EVERSOURCE ENERGY (ES) FY 2021 MD&A

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

EVERSOURCE ENERGY AND SUBSIDIARIES

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K.  References in this combined Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries.  All per-share amounts are reported on a diluted basis.  The consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements."  Our discussion of fiscal year 2021 compared to fiscal year 2020 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2019 items and of fiscal year 2020 compared to fiscal year 2019, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2020 Annual Report on Form 10-K, which is incorporated herein by reference.

Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities of such business, but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP (non-GAAP) that is calculated by dividing the Net Income Attributable to Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period. Our earnings discussion also includes non-GAAP financial measures referencing our 2021 earnings and EPS excluding charges at CL&P related to a settlement agreement that included credits to customers and funding of various customer assistance initiatives and a storm performance penalty imposed on CL&P by the PURA and our 2021 and 2020 earnings and EPS excluding certain acquisition and transition costs.

We use 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.

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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.

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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:

(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.

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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.

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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:

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.

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

(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.

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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:

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:

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:

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:

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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:

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.

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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:

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:

(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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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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:

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.

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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.

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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.

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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:

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:

(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.

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

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:

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.

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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:

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.

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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:

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).

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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).

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RESULTS OF OPERATIONS –

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

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

Operating Revenues

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

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.

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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:

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:

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.

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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:

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.

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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.

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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.