	October 2018	Repaid at maturity on October 1, 2018
NSTAR Gas 4.09% Series P First Mortgage Bonds	September 2018	100.0			October 2048	Repaid short-term borrowings



(Millions of Dollars)	(Decrease)/Increase
Electric Distribution	$	(68.9	)
Natural Gas Distribution	59.5
Transmission	43.9
Total Purchased Power, Fuel and Transmission	$	34.5



(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution:
Employee-related expenses, including labor and benefits	$	(46.8	)
Bad debt expense	(14.5		)
Shared corporate costs (including computer software depreciation at Eversource Service)	24.2
HEEC Boston Harbor distribution cable costs	16.0
Other non-tracked operations and maintenance	7.4
Total Base Electric Distribution	(13.7		)
Base Natural Gas Distribution	4.3
Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution):
Absence in 2017 of earnings benefit related to merger-related costs allowed for recovery through transmission rates	27.5
Other tracked operations and maintenance	(4.4		)
Total Tracked costs (Electric Distribution, Electric Transmission and Natural Gas Distribution)	23.1
Other and eliminations:
Merger-related costs allowed for recovery through NSTAR Electric distribution rates as a result of the November 30, 2017 DPU distribution rate case decision (earnings benefit)	(30.5		)
Addition of Aquarion operations and maintenance expenses due to acquisition on December 4, 2017	6.9
Eversource Parent and Other Companies - other operations and maintenance	7.6
Eliminations	(32.8		)
Total Operations and Maintenance	$	(35.1	)



	Rate	For the Years Ended December 31,
	Structure	2017	2016	Decrease		Percent
CL&P	Decoupled	20,950	21,617	(667	)	(3.1	)%
NSTAR Electric (eastern Massachusetts)	Traditional	20,097	20,619	(522	)	(2.5	)%
NSTAR Electric (western Massachusetts)	Decoupled	3,441	3,546	(105	)	(3.0	)%
PSNH	Traditional	7,758	7,860	(102	)	(1.3	)%



	Common Stock			Capital Surplus, Paid In		Retained Earnings			Accumulated Other Comprehensive (Loss)/Income			Total Common Stockholder's Equity
(Thousands of Dollars, Except Stock Information)	Stock	Amount		Capital Surplus, Paid In		Retained Earnings			Accumulated Other Comprehensive (Loss)/Income			Total Common Stockholder's Equity
Balance as of January 1, 2016	6,035,205	$	60,352	$	1,910,663	$	1,170,278		$	(576	)	$	3,140,717
Net Income						334,254						334,254
Dividends on Preferred Stock						(5,559		)				(5,559		)
Dividends on Common Stock						(199,599		)				(199,599		)
Capital Stock Expenses, Net				51								51
Capital Contributions from Eversource Parent				200,000								200,000
Other Comprehensive Income									523			523
Balance as of December 31, 2016	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



	Total Provision for Uncollectible Accounts				Uncollectible Hardship
	As of December 31,				As of December 31,
(Millions of Dollars)	2018		2017		2018		2017
Eversource	$	212.7	$	195.7	$	131.5	$	122.5
CL&P	88.0		78.9		71.9		65.5
NSTAR Electric	74.5		69.7		42.5		40.3
PSNH	11.1		10.5		—		—


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 building improvements, computer software, hardware and equipment at Eversource Service.~~


(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, 2018
(Years)	Eversource	CL&P	NSTAR Electric	PSNH
Distribution - Electric	34.1	35.4	33.7	32.3
Distribution - Natural Gas	43.8	—	—	—
Transmission - Electric	41.3	38.0	45.3	42.9
Distribution - Water	33.3	—	—	—
Solar	24.9	—	24.9	—
Other	12.9	—	—	—


⁽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,
	2021		2020
Derivatives, Net:
Fair Value as of Beginning of Period	$	(293.1)	$	(329.2)
Net Realized/Unrealized Losses Included in Regulatory Assets	(8.5)		(17.9)
Settlements	52.4		54.0
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 the NSTAR long-term debt at fair value on the date of the 2012 merger and to record the Aquarion long-term debt at fair value on the date of the 2017 acquisition.


(Millions of Dollars)	As of December 31,
PSNH Balance Sheets:	2021		2020
Restricted Cash - Current Portion (included in Current Assets)	$	31.1	$	36.8
Restricted Cash - Long-Term Portion (included in Other Long-Term Assets)	3.2		2.1
Securitized Stranded Cost (included in Regulatory Assets)	478.9		522.1
Other Regulatory Liabilities (included in Regulatory Liabilities)	5.4		9.1
Accrued Interest (included in Other Current Liabilities)	7.5		8.0
Rate Reduction Bonds - Current Portion	43.2		43.2
Rate Reduction Bonds - Long-Term Portion	453.7		496.9


(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)
Balance Sheet:	As of December 31, 2018
Restricted Cash - Current Portion (included in Prepayments and Other Current Assets)	$	47.5
Restricted Cash - Long-Term Portion (included in Other Long-Term Assets)	3.2
Securitized Stranded Cost (included in Regulatory Assets)	608.4
Other Regulatory Liabilities (included in Regulatory Liabilities)	5.8
Accrued Interest (included in Other Current Liabilities)	14.4
Rate Reduction Bonds - Current Portion	52.3
Rate Reduction Bonds - Long-Term Portion	583.3