NSTAR ELECTRIC CO Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

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 2022 compared to fiscal year 2021 is included herein. Unless
expressly stated otherwise, for discussion and analysis of fiscal year 2020
items and of fiscal year 2021 compared to fiscal year 2020, please refer to Item
7, Management's Discussion and Analysis of Financial Condition and Results of
Operations, in our combined 2021   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 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 that is not recognized under GAAP (non-GAAP) and
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 earnings and EPS excluding certain
transaction and transition costs, and our 2021 earnings and EPS excluding
charges at CL&P related to an October 2021 settlement agreement that included
credits to customers and funding of various customer assistance initiatives and
a 2021 storm performance penalty imposed on CL&P by PURA.

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 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 transaction and transition costs, the
CL&P October 2021 settlement agreement, and the 2021 storm performance penalty
imposed on CL&P by PURA, 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 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 $1.40 billion, or $4.05 per share, in 2022, compared with $1.22 billion, or $3.54 per share, in 2021.

•Our results include after-tax transaction and transition costs recorded at
Eversource parent of $15.0 million, or $0.04 per share, in 2022, compared with
$23.6 million, or $0.07 per share, in 2021. Our 2021 results also include
after-tax charges of $86.1 million, or $0.25 per share, resulting from a
PURA-approved CL&P settlement agreement and a PURA assessment as a result of
CL&P's preparation for, and response to, Tropical Storm Isaias in August 2020,
which were recorded within the electric distribution segment. Excluding these
costs, our non-GAAP earnings were $1.42 billion, or $4.09 per share, in 2022,
compared with $1.33 billion, or $3.86 per share, in 2021.

•We project that we will earn within a 2023 non-GAAP earning guidance range of
between $4.25 per share and $4.43 per share, which excludes the potential impact
of the strategic review of our offshore wind investment portfolio. We also
project that our long-term EPS growth rate through 2027 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 $2.40 billion in 2022, compared with $1.96 billion in 2021. Investments in property, plant and equipment totaled $3.44 billion in 2022 and $3.18 billion in 2021.

•Cash and Cash Equivalents totaled $374.6 million as of December 31, 2022,
compared with $66.8 million as of December 31, 2021.  Our available borrowing
capacity under our commercial paper programs totaled $1.21 billion as of
December 31, 2022.

•In 2022, we issued $4.05 billion of new long-term debt and we repaid $1.18 billion of long-term debt.

•In 2022, we issued 2,165,671 common shares, which resulted in proceeds of $197.1 million, net of issuance costs.

•In 2022, we paid dividends totaling $2.55 per common share, compared with
dividends of $2.41 per common share in 2021. Our quarterly common share dividend
payment was $0.6375 per share in 2022, as compared to $0.6025 per share in
2021.  On February 1, 2023, our Board of Trustees approved a common share
dividend payment of $0.675 per share, payable on March 31, 2023 to shareholders
of record as of March 2, 2023.

•We project to make capital expenditures of $21.52 billion from 2023 through
2027, of which we expect $8.86 billion to be in our electric distribution
segment, $5.25 billion to be in our natural gas distribution segment, $5.29
billion to be in our electric transmission segment, and $1.02 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
$1.9 billion and $2.1 billion in 2023 and expect to make investments for our
three projects in total between $1.6 billion and $1.9 billion from 2024 through
2026. These estimates assume that the three projects are completed and are
in-service by the end of 2025, as planned. These projected investments could be
impacted by the strategic review of our offshore wind investment.

Strategic and Regulatory Transactions and Developments:

•On May 4, 2022, we announced that we had initiated a strategic review of our
offshore wind investment portfolio. As part of that review, we are exploring
strategic alternatives that could result in a potential sale of all, or part, of
our 50 percent interest in our offshore wind partnership with Ørsted. We
continue to work with interested parties through this ongoing process and expect
to complete this review in the second quarter of 2023.

•On November 30, 2022, the DPU issued its decision in the NSTAR Electric
distribution rate case and approved a base distribution rate increase of
$64 million effective January 1, 2023. The DPU approved a renewal of the
performance-based ratemaking (PBR) plan originally authorized in its previous
rate case for a five-year term, with a corresponding stay out provision. The PBR
plan term has the possibility of a five-year extension. The PBR mechanism allows
for an annual adjustment to base distribution rates for inflation and exogenous
events. The DPU also allowed for adjustments to the PBR mechanism for the
recovery of future capital additions based on a historical five-year average of
total capital additions, beginning with the January 1, 2024 PBR adjustment. The
decision allows an authorized regulatory ROE of 9.80 percent on a capital
structure including 53.2 percent equity.

Earnings Overview

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

                                                                            

For the Years Ended December 31,

                                                        2022                                   2021                                   2020
(Millions of Dollars, Except Per Share
Amounts)                                     Amount            Per Share            Amount            Per Share            Amount            Per Share
Net Income Attributable to Common
Shareholders (GAAP)                       $ 1,404.9          $     4.05

$ 1,220.5 $ 3.54 $ 1,205.2 $ 3.55

Regulated Companies (Non-GAAP)            $ 1,460.4          $     4.21

$ 1,342.4 $ 3.89 $ 1,223.3 $ 3.60 Eversource Parent and Other Companies (Non-GAAP)

                                    (40.5)              (0.12)             (12.2)              (0.03)              14.0                0.04
Non-GAAP Earnings                         $ 1,419.9          $     4.09

$ 1,330.2 $ 3.86 $ 1,237.3 $ 3.64 CL&P Settlement Impacts (after-tax) (1)

           -                   -              (86.1)              (0.25)                 -                   -
Transaction and Transition Costs
(after-tax) (2)                               (15.0)              (0.04)             (23.6)              (0.07)             (32.1)              (0.09)
Net Income Attributable to Common
Shareholders (GAAP)                       $ 1,404.9          $     4.05          $ 1,220.5          $     3.54          $ 1,205.2          $     3.55



(1)  The 2021 after-tax costs are associated with the October 1, 2021 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 pre-tax charge to earnings to establish a fund that
provided bill payment assistance to certain existing non-hardship and hardship
customers carrying arrearages. The 2021 after-tax costs also include a charge
recorded at CL&P as a result of PURA's April 28, 2021 and July 14, 2021
decisions, which included a pre-tax $28.4 million penalty for storm performance
results provided as credits to customer bills over a one-year period that began
September 1, 2021 and a pre-tax $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
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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 after-tax costs are for the transition of systems as a result of our
purchase of the assets of Columbia Gas of Massachusetts (CMA) on October 9, 2020
and integrating the CMA assets onto Eversource's systems. The after-tax costs
also include costs associated with our water business acquisitions and the
strategic review of our offshore wind investment portfolio. We expect
transaction costs in 2023 as a result of the wind strategic review.

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

                                                                                        For the Years Ended December 31,
                                                               2022                                   2021                                   2020
(Millions of Dollars, Except Per Share Amounts)     Amount            Per Share            Amount            Per Share            Amount            

Per Share Net Income - Regulated Companies (GAAP) $ 1,460.4 $ 4.21 $ 1,256.3 $ 3.64 $ 1,221.8 $

3.60

Electric Distribution, excluding CL&P Settlement
Impacts
  (Non-GAAP)                                     $   592.8          $     1.71          $   556.2          $     1.61          $   544.0          $     1.60
Electric Transmission                                596.6                1.72              544.6                1.58              502.5                1.48
Natural Gas Distribution, excluding
Transaction-Related Costs
 (Non-GAAP)                                          234.2                0.67              204.8                0.59              135.6                0.40
Water Distribution                                    36.8                0.11               36.8                0.11               41.2                0.12

Net Income - Regulated Companies (Non-GAAP) $ 1,460.4 $ 4.21 $ 1,342.4 $ 3.89 $ 1,223.3 $

3.60

CL&P Settlement Impacts (after-tax)                      -                   -              (86.1)              (0.25)                 -                

-

Transaction and Transition Costs (after-tax)             -                   -                  -                   -               (1.5)               

-

Net Income - Regulated Companies (GAAP) $ 1,460.4 $ 4.21 $ 1,256.3 $ 3.64 $ 1,221.8 $

     3.60



Our electric distribution segment earnings increased $122.7 million in 2022, as
compared to 2021, due primarily to the absence in 2022 of CL&P's October 1, 2021
settlement agreement that resulted in a $75 million pre-tax charge to earnings
and a $28.6 million pre-tax charge to earnings at CL&P for a 2021 storm
performance penalty imposed by PURA as a result of CL&P's preparation for, and
response to, Tropical Storm Isaias. The after-tax impact of the CL&P settlement
agreement and CL&P storm performance penalty imposed by PURA was $86.1 million,
or $0.25 per share. Excluding those 2021 charges, electric distribution segment
earnings increased $36.6 million due primarily to a base distribution rate
increase at NSTAR Electric effective January 1, 2022, higher earnings from
CL&P's capital tracking mechanism due to increased electric system improvements,
lower pension plan expense in Connecticut and New Hampshire, and an increase in
interest income primarily on regulatory deferrals. Those earnings increases were
partially offset by higher operations and maintenance expense driven primarily
by higher shared corporate costs resulting from the implementation of new
information technology systems, higher storm costs, a $10 million pre-tax charge
to earnings as a result of CL&P's commitment to contribute to an energy
assistance program as part of its 2022 rate relief plan, and higher insurance
reserves. Earnings were also unfavorably impacted by higher depreciation
expense, higher property and other tax expense, and higher interest expense.

Our electric transmission segment earnings increased $52.0 million in 2022, as
compared to 2021, due primarily to a higher transmission rate base as a result
of our continued investment in our transmission infrastructure, partially offset
by a higher effective income tax rate and higher interest expense on short-term
debt.

Our natural gas distribution segment earnings increased $29.4 million in 2022,
as compared to 2021, due primarily to base distribution rate increases effective
November 1, 2021 and November 1, 2022 at each of EGMA and NSTAR Gas, higher
earnings from capital tracking mechanisms due to continued investments in
natural gas infrastructure, and lower pension plan expense at Yankee Gas. Those
earnings increases were partially offset by higher operations and maintenance
expense, higher property tax expense, higher interest expense, and higher
depreciation expense.

Our water distribution segment earnings were flat in 2022, as compared to 2021.

Eversource Parent and Other Companies:  Eversource parent and other companies'
losses increased $19.7 million in 2022, as compared to 2021, due primarily to
higher interest expense and a higher effective tax rate, partially offset by
higher unrealized gains associated with our equity method investment in a
renewable energy fund and an after-tax decrease of $8.6 million in transition
costs associated with EGMA integration and transaction costs in 2022, as
compared to 2021.

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Liquidity

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

Eversource, CL&P, NSTAR Electric and PSNH each uses its available capital
resources to fund its respective construction expenditures, meet debt
requirements, pay operating costs, including storm-related costs, pay dividends,
and fund other corporate obligations, such as pension contributions.
Eversource's regulated companies recover their electric, natural gas and water
distribution construction expenditures as the related project costs are
depreciated over the life of the assets. This impacts the timing of the revenue
stream designed to fully recover the total investment plus a return on the
equity and debt used to finance the investments. Eversource's regulated
companies spend a significant amount of cash on capital improvements and
construction projects that have a long-term return on investment and recovery
period. In addition, Eversource uses its capital resources to fund investments
in its offshore wind business, which are recognized as long-term assets. These
factors have resulted in current liabilities exceeding current assets by
$2.58 billion, $168.6 million, and $330.0 million at Eversource, CL&P, and PSNH,
respectively, as of December 31, 2022.

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.

As of December 31, 2022, $2.01 billion of Eversource's long-term debt, including
$1.20 billion at Eversource parent, $400.0 million at CL&P, $80.0 million at
NSTAR Electric, and $325.0 million at PSNH, matures within the next 12 months.
CL&P repaid this long-term debt at maturity in January 2023. 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.

Cash and Cash Equivalents totaled $374.6 million as of December 31, 2022, compared with $66.8 million as of December 31, 2021.

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, 2027. 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, 2027. This revolving credit facility serves to
backstop NSTAR Electric's $650 million commercial paper program.

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

                                       Borrowings Outstanding                Available Borrowing Capacity            Weighted-Average Interest Rate as of
                                          as of December 31,                      as of December 31,                             December 31,
(Millions of Dollars)                  2022                  2021               2022               2021                   2022                      2021
Eversource Parent Commercial
Paper Program                   $    1,442.2             $ 1,343.0          $    557.8          $ 657.0                          4.63  %              0.31  %
NSTAR Electric Commercial Paper
Program                                    -                 162.5               650.0            487.5                             -  %              0.14  %

There were no borrowings outstanding on the revolving credit facilities as of December 31, 2022 or 2021.

CL&P and PSNH have uncommitted line of credit agreements totaling $450 million
and $300 million, respectively, which will expire on May 12, 2023. There are no
borrowings outstanding on either the CL&P or PSNH uncommitted line of credit
agreements as of December 31, 2022.

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, 2022, there were intercompany
loans from Eversource parent to PSNH of $173.3 million. As of December 31, 2021,
there were intercompany loans from Eversource parent to PSNH of $110.6 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.

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Availability under Long-Term Debt Issuance Authorizations: On December 14, 2022,
the NHPUC approved PSNH's request for authorization to issue up to $600 million
in long-term debt through December 31, 2023. On November 30, 2022, the PURA
approved CL&P's request for authorization to issue up to $1.15 billion in
long-term debt through December 31, 2024. On June 14, 2022, the DPU approved
NSTAR Gas' request for authorization to issue up to $325 million in long-term
debt through December 31, 2024. The remaining Eversource operating companies,
including NSTAR Electric, have utilized the long-term debt authorizations in
place with the respective regulatory commissions.

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

                                                            Issuance/            Issue Date or                                    Use of Proceeds for Issuance/
(Millions of Dollars)             Interest Rate            (Repayment)           Repayment Date           Maturity Date               Repayment Information
                                                                                                                                 Repaid 2013 Series A Bonds at
                                                                                                                                 maturity and short-term debt,
CL&P 2023 Series A First                                                                                                         and paid capital expenditures
Mortgage Bonds                             5.25  %       $      500.0             January 2023             January 2053          and working capital
CL&P 2013 Series A First
Mortgage Bonds                             2.50  %             (400.0)            January 2023             January 2023          Paid at maturity
                                                                                                                                 Repaid short-term debt, paid
                                                                                                                                 capital expenditures and
NSTAR Electric 2022 Debentures             4.55  %              450.0               May 2022                June 2052            working capital
                                                                                                                                 Refinanced investments in
                                                                                                                                 eligible green expenditures,
                                                                                                                                 which were previously financed
                                                                                                                                 using short-term debt from
                                                                                                                                 October 1, 2020 through June
NSTAR Electric 2022 Debentures             4.95  %              400.0            September 2022           September 2052         30, 2022
NSTAR Electric 2012 Debentures            2.375  %             (400.0)            October 2022             October 2022          Paid at maturity
                                                                                                                                 Repaid short-term debt, paid
PSNH Series W First Mortgage                                                                                                     capital expenditures and
Bonds                                      5.15  %              300.0             January 2023             January 2053          working capital
Eversource Parent Series V                                                                                                       Repaid Series K Senior Notes at
Senior Notes                               2.90  %              650.0            February 2022              March 2027           maturity and short-term debt
Eversource Parent Series W                                                                                                       Repaid Series K Senior Notes at
Senior Notes                              3.375  %              650.0            February 2022              March 2032           maturity and short-term debt
Eversource Parent Series X                                                                                                       Repaid short-term debt and paid
Senior Notes                               4.20  %              900.0              June 2022                June 2024            working capital
Eversource Parent Series Y                                                                                                       Repaid short-term debt and paid
Senior Notes                               4.60  %              600.0              June 2022                July 2027            working capital
Eversource Parent Series K
Senior Notes                               2.75  %             (750.0)             March 2022               March 2022           Paid at maturity
Yankee Gas Series B First
Mortgage Bonds                             8.48  %              (20.0)             March 2022               March 2022           Paid at maturity
                                                                                                                                 Repaid short-term debt, paid
Yankee Gas Series U First                                                                                                        capital expenditures and for
Mortgage Bonds                             4.31  %              100.0            September 2022           September 2032         general corporate purposes
                                                                                                                                 Repaid short-term debt, paid
EGMA Series C First Mortgage                                                                                                     capital expenditures and for
Bonds                                      4.70  %              100.0              June 2022                June 2052            general corporate purposes
                                                                                                                                 Repaid short-term debt, paid
NSTAR Gas Series V First                                                                                                         capital expenditures and for
Mortgage Bonds                             4.40  %              125.0              July 2022               August 2032           general corporate purposes
Aquarion Water Company of New
Hampshire General Mortgage
Bonds                                      4.45  %               (5.0)             July 2022                July 2022            Paid at maturity
Aquarion Water Company of
Connecticut Senior Notes                   4.69  %               70.0             August 2022             September 2052         Repaid short-term debt



As a result of the CL&P and PSNH long-term debt issuances in January 2023, $400
million and $295.3 million, respectively, of current portion of long-term debt
were reclassified as Long-Term Debt on CL&P's and PSNH's balance sheets as of
December 31, 2022.

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
$17.6 million of interest payments in 2022, and paid $43.2 million of RRB
principal payments and $18.9 million of interest payments in 2021.

Common Share Issuances and 2022 Equity Distribution Agreement: On May 11, 2022,
Eversource entered into an equity distribution agreement pursuant to which it
may offer and sell up to $1.2 billion of its common shares from time to time
through an "at-the-market" (ATM) equity offering program. Eversource may issue
and sell its common shares through its sales agents during the term of this
agreement. Shares may be offered in transactions on the New York Stock Exchange,
in the over-the-counter market, through negotiated transactions or otherwise.
Sales may be made at either market prices prevailing at the time of sale, at
prices related to such prevailing market prices or at negotiated prices. In
2022, Eversource issued 2,165,671 common shares, which resulted in proceeds of
$197.1 million, net of issuance costs. Eversource used the net proceeds received
for general corporate purposes.

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 $2.40 billion
in 2022, compared with $1.96 billion in 2021. Changes in Eversource's cash flows
from operations were generally consistent with changes in its results of
operations, after adjustment for non-cash items and as adjusted by changes in
working capital in the normal course of business. Operating cash flows were
favorably impacted by the timing of cash payments made on our accounts payable,
an increase in regulatory over-recoveries driven by the timing of collections
for the non-bypassable FMCC at CL&P and other regulatory tracking mechanisms, a
decrease of $99.2 million in pension and PBOP contributions made in 2022, as
compared to 2021, and a $43.7 million decrease in income tax payments made in
2022, as compared to 2021. The impact of regulatory collections are included in
both Regulatory Over/Under Recoveries and Amortization on the statements of cash
flows. These favorable impacts were partially
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offset by the timing of cash collections on our accounts receivable, $78.4
million of payments in 2022 related to withheld property taxes at our
Massachusetts companies, primarily at NSTAR Electric, $72.0 million of customer
credits distributed to CL&P's customers in 2022 as a result of the October 2021
settlement agreement and the 2021 storm performance penalty for CL&P's response
to Tropical Storm Isaias, a $61.6 million increase in cost of removal
expenditures, and an increase of $34.0 million in cash payments for storm costs
at NSTAR Electric.

In 2022, we paid cash dividends of $860.0 million and issued non-cash dividends
of $23.1 million in the form of treasury shares, totaling dividends of $883.1
million, or $2.55 per common share. 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. Our
quarterly common share dividend payment was $0.6375 per share in 2022, as
compared to $0.6025 per share in 2021.  On February 1, 2023, our Board of
Trustees approved a common share dividend payment of $0.675 per share, payable
on March 31, 2023 to shareholders of record as of March 2, 2023.

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

In 2022, CL&P, NSTAR Electric and PSNH paid $292.4 million, $287.6 million and $104.0 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 income/expense.  In 2022, investments for
Eversource, CL&P, NSTAR Electric, and PSNH were $3.44 billion, $876.7 million,
$954.3 million and $485.6 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, 2022 and are as
follows:
(Millions of Dollars)     2023         2024         2025         2026         2027        Thereafter        Total
Eversource              $ 722.6      $ 654.7      $ 589.6      $ 559.7      $ 517.3      $  5,864.4      $ 8,908.3
CL&P                      154.7        149.7        138.6        135.6        127.6         1,657.2        2,363.4



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. The future funding and
guarantee obligations associated with our offshore wind investment could be
impacted by the strategic review of our offshore wind investment.

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

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

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



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

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



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Impact of COVID-19

The financial impacts of COVID-19 as it relates to our businesses primarily relate to collectability of customer receivables and the outcome of future proceedings before our state regulatory commissions to recover our incremental uncollectible customer receivable costs associated with COVID-19.

As of December 31, 2022, our allowance for uncollectible customer receivable
balance of $486.3 million, of which $284.4 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. As
of December 31, 2022 and 2021, the total amount incurred as a result of COVID-19
included in the allowance for uncollectible accounts was $50.9 million and
$55.3 million at Eversource, $16.0 million and $23.9 million at CL&P, and
$4.1 million and $9.0 million at NSTAR Electric, respectively. At our
Connecticut and Massachusetts utilities, the COVID-19 related uncollectible
amounts were deferred either as incremental regulatory costs 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. No COVID-19 related uncollectible
amounts were deferred at PSNH as a result of a July 2021 NHPUC order. Based on
the status of our COVID-19 regulatory dockets, policies and practices in the
jurisdictions in which we operate, we believe the state regulatory commissions
in Connecticut and Massachusetts will allow us to recover our incremental
uncollectible customer receivable costs associated with COVID-19.

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 income/expense (all of which are non-cash factors), totaled $3.79 billion
in 2022, $3.54 billion in 2021, and $3.06 billion in 2020.  These amounts
included $266.5 million in 2022, $238.0 million in 2021, and $239.1 million in
2020 related to information technology and facilities upgrades and enhancements,
primarily at Eversource Service and The Rocky River Realty Company.

Electric Transmission Business: Our consolidated electric transmission business
capital expenditures increased by $91.7 million in 2022, as compared to 2021.  A
summary of electric transmission capital expenditures by company is as follows:


                                               For the Years Ended December 31,
(Millions of Dollars)                          2022                2021          2020
CL&P                                  $       416.8             $   400.0      $ 402.9
NSTAR Electric                                438.4                 480.3        366.8
PSNH                                          351.8                 235.0        193.9
Total Electric Transmission Segment   $     1,207.0             $ 1,115.3

$ 963.6

Our transmission projects are designed to improve the reliability of the
electric grid, meet customer demand for power and increases in electrification
of municipal infrastructure, strengthen the electric grid's resilience against
extreme weather and other safety and security threats, and enable integration of
increasing amounts of clean power generation from renewable sources, such as
solar, battery storage, and offshore wind. In Connecticut, Massachusetts and New
Hampshire, our transmission projects include transmission line upgrades, the
installation of new transmission interconnection facilities, substations and
lines, and transmission 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 fourth quarter of
2023. Construction on the last remaining upgrade, the Sudbury-Hudson Reliability
Project, commenced in the fourth quarter of 2022. We spent $71.9 million during
2022 and we expect to make additional capital expenditures of approximately $115
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 $23.2 million during 2022 and we expect to make
additional capital expenditures of approximately $110 million on these
transmission upgrades.

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

                                                                         

For the Years Ended December 31,

                                                 NSTAR                               Total
(Millions of Dollars)          CL&P            Electric            PSNH            Electric             Natural Gas           Water              Total
2022
Basic Business              $ 267.8          $   202.4          $  68.6          $    538.8          $       175.2          $  16.8          $   730.8
Aging Infrastructure          199.9              245.1             70.8               515.8                  562.3            137.6            1,215.7
Load Growth and Other          90.7              177.0             31.3               299.0                   66.4              0.9              366.3

Total Distribution          $ 558.4          $   624.5          $ 170.7          $  1,353.6          $       803.9          $ 155.3          $ 2,312.8

2021
Basic Business              $ 256.2          $   179.9          $  56.0          $    492.1          $       206.1          $  16.5          $   714.7
Aging Infrastructure          178.0              219.1             67.7               464.8                  509.6            127.1            1,101.5
Load Growth and Other          80.2              169.9             37.1               287.2                   83.3              0.6              371.1

Total Distribution          $ 514.4          $   568.9          $ 160.8          $  1,244.1          $       799.0          $ 144.2          $ 2,187.3

2020
Basic Business              $ 233.4          $   195.1          $  52.4          $    480.9          $        88.2          $  10.9          $   580.0
Aging Infrastructure          179.9              237.1             80.2               497.2                  391.3            115.5            1,004.0
Load Growth and Other          77.8              112.2             21.3               211.3                   65.6              0.8              277.7

Total Distribution          $ 491.1          $   544.4          $ 153.9          $  1,189.4          $       545.1          $ 127.2          $ 1,861.7



For the electric distribution business, basic business includes the purchase of
meters, tools, vehicles, information technology, transformer replacements,
equipment facilities, and the relocation of plant. Aging infrastructure relates
to reliability and the replacement of overhead lines, plant substations,
underground cable replacement, and equipment failures. Load growth and other
includes requests for new business and capacity additions on distribution lines
and substation additions and expansions.

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

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

Projected Capital Expenditures:  A summary of the projected capital expenditures
for the regulated companies' electric transmission and for the total electric
distribution, natural gas distribution and water distribution for 2023 through
2027, including information technology and facilities upgrades and enhancements
on behalf of the regulated companies, is as follows:

                                                                                 Years
                                                                                                                          2023 - 2027
(Millions of Dollars)                2023             2024             2025             2026              2027               Total
CL&P Transmission                 $   406          $   312          $   324          $    263          $    136          $    1,441
NSTAR Electric Transmission           461              527              436               575               748               2,747
PSNH Transmission                     329              270              252               174                72               1,097
 Total Electric Transmission      $ 1,196          $ 1,109          $ 1,012          $  1,012          $    956          $    5,285
Electric Distribution             $ 1,847          $ 1,750          $ 1,768          $  1,870          $  1,628          $    8,863
Natural Gas Distribution            1,035            1,038            1,146             1,115               918               5,252
 Total Electric and Natural Gas
Distribution                      $ 2,882          $ 2,788          $ 2,914

$ 2,985 $ 2,546 $ 14,115 Water Distribution

$   170          $   194          $   203          $    218          $    235          $    1,020
Information Technology and All
Other                             $   215          $   213          $   244          $    219          $    208          $    1,099
Total                             $ 4,463          $ 4,304          $ 4,373          $  4,434          $  3,945          $   21,519

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 The Torrington Water Company: On October 3, 2022, Aquarion acquired The Torrington Water Company (TWC) following the receipt of all required approvals. The acquisition was structured as a stock-for-stock exchange, and Eversource issued 925,264 treasury shares at closing for a purchase price of $72.1 million. TWC provides regulated water service to approximately 10,100 customers in Connecticut.

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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 an
undeveloped offshore lease area. Our offshore wind projects are being developed
and constructed through a joint and equal partnership with Ørsted.

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.

As of December 31, 2022 and 2021, Eversource's total equity investment balance
in its offshore wind business was $1.95 billion and $1.21 billion, 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.

Strategic Review of Offshore Wind Investments: On May 4, 2022, we announced that
we had initiated a strategic review of our offshore wind investment portfolio.
As part of that review, we are exploring strategic alternatives that could
result in a potential sale of all, or part, of our 50 percent interest in our
offshore wind partnership with Ørsted. In late July, we started preliminary and
targeted outreach to interested parties. We continue to work with interested
parties through this ongoing process and expect to complete this review in the
second quarter of 2023. If the recommended path forward following the strategic
review is a sale of all, or part, of our interest in the partnership, we expect
potential proceeds from such transaction would likely be used to support our
regulated investments in strengthening, modernizing and decarbonizing our
regulated energy and water delivery systems. We currently believe that the fair
market value of our offshore wind investment is greater than the carrying value;
however, there could be changes in market conditions that would impact our
ability to sell this investment or realize a value in excess of our carrying
value. As the strategic review proceeds, we remain committed to continue
providing oversight of the siting and construction of onshore elements of our
South Fork Wind, Revolution Wind and Sunrise Wind offshore wind projects.

Contracts, Permitting and Construction of Offshore Wind Projects: The following
table provides a summary of the Eversource and Ørsted major projects with
announced contracts:

     Wind Project           State Servicing        Size (MW)    Term (Years)     Price per MWh             Pricing Terms            Contract Status
                                                                                                   Fixed price contract; no price
   Revolution Wind            Rhode Island            400            20              $98.43                  escalation                 Approved
                                                                                                     Fixed price contracts; no
   Revolution Wind            Connecticut             304            20         $98.43 - $99.50           price escalation              Approved
                                                                                                      2 percent average price
   South Fork Wind          New York (LIPA)            90            20             $160.33                  escalation                 Approved
                                                                                                      2 percent average price
   South Fork Wind          New York (LIPA)            40            20              $86.25                  escalation                 Approved
                                                                                                   Fixed price contract; no price
     Sunrise Wind          New York (NYSERDA)         924            25           $110.37 (1)                escalation                 Approved



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

Revolution Wind and Sunrise 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.

Revolution Wind and Sunrise Wind filed their COP applications with BOEM in March
2020 and September 2020, respectively. BOEM released its Draft EIS on September
2, 2022 for the Revolution Wind project and on December 16, 2022 for the Sunrise
Wind project. The Draft EIS analyzes the potential environmental impacts of the
project and the alternatives to the project to be evaluated as part of the
process. Each of the identified alternative configurations in the Draft EISs had
a similar level of environmental impacts, and if an alternative configuration
was selected, the Revolution Wind project and the Sunrise Wind project would
each still meet their respective contractual output requirements. For Revolution
Wind, a final EIS is expected in the second quarter of 2023, the Record of
Decision in the third quarter of 2023, and final approval is expected in the
fourth quarter of 2023. For Sunrise Wind, a final EIS and Record of Decision are
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.

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State and Local Siting and Permitting Process: State permitting applications in
Rhode Island for Revolution Wind and in New York for Sunrise Wind were filed in
December 2020. On July 8, 2022, the Rhode Island Energy Facilities Siting Board
issued a Final Decision and Order approving the Revolution Wind project and
granting a license to construct and operate. On September 23, 2022, Sunrise Wind
filed a Joint Proposal to the New York State Public Service Commission. Among
other things, the Joint Proposal includes proposed mitigation for certain
environmental, community and construction impacts associated with constructing
the project. The Joint Proposal was signed by the New York Departments of Public
Service, Environmental Conservation, Transportation and State as well as the
Office of Agriculture and Markets and the Long Island Commercial Fisheries
Association. On November 17, 2022, the New York Public Service Commission
approved an order adopting the Joint Proposal and granting a Certificate of
Environmental Compatibility and Public Need. On November 18, 2022, Sunrise 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 several of the reviewing agencies and parties have been received
and Sunrise Wind is in the process of reviewing and addressing those comments in
the plan.

On November 9, 2022, the Towns of Brookhaven and Suffolk County executed the
easements and other real estate rights necessary to construct the Sunrise Wind
project. On November 28, 2022, the Town of North Kingstown and the Quonset
Development Corporation approved Revolution Wind's real estate PILOT terms and
the personal property PILOT agreement necessary to construct the Revolution Wind
project.

Construction Process: South Fork Wind received all required approvals to start
construction and the project entered the construction phase in early 2022.
Onshore activities for the project's underground onshore transmission line and
construction of the onshore interconnection facility located in East Hampton,
New York are underway. Offshore activities began in the fourth quarter of 2022
with construction of the sea-to-shore conduit system. Other marine construction
activities, including the project's monopile foundations, 11-megawatt wind
turbines, cable installation, and offshore substation, are 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 and federal agency approvals, however
it believes it is probable it will be able to overcome these challenges.

For Revolution Wind and Sunrise Wind, construction is expected to begin in the
second half of 2023 once all necessary federal, state and local approvals are
received.

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.

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 underway. Construction-related
purchase agreements with third-party contractors and materials contracts have
largely been 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 $1.9
billion and $2.1 billion in 2023 and expect to make investments for our three
projects in total between $1.6 billion and $1.9 billion from 2024 through 2026.
These estimates assume that the three projects are completed and are in-service
by the end of 2025, as planned. These projected investments could be impacted by
the strategic review of our offshore wind investment.

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, FERC
issued Opinion No. 531-A and 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, 2022 and 2021.
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, 2022 and 2021.

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.

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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 were appealed to the Court. On
August 9, 2022, the Court issued its decision vacating MISO ROE FERC Opinion
Nos. 569, 569-A and 569-B and remanded to FERC to reopen the proceedings. The
Court found that FERC's development of the new return methodology was arbitrary
and capricious due to FERC's failure to offer a reasonable explanation for its
decision to reintroduce the risk-premium financial model in its new methodology
for calculating a just and reasonable return. At this time, Eversource cannot
predict how and when FERC will address the Court's findings on the remand of the
MISO FERC opinions or any potential associated impact on the NETOs' four pending
ROE complaint cases.

Given the significant uncertainty regarding the applicability of the FERC
opinions in the MISO transmission owners' two complaint cases to the NETOs'
pending four complaint cases, Eversource concluded that there is no reasonable
basis for a change to the reserve or recognized ROEs for any of the complaint
periods at this time. As well, Eversource cannot reasonably estimate a range of
loss for any of the four complaint proceedings at this time. 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 2022 rate
base, a change of 10 basis points to the base ROE would impact Eversource's
future annual after-tax earnings by approximately $5 million per year, and will
increase slightly over time as we continue to invest in our transmission
infrastructure.

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

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

On April 15, 2021, FERC issued a Supplemental NOPR that proposes to eliminate
the existing 50 basis point return on equity for utilities that have been
participating in a regional transmission organization (RTO ROE incentive) for
more than three years. On June 25, 2021, the NETOs jointly filed comments
strongly opposing FERC'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 FERC issues a final order eliminating the
RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual
impact (using 2022 estimated rate base) on Eversource's after-tax earnings is
approximately $18 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.

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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' base 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 PURA on a set schedule. On August 29, 2022, Aquarion filed an
application with PURA to amend its existing rate schedules and a final decision
is expected March 15, 2023.

In Massachusetts, electric distribution companies are required to file
distribution rate schedules every five years, and natural gas local distribution
companies to file distribution rate schedules every 10 years, and those
companies are limited to one settlement agreement in any 10-year period. NSTAR
Electric's base distribution rates were established in a November 2022
DPU-approved rate case. NSTAR Gas' base distribution rates were established in
an October 2020 DPU-approved rate case. EGMA's base 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's base
distribution rates were established in a 2018 DPU-approved rate case.

In New Hampshire, PSNH's base distribution rates were established in a December
2020 NHPUC-approved rate case settlement agreement. Aquarion's base distribution
rates were established in a July 2022 NHPUC-approved rate case settlement
agreement, with a single step adjustment approved on January 19, 2023. Rates are
effective March 1, 2023.

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.

Connecticut:

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. 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 with an updated
schedule for the years 2022 through 2028, which included additional information
as required by 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. The procedural schedule includes briefs
that were filed on April 29, 2022, written comments that were filed July 20,
2022, and a technical session on September 14, 2022.

CL&P Rate Relief Plan: On November 28, 2022, Governor Lamont, DEEP, Office of
Consumer Counsel, and CL&P jointly developed a rate relief plan for electric
customers for the winter peak season of January 1, 2023 through April 30, 2023.
On December 16, 2022, PURA approved the rate relief plan. As part of the rate
relief plan, CL&P reduced the Non-Bypassable Federally Mandated Congestion
Charge (NBFMCC) rate effective January 1, 2023 to provide customers with an
average $10 monthly bill credit from January through April 2023. This rate
reduction accelerates the return to customers of net revenues generated by
long-term state-approved energy contracts with the Millstone and Seabrook
nuclear power plants of approximately $90 million. The rate relief plan also
included instituting a temporary, flat monthly discount for qualifying
low-income hardship customers effective January 1, 2023. This flat-rate credit
will continue until a new low-income discount rate that was approved by PURA in
an October 19, 2022 decision is implemented in 2024. These aspects of the rate
relief plan do not impact CL&P's earnings but do impact its future cash flows.
Also as part of the rate relief plan, CL&P committed to contribute $10 million
to an energy assistance program for qualifying hardship customers, which is
expected to be distributed as a bill credit to those customers by the end of the
first quarter of 2023. CL&P recorded a current liability of $10 million on the
balance sheet and a charge to expense on the statement of income for the year
ended December 31, 2022 associated with the customer assistance program.

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 expected in March 2023 and then a procedural schedule
established for the second phase. On January 25, 2023, PURA staff issued a
proposal outlining a suggested portfolio of performance based regulation
elements for further exploration and implementation in the second phase of the
proceeding. At this time, we cannot predict the ultimate outcome of this
proceeding and the resulting impact to CL&P.

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Aquarion Water Company of Connecticut Distribution Rate Case: On August 29,
2022, Aquarion Water Company of Connecticut (AWC-CT) filed an application with
PURA to amend its existing rate schedules to address an operating revenue
deficiency. AWC-CT's rate application requested approval of rate increases of
$27.5 million, an additional $13.6 million, and an additional $8.8 million,
effective March 15, 2023, 2024, and 2025, respectively. A final decision from
PURA is expected March 15, 2023.

Massachusetts:

NSTAR Electric Distribution Rates: As part of an inflation-based mechanism, NSTAR Electric submitted its fourth annual Performance Based Rate (PBR) Adjustment filing on November 10, 2021 and on December 22, 2021, the DPU approved a $36.8 million increase to base distribution rates effective January 1, 2022.

NSTAR Electric Distribution Rate Case: On November 30, 2022, the DPU issued its
decision in the NSTAR Electric distribution rate case and approved a base
distribution rate increase of $64 million effective January 1, 2023. The DPU
approved a renewal of the performance-based ratemaking (PBR) plan originally
authorized in its previous rate case for a five-year term, with a corresponding
stay out provision. The PBR plan term has the possibility of a five-year
extension. The PBR mechanism allows for an annual adjustment to base
distribution rates for inflation and exogenous events. The DPU also allowed for
adjustments to the PBR mechanism for the recovery of future capital additions
based on a historical five-year average of total capital additions, beginning
with the January 1, 2024 PBR adjustment. The decision allows an authorized
regulatory ROE of 9.80 percent on a capital structure including 53.2 percent
equity.

Among other items, the DPU approved an increase to the annual storm fund
contribution collected through base distribution rates from $10 million to
$31 million, and allowed for the recovery of storm threshold costs of
$1.3 million per storm event subsequent to the eighth storm in a calendar year
(six recovered in base rates plus two additional storms). The DPU approved cost
recovery of a portion of NSTAR Electric's outstanding storm costs beginning on
January 1, 2023 and January 1, 2024, subject to reconciliation from future
prudency reviews. In a subsequent compliance filing, the DPU allowed recovery to
commence for outstanding storm costs occurring between 2018 and 2022 and
interest in a total of $162.1 million over a five-year period starting January
1, 2023. In addition, NSTAR Electric will begin to recover 2021 exogenous storms
and interest in a total of $220.9 million over a five-year period beginning
January 1, 2024. The DPU also approved the recovery of historical exogenous
property taxes of $30.8 million incurred from 2020 through 2022 over a two-year
period and $8.3 million incurred from 2012 through 2015 over a five-year period
effective January 1, 2023. NSTAR Electric's AMI Implementation Plan and a new
Advanced Metering Infrastructure tariff (AMIF) reconciling mechanism effective
January 1, 2023 were also approved and NSTAR Electric will recover all
meter-related capital now through the AMIF as opposed to base distribution
rates.

NSTAR Electric Grid Modernization Plan: On October 7, 2022, the DPU issued an
order approving continuing investments from the initial 2018 to 2021 Grid
Modernization Plan that were included in the 2022 to 2025 Grid Modernization
Plan. The DPU established a preauthorized total budget cap of $162.6 million
over the four-year plan period for these continuing investments. On November 30,
2022, the DPU issued an order that preauthorized a four-year $43.0 million
budget for new grid-facing investments. All of the ongoing and new investments
will have targeted cost recovery through NSTAR Electric's annual grid
modernization factor filings.

NSTAR Electric Advanced Metering Infrastructure Plan: On November 30, 2022, the
DPU approved NSTAR Electric's proposed Advanced Metering Infrastructure
customer-facing investment and implementation plan (including program operating
costs), including a full deployment of advanced metering functionality, for the
years 2022 through 2028. The DPU established preauthorized total budget caps of
$534.8 million for core AMI investments and corresponding operating costs and
$133.1 million for supporting AMI investments and corresponding operating costs
over the seven-year plan period. The DPU approved a new AMIF tariff reconciling
mechanism effective January 1, 2023 to recover eligible costs associated with
both AMI customer-facing investments and implementation costs. Investments above
these budget caps can be recovered in a future base distribution rate
proceeding.

NSTAR Electric Transmission Support Agreement: On June 17, 2022, FERC approved a
transmission support agreement between NSTAR Electric and Park City Wind LLC
(PCW). The agreement commits NSTAR Electric to construct certain transmission
facilities required to interconnect PCW's future 800 MW offshore wind generation
facility to NSTAR Electric's transmission system. Of the total estimated $196
million project, NSTAR Electric will finance an estimated $152 million and earn
a return on those specific investments over a ten-year period once the facility
is in operation based on the authorized return that is in effect at the
applicable time for regional transmission service under the ISO-NE Open Access
Transmission Tariff. The interconnection transmission facilities are currently
expected to be in-service in 2026.

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NSTAR Electric CIP Filing: On December 30, 2022, the DPU approved a provisional
system planning tariff for the recovery of costs associated with a capital
investment project (CIP) proposal submitted by NSTAR Electric for one of six
geographic study areas in its service territory in accordance with DPU's
directives. The DPU established a new, provisional framework for planning and
funding upgrades to the electric power system to foster development and
interconnection of distributed energy facilities. Under the DPU program, NSTAR
Electric has filed infrastructure upgrade proposals to be built within a
four-year construction timeframe that allocate the costs of interconnection
upgrades between the interconnecting distributed generation facility and
distribution customers. Payments made by the distributed generation facility
will be applied against the total capital investment made by NSTAR Electric and
NSTAR Electric will earn a return on the net investment. The amount allocated to
distribution customers will be recovered through a reconciling mechanism, the
Provisional System Planning Tariff. The DPU approved the first of these
provisional system planning projects, the Marion-Fairhaven group study area,
which will enable 141 MW of distributed energy to be interconnected at a total
estimated cost of $119.7 million. Of the total $119.7 million, $65.8 million
will be allocated to distribution customers, once the enabled distributed energy
facilities capacity is fully subscribed by distributed energy facilities
interconnecting customers. Additionally, NSTAR Electric will proceed with
construction of $54 million of transmission upgrades necessary to improve local
reliability and integrate distribution energy resources in the Marion-Fairhaven
area and recover the amount through local transmission rates.

NSTAR Electric Electric Vehicles Program: On December 30, 2022, NSTAR Electric
received DPU approval for a new Phase 2 electric vehicle (EV) charging
infrastructure program (including operating costs) totaling $188 million over a
four-year period, which includes make-ready costs and other EV expenditures to
support the deployment of charging ports and provides incentives for charging
infrastructure installed at commercial and residential sites in Massachusetts.
NSTAR Electric will recover the cost of this program through an Electric Vehicle
Program tariff.

NSTAR Gas Distribution Rates: As part of an inflation-based mechanism, NSTAR Gas
submitted its second annual Performance Based Rate Adjustment filing on
September 15, 2022 and on October 31, 2022, the DPU approved a $21.7 million
increase to base distribution rates for effect on November 1, 2022. The increase
is inclusive of a $4.5 million permanent increase related to exogenous property
taxes and a $5.4 million increase related to an October 6, 2021 mitigation plan
filing that delayed recovery of a portion of a base distribution rate increase
originally scheduled to take effect November 1, 2021. The DPU also approved the
recovery of historical exogenous property taxes incurred from November 1, 2020
through October 31, 2022 of $8.2 million over a two-year period through a
separate reconciling mechanism effective November 1, 2022.

EGMA Distribution Rates: As established in an October 7, 2020 EGMA Rate
Settlement Agreement approved by the DPU, on September 16, 2022 EGMA filed for
its second base distribution rate increase and on October 31, 2022, the DPU
approved a $6.7 million increase to base distribution rates and a $3.3 million
increase to the Tax Act Credit Factor for effect on November 1, 2022. The DPU
also approved the recovery of historical exogenous property taxes incurred from
November 1, 2020 through October 31, 2022 of $8.6 million over a two-year period
through a separate reconciling mechanism effective November 1, 2022. EGMA will
request recovery of incremental property taxes incurred after October 31, 2022
in future exogenous filings.

New Hampshire:

PSNH Distribution Rates: In connection with an October 9, 2020 settlement
agreement, PSNH was permitted three step increases to reflect qualifying plant
additions in calendar years 2019, 2020 and 2021. The first two step adjustments
had effective dates of January 1, 2021 and August 1, 2021, respectively. On
October 20, 2022, the NHPUC approved the third step adjustment for 2021 plant in
service to recover a revenue requirement of $8.9 million, with rates effective
November 1, 2022. The total approved revenue requirement increase is being
collected over the remainder of the rate year (November 1, 2022 - July 31,
2023).

PSNH Pole Acquisition Approval: On November 18, 2022, the NHPUC issued a
decision that approved a proposed purchase agreement between PSNH and
Consolidated Communications, in which PSNH would acquire approximately 343,000
jointly-owned utility poles and approximately 3,800 solely-owned poles and pole
assets. The NHPUC also authorized PSNH to recover certain expenses associated
with the operation and maintenance of the transferred poles, pole inspections,
and vegetation management expenses through a new cost recovery mechanism, the
Pole Plant Adjustment Mechanism (PPAM), subject to consummation of the purchase
agreement. On December 16, 2022, a motion for rehearing of NHPUC's approval was
filed by an intervenor, which was denied by the NHPUC on February 8, 2023. PSNH
cannot predict the timing of consummation of the proposed purchase agreement.

PSNH 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. The
order eliminated the recovery of performance incentives and made other key
changes to the energy efficiency plan beginning in 2022. PSNH sought a rehearing
of the order and was denied, which resulted in PSNH filing a formal appeal to
the New Hampshire Supreme Court.

On February 10, 2022, the NHPUC issued an order that restored the 2022 energy
efficiency rate to be consistent with the 2021 rate, which PSNH implemented
effective March 1, 2022. On February 24, 2022, state legislation was signed into
law that undid the most impactful effects of the November 12, 2021 NHPUC order.
The legislation directed that the joint utility energy efficiency plan and
programming framework in effect on January 1, 2021 be utilized going forward,
including utility performance incentive payments, lost base revenue
calculations, and Evaluation, Measurement, and Verification process.
Additionally, the legislation established a process for future plan proposals,
including the 2024 through 2026 triennial plan, and includes a mechanism for
future rate increases based on the consumer price index. As a result of the new
legislation passed specific to this order, PSNH withdrew its appeal to the New
Hampshire Supreme Court. PSNH made the required filing for the remainder of the
2022 through 2023 triennial plan on March 1, 2022, which was approved as filed
by the NHPUC on April 29, 2022.
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Legislative and Policy Matters

Massachusetts: On August 11, 2022, Governor Baker signed into law
climate-related legislation which, among other things, affirms the state's
commitment to contract for 5,600 MW of offshore wind by June 30, 2027, modifies
the bidding process to encourage more competition among offshore wind
developers, and provides incentives to increase the manufacturing and assembly
of offshore wind components in Massachusetts. The law also provides incentives
to encourage the sale and leasing of electric vehicles, promotes energy storage
and electrification technologies, directs electric companies to develop grid
modernization plans to upgrade distribution and transmission facilities, and
initiates a pilot program that would allow up to ten communities in the state to
restrict fossil fuel use in new buildings. Additionally, for long-term contracts
that are approved by the DPU between developers of offshore wind generation and
the contracting electric distribution company, the law provides for an annual
remuneration for the distribution company equal to 2.25 percent of the annual
payments under the contract to compensate the distribution company for accepting
the financial obligation of the long-term contract.

Federal: On August 16, 2022, the Inflation Reduction Act of 2022 (IRA) was
signed into law. This is a broad package of legislation that includes incentives
and support for clean energy resource development. Most notable for Eversource,
the investment tax credit (ITC) on offshore wind projects increases from 30
percent to 40 percent if certain requirements for labor and domestic content are
met. The act also re-establishes the production tax credit for solar and wind
energy projects, gives increased credit for projects in certain communities, and
sets credits for qualifying clean energy generation and energy storage projects.
The tax provisions of the IRA provide additional incentives for offshore wind
projects and could reduce retail electricity costs for our customers related to
those clean energy investments. The IRA includes other tax provisions focused on
implementing a 15 percent minimum tax on adjusted financial statement income and
a one percent excise tax on corporate share repurchases. The Department of
Treasury and the Internal Revenue Service issued limited guidance in the fourth
quarter; however, they are expected to issue additional needed guidance with
respect to the application of the newly enacted IRA provisions in the future. We
will continue to monitor and evaluate impacts on our consolidated financial
statements. We currently do not expect the alternative minimum tax change to
have a material impact on our earnings, financial condition or cash flows.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires
management to make estimates, assumptions and, at times, difficult, subjective
or complex judgments. Changes in these estimates, assumptions and judgments, in
and of themselves, could materially impact our financial position, results of
operations or cash flows. Our management discusses with the Audit Committee of
our Board of Trustees significant matters relating to critical accounting
policies. Our critical accounting policies are discussed below. See the combined
notes to our financial statements for further information concerning the
accounting policies, estimates and assumptions used in the preparation of our
financial statements.

Regulatory Accounting:  Our regulated companies are subject to rate regulation
that is based on cost recovery and meets the criteria for application of
accounting guidance for rate-regulated operations, which considers the effect of
regulation on the timing of the recognition of certain revenues and expenses.
The regulated companies' financial statements reflect the effects of the
rate-making process. The rates charged to the customers of our regulated
companies are designed to collect each company's costs to provide service, plus
a return on investment.

The application of accounting guidance for rate-regulated enterprises results in
recording regulatory assets and liabilities. Regulatory assets represent the
deferral of incurred costs that are probable of future recovery in customer
rates. Regulatory assets are amortized as the incurred costs are recovered
through customer rates. In some cases, we record regulatory assets before
approval for recovery has been received from the applicable regulatory
commission. We must use judgment to conclude that costs deferred as regulatory
assets are probable of future recovery. We base our conclusion on certain
factors, including, but not limited to, regulatory precedent.

Regulatory liabilities represent either revenues received from customers to fund
expected costs that have not yet been incurred or probable future refunds to
customers. We make judgments regarding the future outcome of regulatory
proceedings that involve potential future refund to customers and record
liabilities for these loss contingencies when probable and reasonably estimable
based upon available information. Regulatory liabilities are recorded at the
best estimate, or at a low end of the range of possible loss. The amount
recorded may differ from when the uncertainty is resolved. Such differences
could have a significant impact on our financial statements.

We 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 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. Storm restoration and pre-staging costs are subject to
prudency reviews from our regulators. We have approximately $1.4 billion of
deferred storm costs that either have yet to be filed with the applicable
regulatory commission, are pending regulatory approval, or are subject to
prudency review as of December 31, 2022. Tropical Storm Isaias resulted in
deferred storm restoration costs of approximately $235 million at CL&P as of
December 31, 2022. While it is possible that some amount of the Tropical Storm
Isaias costs may be disallowed by PURA in a future proceeding, any such
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amount cannot be estimated at this time. We believe that our storm restoration costs were prudently incurred, meet the criteria for cost recovery and are probable of recovery.

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.  Plan assets and the benefit obligation
are presented on a net basis and we recognize the overfunded or underfunded
status of the plans as an asset or liability on the balance sheet. These amounts
are remeasured annually using a December 31st measurement date. For each of
these plans, several significant assumptions are used to determine the projected
benefit obligation, funded status and net periodic benefit expense/income. 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 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 Assumption:  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, 2022, 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 2023 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 Assumptions:  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, 2022, the discount rates used to
determine the funded status were within a range of 5.1 percent to 5.2 percent
for the Pension and SERP Plans, and 5.2 percent for the PBOP Plans.  As of
December 31, 2021, the discount rates used 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.  The increase in the discount rates used to
calculate the funded status resulted in a decrease to the Pension and SERP
Plans' projected benefit obligation and the PBOP Plans' projected benefit
obligation of $1.48 billion and $180.1 million, respectively, as of December 31,
2022.

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 2022 expense
were within a range of 2.2 percent to 3.2 percent for the Pension and SERP
Plans, and within a range of 2.3 percent to 3.3 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. The mortality assumption is composed of a base
table that represents the current expectation of life expectancy of the
population adjusted by an improvement scale that attempts to anticipate future
improvements in life expectancy. In 2022, our mortality assumption utilized the
Society of Actuaries base mortality tables (Pri-2012), adjusted to reflect
Eversource's own mortality experience, and projected generationally using the
MP-2021 improvement scale.

Compensation/Progression Rate Assumptions:  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 will receive in the future.  As
of December 31, 2022 and 2021, 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 Assumptions: The Eversource Service PBOP Plan is not subject to
health care cost trends. As of December 31, 2022, for the Aquarion PBOP Plan,
the health care trend rate used to determine the funded status for pre-65
retirees is 7 percent, with an ultimate rate of 5 percent in 2031, and for
post-65 retirees, the health care trend rate and ultimate rate is 3.5 percent.

Actuarial Gains and Losses:  Actuarial gains and losses represent the
differences between actuarial assumptions and actual information or updated
assumptions. Unamortized actuarial gains or losses arising at the December 31st
measurement date are primarily from differences in actual investment performance
compared to our expected return and changes in the discount rate assumption. The
Eversource Service Pension and PBOP Plans use the corridor approach to determine
the amount of gain or loss to amortize into net periodic benefit expense/income.
The corridor approach defers all actuarial gains and losses arising at
remeasurement and the net unrecognized actuarial gain or loss balance is
amortized as a component of expense if, as of the beginning of the year, that
net gain or loss exceeds 10 percent of the greater of the market value of the
plan's assets or the projected benefit obligation. The amount of net
unrecognized actuarial gain or loss in excess of the 10 percent corridor is
amortized to expense over the estimated average future employee service period.
For the Eversource Service Pension Plan, the net actuarial gain or loss is
amortized as a component of expense over the estimated average future employee
service period of seven years. For the Eversource Service PBOP Plan, the net
unrecognized actuarial gain or loss was within the 10 percent corridor and
therefore there was no amortization to expense during 2022.

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An increase in the discount rate used to determine our pension funded status
would decrease our projected benefit obligation at December 31st, resulting in a
lower unamortized actuarial loss to be recognized in future years' pension
expense, subject to exceeding the 10 percent corridor. An increase in the
discount rate at December 31st would also result in an increase in the interest
cost component and a decrease in the service cost component of the subsequent
year's benefit plan expense.

The calculated expected return on plan assets 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.

An underperformance of our pension plan investment returns relative to the expected returns would increase our pension liability at December 31st, resulting in a higher unamortized actuarial loss to be recognized in future years' pension expense, subject to exceeding the 10 percent corridor, and a lower expected return on assets component of pension expense in future years' pension expense.

Net Periodic Benefit Expense/Income: Pension, SERP and PBOP expense/income is
determined by our actuaries and consists of service cost and prior service
cost/credit, interest cost based on the discounting of the obligations,
amortization of actuarial gains and losses, and the expected return on plan
assets. For the Pension and SERP Plans, pre-tax net periodic benefit income was
$181.6 million for the year ended December 31, 2022, and there was pre-tax net
periodic benefit expense of $23.6 million and $56.9 million for the years ended
December 31, 2021 and 2020, respectively.  For the PBOP Plans, pre-tax net
periodic benefit income was $79.8 million, $60.5 million and $51.6 million for
the years ended December 31, 2022, 2021 and 2020, respectively.

The change in pension, SERP and PBOP expense/income arising from the annual
remeasurement does not fully impact earnings. Our Massachusetts utilities
recover qualified pension and PBOP expenses related to their distribution
operations through a rate reconciling mechanism that fully tracks the change in
net pension and PBOP expenses each year, therefore the change in their pension
and PBOP expense does not impact earnings. Our electric transmission companies'
rates provide for an annual true-up of estimated to actual costs, which include
pension and PBOP expenses, therefore the change in their pension and PBOP
expense does not impact earnings. Additionally, the portion of our pension and
PBOP expense that relates to company labor devoted to capital projects is
capitalized on the balance sheet instead of being charged to expense.

Forecasted Expense/Income and Expected Contributions:  We estimate that net
periodic benefit income in 2023 for the Pension and SERP Plans will be
approximately $114 million and for the PBOP Plans will be approximately $57
million. The change in pension income from 2022 to 2023 is driven primarily by
an increase in the interest cost component due to a higher discount rate and
lower expected return on assets due to a lower asset balance, partially offset
by lower amortization of actuarial losses due to unrecognized actuarial gains
arising in 2022. The change in PBOP income from 2022 to 2023 is driven primarily
by an increase in the interest cost component due to a higher discount rate and
lower expected return on assets due to a lower asset balance. For the PBOP
Plans, there is no amortization of actuarial losses in 2023. Pension, SERP and
PBOP expense/income 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
$80.0 million to the Pension Plans in 2022.  Based on the current status of the
Pension Plans and federal pension funding requirements, there is no minimum
funding requirement for our Eversource Service Pension Plan in 2023 and we do
not expect to make pension contributions in 2023. It is our policy to fund the
PBOP Plans annually through tax deductible contributions to external trusts. We
do not expect to make any contributions to the Eversource Service PBOP Plan in
2023. We contributed $3.1 million to the Aquarion PBOP Plan in 2022.  We
currently estimate contributing $5.0 million and $2.9 million to the Aquarion
Pension and PBOP Plans, respectively in 2023.

Sensitivity Analysis:  The following table illustrates the hypothetical effect
on reported annual net periodic benefit income as a result of a change in the
following assumptions by 50 basis points:

                                    Pension Plans (excluding SERP Plans)                           PBOP Plans
                                 Decrease in Plan           Increase in Plan
                                      Income                    Expense                     Decrease in Plan Income
(Millions of Dollars)                 For the Years Ended December 31,                  For the Years Ended December 31,
Eversource                             2022                       2021                     2022                   2021
Lower expected long-term rate  $             32.5          $          26.5          $           5.6          $        4.8
of return
Lower discount rate                          32.6                     27.0                      1.7                   2.6
Higher compensation rate                      7.6                      9.9                         N/A                   N/A



Goodwill:  We recorded goodwill on our balance sheet associated with previous
mergers and acquisitions, all of which totaled $4.52 billion as of December 31,
2022. 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, 2022, 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 $951 million
to Water Distribution.

Goodwill recorded and allocated to the Water Distribution reporting unit
included $44.8 million in 2022 arising from the acquisition of The Torrington
Water Company on October 3, 2022 and $22.2 million arising from the acquisition
of NESC on December 1, 2021, which included measurement period increases in 2022
totaling $0.5 million.

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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 its carrying amount.

We performed an impairment assessment of goodwill as of October 1, 2022 for the
Electric Distribution, Electric Transmission, Natural Gas Distribution and Water
Distribution reporting units. Our qualitative assessment 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 2022 goodwill impairment assessment resulted in a conclusion that goodwill
is not impaired and no reporting unit is at risk of a goodwill impairment. We
believe that the fair value of the reporting units was substantially in excess
of carrying value. Adverse regulatory actions, changes in the regulatory and
political environment, or changes in significant assumptions could potentially
result in future goodwill impairment indicators.

Long-Lived Assets: Impairment evaluations of long-lived assets, including
property, plant and equipment and other assets, involve a significant degree of
estimation and judgment, including identifying circumstances that indicate an
impairment may exist. An 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. If indicators are present for a long-lived
asset or asset group, a comparison of the undiscounted expected future cash
flows to the carrying value is performed. No impairments occurred during the
year 2022.

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 at the equity method investment level, selecting discount rates used
to determine fair values, and developing an estimate of discounted future cash
flows expected from investment operations or the sale of the investment. No
impairments occurred during 2022. Eversource continually monitors and evaluates
its equity method investments to determine if there are indicators of an
other-than-temporary impairment.

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, 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
                                       44
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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," 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, AROs, and in the valuation of business combinations and asset
acquisitions. The fair value measurement guidance was also applied in estimating
the fair value of preferred stock, long-term debt and RRBs.

Changes in fair value of our derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers. These valuations are sensitive to the prices of energy-related products in future years and assumptions made.

We use quoted market prices when available to determine the fair value of
financial instruments.  When quoted prices in active markets for the same or
similar instruments are not available, we value derivative contracts using
models that incorporate both observable and unobservable inputs.  Significant
unobservable inputs utilized in the models include energy-related product prices
for future years for long-dated derivative contracts and market volatilities.
 Discounted cash flow valuations incorporate estimates of premiums or discounts,
reflecting risk-adjusted profit that would be required by a market participant
to arrive at an exit price, using available historical market transaction
information. Valuations of derivative contracts also reflect our estimates of
nonperformance risk, including credit risk.
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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, 2022 and 2021 included in this Annual Report on Form 10-K:

                                                              For the Years Ended December 31,
(Millions of Dollars)                                 2022                    2021                Increase
Operating Revenues                             $    12,289.3             $    9,863.1          $    2,426.2
Operating Expenses:
Purchased Power, Purchased Natural Gas and
Transmission                                         5,014.1                  3,372.3               1,641.8
Operations and Maintenance                           1,865.3                  1,739.7                 125.6
Depreciation                                         1,194.2                  1,103.0                  91.2
Amortization                                           448.9                    232.0                 216.9
Energy Efficiency Programs                             658.0                    592.8                  65.2
Taxes Other Than Income Taxes                          910.6                    830.0                  80.6

Total Operating Expenses                            10,091.1                  7,869.8               2,221.3
Operating Income                                     2,198.2                  1,993.3                 204.9
Interest Expense                                       678.3                    582.4                  95.9
Other Income, Net                                      346.1                    161.3                 184.8
Income Before Income Tax Expense                     1,866.0                  1,572.2                 293.8
Income Tax Expense                                     453.6                    344.2                 109.4
Net Income                                           1,412.4                  1,228.0                 184.4
Net Income Attributable to Noncontrolling
Interests                                                7.5                      7.5                     -
Net Income Attributable to Common Shareholders $     1,404.9             $    1,220.5          $      184.4



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

                                                             Electric                                                          Firm Natural Gas                                                       Water
                                       Sales Volumes (GWh)                       Percentage                      Sales Volumes (MMcf)                  Percentage                   Sales Volumes (MG)                  Percentage
                                     2022                 2021              (Decrease)/Increase                 2022                 2021               Increase                 2022                 2021               Increase
Traditional                            7,764              7,782                             (0.2) %                   -                  -                       -  %              1,857              1,256                    47.9  %
Decoupled and Special Contracts
(1)                                   43,493             43,228                              0.6  %             152,291            150,145                     1.4  %             23,154             22,099                     4.8  %
Total Sales Volumes                   51,257             51,010                              0.5  %             152,291            150,145                     1.4  %             25,011             23,355                     7.1  %

(1) Special contracts are unique to Yankee Gas natural gas distribution customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.

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 2022, as compared
to 2021, as follows:

(Millions of Dollars)       Increase/(Decrease)
Electric Distribution      $            1,981.7
Natural Gas Distribution                  426.0
Electric Transmission                     174.1
Water Distribution                         11.2
Other                                      81.5
Eliminations                             (248.3)
Total Operating Revenues   $            2,426.2



Electric and Natural Gas (excluding EGMA) Distribution Revenues:
Base Distribution Revenues:
•Base electric distribution revenues increased $43.4 million in 2022, as
compared to 2021, due primarily to the impact of base distribution rate
increases at NSTAR Electric effective January 1, 2022 resulting from its annual
Performance Based Rate Adjustment filing and at PSNH effective August 1, 2021
and November 1, 2022.

•Base natural gas distribution revenues (excluding EGMA) increased $21.4 million
in 2022, as compared to 2021, due primarily to base distribution rate increases
at NSTAR Gas effective November 1, 2021 and November 1, 2022.

Electric distribution revenues at CL&P also increased $93.4 million in 2022, as
compared to 2021, due to the absence of a 2021 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 the 2021 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 period from
December 1, 2021 to January 31, 2022. Additionally, CL&P recorded a $28.4
million reserve in 2021 for a civil penalty for non-compliance with storm
performance standards that was provided as credits to customers on electric
bills beginning on September 1, 2021 over a one-year period.

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.

Customers have the choice to purchase electricity from each Eversource electric
utility or from a competitive third party supplier. For customers who have
contracted separately with these competitive suppliers, revenue is not recorded
for the sale of the electricity commodity, as the utility is acting as an agent
on behalf of the third party supplier. For customers that choose to purchase
electric generation from CL&P, NSTAR Electric or PSNH, each purchases power on
behalf of, and is permitted to recover the related energy supply cost without
mark-up from, its customers, and records offsetting amounts in revenues and
purchased power and amortization expense related to this energy supply
procurement. CL&P, NSTAR Electric and PSNH each remain as the distribution
service provider for all customers and charge a regulated rate for distribution
delivery service recorded in revenues.

Tracked distribution revenues increased/(decreased) in 2022, as compared to 2021, due primarily to the following:

(Millions of Dollars)                           Electric Distribution           Natural Gas Distribution
Retail Tariff Tracked Revenues:
Energy supply procurement                     $              1,032.9          $                   144.1
Retail transmission                                            246.8                                  -
CL&P FMCC                                                      (87.8)                                 -
Energy efficiency                                               52.9                               (1.4)
Stranded costs                                                 (72.5)                                 -
Other distribution tracking mechanisms                          49.8                               31.7
Wholesale Market Sales Revenue                                 615.1                               33.3



The increase in energy supply procurement within electric distribution and
natural gas distribution in 2022, as compared to 2021, was driven by higher
average prices and higher average supply-related sales volumes. 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,
Purchased Natural Gas and Transmission Expense" below.

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The increase in electric distribution wholesale market sales revenue in 2022, as
compared to 2021, was due primarily to higher average electricity market prices
received for wholesale sales at CL&P, NSTAR Electric and PSNH. ISO-NE average
market prices received for CL&P's wholesale sales increased approximately 90
percent in 2022, as compared to 2021, driven primarily by higher natural gas
prices in New England. The increase was also due to higher wholesale sales
volumes at CL&P resulting from the sale of output generated by the Seabrook PPA
beginning in the first quarter of 2022. Volumes sold into the market were
primarily from the sale of output generated by the Millstone PPA and Seabrook
PPA that CL&P entered into in 2019, as required by regulation. CL&P sells the
energy purchased from Millstone and Seabrook into the wholesale market and uses
the proceeds from the energy sales to offset the contract costs. The net sales
or net cost amount is refunded to, or recovered from, customers in the
non-bypassable component of the CL&P FMCC rate. The increase in electric
distribution wholesale market sales revenues was also driven by higher proceeds
from the sale of transmission rights over a one-year period under CL&P's, NSTAR
Electric's and PSNH's Hydro-Quebec transmission support agreements. Proceeds
from these sales are credited back to customers.

The decrease in CL&P's FMCC revenues and PSNH's stranded cost revenues was
driven by decreases in the retail rate, which reflect the net benefit of higher
wholesale market sales received in the ISO-NE market for long-term state
approved energy contracts at CL&P and PSNH, which are then credited back to
customers through these retail rates. The decrease in PSNH's stranded cost
revenues was also due to lower stranded costs to be recovered due to higher
Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are credited
back to customers.

EGMA Natural Gas Distribution Revenues: EGMA total operating revenues at the
natural gas distribution segment increased by $193.8 million in 2022, as
compared to 2021. Included in the total operating revenues increase was EGMA's
base natural gas distribution revenues increase of $26.3 million in 2022, as
compared to 2021, due primarily to base distribution rate increases effective
November 1, 2021 and November 1, 2022.

Electric Transmission Revenues:  Electric transmission revenues increased $174.1
million in 2022, as compared to 2021, 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, Purchased Natural Gas 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,
Purchased Natural Gas and Transmission expense increased in 2022, as compared to
2021, due primarily to the following:

(Millions of Dollars)                                              Increase
Purchased Power Costs                                             $ 1,217.5
Natural Gas Costs                                                     307.7
Transmission Costs                                                    277.1
Eliminations                                                         (160.5)

Total Purchased Power, Purchased Natural Gas and Transmission $ 1,641.8

The increase in purchased power expense at the electric distribution business in
2022, as compared to 2021, was driven primarily by higher energy supply
procurement costs resulting from higher average prices and higher average
supply-related sales volumes, as well as higher long-term contractual
energy-related costs that are recovered in the non-bypassable component of the
FMCC mechanism at CL&P, and higher net metering costs at NSTAR Electric and
CL&P.

The increase in costs at the natural gas distribution segment in 2022, as compared to 2021, was due primarily to higher average prices and higher average supply-related sales volumes.

The increase in transmission costs in 2022, as compared to 2021, was primarily
the result of an increase resulting from the retail transmission cost deferral,
which reflects the actual cost 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, and a decrease in
costs billed by ISO-NE that support regional grid investments.

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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 2022, as compared to 2021, due primarily to the following:

(Millions of Dollars)                                                       

Increase/(Decrease)

Base Electric Distribution (Non-Tracked Costs):
General costs (including vendor services in corporate areas, insurance, fees and
assessments)                                                                      $               26.8

Shared corporate costs (including computer software depreciation at Eversource

                    25.0

Service)

Storm costs                                                                                       22.0

Commitment to energy assistance program as part of CL&P rate relief plan

                       10.0

Operations-related expenses (including vegetation management, vendor services and

                  4.4

vehicles)

Employee-related expenses, including labor and benefits                                          (20.5)

Absence in 2022 of CL&P charge to fund various customer assistance initiatives

                   (10.0)

associated with the settlement agreement on October 1, 2021 Other non-tracked operations and maintenance

                                                      20.3
Total Base Electric Distribution (Non-Tracked Costs)                                              78.0

Tracked Electric Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher transmission expenses of $35.1 million and increase of $34.7 million due to higher pension tracking mechanism at NSTAR Electric

                                                                                          72.4
Total Electric Distribution and Electric Transmission                                            150.4
Natural Gas Distribution:
Base (Non-Tracked Costs) - Increase due primarily to higher employee-related
expenses and higher shared corporate costs                                                        12.6
Tracked Costs                                                                                     18.6
Total Natural Gas Distribution                                                                    31.2
Water Distribution                                                                                 8.3
Parent and Other Companies and Eliminations:
Eversource Parent and Other Companies - other operations and maintenance                          30.5
Transaction and Transition Costs                                                                 (11.8)
  Eliminations                                                                                   (83.0)
Total Operations and Maintenance                                                  $              125.6

Depreciation expense increased in 2022, as compared to 2021, due to higher utility plant in service balances.

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 2022, as compared to 2021, due primarily to the
deferral adjustment of energy supply, energy-related and other tracked costs at
CL&P (included in the non-bypassable component of the FMCC mechanism), and NSTAR
Electric, which can fluctuate from period to period based on the timing of costs
incurred and related rate changes to recover these costs. The increase in the
FMCC mechanism at CL&P was driven primarily by the net costs and benefits of the
long-term state approved contracts that Eversource has executed with Millstone
and Seabrook, among others. 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 cost deferred assets.

Energy Efficiency Programs expense increased in 2022, as compared to 2021, due
primarily to the deferral adjustment, 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 2022, as compared to 2021,
due primarily to an increase in property taxes as a result of higher utility
plant balances and higher Connecticut gross earnings taxes.

Interest Expense increased in 2022, as compared to 2021, due primarily to an
increase in interest on long-term debt as a result of new debt issuances ($101.3
million), an increase in interest on short-term notes payable ($10.9 million),
an increase in interest expense on regulatory deferrals ($6.7 million), and
higher amortization of debt discounts and premiums, net ($3.3 million),
partially offset by an increase in capitalized AFUDC related to debt funds and
other capitalized interest ($20.0 million), lower interest resulting from the
2022 payment of withheld property taxes at NSTAR Electric ($5.0 million), and a
decrease in RRB interest expense ($1.4 million).

Other Income, Net increased in 2022, as compared to 2021, due primarily to an
increase related to pension, SERP and PBOP non-service income components ($135.4
million), an increase in interest income primarily from regulatory deferrals
($24.9 million), an increase in capitalized AFUDC related to equity funds ($10.0
million), an increase in equity in earnings related to Eversource's equity
method investments ($8.7 million), a gain on the sale of property in 2022 ($2.5
million) and investment income in 2022 compared to investment losses in 2021
driven by market volatility ($2.1 million).

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Income Tax Expense increased in 2022, as compared to 2021, due primarily to
higher pre-tax earnings ($61.7 million), higher state taxes ($5.9 million),
lower share-based payment excess tax benefits ($1.9 million), an increase in
return to provision adjustments ($11.2 million), a decrease in amortization of
EDIT ($20.0 million), an increase in valuation allowances ($8.5 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).


                            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, 2022 and 2021 included in this Annual Report on
Form 10-K:

                                                                                                         For the Years Ended December 31,
                                                            CL&P                                                 NSTAR Electric                                                  PSNH
                                                                                                                                      Increase/                                                  Increase/
(Millions of Dollars)                    2022               2021             Increase             2022               2021             (Decrease)             2022               2021             (Decrease)
Operating Revenues                   $ 4,817.7          $ 3,637.4

$ 1,180.3 $ 3,583.1 $ 3,056.4 $ 526.7

$ 1,474.8 $ 1,177.2 $ 297.6 Operating Expenses: Purchased Power and Transmission 2,110.3

            1,393.0              717.3            1,264.8              932.5                332.3              665.5              370.3                295.2
Operations and Maintenance               707.2              644.2               63.0              640.8              563.2                 77.6              256.0              237.7                 18.3
Depreciation                             355.5              338.9               16.6              362.0              337.5                 24.5              128.0              120.1                  7.9
Amortization of Regulatory Assets,
Net                                      335.6               99.0              236.6               83.9               55.8                 28.1               42.9               86.8                (43.9)
Energy Efficiency Programs               134.2              129.6                4.6              332.3              288.6                 43.7               37.4               38.7                 (1.3)
Taxes Other Than Income Taxes            384.7              363.8               20.9              246.7              216.7                 30.0               95.3               91.5                  3.8
Total Operating Expenses               4,027.5            2,968.5            1,059.0            2,930.5            2,394.3                536.2            1,225.1              945.1                280.0
Operating Income                         790.2              668.9              121.3              652.6              662.1                 (9.5)             249.7              232.1                 17.6
Interest Expense                         169.4              166.1                3.3              162.9              146.0                 16.9               59.5               57.0                  2.5
Other Income, Net                         83.3               30.2               53.1              142.7               74.8                 67.9               32.7               14.6                 18.1
Income Before Income Tax Expense         704.1              533.0              171.1              632.4              590.9                 41.5              222.9              189.7                 33.2
Income Tax Expense                       171.2              131.3               39.9              140.0              114.3                 25.7               51.3               39.4                 11.9
Net Income                           $   532.9          $   401.7          $   131.2          $   492.4          $   476.6          $      15.8          $   171.6          $   150.3          $      21.3

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

For the Years Ended December 31,

                                                                                                                                   Percentage
                                         2022                       2021                  Increase/(Decrease)                 Increase/(Decrease)
CL&P                                         20,560                   20,501                          59                                          0.3  %
NSTAR Electric                               22,933                   22,727                         206                                          0.9  %
PSNH                                          7,764                    7,782                         (18)                                        (0.2) %



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 $1.18 billion
at CL&P, $526.7 million at NSTAR Electric, and $297.6 million at PSNH in 2022,
as compared to 2021.

Base Distribution Revenues:
•CL&P's distribution revenues increased $0.4 million.
•NSTAR Electric's distribution revenues increased $36.9 million due primarily to
the impact of its base distribution rate increase effective January 1, 2022
resulting from its annual Performance Based Rate Adjustment filing.
•PSNH's distribution revenues increased $6.1 million due primarily to the impact
of its base distribution rate increases effective August 1, 2021 and November 1,
2022.

Electric distribution revenues at CL&P also increased $93.4 million in 2022, as
compared to 2021, due to the absence of a 2021 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 the 2021 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 period from
December 1, 2021 to January 31, 2022. Additionally, CL&P recorded a $28.4
million reserve in 2021 for a civil penalty for non-compliance with storm
performance standards that was provided as credits to customers on electric
bills beginning on September 1, 2021 over a one-year period.

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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.

Customers have the choice to purchase electricity from each Eversource electric
utility or from a competitive third party supplier. For customers who have
contracted separately with these competitive suppliers, revenue is not recorded
for the sale of the electricity commodity, as the utility is acting as an agent
on behalf of the third party supplier. For customers that choose to purchase
electric generation from CL&P, NSTAR Electric or PSNH, each purchases power on
behalf of, and is permitted to recover the related energy supply cost without
mark-up from, its customers, and records offsetting amounts in revenues and
purchased power and amortization expense related to this energy supply
procurement. CL&P, NSTAR Electric and PSNH each remain as the distribution
service provider for all customers and charge a regulated rate for distribution
delivery service recorded in revenues.

Tracked revenues increased/(decreased) in 2022, as compared to 2021, due primarily to the following:

(Millions of Dollars)                       CL&P        NSTAR Electric      

PSNH

Retail Tariff Tracked Revenues:
Energy supply procurement                 $ 559.9      $        178.4      $ 294.6
Retail transmission                         110.6               155.1        (18.9)
CL&P FMCC                                   (87.8)                  -            -
Energy efficiency                             7.2                41.9          3.8
Stranded costs                                1.1               (14.6)       (59.0)
Other distribution tracking mechanisms       28.2                22.9       

(1.3)

Wholesale Market Sales Revenue              464.9               105.8       

44.4

The increase in energy supply procurement at CL&P was driven by higher average
prices and higher average supply-related sales volumes. The increase in energy
supply procurement at NSTAR Electric was driven by higher average prices,
partially offset by lower average supply-related sales volumes. The increase in
energy supply procurement at PSNH was driven by higher 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 in 2022, as compared to 2021, was
due primarily to higher average electricity market prices received for wholesale
sales at CL&P, NSTAR Electric and PSNH. ISO-NE average market prices received
for CL&P's wholesale sales increased approximately 90 percent in 2022, as
compared to 2021, driven primarily by higher natural gas prices in New England.
The increase at CL&P was also due to higher wholesale sales volumes resulting
from the sale of output generated by the Seabrook PPA beginning in the first
quarter of 2022. CL&P's volumes sold into the market were primarily from the
sale of output generated by the Millstone PPA and Seabrook PPA that CL&P entered
into in 2019, as required by regulation. CL&P sells the energy purchased from
Millstone and Seabrook into the wholesale market and uses the proceeds from the
energy sales to offset the contract costs. The net sales or net cost amount is
refunded to, or recovered from, customers in the non-bypassable component of the
CL&P FMCC rate. The increase in wholesale market sales revenues at CL&P, NSTAR
Electric and PSNH was also driven by higher proceeds from the sale of
transmission rights over a one-year period under Hydro-Quebec transmission
support agreements. Proceeds from these sales are credited back to customers.

The decrease in CL&P's FMCC revenues and PSNH's stranded cost revenues was
driven by decreases in the retail rate, which reflect the net benefit of higher
wholesale market sales received in the ISO-NE market for long-term state
approved energy contracts at CL&P and PSNH, which are then credited back to
customers through these retail rates. The decrease in PSNH's stranded cost
revenues was also due to lower stranded costs to be recovered due to higher
Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are credited
back to customers.

Transmission Revenues: Transmission revenues increased $61.5 million at CL&P,
$73.5 million at NSTAR Electric and $39.1 million at PSNH in 2022, as compared
to 2021, 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 $60.8 million at
CL&P, $78.6 million at NSTAR Electric and $12.9 million at PSNH in 2022, as
compared to 2021.

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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 2022, as compared to 2021, due primarily to the following:

(Millions of Dollars)                       CL&P        NSTAR Electric       PSNH
Purchased Power Costs                     $ 650.6      $        255.5      $ 311.4
Transmission Costs                          125.1               155.4         (3.4)
Eliminations                                (58.4)              (78.6)       (12.8)

Total Purchased Power and Transmission $ 717.3 $ 332.3 $ 295.2

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

•The increase at CL&P was due primarily to higher energy supply procurement
costs resulting from higher average prices and higher average supply-related
volumes. The increase was also due to higher long-term contractual
energy-related costs and higher net metering costs that are recovered in the
non-bypassable component of the FMCC mechanism.
•The increase at NSTAR Electric was due primarily to higher energy supply
procurement costs resulting from higher average prices, partially offset by
lower supply-related sales volumes. The increase was also due to higher net
metering costs.
•The increase at PSNH was due primarily to higher energy supply procurement
costs resulting from higher average prices.

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

Operations and Maintenance expense includes tracked costs and costs that are
part of base distribution rates with changes impacting earnings (non-tracked
costs).  Operations and Maintenance expense increased in 2022, as compared to
2021, due primarily to the following:

(Millions of Dollars)                                           CL&P             NSTAR Electric            PSNH
Base Electric Distribution (Non-Tracked Costs):
General costs (including vendor services in corporate areas, $   12.3          $           8.8          $    5.7

insurance, fees and assessments) Shared corporate costs (including computer software depreciation at Eversource Service)

                               8.7                     13.2               3.1
Storm costs                                                       9.0                      9.5               3.5

Commitment to energy assistance program as part of CL&P rate 10.0

                  -                 -
relief plan
Operations-related expenses (including vegetation
management, vendor services and vehicles)                         3.1                      2.2              (0.9)

Absence in 2022 of CL&P charge to fund various customer assistance initiatives associated with the settlement agreement on October 1, 2021

                                    (10.0)                       -                 -

Employee-related expenses, including labor and benefits (1.5)

              (11.0)              0.5
Other non-tracked operations and maintenance                      5.6                     15.8              (1.1)
Total Base Electric Distribution (Non-Tracked Costs)             37.2                     38.5              10.8
Tracked Costs:
Transmission expenses                                            19.4                      7.4               8.3
Other tracked operations and maintenance                          6.4                     31.7              (0.8)
Total Tracked Costs                                              25.8                     39.1               7.5
Total Operations and Maintenance                             $   63.0

$ 77.6 $ 18.3

Depreciation expense increased in 2022, as compared to 2021, for CL&P, NSTAR Electric and PSNH due to higher net plant in service balances.

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 2022, as compared to 2021, 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 that are included in the
non-bypassable component of the FMCC mechanism, which can fluctuate from period
to period based on the timing of
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costs incurred and related rate changes to recover these costs. The increase in
the FMCC mechanism was driven primarily by the net costs and benefits of the
long-term state approved contracts that CL&P executed with Millstone and
Seabrook, among others. 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 increase at NSTAR Electric was due to the deferral adjustment of energy
supply, energy-related costs and other tracked costs.
•The decrease at PSNH was due to the deferral adjustment of energy-related and
other tracked 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 2022, as compared to 2021, due primarily
to the following:

•The increases at CL&P and NSTAR Electric 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.
•The decrease at PSNH was due to the deferral adjustment and the timing of the
recovery of energy efficiency costs.

Taxes Other Than Income Taxes increased in 2022, as compared to 2021, due primarily to the following:

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

Interest Expense increased in 2022, as compared to 2021, due primarily to the following:

•The increase at CL&P was due primarily to an increase in interest expense on
regulatory deferrals ($3.4 million), higher interest on long-term debt ($0.8
million), and higher amortization of debt discounts and premiums, net ($0.3
million), partially offset by an increase in capitalized AFUDC related to debt
funds ($1.9 million).
•The increase at NSTAR Electric was due primarily to higher interest on
long-term debt ($19.9 million), an increase in interest expense on regulatory
deferrals ($3.0 million), and higher amortization of debt discounts and
premiums, net ($0.5 million), partially offset by lower interest resulting from
the 2022 payment of withheld property taxes ($5.0 million), and an increase in
capitalized AFUDC related to debt funds ($1.7 million).
•The increase at PSNH was due primarily to higher interest expense on regulatory
deferrals ($3.2 million), higher interest on short-term notes payable ($2.1
million), higher interest on long-term debt ($0.6 million), partially offset by
lower amortization of debt discounts and premiums, net ($1.6 million), a
decrease in RRB interest expense ($1.4 million), and an increase in capitalized
AFUDC related to debt funds ($0.6 million).

Other Income, Net increased in 2022, as compared to 2021, 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 ($49.2 million), an increase in
capitalized AFUDC related to equity funds ($5.9 million) and an increase in
interest income primarily on regulatory deferrals ($0.6 million), partially
offset by investment losses in 2022 compared to investment income in 2021 driven
by market volatility ($2.6 million).
•The increase at NSTAR Electric was due primarily to an increase related to
pension, SERP and PBOP non-service income components ($45.3 million), an
increase in interest income primarily on regulatory deferrals ($17.3 million),
an increase in capitalized AFUDC related to equity funds ($4.2 million) and an
increase in investment income ($1.1 million).
•The increase at PSNH was due primarily to an increase related to pension, SERP
and PBOP non-service income components ($16.5 million), an increase in
capitalized AFUDC related to equity funds ($0.9 million) and an increase in
interest income primarily on regulatory deferrals ($0.7 million).

Income Tax Expense increased in 2022, as compared to 2021, due primarily to the following:

•The increase at CL&P was due primarily to higher pre-tax earnings ($36.0
million), higher state taxes ($2.3 million), an increase in valuation allowances
($8.0 million), a decrease in amortization of EDIT ($0.6 million) and lower
share-based payment excess tax benefits ($0.8 million), partially offset by
lower return to provision adjustments ($6.3 million) and a decrease in items
that impact our tax rate as a result of regulatory treatment (flow-through
items) and permanent differences ($1.5 million).
•The increase at NSTAR Electric was due primarily to a decrease in amortization
of EDIT ($14.0 million), an increase in pre-tax earnings ($8.7 million), higher
state taxes ($2.8 million), and lower share-based payment excess tax benefits
($0.6 million), partially offset by a decrease in items that impact our tax rate
as a result of regulatory treatment (flow-through items) and permanent
differences ($0.4 million).
•The increase at PSNH was due primarily to higher pre-tax earnings ($6.9
million), higher state taxes ($3.2 million), a decrease in amortization of EDIT
($2.8 million), and an increase in items that impact our tax rate as a result of
regulatory treatment (flow-through items) and permanent differences ($1.3
million), partially offset by a decrease in return to provision adjustments
($2.3 million).

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EARNINGS SUMMARY

CL&P's earnings increased $131.2 million in 2022, as compared to 2021, due
primarily to the absence in 2022 of the October 1, 2021 settlement agreement
that resulted in a $75 million pre-tax charge to earnings and a $28.6 million
pre-tax charge to earnings for a 2021 storm performance penalty imposed by PURA
as a result of CL&P's preparation for, and response to, Tropical Storm Isaias.
The after-tax impact of the settlement agreement and storm performance penalty
imposed by PURA was $86.1 million. Earnings were also favorably impacted by
higher earnings from its capital tracking mechanism due to increased electric
system improvements, an increase in transmission earnings driven by a higher
transmission rate base and lower pension plan expense. The earnings increase was
partially offset by higher operations and maintenance expense driven primarily
by a $10 million pre-tax charge to earnings as a result of CL&P's commitment to
contribute to an energy assistance program as part of its 2022 rate relief plan,
higher storm costs, higher shared corporate costs resulting from the
implementation of new information technology systems and higher insurance
reserves, as well as higher depreciation expense and higher property and other
tax expense.

NSTAR Electric's earnings increased $15.8 million in 2022, as compared to 2021,
due primarily to the base distribution rate increase effective January 1, 2022,
an increase in transmission earnings driven by a higher transmission rate base,
and an increase in interest income primarily on regulatory deferrals. The
earnings increase was partially offset by higher operations and maintenance
expense driven primarily by higher shared corporate costs resulting from the
implementation of new information technology systems and higher storm costs, as
well as higher property tax expense, higher depreciation expense, and higher
interest expense.

PSNH's earnings increased $21.3 million in 2022, as compared to 2021, due
primarily to an increase in transmission earnings driven by a higher
transmission rate base, lower pension plan expense, and the base distribution
rate increases effective August 1, 2021 and November 1, 2022. The earnings
increase was partially offset by higher operations and maintenance expense
driven primarily by higher storm costs and higher shared corporate costs
resulting from the implementation of new information technology systems, the
absence in 2022 of a favorable impact of a new tracker mechanism at PSNH
approved as part of the 2020 rate settlement agreement that was recorded in
2021, and higher depreciation expense.

LIQUIDITY

Cash Flows: CL&P had cash flows provided by operating activities of $869.6
million in 2022, as compared to $612.9 million in 2021.  The increase in
operating cash flows was due primarily to an increase in regulatory
over-recoveries driven by the timing of collections for the non-bypassable FMCC
and other regulatory tracking mechanisms, the timing of cash payments made on
our accounts payable, the absence in 2022 of pension contributions of $98.9
million made in 2021, an increase in earnings after adjustment for non-cash
items primarily due to higher revenues, and a $24.2 million decrease in cost of
removal expenditures. The impact of regulatory collections are included in both
Regulatory Over/Under Recoveries and Amortization of Regulatory Assets on the
statements of cash flows. These favorable impacts were partially offset by the
timing of cash collections on our accounts receivable, a $79.2 million increase
in income tax payments made in 2022, as compared to 2021, $72.0 million of
customer credits distributed in 2022 as a result of the October 2021 settlement
agreement and the 2021 storm performance penalty for CL&P's response to Tropical
Storm Isaias, and the timing of other working capital items.

NSTAR Electric had cash flows provided by operating activities of $771.5 million
in 2022, as compared to $700.9 million in 2021.  The increase in operating cash
flows was due primarily to an increase in earnings after adjustment for non-cash
items primarily due to higher revenues, a decrease in regulatory
under-recoveries driven by the timing of collections for regulatory tracking
mechanisms, a $50.4 million decrease in income tax payments made in 2022, as
compared to 2021, the timing of cash collections on our accounts receivable, a
$15.0 million decrease in pension contributions made in 2022, as compared to
2021, and the timing of other working capital items. The impact of regulatory
collections are included in both Regulatory Over/Under Recoveries and
Amortization of Regulatory Assets on the statements of cash flows. These
favorable impacts were partially offset by $76.3 million of payments in 2022
related to withheld property taxes, a $34.0 million increase in cash payments
for storm costs, and the timing of cash payments made on our accounts payable.

PSNH had cash flows provided by operating activities of $361.5 million in 2022,
as compared to $336.1 million in 2021. The increase in operating cash flows was
due primarily to the timing of cash payments made on our accounts payable and an
increase in earnings after adjustment for non-cash items primarily due to higher
revenues. These favorable impacts were partially offset by the timing of cash
collections on our accounts receivable, a decrease in regulatory over-recoveries
driven by the timing of collections for regulatory tracking mechanisms, the
timing of other working capital items, a $9.1 million increase in cost of
removal expenditures, and a $7.2 million increase in income tax payments made in
2022, as compared to 2021. The impact of regulatory collections are included in
both Regulatory Over/Under Recoveries and Amortization of Regulatory Assets on
the statements of cash flows.

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.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

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

Other Risk Management Activities

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

Interest Rate Risk Management:  We manage our interest rate risk exposure in
accordance with our written policies and procedures by maintaining a mix of
fixed and variable rate long-term debt.  As of December 31, 2022, approximately
98 percent of our long-term debt was at a fixed interest rate. The remaining
long-term debt is at variable interest rates and is subject to interest rate
risk that could result in earnings volatility. Assuming a one percentage point
increase in our variable interest rates, annual interest expense would have
increased by a pre-tax amount of $3.5 million.

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

Our regulated companies are subject to credit risk from certain long-term or
high-volume supply contracts with energy marketing companies.  Our regulated
companies manage the credit risk with these counterparties in accordance with
established credit risk practices and monitor contracting risks, including
credit risk.  As of December 31, 2022, our regulated companies held collateral
(letters of credit or cash) of $32 million from counterparties related to our
standard service contracts. As of December 31, 2022, Eversource had
$35.7 million of cash posted with ISO-NE related to energy transactions. For
further information on cash collateral deposited and posted with counterparties,
see Note 1M, "Summary of Significant Accounting Policies - Supplemental Cash
Flow Information," to the financial statements.

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

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