# Nstar Electric Co: Form 10-K for the period ended Dec 31, 2021

- Company: [Nstar Electric Co](/companies/nsaro.md) (CIK 13372)
- Form: 10-K
- Filed: 2022-02-17
- Accepted by EDGAR: Feb 16, 2022, 18:37 ET
- Period: 2021-12-31
- Accession: 0000072741-22-000015
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/13372/000007274122000015/es-20211231.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/13372/000007274122000015/

## Business

As filed, 76,472 characters.

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

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

On October 9, 2020, Eversource acquired certain assets and liabilities that comprised NiSource Inc.’s natural gas distribution business in Massachusetts, which was previously doing business as Columbia Gas of Massachusetts (CMA). The natural gas distribution assets acquired from CMA were assigned to EGMA, an indirect wholly-owned subsidiary of Eversource formed in 2020. The LNG assets acquired from CMA were assigned to Hopkinton LNG Corp, also a subsidiary of Eversource.

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

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

### ELECTRIC DISTRIBUTION SEGMENT

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

### 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, 2021, CL&P furnished retail franchise electric service to approximately 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 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 generation service charge is adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.
- A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver electricity to customers, as well as ongoing operating costs to maintain the infrastructure.
- A revenue decoupling adjustment that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the PURA.
- An Electric System Improvements (ESI) charge, which collects the costs of building and expanding the infrastructure to deliver electricity to customers above the level recovered through the distribution charge. The ESI also recovers costs associated with CL&P’s system resiliency program. The ESI is adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers.
- 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, any costs approved by the PURA to reduce these 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 Competitive Transition Assessment (CTA) charge, assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts. The CTA is reconciled annually to actual costs incurred and reviewed by the PURA, with any difference refunded to, or recovered from, customers.
- A Systems Benefits Charge (SBC), established to fund expenses associated with various hardship and low-income programs. The SBC is reconciled annually to actual costs incurred, and reviewed by the PURA, with any difference refunded to, or recovered from, customers.
- A Renewable Energy Investment Charge, which is used to promote investment in renewable energy sources. Amounts collected by this charge are deposited into the Connecticut Clean Energy Fund and administered by the Connecticut Green Bank.
- A Conservation Adjustment Mechanism (CAM) charge established to implement cost-effective energy conservation programs and market transformation initiatives. The CAM charge is reconciled annually to actual costs incurred, and reviewed by the PURA, with any difference refunded to, or recovered from, customers through an approved adjustment to the following year’s energy conservation spending plan budget.

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

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

CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel (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 accordance with the settlement agreement, CL&P has agreed that its current base distribution rates shall be frozen, subject to certain customer credits, until no earlier than January 1, 2024. The rate freeze applies only to base distribution rates (including storm costs) and not to other rate mechanisms such as the retail rate components, rate reconciling mechanisms, formula rates and any other adjustment mechanisms. The rate freeze also does not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings, either currently pending or that may be initiated during the rate freeze period, that may place additional obligations on CL&P. The approval of the settlement agreement satisfies the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case.

### Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. During 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

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

- A basic service charge that represents the collection of energy costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers, including costs related to charge-offs of uncollectible energy costs from customers. Basic service rates are reset every six months (every three months for large commercial and industrial customers). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its NSTAR Green wind contracts through the basic service charge. Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers.
- A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the distribution infrastructure to deliver electricity to its destination, as well as ongoing operating costs.
- A revenue decoupling adjustment that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the DPU. Annual base distribution amounts are adjusted for inflation and filed for approval by the DPU on an annual basis, until the next rate case.
- A transmission charge that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.
- A transition charge that represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contract buy-outs. The transition charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.
- A renewable energy charge that represents a legislatively-mandated charge to support the Massachusetts Renewable Energy Trust Fund.
- An energy efficiency charge that represents a legislatively-mandated charge to collect costs for energy efficiency programs. The energy efficiency charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.
- Reconciling adjustment charges that recover certain DPU-approved costs, including pension and PBOP benefits, low income customer discounts, credits issued to net-metering facilities installed by customers, payments to solar facilities qualified under the state solar renewable energy target program, attorney general consultant expenses, long-term renewable contracts, company-owned solar facilities, vegetation management costs, credits related to the Tax Cuts and Jobs Act of 2017, grid modernization costs, and storm restoration. These charges are reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.

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

Distribution Rate Case: NSTAR Electric's distribution rates were established in a 2017 DPU-approved rate case with rates effective February 1, 2018. DPU-approved inflation-based adjustments to annual base distribution amounts were effective annually beginning in 2019 and last through 2022. On January 14, 2022, NSTAR Electric filed an application with the DPU for new base distribution rates to be effective January 1, 2023.

Service Quality Metrics: NSTAR Electric is subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. NSTAR Electric will not be required to pay a SQ charge for its 2021 performance as the company achieved results at or above target for all of its SQ metrics in 2021.

### Sources and Availability of Electric Power Supply

As noted above, NSTAR Electric does not own any generation assets (other than 70 MW of solar power facilities that produce energy that is sold into the ISO-NE market) and purchases its energy supply requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. As approved by the DPU, NSTAR Electric enters into supply contracts for basic service for approximately 30 percent of its residential and 23 percent of its small commercial and industrial (C&I) customers twice per year for twelve-month terms. NSTAR Electric enters into supply contracts for basic service for 13 percent of its large C&I customers every three months.

During 2021, NSTAR Electric supplied approximately 17 percent of its overall customer load at basic service rates. The remaining 83 percent of its overall customer load was served either by municipal aggregation or competitive supply. Because customer migration is limited to energy supply service, it has no impact on NSTAR Electric’s electric distribution business or operating income of NSTAR Electric.

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

PSNH's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2021, PSNH furnished retail franchise electric service to approximately 532,000 retail customers in 211 cities and towns in New Hampshire, covering an area of approximately 5,630 square miles. PSNH does not own any electric generation facilities.

### Rates

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

Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers. For those customers who do not choose a competitive energy supplier, PSNH purchases power on behalf of, and passes the related cost 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.
- A distribution charge, which includes kilowatt-hour and/or demand-based charges to recover costs related to the maintenance and operation of PSNH's infrastructure to deliver power to its destination, as well as power restoration and service costs. It also includes a customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records.
- A transmission charge that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.
- A Stranded Cost Recovery Charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations, other long-term investments and obligations, and the remaining costs associated with the 2018 sales of its generation facilities.
- A Systems Benefits Charge (SBC), which funds energy efficiency programs for all customers, as well as assistance programs for residential customers within certain income guidelines.
- A Regulatory Reconciliation Adjustment (RRA) that reconciles the difference between certain estimated and actual costs included in base distribution rates, including costs related to regulatory assessments, vegetation management program expenses, property tax expenses, storm cost amortization updated for the actual cost of long-term debt and lost base revenues related to net metering.

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

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

Distribution Rate Case: PSNH’s distribution rates were established in a December 2020 NHPUC-approved settlement agreement, with rates effective January 1, 2021. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant additions in calendar years 2019, 2020 and 2021, respectively.

### Sources and Availability of Electric Power Supply

PSNH does not own any generation assets and as approved by the NHPUC, purchases energy supply from a variety of competitive suppliers for its energy service customers through requests for proposals issued twice per year, for six-month terms, for approximately 82 percent of its residential and small C&I customers and for 17 percent of its large C&I customers.

During 2021, PSNH supplied approximately 47 percent of its customer load at default energy service rates while the other 53 percent of its customer load had migrated to competitive energy suppliers. Because this customer migration is only for energy supply service, it has no impact on PSNH’s electric distribution business or its operating income.

### ELECTRIC TRANSMISSION SEGMENT

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

### Wholesale Transmission Rates

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

### Transmission Rate Base

Transmission rate base under our FERC-approved tariff primarily consists of our investment in transmission net utility plant less accumulated deferred income taxes. Under our FERC-approved tariff, investments in net utility plant generally enter rate base after they are placed in commercial operation. At the end of 2021, our estimated transmission rate base was approximately $8.7 billion, including approximately $3.8 billion at CL&P, $3.5 billion at NSTAR Electric, and $1.4 billion at PSNH.

### FERC ROE Complaints

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

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

On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases.

On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in its four pending cases. FERC Opinion Nos. 569-A and 569-B are currently under appeal with the 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 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 2021, we were involved in the planning, development and construction of a series of electric transmission projects that enhance system reliability and improve capacity. For more information on transmission projects, see "Business Development and Capital Expenditures – Electric Transmission Business" in the accompanying Item 7, *Management's Discussion and Analysis of Financial Condition and Results of Operations.*

### 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 303,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square 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 249,000 customers in 74 cities and towns in Connecticut covering 2,632 square miles. Total throughput (sales and transportation) in 2021 was approximately 66.9 Bcf for NSTAR Gas, 53.4 Bcf for EGMA, and 56.4 Bcf for Yankee Gas. Our natural gas businesses provide firm natural gas sales and transportation service to eligible retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, as well as commercial and industrial customers 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 facilities consisting of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas and facilities that include additional storage capacity of 0.5 Bcf. Total vaporization capacity of these facilities is 0.21 Bcf per day. EGMA has access to approximately 1.8 Bcf of LNG and 0.1 Bcf of Liquefied Petroleum Gas (LPG) storage, with a total vaporization capacity of 0.14 Bcf per day. Yankee Gas owns a 1.2 Bcf LNG facility, which also has the ability to liquefy and vaporize up to 0.1 Bcf per day. This facility is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas, typically during periods of low demand.

### Rates

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

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

- A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building, maintaining, and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs.
- A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas and EGMA that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset semi-annually with any difference being recovered from, or refunded to, customers during the following corresponding season. In addition, NSTAR Gas and EGMA file interim changes to the CGAC factor when the actual costs of natural gas supply vary from projections by more than five percent.
- A Purchased Gas Adjustment (PGA) clause at Yankee Gas that collects the costs of the procurement of natural gas for its firm and seasonal customers. The PGA is evaluated monthly. Differences between actual natural gas costs and collection amounts from September 1st through August 31st of each PGA year are deferred and then recovered from, or refunded to, customers during the following PGA year. Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA.
- A local distribution adjustment clause (LDAC) at NSTAR Gas and EGMA that collects all energy efficiency and related program costs, environmental costs, pension and PBOP related costs, attorney general consultant costs, credits related to the Tax Cuts and Jobs Act of 2017, gas system enhancement program (GSEP) costs 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 Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency. A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from, or refunded to, customers with carrying charges during the following year.
- A Gas System Improvement (GSI) reconciliation mechanism at Yankee Gas, which collects the costs of certain Distribution Integrity Management Program (DIMP) and core capital plant in service above and beyond the level that is recovered through the distribution charge. The GSI is adjusted and reconciled annually, with any differences refunded to, or recovered from, customers.
- A System Expansion Rate (SER) Reconciliation Mechanism at Yankee Gas, which compares distribution system expansion investment costs and revenues for new customers, with the level projected in current distribution customer rates. This reconciliation is performed annually and customer rates are adjusted accordingly.
- A Revenue Decoupling Mechanism (RDM) at NSTAR Gas and EGMA that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the DPU in 2020. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment in accordance with provisions of the November 2020 NSTAR Gas distribution rate case and the October 2020 EGMA rate settlement agreement.
- A RDM at Yankee Gas that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the PURA 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 an SQ charge for their 2021 performance as each achieved results at or above target for all of their SQ metrics in 2021.

Distribution Rate Cases:

NSTAR Gas: NSTAR Gas distribution rates were established in an October 2020 DPU-approved rate case, with rates effective November 1, 2020. 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 established in a December 2018 PURA-approved rate case settlement agreement, with rates effective November 15, 2018. PURA also approved step adjustments effective January 1, 2019, January 1, 2020 and March 1, 2021.

### Natural Gas Replacement

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

In October 2020, the DPU opened Docket “DPU 20-80 The Future of Gas” to examine the role of Massachusetts natural gas local distribution companies (LDCs) in helping to meet the state’s 2050 climate goals. The DPU will consider new policies and structures that would protect 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: Yankee Gas' December 2018 PURA approved rate case settlement agreement included an accelerated pipeline replacement cost recovery program. The Gas System Improvement (GSI) rate recovers accelerated pipeline replacement as well as other capital investment through an annual reconciliation. Yankee Gas files its GSI reconciliation annually on March 1st for rates effective April 1st.

### Sources and Availability of Natural Gas Supply

NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport natural gas from major natural gas producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area. NSTAR Gas purchases all of its natural gas supply under a firm, competitively bid annual portfolio management contract. In addition to the firm transportation and natural gas storage supplies discussed above, NSTAR Gas utilizes on-system LNG facilities to meet its winter peaking demands. These LNG facilities are located within NSTAR Gas' distribution system and are used to liquefy and store pipeline natural gas during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in Maryland and Pennsylvania. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf, and 3.5 Bcf LNG storage is provided by Hopkinton LNG Corp. in facilities located in two different locations in Massachusetts.

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

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

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

### WATER DISTRIBUTION SEGMENT

Aquarion Company (Aquarion) operates four separate regulated water utilities in Connecticut (Aquarion Water Company of Connecticut, or AWC-CT), Massachusetts (Aquarion Water Company of Massachusetts, or AWC-MA), New Hampshire (Aquarion Water Company of New Hampshire, or AWC-NH) and Abenaki Water Company (Abenaki). These regulated companies provide water services to approximately 226,000 residential, commercial, industrial, municipal and fire protection and other customers, in 68 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, 2021, approximately 92 percent of Aquarion’s customers were based in Connecticut.

### Rates

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

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

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

- A base rate, which is comprised of fixed charges based on meter/fire connection sizes, as well as volumetric charges based on the amount of water sold. Together these charges are designed to recover the full cost of service resulting from a general rate proceeding.
- In Connecticut, a revenue adjustment mechanism (RAM) that reconciles earned revenues, with certain allowed adjustments, on an annual basis, to the revenue requirement approved by the PURA.
- In Connecticut and New Hampshire, a water infrastructure conservation adjustment (WICA) charge, and in Massachusetts, an annual main replacement adjustment mechanism (MRAM) charge, which is applied between rate case proceedings and seeks recovery of allowed costs associated with eligible infrastructure improvement projects placed in-service. The WICA is updated semi-annually in Connecticut and annually in New Hampshire. In Connecticut, an annual WICA reconciliation mechanism reconciles earned WICA revenue to the approved WICA revenue with any differences refunded to, or recovered from, customers.

### Sources and Availability of Water Supply

Our water utilities obtain their water supplies from owned surface water sources (reservoirs) and groundwater supplies (wells) with a total supply yield of approximately 127 million gallons per day, as well as water purchased from other water suppliers. Approximately 99 percent of our annual production is self-supplied and processed at nine surface water treatment plants and numerous well stations, which are all located in Connecticut, Massachusetts, and New Hampshire.

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

### OFFSHORE WIND PROJECTS

Eversource's offshore wind business includes a 50 percent ownership interest in North East Offshore, which holds power purchase agreements (PPAs) and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as offshore leases issued by BOEM. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted. This partnership also participates in new procurement opportunities for 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 approximately 25 miles south of the coast of Massachusetts. In aggregate, these ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy.

Revolution Wind is a 704 MW offshore wind power project located approximately 15 miles south of the Rhode Island coast, and South Fork Wind is a 130 MW offshore wind power project located approximately 35 miles east of Long Island. Sunrise Wind is a 924 MW offshore wind facility, which will be developed 35 miles east of Montauk Point, Long Island. The completion dates for these projects are subject to federal permitting through BOEM, and engineering, state siting and permitting in New York, Rhode Island and Massachusetts. For more information on these projects, see "Business Development and Capital Expenditures – Offshore Wind Business" in the accompanying Item 7, *Management's Discussion and Analysis of Financial Condition and Results of Operations.*

### PROJECTED CAPITAL EXPENDITURES

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

### FINANCING

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

### NUCLEAR FUEL STORAGE

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

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

### OTHER REGULATORY AND ENVIRONMENTAL MATTERS

### General

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

### Renewable Portfolio Standards

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

Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2021, the total RPS obligation was 30.5 percent and will ultimately reach 48.0 percent in 2030. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its Generation Service Charge rate.

Massachusetts' RPS program requires electricity suppliers to meet renewable energy standards. For 2021, the RPS and Clean Energy Standard (CES) requirements were 49.26 percent, and will ultimately reach 57.30 percent in 2025. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 5.25 percent and Clean Peak Energy Standards (CPS) of 3.0 percent in 2021. Those requirements will reach 6.25 and 9.00 percent in 2025, respectively. NSTAR Electric is permitted to recover any costs incurred in complying with 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 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 material sites. As of December 31, 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 $115.4 million, representing 61 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 $105.6 million of the total $115.4 million as of December 31, 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 forty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities, including appliances, and wiring in buildings and homes. Some epidemiology studies have reported a possible statistical association between adverse health effects and exposure with EMF. The association identified in some of these studies remain unexplained and inconclusive. Numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support a conclusion that EMF affects human health at levels expected in the vicinity. In accordance with recommendations of various regulatory bodies and public health organizations, we use design principles that help reduce potential EMF exposures associated with new transmission lines.

### HUMAN CAPITAL

Eversource is committed to delivering reliable energy and superior customer service; expanding energy options for our region; environmental stewardship; a safe, diverse and fairly-compensated workforce; and community service and leadership. Our employees are critical to achieving this mission. We recognize our employees are our most valuable asset and the importance of attracting, retaining, growing and developing our employees. Leaders at all levels strive to create a workplace where our employees are engaged, advocate for the customer, work collaboratively, raise ideas for improvement and focus on delivering a superior customer experience. We build employee engagement through continuous communication, developing talent, fostering teamwork and creating a diverse, equitable and inclusive workplace.

As of December 31, 2021, Eversource Energy employed a total of 9,227 employees, excluding temporary employees, of which 1,382 were employed by CL&P, 1,599 were employed by NSTAR Electric, and 765 were employed by PSNH. In addition, 3,335 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 51 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 14 collective bargaining agreements.

**Safety.** At Eversource, our commitment to “Safety First and Always” is a principle and a mindset present in every job and every task, whether in the field, office or at home. A priority at Eversource is continuous improvement and safety is at the forefront as we continue to build a strong safety culture, embrace new technologies, and learn with our industry and community partners to improve safety performance. We use metrics such as Eversource Corporate Days Away Restricted Time (DART) and Preventable Motor Vehicle events, among others, to monitor safety performance. Our DART safety performance was 0.9 in 2021, measured by days away, restricted or transferred per 100 workers.

In our continued response to the COVID-19 pandemic, we operated under our company-wide pandemic plan in the best interest of our employees, customers, and communities. This included having nearly half of our employees working remotely, while implementing additional significant safety measures for employees that continued critical on-site work. State and federal guidelines, public health guidance, external conditions, and critical business priorities continue to inform our plan, with the safety of our employees and customers as our highest priority. By the end of 2021, we completed the re-entry phase of our pandemic response plan for those of our employees that were working remotely. Significant health and safety measures and pandemic protocols have remained in place, including the use of 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.

## Risk factors

As filed, 34,208 characters.

In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1, *Business,* above, we are subject to a variety of material risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our financial position, results of operations, and cash flows.

### Cybersecurity and Data Privacy Risks:

**Cyberattacks, including acts of war or terrorism, targeted directly on or indirectly affecting our systems or the systems of third parties on which we rely, could severely impair operations, negatively impact our business, lead to the disclosure of confidential information and adversely affect our reputation.**

Cyberattacks that seek to exploit potential vulnerabilities in the utility industry and seek to disrupt electric, natural gas and water transmission and distribution systems are increasing in sophistication, magnitude and frequency. A successful cyberattack on the information technology systems that control our transmission, distribution, natural gas and water systems or other assets could impair or prevent us from managing these systems and facilities, operating our systems effectively, or properly managing our data, networks and programs. The breach of certain information technology systems could adversely affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and to repair system damage or security breaches and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation.

We have instituted safeguards to protect our information technology systems and assets. We deploy substantial technologies to system and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or misuse. Specifically, regarding vulnerabilities, we patch systems where patches are available to deploy, and have technologies that detect exploits of vulnerabilities and proactively block the exploit when it happens. Although we did not experience any material impacts from the SolarWinds event in 2020 or the Log4j security vulnerability that was widely publicized in December 2021, there can be no assurance that we will not experience future events that may be material. We also interface with numerous external entities to improve our cybersecurity situational awareness. The FERC, through the North American Electric Reliability Corporation (NERC), requires certain safeguards to be implemented to deter cyberattacks. These safeguards may not always be effective due to the evolving nature of cyberattacks. We maintain cyber insurance to cover damages and defense costs related to breaches of networks or operational technology, but it may be insufficient in limits and coverage exclusions to cover all losses.

Any such cyberattacks could result in loss of service to customers and a significant decrease in revenues, which could have a material adverse impact on our financial position, results of operations and cash flows.

**The unauthorized access to, and the misappropriation of, confidential and proprietary customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation.**

In the regular course of business, we, and our third-party suppliers, rely on information technology to maintain sensitive customer, employee, financial and system operating information. We are required by various federal and state laws to safeguard this information. Cyber intrusions, security breaches, theft or loss of this information by cybercrime or otherwise could lead to the release of critical operating information or confidential customer or employee information, which could adversely affect our business operations or adversely impact our reputation, and could result in significant costs, fines and litigation. We employ system controls to prevent the dissemination of certain confidential information and periodically train employees on phishing risks. We maintain cyber insurance to cover damages and defense costs arising from unauthorized disclosure of, or failure to protect, private information, as well as costs for notification to, or for credit monitoring of, customers, employees and other persons in the event of a breach of private information. This insurance covers amounts paid to avert, prevent or stop a network attack or the disclosure of personal information, and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach, but it may be insufficient to cover all losses. While we have implemented measures designed to prevent network attacks and mitigate their effects should they occur, these measures may not be effective due to the continually evolving nature of efforts to access confidential information.

### Business and Operational Risks:

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

We are pursuing broader strategic development investment opportunities that will benefit the Northeast region related to the development, construction and operation of offshore wind electric generation facilities, and investment opportunities in electric transmission facilities and other clean-energy infrastructure. The states in which we provide service have implemented selection procedures for such new facilities that require the review of competing projects and permit the selection of only those projects that are expected to provide the greatest benefit to customers. Accordingly, our projects may not be selected for construction. The development and construction of projects selected for construction involves numerous significant risks including scheduling delays, increased costs, tax strategies and changes to federal tax laws, federal, state and local permitting and regulatory approval processes, specifically BOEM’s approval processes, new legislation impacting the industry, future legislative or regulatory actions that could result in these projects not being probable of entering the construction phase, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent utilities and other entities, actions of our strategic partners, and capacity factors once projects are placed in operation. Our offshore wind partnership’s ability to generate returns from its offshore wind projects will depend on meeting construction schedules, controlling cost overruns, maintaining continuing interconnection arrangements, power purchase agreements, or other market mechanisms as well as interconnecting utility and Regional Transmission Organizations rules, policies, procedures and FERC tariffs that permit future offshore wind project operations. Additionally, scheduling delays in offshore wind projects, any changes to tax laws impacting Eversource’s ability to monetize tax attributes associated with these projects, or the cancellation of any projects, as well as the other risk factors described above, could have a material adverse effect on our financial position, results of operations, and cash flows, or our future growth opportunities may not be realized as anticipated.

**We rely on third-party suppliers for equipment, materials, and services and we outsource certain business functions to third-party suppliers and service providers, and substandard performance or inability to fulfill obligations by those third parties could harm our business, reputation and results of operations.**

We outsource certain services to third parties in areas including information technology, transaction processing, human resources, payroll and payroll processing and certain operational areas. As a result of our acquisition of the Columbia Gas of Massachusetts (CMA) assets from NiSource on October 9, 2020, we have entered into a Transition Services Agreement with NiSource whereby NiSource is performing certain services on behalf of Eversource Gas Company of Massachusetts in the areas of information technology, transaction processing, human resources, payroll and payroll processing and certain operational areas for periods ranging from 1 to 24 months from the acquisition date. Outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively impact our results of operations. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Due to the COVID-19 pandemic and current state of the global economy as a whole, we may experience supply chain issues with obtaining key materials, equipment or services timely and at a reasonable price across all business lines. We also continue to pursue enhancements to standardize our systems and processes. If any difficulties in the global supply chain cycle or operation of these systems were to occur, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.

**Our transmission and distribution systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.**

Our ability to properly operate our transmission and distribution systems is critical to the financial performance of our business. Our transmission and distribution businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity, natural gas and water; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events such as fires, explosions, a solar event, an electromagnetic event, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; human error; global supply chain disruptions; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage. Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the in-service date for one or more of these projects is delayed due to economic events or factors, or regulatory or other delays, the risk of failures in the electric transmission system may increase. We also implement new information technology systems from time to time, which may disrupt operations. Any failure of our transmission and distribution systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.

**New technology and alternative energy sources could adversely affect our operations and financial results.**

Advances in technology that reduce the costs of alternative methods of producing electric energy to a level that is competitive with that of current electric production methods, could result in loss of market share and customers, and may require us to make significant expenditures to remain competitive. These changes in technology, including micro-grids and advances in energy or battery storage, could also alter the channels through which electric customers buy or utilize energy, which could reduce our revenues or increase our expenses. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers.

**The loss of key personnel, the inability to hire and retain qualified employees, or the failure to maintain a positive relationship with our workforce could have an adverse effect on our business, financial position and results of operations.**

Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the Eversource parent or subsidiary level will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our workforce in our subsidiaries, including many workers with specialized skills maintaining and servicing the electric, natural gas and water infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but we cannot predict the impact of these plans on our ability to hire and retain key employees. Labor disputes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms, as well as the increased competition for talent or the intentional misconduct of employees or contractors, may also have an adverse effect on our business, financial position and results of operations.

### Risks Related to the Environment and Catastrophic Events:

**The effects of climate change, including severe storms, could cause significant damage to any of our facilities requiring extensive expenditures, the recovery for which is subject to approval by regulators.**

Climate change creates physical and financial risks to our operations. Physical risks from climate change may include an increase in sea levels and changes in weather conditions, such as changes in precipitation and extreme weather events. Customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. For water customers, conservation measures imposed by the communities we serve could impact water usage. To the extent weather conditions are affected by climate change, customers’ energy and water usage could increase or decrease depending on the duration and magnitude of the changes.

Severe weather, such as ice and snow storms, tornadoes, micro-bursts, hurricanes, floods, droughts, and other natural disasters, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers, and could result in penalties or fines. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows. We maintain property insurance, but it may be insufficient in limits and coverage exclusions to cover all losses.

**Contamination of our water supplies, the failure of dams on reservoirs providing water to our customers, or requirements to repair, upgrade or dismantle any of these dams, may disrupt our ability to distribute water to our customers and result in substantial additional costs, which could adversely affect our financial position, results of operations and cash flows.**

Our water supplies, including water provided to our customers, are subject to possible contamination from naturally occurring compounds or man-made substances. Our water systems include impounding dams and reservoirs of various sizes. Although we believe our dams are structurally sound and well-maintained, significant damage to these facilities, or a significant decrease in the water in our reservoirs, could adversely affect our ability to provide water to our customers until the facilities and a sufficient amount of water in our reservoirs can be restored. A failure of a dam could result in personal injuries and downstream property damage for which we may be liable. The failure of a dam would also adversely affect our ability to supply water in sufficient quantities to our customers. Any losses or liabilities incurred due to a failure of one of our dams may not be recoverable in rates and may have a material adverse effect on our financial position, results of operations and cash flows. We maintain liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses.

**Physical attacks, including acts of war or terrorism, both threatened and actual, could adversely affect our ability to operate our systems and could adversely affect our financial results and liquidity.**

Physical attacks, including acts of war or terrorism, both threatened and actual, that damage our transmission and distribution systems or other assets could negatively impact our ability to transmit or distribute energy, water, natural gas, or operate our systems efficiently or at all. Because our electric transmission systems are part of an interconnected regional grid, we face the risk of widespread blackouts due to grid disturbances or disruptions on a neighboring interconnected system. Similarly, our natural gas distribution system is connected to transmission pipelines, not owned by Eversource. If there was an attack on the transmission pipelines, it could impact our ability to deliver natural gas. If our assets were physically damaged and were not recovered in a timely manner, it could result in a loss of service to customers, a significant decrease in revenues, significant expense to repair system damage, costs associated with governmental actions in response to such attacks, and liability claims, all of which could have a material adverse impact on our financial position, results of operations and cash flows. We maintain property and liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. In addition, physical attacks against third-party providers could have a similar effect on the operation of our systems.

### Regulatory, Legislative and Compliance Risks:

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

The rates that our electric, natural gas and water companies charge their customers are determined by their state regulatory commissions and by the FERC. These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters. The FERC also regulates the transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters, including reliability standards through the NERC.

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.

The FERC has jurisdiction over our transmission costs recovery and our allowed ROEs. Certain outside parties have filed four complaints against all electric companies under the jurisdiction of ISO-NE alleging that our allowed ROEs are unjust and unreasonable. An adverse decision in any of these four complaints could adversely affect our financial position, results of operations and cash flows.

FERC's policy has encouraged competition for transmission projects, even within existing service territories of electric companies. Implementation of FERC's goals, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects, which may adversely affect our results of operations and lower rate base growth.

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

**We are exposed to significant reputational risks, which make us vulnerable to increased regulatory oversight or other sanctions.**

Because utility companies, including our electric, natural gas 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.**

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 material and solid waste, and air emissions. Compliance with these requirements requires us to incur significant costs relating to environmental permitting, monitoring, maintenance and upgrading of facilities, and remediation.

The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. Although we have recorded liabilities for known environmental obligations, these 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.**

We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors, many of which are beyond our control. These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing, amounts, and number of future financings and negatively affect our financial position, results of operations and cash flows.

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

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

## Properties

As filed, 15,269 characters.

### Transmission and Distribution System

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

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

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

### Electric Generating Plants

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

| Type of Plant | Number of Sites | Year Installed | Claimed Capability\*\* (kilowatts, dc) |
| --- | ---: | --- | ---: |
| Solar Fixed Tilt, Photovoltaic | 22 | 2010 - 2019 | 70,000 |

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

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

### Natural Gas Distribution System

As of December 31, 2021, NSTAR Gas owned 22 active gate stations, 148 district regulator stations, and approximately 3,322 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, Massachusetts (0.5 Bcf of natural gas). In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, Massachusetts (3.0 Bcf of natural gas). Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract.

As of December 31, 2021, EGMA owned 14 active gate stations, 193 district regulator stations, and approximately 5,014 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns liquefaction and vaporization plants and above ground storage tanks at four locations throughout Massachusetts with an aggregate storage capacity equivalent to 1.8 Bcf of natural gas. In addition, Hopkinton owns three propane peak shaving plants at three locations throughout Massachusetts with an aggregate storage capacity equivalent to 0.1 Bcf.

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

### Natural Gas Transmission System

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

### Water Distribution System

Aquarion’s properties consist of water transmission and distribution mains and associated valves, hydrants and service lines, water treatment plants, pumping facilities, wells, tanks, meters, dams, reservoirs, buildings, and other facilities and equipment used for the operation of our systems, including the collection, treatment, storage, and distribution of water.

As of December 31, 2021, Aquarion owned and operated sources of water supply with a combined yield of approximately 127 million gallons per day; 3,573 miles of transmission and distribution mains; 9 surface water treatment plants; 29 dams; and 123 wellfields.

### Franchises

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

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

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

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

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

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

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

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

**Eversource Gas Company of Massachusetts** Eversource Gas Company of Massachusetts holds valid franchises to sell natural gas in the areas in which it supplies natural gas service. Generally, Eversource Gas Company of Massachusetts holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Massachusetts so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility or by consent.

**Yankee Gas** Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas service. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility or by consent. Yankee Gas' franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the PURA and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas' franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute natural gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.

**Aquarion Water Company of Connecticut** AWC-CT derives its rights and franchises to operate from special acts of the Connecticut General Assembly and subject to certain approvals, permits and consents of public authority and others prescribed by statute and by its charter, AWC-CT has, with minor exceptions, solid franchises free from burdensome restrictions and unlimited as to time, and is authorized to sell potable water in the towns (or parts thereof) in which water is now being supplied by AWC-CT.

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 Massachusetts** Through its charters, which are unlimited in time, AWC-MA has the right to engage in the business of distributing and selling water within its service territories, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon water companies under Massachusetts laws. AWC-MA has the right to construct and maintain its mains and distribution pipes in and under any public ways and to take and hold water within its respective service territories. Subject to DPU regulation, AWC-MA has the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same. Certain of the towns within our service area have the right, at any time, to purchase the corporate property and all rights and privileges of AWC-MA according to pricing formulas and procedures specifically described in AWC-MA's respective charters and in compliance with Massachusetts law.

**Aquarion Water Company of New Hampshire** The NHPUC, pursuant to statutory law, has issued orders granting and affirming AWC-NH’s exclusive franchise to own, operate, and manage plant and equipment and any part of the same, for the conveyance of water for the public located within its franchise territory. That franchise territory encompasses the towns of Hampton, North Hampton and Rye. Abenaki Water Systems territory encompasses the towns of Belmont, Bow, Carroll, and Gilford. Subject to NHPUC’s regulations, AWC-NH has the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same.

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.

## Legal proceedings

As filed, 968 characters.

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

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

## Management's discussion and analysis

As filed, 165,471 characters.

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 these non-GAAP financial measures to evaluate and provide details of earnings results by 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 of our business. These non-GAAP financial measures should not be considered as alternatives to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as indicators of operating performance.

### Financial Condition and Business Analysis

#### Executive Summary

Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business. Eversource Energy's wholly-owned regulated utility subsidiaries consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR Gas and 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 $1.22 billion, or $3.54 per share, in 2021, compared with $1.21 billion, or $3.55 per share, in 2020.
- Our 2021 results include after-tax costs recorded within the electric distribution segment resulting from a PURA-approved CL&P settlement agreement and an after-tax 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 $0.32 per share in 2021. Our 2020 results include after-tax acquisition and transition costs of $32.1 million, or $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 2021, compared with $1.24 billion, or $3.64 per share, in 2020.
- We currently project 2022 non-GAAP earning guidance of between $4.00 per share and $4.17 per 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 $1.96 billion in 2021, compared with $1.68 billion in 2020. Investments in property, plant and equipment totaled $3.18 billion in 2021 and $2.94 billion in 2020.
- Cash totaled $66.8 million as of December 31, 2021, compared with $106.6 million as of December 31, 2020. Our available borrowing capacity under our commercial paper programs totaled $1.14 billion as of December 31, 2021. In 2021, we issued $3.23 billion of new long-term debt and we repaid $1.14 billion of long-term debt.
- In 2021, we issued dividends totaling $2.41 per common share, compared with dividends of $2.27 per common share in 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 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.
- We project to make capital expenditures of $18.14 billion from 2022 through 2026, of which we expect $7.02 billion to be in our electric distribution segment, $4.53 billion to be in our natural gas distribution segment, $4.60 billion to be in our electric transmission segment, and $0.89 billion to be in our water distribution segment. We also project to invest $1.10 billion in information technology and facilities upgrades and enhancements. Additionally, we currently expect to make investments in our offshore wind business between $0.9 billion and $1.0 billion in 2022 and expect to make investments for our three projects in total between $3.0 billion and $3.6 billion from 2023 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned.

#### Strategic and Regulatory Items:

- On January 18, 2022, South Fork Wind received BOEM’s final approval of its Construction and Operations Plan (COP), following BOEM’s November 2021 issuance of the Record of Decision, which concluded BOEM’s environmental review of the project. The COP approval outlines the project’s one nautical mile turbine spacing, the requirements on the construction methodology for all work occurring in federal ocean waters, and mitigation measures to protect marine habitats and species. The final decision from BOEM was needed to move the project toward the start of construction, and with the decision received, South Fork has now entered the construction phase.
- On October 1, 2021, CL&P entered into 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 approved by the PURA. In exchange for the $75 million of customer credits and assistance, PURA’s interim rate reduction docket was resolved without findings. As a 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. Additionally, CL&P agreed to withdraw its pending appeals related to the $28.6 million storm performance penalty imposed in PURA’s April 28, 2021 and July 14, 2021 decisions. CL&P has also agreed to freeze its current base distribution rates until no earlier than January 1, 2024. The cumulative pre-tax impact of the October 1, 2021 settlement agreement and the Storm Isaias penalty imposed by PURA totaled $103.6 million, and the after-tax earnings impact was $86.1 million, or $0.25 per share, in 2021.

#### Earnings Overview

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

*(Millions of Dollars, Except Per Share Amounts)*

|  | For the Years Ended December 31, 2021 Amount | Per Share | 2020 Amount | Per Share | 2019 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 |

28

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

*(Millions of Dollars, Except Per Share Amounts)*

|  | For the Years Ended December 31, 2021 Amount | Per Share | 2020 Amount | Per Share | 2019 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 |

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

(2) The 2021 costs are for the transition of systems as a result of our purchase of the assets of CMA on October 9, 2020 and costs associated with our December 1, 2021 water business acquisition. The 2020 acquisition costs are associated with our CMA acquisition. We expect integration costs in 2022 as a result of continuing to transition the CMA assets onto Eversource’s systems.

Our electric distribution segment earnings decreased $73.9 million in 2021, as compared to 2020, due primarily to CL&P’s settlement agreement on October 1, 2021 resulting in a $75 million pre-tax charge to earnings and a $28.6 million pre-tax charge to earnings at CL&P for a storm performance penalty imposed by PURA as a result of CL&P’s preparation for and response to Tropical Storm Isaias in August 2020 that was recorded in 2021. The after-tax impact of the CL&P 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 effective January 1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020, and higher earnings from CL&P's capital tracker mechanism due to increased electric system improvements. Those earnings increases were partially offset by higher operations and maintenance expense driven by higher employee-related expenses and higher vegetation management costs, higher depreciation expense, higher property tax expense, and higher interest expense.

Our electric transmission segment earnings increased $42.1 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.

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

Our water distribution segment earnings decreased $4.4 million in 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 the sale of the water system and treatment plant in Hingham, Massachusetts in July 2020.

*Eversource Parent and Other Companies:* Eversource parent and other companies had an increased loss of $19.2 million in 2021, as compared to 2020, due primarily to a higher effective tax rate and higher employee-related costs. The higher loss was partially offset by a decrease of $7.0 million in acquisition and transition costs of EGMA recorded at Eversource parent and a higher return at 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 critical service to our customers and have taken extensive measures to maintain its safety and reliability. We continue to address the impacts of the COVID-19 pandemic and how the related developments affect Eversource. By the end of 2021, we completed the re-entry phase of our pandemic response plan for those of our employees that were working remotely. We have not experienced significant impacts directly related to the pandemic that have materially affected our current operations, our workforce, or results of operations. The extent of the impact to us in the future will vary, and depend on the duration, scope and severity of the pandemic and the resulting impact on economic, health care and capital market conditions. The future impact will also depend on the outcome of future proceedings before our state regulatory commissions to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses.

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

As of December 31, 2021, our allowance for uncollectible customer receivable balance of $417.4 million, of which $226.1 million relates to hardship accounts that are specifically recovered in rates charged to customers, adequately reflected the collection risk and net realizable value for our receivables. 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 future rate case to the extent those costs are relevant at that time. As a result of the order, PSNH removed its $0.6 million deferral of net incremental COVID-19 costs in 2021. In New Hampshire, the moratorium on 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 evaluation performed, for the year ended December 31, 2021, management increased the allowance for uncollectible accounts for amounts incurred as a result of COVID-19 by $24.1 million for Eversource (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 future rates. As of December 31, 2021, the total amount incurred as a result of COVID-19 included in the allowance for uncollectible accounts was $55.3 million at Eversource ($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 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 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, 2021, a total of $39.8 million of net deferred incremental COVID-19 costs were recorded on the balance sheet, of which $33.0 million of that deferral related to uncollectible expense that impacts earnings and $6.8 million related to cleaning and supplies for personal protective equipment.

#### Liquidity

*Sources and Uses of Cash:* Eversource’s regulated business is capital intensive and requires considerable capital resources. Eversource’s regulated companies’ capital resources are provided by cash flows generated from operations, short-term borrowings, long-term debt issuances, capital contributions from Eversource parent, and existing cash, and are used to fund their liquidity and capital requirements. Eversource’s regulated companies typically maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. Short-term borrowings are also used as a bridge to long-term debt financings. The levels of short-term borrowing may vary significantly over the course of the year due to the impact of fluctuations in cash flows from operations, dividends paid, capital contributions received and the timing of long-term debt financings.

Eversource, CL&P, NSTAR Electric and PSNH each uses its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends, and fund other corporate obligations, such as pension contributions. Eversource's regulated companies recover their electric, natural gas and water distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity and debt used to finance the investments. Eversource's regulated companies’ spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment and recovery period. In addition, Eversource’s investments in its offshore wind business are recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by $2.58 billion, $537.0 million, and $165.0 million at Eversource, NSTAR Electric and PSNH, respectively, as of December 31, 2021.

As of December 31, 2021, $1.18 billion of Eversource's long-term debt, including $750.0 million at Eversource parent, $400.0 million at NSTAR Electric, $20.0 million at Yankee Gas, and $5.4 million at Aquarion, will mature within the next 12 months. Eversource, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. Eversource, CL&P, NSTAR Electric and PSNH will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile.

We expect the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with our existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities.

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

*Short-Term Debt - Commercial Paper Programs and Credit Agreements*: Eversource parent has a $2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are parties to a five-year $2.00 billion revolving credit facility, which terminates on October 15, 2026. This revolving credit facility serves to backstop Eversource parent's $2.00 billion commercial paper program.

NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility, which terminates on October 15, 2026. The revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program.

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

| (Millions of Dollars) | Borrowings Outstanding as of December 31, 2021 | 2020 | Available Borrowing Capacity as of December 31, 2021 | 2020 | Weighted-Average Interest Rate as of December 31, 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) CL&P: | Issuance/(Repayment) | Issue Date or Repayment Date | Maturity Date | Use of Proceeds for Issuance/ Repayment Information |
| --- | ---: | --- | --- | --- |
| 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 | 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 million in the form of treasury shares, totaling dividends of $828.3 million, or $2.41 per common share. In 2020, we paid cash dividends of $744.7 million and issued non-cash dividends of $22.8 million in the form of treasury shares, totaling dividends of $767.5 million, or $2.27 per common share. Our quarterly common share dividend payment was $0.6025 per share in 2021, as compared to $0.5675 per share in 2020. On February 2, 2022, our Board of Trustees approved a common share dividend payment of $0.6375 per share, payable on March 31, 2022 to shareholders of record as of March 3, 2022.

Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan.

In 2021, CL&P, NSTAR Electric and PSNH paid $341.4 million, $283.2 million and $260.8 million, respectively, in common stock dividends to Eversource parent.

Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP expense. In 2021, investments for Eversource, CL&P, NSTAR Electric and PSNH were $3.18 billion, $790.1 million, $960.9 million and $326.4 million, respectively. Capital expenditures were primarily for continuing projects to maintain and improve infrastructure and operations, including enhancing reliability to the transmission and distribution systems.

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

Estimated interest payments on existing long-term fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement as of December 31, 2021 and are as follows:

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

Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, future funding of our offshore wind equity method investment, and guarantees of certain obligations primarily associated with our offshore wind investment.

For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures - Projected Capital Expenditures" and for projected investments in our offshore wind business, see Business Development and Capital Expenditures - Offshore Wind Business" included in this *Management's Discussion and Analysis of Financial Condition and Results of Operations.*

*Credit Ratings:* A summary of our corporate credit ratings and outlooks by S&P, Moody's, and Fitch is as follows:

|  | S&P |  | Moody's |  | Fitch |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | **Current** | **Outlook** | **Current** | **Outlook** | **Current** | **Outlook** |
| Eversource Parent | A- | Stable | Baa1 | Negative | BBB+ | Stable |
| CL&P | A | Stable | A3 | Negative | A- | Negative |
| NSTAR Electric | A | Stable | A1 | Stable | A | Stable |
| PSNH | A | Stable | A3 | Stable | A- | Stable |

A summary of the current credit ratings and outlooks by S&P, Moody's, and Fitch for senior unsecured debt of Eversource parent and NSTAR Electric, and senior secured debt of CL&P and PSNH is as follows:

|  | S&P |  | Moody's |  | Fitch |  |
| --- | --- | --- | --- | --- | --- | --- |
|  | **Current** | **Outlook** | **Current** | **Outlook** | **Current** | **Outlook** |
| Eversource Parent | BBB+ | Stable | Baa1 | Negative | BBB+ | Stable |
| CL&P | A+ | Stable | A1 | Negative | A+ | Negative |
| NSTAR Electric | A | Stable | A1 | Stable | A+ | Stable |
| PSNH | A+ | Stable | A1 | Stable | A+ | Stable |

#### Business Development and Capital Expenditures

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

| (Millions of Dollars) | For the Years Ended December 31, 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 |

33

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

Our transmission projects in Massachusetts include electric transmission upgrades in the greater Boston metropolitan area. Two of these upgrades, the Mystic-Woburn and the Wakefield-Woburn reliability projects, are under construction and are expected to be placed in service by the second quarter of 2023. The last remaining upgrade, the Sudbury-Hudson Reliability Project, received siting approval, however one appeal remains pending with expected resolution in the first quarter of 2022. We 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 Southeastern Massachusetts transmission system and bring the system into compliance with applicable national and regional reliability standards. We spent $20 million during 2021 and we expect to make additional capital expenditures of approximately $140 million on these transmission upgrades.

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

| (Millions of Dollars) 2021 | For the Years Ended December 31, CL&P | NSTAR Electric | PSNH | Total Electric | Natural Gas | Water | Total |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 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 electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth and other includes requests for new business and capacity additions on distribution lines and substation additions and expansions.

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

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

*Projected Capital Expenditures:* A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution, natural gas distribution and water distribution for 2022 through 2026, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:

| (Millions of Dollars) | Years 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 |

The projections do not include investments related to offshore wind projects. Actual capital expenditures could vary from the projected amounts for the companies and years above.

*Acquisition of New England Service Company:* Following receipt of all required approvals, on December 1, 2021, Aquarion acquired New England Service Company (NESC), pursuant to a definitive agreement entered into on April 8, 2021. The acquisition was structured as a stock-for-stock merger and Eversource issued 462,517 treasury shares at closing for a purchase price of $38.1 million. NESC’s utility subsidiaries provided regulated water service to approximately 10,000 customers in Connecticut, Massachusetts, and New Hampshire.

*Offshore Wind Business:* Our offshore wind business includes a 50 percent ownership 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 developed and constructed through a joint and equal partnership with Ørsted. 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 approximately 25 miles south of the coast of Massachusetts. In aggregate, these ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy.

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

| Wind Project | State Servicing | Size (MW) | Term (Years) | Price per MWh | Pricing Terms | Contract Status |
| --- | --- | ---: | ---: | ---: | --- | --- |
| Revolution Wind | Rhode Island | 400 | 20 | $98.43 | Fixed price contract; no price escalation | Approved |
| Revolution Wind | Connecticut | 304 | 20 | $98.43 - $99.50 | Fixed price contracts; no price escalation | Approved |
| South Fork Wind | New York (LIPA) | 90 | 20 | $160.33 | 2 percent average price escalation | Approved |
| South Fork Wind | New York (LIPA) | 40 | 20 | $86.25 | 2 percent average price escalation | Approved |
| Sunrise Wind | New York (NYSERDA) | 924 (1) | 25 | $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 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 all work occurring in federal ocean waters, and mitigation measures to protect marine habitats and 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 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 will be constructed in accordance with the conditions of the approved Joint Proposal. Comments from reviewing agencies and parties have been received and South Fork Wind has responded to and addressed those comments in the plan which was re-submitted in September 2021. The project received approval of the EM&CP in November 2021.

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

State permitting applications in Rhode Island for Revolution Wind and in New York for Sunrise Wind were filed in December 2020. The Revolution Wind state siting application was deemed complete on January 22, 2021, and the preliminary hearing was completed on March 22, 2021. On April 26, 2021, the Rhode Island Energy Facilities Siting Board issued a Preliminary Decision and Order on scheduling with Advisory Opinions for local and state agencies. All advisory opinions were received in August, in accordance with the expedited schedule, and evidentiary hearings began in October 2021. The Sunrise Wind state siting application 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 be the first to begin. Offshore installation, including the project’s monopile foundations, 11-megawatt wind turbines, and offshore substation, is expected to occur in 2023. Construction-related purchase agreements with third-party contractors and materials contracts have largely been secured. South Fork Wind faces several challenges and appeals of New York State agency approvals, however it believes it will be able to overcome these challenges.

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

Projected Investments: For Revolution Wind and Sunrise Wind, we are preparing our final project designs and advancing the appropriate federal, state, and local siting and permitting processes along with our offshore wind partner, Ørsted. Construction of South Fork Wind is now underway. Construction-related purchase agreements with third-party contractors and materials contracts are approximately 80 percent secured. Subject to advancing our final project designs and federal, state and local permitting processes and construction schedules, we currently expect to make investments in our offshore wind business between $0.9 billion and $1.0 billion in 2022 and expect to make investments for our three projects in total between $3.0 billion and $3.6 billion from 2023 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned.

#### FERC Regulatory Matters

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

The ROE originally billed during the period October 1, 2011 (beginning of the first complaint period) through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, the FERC set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period. This was also effective for all prospective billings to customers beginning October 16, 2014. This FERC order was vacated on April 14, 2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court).

All amounts associated with the first complaint period have been refunded. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 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, 2021 and 2020.

On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results.

The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, for the NETOs, which FERC concludes are of average financial risk, the preliminary just and reasonable base ROE is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent. If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order.

On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases.

On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in its four pending cases. FERC Opinion Nos. 569-A and 569-B are currently under appeal with the 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 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.

A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource’s after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods. Prospectively from the date of a final FERC order implementing a new base ROE, based off of estimated 2021 rate base, a change of 10 basis points to the base ROE would impact Eversource’s future annual after-tax earnings by approximately $5 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

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

*FERC Notice of Inquiry and Proposed Rulemaking on Transmission Incentives:* On March 21, 2019, FERC issued an NOI seeking comments on FERC's policies for implementing electric transmission incentives. On June 26, 2019, Eversource filed comments requesting that FERC retain policies that have been effective in encouraging new transmission investment and remain flexible enough to attract investment in new and emerging transmission technologies. Eversource filed reply comments on August 26, 2019. On March 20, 2020, FERC issued a Notice of Proposed Rulemaking (NOPR) on transmission incentives. The NOPR intends to revise FERC’s electric transmission incentive policies to reflect competing uses of transmission due to generation resource mix, technological innovation and shifts in load patterns. FERC proposes to grant transmission incentives based on measurable project economics and reliability benefits to consumers rather than its current project risks and challenges framework. On July 1, 2020, Eversource filed comments generally supporting the NOPR.

On April 15, 2021, FERC issued a Supplemental NOPR that proposes to eliminate the existing 50 basis point return on equity for utilities that have been participating in a regional transmission organization (RTO ROE incentive) for more than three years. On June 25, 2021, the NETOs jointly filed comments strongly opposing the Commission’s proposal. On July 26, 2021, the NETOs filed Supplemental NOPR reply comments responding to various parties advocating for the elimination of the RTO Adder. If the FERC issues a final order eliminating the RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual impact (using 2021 estimated rate base) on Eversource’s after-tax earnings is approximately $17 million. The Supplemental NOPR contemplates an effective date 30 days from the final order.

At this time, Eversource cannot predict the ultimate outcome of these proceedings, including possible appellate review, and the resulting impact on its transmission incentives.

#### Regulatory Developments and Rate Matters

*Electric, Natural Gas and Water Utility Retail Tariff Rates:* Each Eversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P, Yankee Gas and Aquarion operate in Connecticut and are subject to PURA regulation; NSTAR Electric, NSTAR Gas, EGMA and Aquarion operate in Massachusetts and are subject to DPU regulation; and PSNH and Aquarion operate in New Hampshire and are subject to NHPUC regulation. The regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs.

Base Distribution Rates: In Connecticut, electric and natural gas utilities are required to file a distribution rate case within four years of the last rate case. CL&P's and Yankee Gas' distribution rates were each established in 2018 PURA-approved rate case settlement agreements. On October 27, 2021, PURA approved a settlement agreement at CL&P that included a current base distribution rate freeze until no earlier than January 1, 2024. The approval of the settlement agreement satisfies the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case. Aquarion is not required to initiate a rate review with the 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. On January 14, 2022, NSTAR Electric filed an application with the DPU for an increase in base distribution rates, effective January 1, 2023. NSTAR Gas' distribution rates were established in 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 a 2018 DPU-approved rate case.

In New Hampshire, PSNH's distribution rates were established in a December 2020 NHPUC-approved rate case settlement 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.

Rate Reconciling Mechanisms: The Eversource electric distribution companies obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier. The natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply procurement costs are recovered from customers in energy supply rates that are approved by the respective state regulatory commission. The rates are reset periodically and are fully reconciled to their costs. Each electric and natural gas distribution company fully recovers its energy supply costs through approved regulatory rate mechanisms on a timely basis and, therefore, such costs have no impact on earnings.

The electric and natural gas distribution companies also recover certain other costs in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and, therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates. These cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings.

*Excess 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, 2021 and December 30, 2021 that approved the refund of EDIT to its transmission customers ($1.6 million at CL&P, $12.0 million at NSTAR Electric and $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 the 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 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 on CL&P’s balance sheet and as a reduction to 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 an October 2020 Connecticut law, PURA opened a proceeding related to new

rate designs to consider the implementation of an interim rate decrease, low-income and economic development rates for electric customers, and a

review of that rate design implementation process. The proceeding has separate phases. In the 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 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 October 2021 settlement agreement, described below. In addition, PURA is also investigating low-income and other economic development rates. A procedural schedule for this part of the proceeding has not yet been set by the PURA.

CL&P Settlement Agreement: On October 1, 2021, CL&P entered into a settlement agreement with the DEEP, Office of Consumer Counsel (OCC), Office of the Attorney General (AG) and the Connecticut Industrial Energy Consumers, resolving certain issues that arose in then-pending regulatory proceedings initiated by the PURA. PURA approved the settlement agreement on October 27, 2021. In the settlement agreement, CL&P agreed to provide a total of $65 million of customer credits, which were distributed based on customer sales over a two-month billing period from December 1, 2021 to January 31, 2022. CL&P also agreed to irrevocably set aside $10 million to provide bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages, as approved by the PURA, with the objective of disbursing the funds prior to April 30, 2022. CL&P recorded a current regulatory liability of $75 million on the balance sheet associated with the provisions of the settlement agreement, with a $65 million pre-tax charge as a reduction to Operating Revenues associated with the customer credits and a $10 million charge to Operations and Maintenance expense associated with the customer assistance fund on the year ended December 31, 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 overall rate increase of $0.00411 per kWh for residential customers. The rate increase included delivery rate changes for the CTA, TAC, ESI and RDM charges. Partially offsetting the rate increase was a base distribution rate decrease, which was driven by a reduction to storm cost amortization resulting from a 2019 PURA decision. For residential customers with 700 kWh monthly usage, the impact of the June 1, 2021 rate changes equated to an increase of $2.88 on monthly customer bills.

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

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

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

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

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

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

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

CL&P Performance Based Rate Making: On May 26, 2021, in accordance with an October 2020 Connecticut law, PURA opened a proceeding to begin to evaluate and eventually implement performance based regulation for electric distribution companies. PURA will conduct the proceeding in two phases, with a draft decision on the first phase and procedural schedule established for the second phase expected in March 2023. At this time, we cannot predict the ultimate outcome of this proceeding and the resulting impact to CL&P.

CL&P Advanced Metering Infrastructure Filing: On July 31, 2020, CL&P submitted to PURA its proposed $512 million Advanced Metering Infrastructure investment and implementation plan for the years 2021 through 2027. On August 17, 2021, PURA issued a Notice of Request for Amended EDC Advanced Metering Infrastructure Proposal. CL&P submitted an Amended Proposal in response to this request on November 8, 2021, which included additional information as required by the PURA. As required, the plan includes a full deployment of advanced metering functionality and a composite business case in support of the Advanced Metering Infrastructure plan. A procedural schedule in this proceeding has not been issued by 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: On January 14, 2022, NSTAR Electric filed an application with the DPU for approval of an $89 million increase in base distribution rates, with new rates anticipated to be effective January 1, 2023. As part of this filing, NSTAR Electric is requesting a renewal of the performance-based ratemaking plan originally authorized in its last rate case for up to a ten-year term, alignment with state electrification policy, storm fund refinements, and Advanced Metering Infrastructure tariff approval. A final decision from the DPU is expected on December 1, 2022.

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

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

NSTAR Gas and EGMA Distribution Rates and Mitigation Filings: As part of an inflation-based mechanism, NSTAR Gas submitted its first annual Performance Based Rate Adjustment filing on September 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 $13.6 million increase to base distribution rates on 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, 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.

COVID Regulatory Docket: 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 the context of the utility’s next rate case when related costs, to the extent those costs remain relevant under test year based rate-setting, would be considered in the context of the utility’s full revenue requirement and overall rate of return. The NHPUC concluded that New Hampshire utilities would not be permitted to establish a regulatory asset for these items. As a result of the order, in the second quarter of 2021, PSNH removed its $0.6 million deferral of net incremental COVID-19 costs.

Energy Efficiency Plan: On November 12, 2021, the NHPUC issued an order rejecting the proposed 2021 through 2023 energy efficiency plan and significantly reduced funding and operational functions of the program. 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 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 the provisions of the NHPUC order will be undone. At this time, PSNH cannot predict the ultimate outcome of this order, and the resulting impact on its financial statements.

#### Legislative and Policy Matters

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

*Massachusetts:* On 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 risks of climate change by owning solar facilities equal to up to 10 percent of the 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 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 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 our regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If we determine that we can no longer apply the accounting guidance applicable to rate-regulated enterprises, or that we cannot conclude it is probable that costs will be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made.

*Pension, SERP and PBOP:* We sponsor Pension, SERP and PBOP Plans to provide retirement benefits to our employees. 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. For the year ended December 31, 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 2022 pension and PBOP expense, an expected long-term rate of return of 8.25 percent for the Eversource Service plans and 7 percent for the Aquarion plans will be used reflecting our target asset allocations.

Discount Rate: Payment obligations related to the Pension, SERP and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows. The discount rate that was utilized in determining the pension, SERP and PBOP obligations was based on a yield-curve approach. This approach utilizes a population of bonds with an average rating of AA based on bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields within that population. As of December 31, 2021, the discount rates used to determine the funded status were within a range of 2.8 percent to 3.0 percent for the Pension and SERP Plans, and within a range of 2.91 percent to 2.92 percent for the PBOP Plans. As of December 31, 2020, the discount rates used were within a range of 2.4 percent to 2.7 percent for the Pension and SERP Plans, and within a range of 2.5 percent to 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 $286.8 million and $29.8 million, respectively, as of December 31, 2021.

The Company uses the spot rate methodology for the service and interest cost components of Pension, SERP and PBOP expense because it provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. The discount rates used to estimate the 2021 expense were within a range of 1.5 percent to 3.0 percent for the Pension and SERP Plans, and within a range of 1.8 percent to 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 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, 2021 and 2020, the compensation/progression rates used to determine the funded status were within a range of 3.5 percent to 4.0 percent.

Health Care Cost: The Eversource Service PBOP Plan is not subject to health care cost trends. As of December 31, 2021, for the Aquarion PBOP Plan, the health care trend rate for pre-65 retirees is 6.5 percent, with an ultimate rate of 5 percent in 2028, and for post-65 retirees, the health care trend rate and 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 $23.6 million, $56.9 million and $63.7 million for the years ended December 31, 2021, 2020 and 2019, respectively. For the PBOP Plans, there was net periodic PBOP income of $60.5 million, $51.6 million and $41.5 million for the years ended December 31, 2021, 2020 and 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 income in 2022 for the Pension and SERP Plans will be approximately $177 million and income in 2022 for the PBOP Plans will be approximately $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 $180.0 million to the Pension Plans in 2021. We currently estimate contributing between $100 million to $175 million to the Pension Plans in 2022, however, there is no minimum funding requirement for our Pension Plans for 2022, and therefore the planned contribution is discretionary and subject to change. It is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts. We contributed $2.3 million to the PBOP Plans in 2021. We currently estimate contributing $2.4 million to the PBOP Plans in 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) Assumption Change Eversource | Increase in Pension Plan Cost For the Years Ended December 31, 2021 | 2020 | Decrease in PBOP Plan Income For the Years Ended December 31, 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 |

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

We recorded $51.9 million of goodwill arising 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 test date. Goodwill impairment is deemed to exist if the carrying amount of a reporting unit exceeds its estimated fair value. If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.

In assessing goodwill for impairment, an entity is permitted to first assess qualitatively whether it is more likely than not that goodwill impairment exists as of the annual impairment test date. A quantitative impairment test is required only if it is concluded that it is more likely than not that a reporting unit’s fair value is less than it’s carrying amount.

We performed an impairment test of goodwill as of October 1, 2021 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units. Our qualitative evaluation included an evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings.

The 2021 goodwill impairment assessment resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment. We believe that the fair value of the reporting units was substantially in excess of carrying value. Adverse regulatory actions, changes in the regulatory and political environment, or changes in significant assumptions could potentially result in future goodwill impairment indicators.

*Long-Lived Assets:* Impairment evaluations of long-lived assets, including property, plant and equipment and other assets, involve a significant degree of estimation and judgment, including identifying circumstances that indicate an impairment may exist. 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.

*Equity Method Investments:* Investments in affiliates where we have the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost. Any differences between the cost of an investment and the amount of underlying equity in net assets of an investee are considered basis differences and are determined based upon the estimated fair values of the investee's identifiable assets and liabilities. For our offshore wind equity method investment, basis differences are related to intangible assets for PPAs that will be amortized over the term of the PPAs, and equity method goodwill that is not amortized. Capitalized interest associated with our offshore wind equity method investment is included in the investment balance.

Equity method investments are assessed for impairment when conditions exist that indicate that the fair value of the investment is less than book value. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations involve a significant degree of judgment and estimation, including identifying circumstances that indicate an impairment may exist and developing an estimate of undiscounted future cash 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.

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

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

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

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

*Fair Value Measurements:* We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to our Company's derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal), to marketable securities held in trusts, and to our investments in our Pension and PBOP Plans. Fair value measurements are also incorporated into the accounting for goodwill, long-lived assets, equity method investments, and AROs, and 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 our derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers. These valuations are sensitive to the prices of energy-related products in future years and assumptions made.

We use quoted market prices when available to determine the fair value of financial instruments. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy-related product prices for future years for long-dated derivative contracts and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk-adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

### RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the years ended December 31, 2021 and 2020 included in this Annual Report on Form 10-K:

| (Millions of Dollars) | For the Years Ended December 31, 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 |

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

### Operating Revenues

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

|  | Electric Sales Volumes (GWh) 2021 | 2020 | Percentage Increase 2021 | Firm Natural Gas Sales Volumes (MMcf) 2020 |  | Percentage Increase 2021 | Water Sales Volumes (MG) 2020 |  | Percentage Decrease |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 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)% |

(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.

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

Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage and water consumption. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts both electric and water sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.

Fluctuations in retail electric sales volumes at PSNH impact earnings ("Traditional" in the table above). For CL&P, NSTAR Electric, NSTAR Gas, EGMA, Yankee Gas, and our Connecticut water distribution business, fluctuations in retail sales volumes do not materially impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled" in the table above). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.

Operating Revenues: Operating Revenues by segment increased in 2021, as compared to 2020, as follows:

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

*Electric and Natural Gas (excluding EGMA) Distribution Revenues:*

#### Base Distribution Revenues:

- Base electric distribution revenues increased $28.8 million in 2021, as compared to 2020, due primarily to the impact of base distribution rate increases at NSTAR Electric effective January 1, 2021, at PSNH effective January 1, 2021 and August 1, 2021, and at CL&P effective May 1, 2020. These increases were partially offset by a base distribution rate decrease at CL&P implemented June 1, 2021. The decrease in the CL&P 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.
- Base natural gas distribution revenues increased $62.8 million in 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 settlement agreement, CL&P agreed to provide a total of $65 million of customer credits, which were distributed based on customer sales over a two-month billing period from December 1, 2021 to January 31, 2022. CL&P recorded a $28.4 million reserve in 2021 for a civil penalty for non-compliance with storm performance standards that is currently being credited to customers on electric bills beginning on September 1, 2021 over a one-year period. CL&P recorded these reserves as a current regulatory liability and a reduction to Operating Revenues. As of December 31, 2021, the remaining reserve that has not yet been issued as customer credits and not yet reflected in rates totaled $71.1 million. For further information, see "*Regulatory Developments and Rate Matters - Connecticut*" included in this *Management’s Discussion and Analysis.*

Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third party marketers, and the sale of RECs to various counterparties.

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

| (Millions of Dollars) Retail Tariff Tracked Revenues: | Electric Distribution | Natural Gas Distribution |
| --- | ---: | ---: |
| 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 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 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 revenues of Eversource's service company, most of which are eliminated in consolidation. Eliminations are also primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers.

**Purchased Power, Fuel and Transmission** expense includes costs associated with purchasing electricity and natural gas on behalf of our customers and the cost of energy purchase contracts, as required by regulation. These electric and natural gas supply costs and other energy-related costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense increased in 2021, as compared to 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 |

The decrease in purchased power expense at the electric distribution business in 2021, as compared to 2020, was driven primarily by lower expense related to the procurement of energy supply resulting from lower average supply-related sales volumes and lower average prices. The lower energy supply expense was partially offset by higher long-term contractual energy-related costs that are recovered in the NBFMCC mechanism at CL&P and 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 of $145.0 million, as well as higher average prices and higher average supply-related sales volumes.

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

**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 2021, as compared to 2020, due primarily to the following:

| (Millions of Dollars) Base Electric Distribution (Non-Tracked Costs): | Increase/(Decrease) |
| --- | ---: |
| 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 |

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

**Amortization** expense includes the deferral of energy supply, energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates.

Amortization increased in 2021, as compared to 2020, due primarily to the deferral adjustment of 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 completion of the amortization period of certain storm costs deferred assets.

**Energy Efficiency Programs** expense increased in 2021, as compared to 2020, due primarily to the incremental impact of EGMA energy efficiency program costs of $48.0 million. The increase was also due to the deferral adjustment at NSTAR Electric, which reflects the actual costs of energy efficiency programs compared to the amounts billed to customers, and the timing of the recovery of energy efficiency costs. The costs for the majority of the state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.

**Taxes Other Than Income Taxes** expense increased in 2021, as compared to 2020, due primarily to an increase in property taxes as a result of higher utility plant balances, the incremental impact of EGMA property and other taxes of $23.5 million, higher Connecticut gross earnings taxes, and the absence in 2021 of a benefit at NSTAR Gas in 2020 relating to the resolution of disputed property taxes for prior years.

**Interest Expense** increased in 2021, as compared to 2020, due primarily to an increase in interest on long-term debt as a result of new debt issuances ($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 ($3.4 million), a decrease in RRB interest expense ($1.3 million), and an increase in capitalized AFUDC related to debt funds and other capitalized interest ($1.1 million).

**Other Income, Net** increased in 2021, as compared to 2020, due primarily to an increase related to pension, SERP and PBOP non-service income components ($40.0 million) and an increase in interest income primarily from regulatory deferrals ($20.8 million), partially offset by lower AFUDC related to equity funds ($4.7 million) and investment losses in 2021 compared to investment income in 2020 driven by market volatility ($1.3 million).

**Income Tax Expense** decreased in 2021, as compared to 2020, due primarily to the absence of the sale of the Hingham water system ($12.5 million), an increase in amortization of EDIT ($20.4 million), the CL&P settlement agreement ($17.5 million), a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($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 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, 2021 and 2020 included in this Annual Report on Form 10-K:

| (Millions of Dollars) | For the Years Ended December 31, CL&P 2021 | 2020 | Increase/(Decrease) | NSTAR Electric 2021 | 2020 | Increase/(Decrease) | PSNH 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 |

### Operating Revenues

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

|  | For the Years Ended December 31, 2021 | 2020 | Increase | Percentage Increase |
| --- | ---: | ---: | ---: | ---: |
| CL&P | 20,501 | 20,113 | 388 | 1.9% |
| NSTAR Electric | 22,727 | 22,418 | 309 | 1.4% |
| PSNH | 7,782 | 7,675 | 107 | 1.4% |

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

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

#### 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 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.

Electric distribution revenues at CL&P also decreased $93.4 million in 2021, as compared to 2020, due to a reserve established to provide bill credits to customers as a result of CL&P’s settlement agreement on October 1, 2021 and a storm performance penalty assessed by PURA in 2021. In the settlement agreement, CL&P agreed to provide a total of $65 million of customer credits, which were distributed based on customer sales over a two-month billing period from December 1, 2021 to January 31, 2022. CL&P recorded a $28.4 million reserve in 2021 for a civil penalty for non-compliance with storm performance standards that is currently being credited to customers on electric bills beginning on September 1, 2021 over a one-year period. CL&P recorded these reserves as a current regulatory liability and a reduction to Operating Revenues. As of December 31, 2021, the remaining reserve that has not yet been issued as customer credits and not yet reflected in rates totaled $71.1 million. For further information, see "*Regulatory Developments and Rate Matters - Connecticut*" included in this Management’s Discussion and Analysis.

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

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

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

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

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

recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties.

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

| (Millions of Dollars) Retail Tariff Tracked Revenues: | CL&P | NSTAR Electric | PSNH |
| --- | ---: | ---: | ---: |
| 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 |

The decrease in energy supply procurement at CL&P was driven primarily by lower average prices, partially offset by higher average supply-related sales volumes. The decrease in energy supply procurement at NSTAR Electric was driven by lower average supply-related sales volumes, partially offset by higher average prices. The increase in energy supply procurement at PSNH was driven primarily by higher average supply-related sales volumes, partially offset by lower average prices. Fluctuations in retail transmission revenues 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 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 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.

*Transmission Revenues:* Transmission revenues increased $42.6 million at CL&P, $30.1 million at NSTAR Electric and $25.8 million at PSNH 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.

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

**Purchased Power and Transmission** expense includes costs associated with purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's 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 and Transmission expense increased in 2021, as compared to 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 |

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

- The increase at CL&P was due primarily to higher long-term contractual energy-related costs that are recovered in the NBFMCC mechanism, partially offset by lower expense related to the procurement of energy supply resulting from lower average prices.
- The decrease at NSTAR Electric was due primarily to lower expense related to the procurement of energy supply resulting from lower average supply-related sales volumes, partially offset by higher net metering costs.
- The decrease at PSNH was due primarily to lower stranded costs resulting from higher Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are credited back to customers. The higher RGGI proceeds resulted from an increase in RGGI auction clearing prices for allowances in 2021 as 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 increase in transmission costs at CL&P was due primarily to an increase in costs billed by ISO-NE that support regional grid investments. This was partially offset by a decrease resulting from the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers, and a decrease in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network.
- The increase in transmission costs at NSTAR Electric and PSNH was due primarily to an increase in costs billed by ISO-NE, an increase resulting from the retail transmission cost deferral, and an increase in costs billed by ISO-NE that support regional grid 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 in 2021, as compared to 2020, due primarily to the following:

| (Millions of Dollars) Base Electric Distribution (Non-Tracked Costs): | CL&P | NSTAR Electric | PSNH |
| --- | ---: | ---: | ---: |
| 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 |

**Depreciation** expense increased in 2021, as compared to 2020, for CL&P, NSTAR Electric and PSNH due to higher net plant in service balances. The increase at PSNH was also due to new depreciation rates effective January 1, 2021 resulting from the 2020 distribution rate settlement agreement.

**Amortization of Regulatory Assets, Net** expense includes the deferral of energy supply, energy-related costs and other costs that are included in certain regulatory-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates. Amortization of Regulatory Assets, Net increased/decreased in 2021, as compared to 2020, due primarily to the following:

- The increase at CL&P was due primarily to the deferral adjustment of 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 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 was due to the deferral adjustment of 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.

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

- The decrease at CL&P was due to the deferral adjustment, which reflects actual costs of energy efficiency programs compared to the estimated amounts billed to customers, and the timing of 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 the estimated amounts billed to customers, and the timing of the recovery of energy efficiency costs.

**Taxes Other Than Income Taxes** increased in 2021, as compared to 2020, due primarily to the following:

- The increase at CL&P was related to higher property taxes as a result of a higher utility plant balance and higher gross earnings taxes.
- The increases at NSTAR Electric and PSNH were due to higher property taxes as a result of higher utility plant balances.

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

- The increase at CL&P was due primarily to higher interest on long-term debt ($5.4 million), an increase in interest expense on regulatory deferrals ($3.7 million), a decrease in AFUDC related to debt funds ($3.7 million), and higher amortization of debt discounts and premiums, net ($0.9 million).
- The increase at NSTAR Electric was due primarily to an increase in interest expense on regulatory deferrals ($7.6 million), higher interest on long-term debt ($6.0 million), and higher amortization of debt discounts and premiums, net ($0.4 million).
- The decrease at PSNH was due primarily to a decrease in RRB interest expense ($1.3 million), lower amortization of debt discounts and premiums, net ($0.7 million), and lower interest on long-term debt ($0.5 million), partially offset by a decrease in AFUDC related to debt funds ($1.3 million) and an increase in interest expense on regulatory deferrals ($0.4 million).

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

- The increase at CL&P was due primarily to an increase related to pension, SERP and PBOP non-service income components ($11.4 million), higher interest income ($3.9 million), and an increase in investment income ($0.2 million), partially offset by a decrease in AFUDC related to equity funds ($6.1 million).
- The increase at NSTAR Electric was due primarily to higher interest income ($12.5 million) and an increase related to pension, SERP and PBOP non-service income components ($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 2021, as compared to 2020, due primarily to the following:

- The decrease at CL&P was due primarily to the CL&P settlement agreement ($17.5 million), a decrease in valuation allowance ($17.0 million), and a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($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 an increase in amortization of EDIT ($22.8 million), partially offset by higher pre-tax earnings ($3.2 million), higher state taxes ($1.4 million), an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.8 million), and lower share-based payment excess tax benefits ($0.9 million).
- The increase at PSNH was due primarily to a decrease in amortization of EDIT ($4.9 million), higher state taxes ($0.4 million), higher pre-tax earnings ($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 ($0.2 million).

### EARNINGS SUMMARY

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

NSTAR Electric's earnings increased $31.6 million in 2021, as compared to 2020, due primarily to an increase in transmission earnings driven by a higher transmission rate base, the base distribution rate increase effective January 1, 2021, a lower effective tax rate, and 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.

PSNH's earnings 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 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.

### LIQUIDITY

*Cash Flows:* CL&P had cash flows provided by operating activities of $612.9 million in 2021, as compared to $397.1 million in 2020. The increase in operating cash flows was due primarily to the timing of collections for regulatory 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 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 $700.9 million in 2021, as compared to $525.8 million in 2020. The increase in operating cash flows was due primarily to the timing of collections for regulatory tracking mechanisms, the timing of other working capital items, a $36.5 million decrease in income tax payments made in 2021, as compared to 2020, the timing of cash collections on our accounts receivable, and the timing of cash payments made on our accounts payable. These favorable impacts were partially offset by a $29.4 million increase in pension contributions made in 2021, as compared to 2020, and a $19.8 million increase in cost of removal expenditures.

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

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

## Market risk

As filed, 4,985 characters.

### Market Risk Information

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

### Other Risk Management Activities

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

*Interest Rate Risk Management:* We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As of December 31, 2021, approximately 98 percent of our long-term debt was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rates, annual interest expense would have increased by a pre-tax amount of $3.5 million.

*Credit Risk Management:* Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural gas and electric utilities, oil and natural gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of December 31, 2021, our regulated companies held collateral (letters of credit or cash) of $210.9 million from counterparties related to our standard service contracts. As of December 31, 2021, Eversource had $34.6 million of cash posted with ISO-NE related to energy transactions. For further information on cash collateral deposited and posted with counterparties, see Note 1O, "Summary of Significant Accounting Policies - Supplemental Cash Flow Information," to the financial statements.

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

## Controls and procedures

As filed, 3,586 characters.

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

Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for establishing and maintaining adequate internal controls over financial reporting. The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established in *Internal Control - Integrated Framework* (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at Eversource, CL&P, NSTAR Electric and PSNH were effective as of December 31, 2021.

Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, evaluated the design and operation of the disclosure controls and procedures as of December 31, 2021 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officer and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of Eversource, CL&P, NSTAR Electric and PSNH are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for Eversource, CL&P, NSTAR Electric and PSNH during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

Filed Feb 17, 2022.
Source: SEC EDGAR, the filing index for accession 0000072741-22-000015. Last ingested by Listed: Nov 6, 2026, 14:09 ET. No prices; not investment advice.