PUBLIC SERVICE CO OF NEW HAMPSHIRE - 10-Q Quarterly Report

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FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002
------------------
OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________ to ________

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

1-5324 NORTHEAST UTILITIES 04-2147929
(a Massachusetts voluntary association)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
Telephone: (413) 785-5871

0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850
(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616
Telephone: (860) 665-5000

1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03101-1134
Telephone: (603) 669-4000

0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130
(a Massachusetts corporation)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
Telephone: (413) 785-5871

Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.

Yes X No
--- ---

Indicate the number of shares outstanding of each of the issuers' classes of
common stock, as of the latest practicable date:

Company - Class of Stock Outstanding at October 31, 2002
- ------------------------ -------------------------------

Northeast Utilities
Common shares, $5.00 par value 128,507,340 shares

The Connecticut Light and Power Company
Common stock, $10.00 par value 6,811,994 shares

Public Service Company of New Hampshire
Common stock, $1.00 par value 388 shares

Western Massachusetts Electric Company
Common stock, $25.00 par value 434,653 shares

GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that
are found throughout this report:

COMPANIES

CL&P....................... The Connecticut Light and Power Company
NAEC....................... North Atlantic Energy Corporation
NGC........................ Northeast Generation Company
NGS........................ Northeast Generation Services Company
NU or the company.......... Northeast Utilities
NU system.................. The Northeast Utilities system companies,
including NU and its wholly owned
operating subsidiaries: CL&P, PSNH,
WMECO, NAEC, and Yankee Gas
NUEI Parent................ NU Enterprises, Inc.
PSNH....................... Public Service Company of New Hampshire
Select Energy.............. Select Energy, Inc. (including its wholly
owned subsidiary SENY)
SENY....................... Select Energy New York, Inc.
SESI....................... Select Energy Services, Inc.
WMECO...................... Western Massachusetts Electric Company
Yankee..................... Yankee Energy System, Inc.
Yankee Gas................. Yankee Gas Services Company
YESCO...................... Yankee Energy Services Company

NUCLEAR UNIT

Seabrook................... Seabrook Unit No. 1, a 1,148 megawatt nuclear
electric generating unit completed in 1986;
Seabrook went into service in 1990.

REGULATORS

DPUC....................... Connecticut Department of
Public Utility Control
DTE........................ Massachusetts Department of
Telecommunications and Energy
NHPUC...................... New Hampshire Public Utilities Commission
SEC........................ Securities and Exchange Commission

OTHER

CSC........................ Connecticut Siting Council
EITF....................... Emerging Issues Task Force
EPS........................ Earnings per share
FASB....................... Financial Accounting Standards Board
FPPAC...................... Fuel and purchased-power adjustment clause
IERM....................... Infrastructure Expansion Rate Mechanism
kWh........................ Kilowatt-hour
MW......................... Megawatts
NU 2001 Form 10-K.......... The NU system combined 2001 Form 10-K as
filed with the SEC
O&M........................ Operation and maintenance
SFAS....................... Statement of Financial Accounting Standards

Northeast Utilities and Subsidiaries
The Connecticut Light and Power Company and Subsidiaries
Public Service Company of New Hampshire and Subsidiaries
Western Massachusetts Electric Company and Subsidiary

TABLE OF CONTENTS
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Page
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Part I. Financial Information

Item 1. Consolidated Financial Statements (Unaudited)

and

Item 2. Management's Discussion and
Analysis of Financial Condition
and Results of Operations

For the following companies:

Northeast Utilities and Subsidiaries

Consolidated Balance Sheets -
September 30, 2002 and December 31, 2001.............. 2

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2002 and 2001........................... 4

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2002 and 2001......... 5

Management's Discussion and Analysis of
Financial Condition and Results of Operations......... 6

Independent Accountants' Report....................... 29

Notes to Consolidated Financial Statements
(unaudited - all companies)................................. 30

The Connecticut Light and Power Company
and Subsidiaries

Consolidated Balance Sheets -
September 30, 2002 and December 31, 2001.............. 50

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2002 and 2001........................... 52

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2002 and 2001......... 53

Management's Discussion and Analysis of
Financial Condition and Results of Operations......... 54

Public Service Company of New Hampshire
and Subsidiaries

Consolidated Balance Sheets -
September 30, 2002 and December 31, 2001.............. 60

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2002 and 2001........................... 62

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2002 and 2001......... 63

Management's Discussion and Analysis of
Financial Condition and Results of Operations......... 64

Western Massachusetts Electric Company
and Subsidiary

Consolidated Balance Sheets -
September 30, 2002 and December 31, 2001.............. 70

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2002 and 2001........................... 72

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2002 and 2001......... 73

Management's Discussion and Analysis of
Financial Condition and Results of Operations......... 74

Item 3. Quantitative and Qualitative
Disclosures About Market Risk......................... 77

Item 4. Controls and Procedures............................... 77

Part II. Other Information

Item 1. Legal Proceedings..................................... 78

Item 6. Exhibits and Reports on Form 8-K...................... 79

Signatures and Certifications Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.................................... 82

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

Management's Discussion and Analysis of
Financial Condition and Results of Operations

This discussion should be read in conjunction with the consolidated financial
statements and footnotes in this Form 10-Q, the First and Second Quarter 2002
Form 10-Qs, current reports on Form 8-K dated July 23, 2002, August 2, 2002,
August 14, 2002, October 8, 2002, and October 21, 2002, and the 2001 Form
10-K. All per share amounts are reported on a fully diluted basis.

FINANCIAL CONDITION

Overview

Northeast Utilities and subsidiaries (NU or the company) earned $48.6
million, or $0.38 per share, during the third quarter of 2002, compared with
earnings of $34.6 million, or $0.26 per share, during the same period of
2001. For the first nine months of 2002, NU earned $96.1 million, or $0.74
per share, compared with $193.5 million, or $1.41 per share, during the same
period of 2001.

During the third quarter of 2002, NU recorded a net after-tax gain of $14.5
million, or $0.11 per share, primarily related to the elimination of reserves
associated with NU's ownership shares of Seabrook unit 2. During the first
quarter of 2002, NU recorded after-tax charges of $10 million, or $0.08 per
share, associated with the write-down of our investments in NEON
Communications, Inc. (NEON) and Accumentrics Corporation. Excluding these
items, NU earned $34.1 million, or $0.27 per share, during the third quarter
of 2002 and $91.6 million, or $0.71 per share, during the first nine months
of 2002. On November 1, 2002, a subsidiary of the FPL Group, Inc. (FPL)
purchased NU's 40.04 percent combined shares of Seabrook. During the fourth
quarter NU will record approximately $10 million of additional net after-tax
gains associated with the sale.

During the first nine months of 2001, NU recorded a gain related to the sale
of the Millstone nuclear units, which occurred in March 2001, a loss related
to the adoption of Statement of Financial Accounting Standards (SFAS) No.
133, "Accounting for Derivative Instruments and Hedging Activities," as
amended, and a loss related to the forward repurchase of 10.1 million NU
common shares. Excluding these items, NU earned $126.5 million, or $0.92 per
share, during the first nine months of 2001.

The decline in NU's earnings for the first nine months of 2002 resulted
primarily from weaker performance at the competitive energy subsidiaries.
During the first nine months of 2002, NU's competitive energy subsidiaries
lost $39.9 million, compared with essentially break-even results during the
same period of 2001, before the cumulative effect of an accounting change of
$22 million. These weaker results are related primarily to mild weather in
the first quarter of 2002, which caused significant losses serving
unregulated retail gas and electric customers, natural gas trading losses in
March and April 2002, and low water flows, which reduced conventional
hydroelectric production. NU's competitive energy subsidiaries lost $9
million, or $0.07 per share, in the third quarter of 2002, compared with a
loss of $9.7 million, or $0.07 per share, during the same period of 2001.

NU's revenues during the first nine months of 2002 decreased to $3.8 billion
from $4.7 billion during the same period of 2001. The decrease in revenues
relates to lower wholesale marketing revenues at the competitive energy
subsidiaries as a result of wholesale contracts not being renewed at the same
prices and volumes for 2002. Also contributing to the revenue decrease is
lower regulated company wholesale revenues from lower sales of energy and
capacity in New Hampshire and from 2001 sales of output from the Millstone
units. Regulated retail revenues also decreased, primarily due to rate
decreases associated with industry restructuring and lower industrial sales to
New Hampshire customers.

NU's regulated electric subsidiaries benefited from an extremely hot summer.
Third quarter 2002 residential electric sales increased 10.9 percent and
commercial electric sales increased 6.0 percent, while industrial sales
decreased 1.6 percent due to weaker economic conditions compared with the
same period of 2001. Overall, third quarter 2002 total electric sales
increased 6.4 percent compared with the same period of 2001. During the first
nine months of 2002, total electric sales increased 0.6 percent compared with
the same period of 2001.

Revenues of NU's competitive energy subsidiaries were reduced significantly
from amounts previously reported as a result of recently released accounting
guidance related to the classification of revenues and expenses associated
with energy trading contracts. As a result, NU's revenues and expenses for
the first six months of 2002 have been reduced by $1.2 billion with no change
in net income. The retroactive reclassification of revenues and expenses,
combined with the unavailability of the company's previous independent public
accountants, has resulted in the requirement to have the company's financial
information as of and for the year ended December 31, 2001, reaudited.
Management does not expect the reaudit of this financial information to have
a material impact on amounts previously reported other than the
reclassification of revenues and expenses itself.

NU's trading revenues and expenses for all periods presented have been
reclassified. The changes to 2001 information that was previously reported
are included in Note 1C, "New Accounting Standards," to the consolidated
financial statements. On October 25, 2002, the Emerging Issues Task Force
(EITF) decided to rescind the consensus reached in EITF Issue No. 98-10,
"Accounting for Energy Trading and Risk Management Activities," under which
the competitive energy subsidiaries currently account for trading activities
on a mark-to-market basis. For information regarding this change in
accounting, which will impact the competitive energy subsidiaries in the
future, see Note 1C, "New Accounting Standards," to the consolidated
financial statements.

NU's earnings per share in both 2002 and 2001 benefited from the company's
ongoing share repurchase program. NU had approximately 129.3 million shares
outstanding as of September 30, 2002, compared with 130.1 million shares
outstanding as of December 31, 2001. NU repurchased approximately 14.3
million shares in 2001 and approximately 1.8 million additional shares during
the first nine months of 2002. NU's Board of Trustees has authorized the
repurchase of approximately 9 million additional shares through June 30,
2003. NU has repurchased approximately 880,000 shares at an average share
price of $14.98 from October 1, 2002 through October 31, 2002.

Earnings before preferred dividends at The Connecticut Light and Power
Company (CL&P), NU's largest regulated subsidiary, totaled $29.3 million for
the third quarter of 2002, and $62.4 million for the first nine months of
2002, compared with $18.8 million for the third quarter of 2001 and $75.9
million for the first nine months of 2001. The third quarter 2002 increase
was primarily due to a weather-driven 7.6 percent increase in retail sales,
compared with the same period of 2001. The lower earnings for the first nine
months of 2002 were primarily due to an after-tax gain of $19.1 million
recorded during the first quarter of 2001 as a result of the Millstone sale,
offset by the aforementioned increase in retail sales.

Combined earnings before preferred dividends at Public Service Company of New
Hampshire (PSNH) and North Atlantic Energy Corporation (NAEC) totaled $36.4
million for the third quarter of 2002, and $67.1 million for the first nine
months of 2002, compared with $21.8 million for the third quarter of 2001 and
$76.1 million for the first nine months of 2001. The third quarter 2002
increase was primarily due to the elimination of the Seabrook-related reserve
at NAEC. The lower earnings for the first nine months of 2002 were primarily
due to an after-tax gain of $15.5 million recorded during the first quarter
of 2001 associated with the sale of PSNH's share of the Millstone 3 nuclear
unit and to a greater than 10 percent retail rate reduction that took effect
on May 1, 2001, in connection with industry restructuring, offset by the
aforementioned elimination of the Seabrook reserve at NAEC.

Earnings before preferred dividends at Western Massachusetts Electric Company
(WMECO) totaled $4.7 million during the third quarter of 2002, and $26.9
million for the first nine months of 2002, compared with $3.9 million for the
third quarter of 2001 and $8.7 million for the first nine months of 2001.
The third quarter 2002 increase was primarily due to hotter weather, compared
with the same period of 2001. The higher earnings for the first nine months
of 2002 were primarily due to the recognition during 2002 of approximately
$13 million in tax credits as a result of a regulatory decision received
during the second quarter of 2002 and due to a first quarter 2001 refueling
outage at the Millstone 3 nuclear unit.

Yankee Energy System, Inc. (Yankee) lost $5.8 million during the third
quarter of 2002 and earned $6.3 million during the first nine months of 2002,
compared with earnings of $3.2 million during the third quarter of 2001 and
earnings of $12.1 million during the first nine months of 2001. The lower
earnings for 2002 were primarily due to the recording of approximately $10
million after-tax in August of 2001 related to a favorable property tax
settlement.

Future Outlook

NU currently estimates it will earn between $1.10 per share and $1.30 per
share in 2002. That estimate assumes that NU will earn between $0.36 and
$0.56 per share in the fourth quarter of 2002, including net after-tax gains
of approximately $10 million related to the sale of Seabrook in the fourth
quarter of 2002, compared to $0.38 per share in 2001. The range also assumes
losses of between $10 million and $20 million at NU's competitive energy
subsidiaries in the fourth quarter of 2002, compared with earnings of $5.3
million in the fourth quarter of 2001. The reduction in fourth quarter 2002
earnings compared to the fourth quarter of 2001 is primarily due to reduced
gains related to contract restructuring. Offsetting weaker projected
performance at NU's competitive businesses will be a lower share count and an
expected return to normal weather from the mild November and December of
2001. The earnings range also reflects management's uncertainty over the
outcome of regulatory dockets in Connecticut, New Hampshire and Massachusetts
related to the recovery of certain stranded costs, which management believes
were prudently incurred and are probable of recovery.

NU also expects to earn between $1.10 per share and $1.30 per share in 2003.
That estimate assumes earnings of between $1.05 per share and $1.15 per share
at NU's regulated businesses and between $0.15 and $0.25 at NU's competitive
energy subsidiaries. NU also assumes it will incur after-tax costs of
approximately $0.10 per share at the parent company, primarily related to
debt expenses. The 2003 earnings range assumes significantly lower earnings
at NU's regulated businesses and significantly improved results at NU's
competitive businesses, compared with 2002. Lower earnings at the regulated
businesses are related primarily to the absence of 2002 gains related to
Seabrook, lower investment tax credits and to much lower pension income.
Improved results at NU's competitive energy subsidiaries are projected as a
result of an improvement to modest profitability in its trading function and
to break-even in its retail marketing function. The competitive energy
subsidiaries are expected to lose approximately $50 million to $60 million in
2002.

As a result of continued poor performance in the equity markets in 2002, the
NU system is projecting approximately $34 million of pre-tax pension income
in 2003, a decrease from approximately $73 million in 2002 and approximately
$101 million in 2001. The lower 2003 pension income primarily affects NU's
regulated businesses, particularly CL&P and WMECO. Offsetting the impact the
lower pension income will have on earnings is the amount of pension income
that will be capitalized as utility plant. Approximately 30 percent of
pension income has been capitalized as utility plant in the past along with
other costs related to employees who work on capital projects. The
percentage of pension income capitalized depends on the scope of capital
programs at the regulated businesses. The lower pension income and higher
projected health care costs will also be partially offset by a reduction in
the number of employees at NU. In September 2002, the NU system reduced its
workforce by approximately 200 employees and expects to reduce its contractor
workforce by approximately 100 contractors by the beginning of 2003.
Together, these workforce reductions are expected to result in approximately
a $20 million pre-tax reduction in costs in 2003. Management believes that
most of the cost of the workforce reduction, which was approximately $5
million, is recoverable from ratepayers as a stranded cost related to
industry restructuring.

Liquidity

NU maintained a high level of liquidity throughout the first nine months of
2002, and maintaining liquidity remains a significant focus for NU. As of
September 30, 2002, NU had $70.7 million in cash and cash equivalents on
hand. In addition to cash and cash equivalents on hand, NU has access to
approximately $415 million through available credit facilities. NU expects
its cash position to further improve in the fourth quarter of 2002 due to the
sale of CL&P's and NAEC's combined 40.04 percent shares of Seabrook on
November 1, 2002. CL&P and NAEC received approximately $370 million in total
gross proceeds, which are subject to certain true-up adjustments. Of the
total cash proceeds NU received from the Seabrook sale, a portion of these
proceeds were used to repay all $90 million of NAEC's outstanding debt, and
will be used to return all of NAEC's equity, which totaled $55.7 million as
of September 30, 2002, to NU and pay between $90 million and $100 million in
taxes. The remaining proceeds were refunded to PSNH through the Seabrook
Power Contracts. PSNH will use the proceeds refunded from NAEC to recover
stranded costs and repay approximately $60 million of debt with any remaining
amounts being available to be returned to NU. The net gain from the sale
related to CL&P's share of Seabrook primarily will be used to offset stranded
costs, and the cash proceeds received by CL&P will be used to meet its
capital requirements. NU additionally received approximately $14 million
from an unaffiliated owner of Seabrook upon the close of the sale. NU
expects to use these additional proceeds, the $55.7 million from NAEC and any
amounts received from PSNH to reduce short-term borrowings, fund continued
share repurchases, and continue to maintain a high level of liquidity within
the NU system.

NU had no significant financing activity in the third quarter of 2002. In
November 2002, NU expects to refinance its two principal credit lines. It
expects to decrease to $300 million from $350 million a line of credit for
its regulated subsidiaries. It also expects to increase to $350 million its
$300 million line of credit for the parent company and NU's competitive
energy subsidiaries. As of September 30, 2002, PSNH, WMECO and Yankee had
$55 million, $55 million, and $40 million, respectively, outstanding under
the regulated company credit line. Also, as of September 30, 2002, NU parent
and NU's competitive energy subsidiaries had a total of $75 million of direct
borrowings and $70.4 million of letters of credit outstanding. Total direct
borrowings included $55 million, $10 million, and $10 million advanced by NU
parent through the NU system Money Pool to Select Energy, Inc. (Select
Energy) Northeast Generation Services Company (NGS) and Select Energy
Services, Inc. (SESI), respectively. The $70.4 million represents letters of
credit issued to counterparties with whom Select Energy has energy contracts
and to other parties.

NU projects a modest level of system financings over the next three to six
months. CL&P is currently contemplating the issuance of up to $200 million
of debt to refinance its spent nuclear fuel obligations. WMECO has applied
to the Massachusetts Department of Telecommunications and Energy (DTE) to
issue $100 million of debt to refinance its existing short-term debt and
spent nuclear fuel obligations. Yankee Gas Services Company (Yankee Gas) may
seek to issue up to $75 million of debt to reduce short-term debt, which
totaled $66 million as of September 30, 2002. In 2001, NU applied to the
Securities and Exchange Commission (SEC) to increase to $750 million from
$500 million its authority to provide credit assurance in the form of
guarantees and letters of credit for the financial performance obligations of
certain of its competitive energy subsidiaries, including Select Energy. In
addition, NU has applied to the SEC for authority to exempt Select Energy,
Select Energy New York, Inc. (SENY) and certain other subsidiaries from the
SEC rule limiting NU's "aggregate investment" in such companies to 15 percent
of NU's most recent quarterly capitalization. The SEC has not indicated
when, or if, it will authorize these increases, and its failure to do so
could restrict Select Energy's future growth potential.

Over the longer term, a low level of maturities and sinking fund payments
will mitigate the NU system's need to obtain funds from the capital markets.
In 2003, 2004, and 2005, total system maturities total $54 million, $58
million, and $87 million, respectively.

NU's net cash flows provided by operating activities increased to $467.1
million in the first nine months of 2002, compared with $399.2 million during
the same period of 2001. Cash flows provided by operating activities
increased primarily due to taxes payable in 2001 in connection with the sale
of the Millstone units. Also contributing to the increase is the
amortization of recoverable energy costs in 2002 compared with deferrals in
2001. Changes in working capital items also contributed to the increase.

There was a lower level of investing and financing activities in the first
nine months of 2002, as compared to the same period of 2001, primarily due to
the sale of the Millstone units, the buyout and buydown of independent power
producer contracts, and the issuance of CL&P, PSNH and WMECO rate reduction
certificates and bonds in 2001. The level of NU's common dividends totaled
$50.2 million in the first nine months of 2002, compared with $44.5 million
in the same period of 2001. This increase was a result of NU paying a $0.10
per share quarterly common dividend in the first two quarters of 2001, a
$0.125 per share quarterly common dividend in the last two quarters of 2001
and the first two quarters of 2002, and a $0.1375 dividend in the third
quarter of 2002. The increase in common dividends was partially offset by a
lower share count.

On May 14, 2002, NU's Board of Trustees approved payment of a quarterly cash
dividend of $0.1375 per share, payable on September 30, 2002, to shareholders
of record as of September 1, 2002. This increase is consistent with the
company's announced intention of raising the dividend by 10 percent annually.
Management has stated that NU may consider raising the dividend target beyond
the previously stated goal of paying out approximately 50 percent of
regulated company earnings. Such a program will be dependent upon numerous
factors, including NU's ability to meet earnings targets and the judgment of
its Board of Trustees at the time dividends are declared.

Competitive Energy Subsidiaries

Subsidiaries: NU's competitive energy subsidiaries include Select Energy and
its subsidiary SENY (collectively Select Energy), Northeast Generation
Company (NGC), Holyoke Water Power Company (HWP), SESI and NGS. Select
Energy engages in wholesale and retail energy marketing activities and energy
trading activities.

NU's competitive energy subsidiaries own 1,439 megawatts (MW) of generation
capacity, consisting of 1,292 MW at NGC and 147 MW at HWP. On June 17, 2002,
the air circuit breaker in one of NGC's four 270-megawatt pumped storage
units at Northfield Mountain was damaged by fire. This unit returned to
service on September 4, 2002. Northfield Mountain's other three units were
not damaged and continued to operate. NGC carries property insurance and
business interruption insurance for Northfield Mountain. As a result, the
fire did not have a material effect on NU's or NGC's financial position or
results of operations.

SESI performs energy management services for large industrial, commercial and
institutional facilities, including the United States Department of Defense,
and engages in energy related construction services. NGS operates and
maintains NGC's and HWP's generation assets and provides third-party
electrical and engineering contracting services.

Consistent with its business strategy, the competitive energy subsidiaries
acquired certain assets and assumed certain liabilities of an electrical
services company and a telecommunications, construction and service company
for an aggregate purchase price of $15.3 million on July 1, 2002. Financial
results of the acquired companies are included in NU's results of operations
since July 1, 2002. For further information regarding this acquisition, see
Note 3, "Goodwill and Other Intangible Assets," to the consolidated financial
statements.

Results: NU's competitive businesses lost $39.9 million after-tax through
the first three quarters of 2002 and are expected to lose another $10 million
to $20 million after-tax in the fourth quarter of 2002. This compares to
break-even results in the first three quarters of 2001 and a profit of
approximately $5 million after-tax in the fourth quarter of 2001. Those
break-even results for the first three quarters of 2001 exclude a $22 million
cumulative effect of an accounting change related to the negative fair value
of derivative contracts, primarily at Select Energy's retail marketing
business. Most of these contracts expire in 2002. In the first quarter of
2002, NU's competitive businesses lost approximately $22 million, which
included after-tax gains of $7 million associated with the renegotiation of
certain long-term supply contracts. The first quarter losses included an
after-tax loss of $10.6 million in the energy trading area, primarily as a
result of a steep increase in the cost of natural gas in the month of March.
The competitive retail business lost $13.9 million in the first quarter of
2002 primarily due to unusually mild weather that reduced the consumption of
natural gas, requiring Select Energy to sell excess natural gas back into
the market at lower prices.

In the second quarter of 2002, the competitive businesses lost approximately
$9 million. Much of that loss was related to $7.1 million of after-tax
losses in the trading area, again resulting from higher natural gas prices in
April 2002. In the third quarter of 2002, the competitive businesses lost
approximately $9 million, primarily due to unexpectedly high demand brought
on by an extremely hot summer. The hot weather caused Select Energy to buy
electricity in the spot market as wholesale electricity prices were rising.
The trading function lost $1.3 million after-tax in the third quarter.

Outlook: In the fourth quarter of 2002 management expects Select Energy to
continue to be negatively affected by energy price volatility. However,
management has taken steps to purchase virtually all of its projected
electricity requirements for November and December, providing more
predictability to the quarter's financial results.

Management is taking a number of steps to return the competitive energy
businesses to profitability in 2003. It has acquired additional businesses
in the energy services field and expects that projected profits of $5 million
in 2002 will increase in 2003. It has considerably reduced the amount of
capital at risk in the trading operation and projects that after-tax losses
in the range of $16 million to $19 million in 2002 will turn into modest
profits in 2003. Many unprofitable retail contracts expire in 2002. Select
Energy plans to size the retail organization to fit a reduced level of
business and expects to better manage volumetric risk, particularly in the
winter heating months. As a result, management expects to roughly break-even
in the retail business in 2003, compared with projected losses of $25 million
to $28 million in 2002.

In the wholesale marketing area, Select Energy, including NGC, expects to
have modest profits in 2003, compared with projected losses of $15 million to
$19 million in 2002. Select Energy expects the improvement to come from
improved results on its contract with CL&P, which has negatively impacted
Select Energy's results by approximately $36.4 million after-tax for the
first nine months of 2002, and improved management of the supplies associated
with its full requirements contracts. This forecast assumes that Select
Energy will be successful in securing a significant amount of new business at
acceptable margins.

CL&P's standard offer service purchases from Select Energy represented $375.7
million of total competitive energy subsidiaries' revenues for the first nine
months of 2002, compared with $378.5 million for the first nine months of
2001. Other transactions between CL&P and Select Energy amounted to $97.2
million in revenues for Select Energy for the first nine months of 2002,
compared with $116.8 million for the same period in 2001. These amounts are
eliminated in consolidation.

In the second quarter of 2002, the competitive energy subsidiaries conducted
studies of the depreciable lives of certain generation and software assets.
The impact of these studies was to lengthen the useful lives of those
generation assets by 20 years to an average of 58 remaining years and to
shorten the useful lives of that software to 1.5 remaining years effective
for the second quarter of 2002. As a result of these studies, NU's operating
expenses decreased by approximately $3 million since the beginning of the
second quarter of 2002 and are expected to decrease by approximately $6
million annually.

Competitive Energy Subsidiaries' Market and Other Risks

Overview: NU's competitive energy subsidiaries are exposed to certain market
risks inherent in their business activities. Certain competitive energy
subsidiaries, primarily Select Energy, enter into contracts of varying
lengths of time to buy and sell energy commodities, including electricity,
natural gas and oil. Market risk represents the risk of loss that may impact
Select Energy's financial results due to adverse changes in commodity market
prices.

Wholesale and Retail Marketing: A significant portion of Select Energy's
wholesale marketing business is providing energy to full requirements
customers, primarily regulated distribution companies. Under full
requirements contract terms, Select Energy is required to provide the total
energy requirement for the customers' load at all times. A key component of
Select Energy's risk management strategy is focused on managing the volume
and price risks of full requirements contracts. These risks include
significant fluctuations in supply and demand due to numerous factors such as
weather, plant availability, transmission congestion, and potentially
volatile price fluctuations. As discussed above, Select Energy's year to
date 2002 results were negatively impacted by weather patterns that resulted
in contracted supply exceeding demand in the warmer than expected winter and
committed supply during certain summer months purchased at prices higher than
those forecasted.

The competitive energy subsidiaries manage their portfolio of wholesale and
retail marketing contracts and assets to maximize value and minimize
associated risks. The lengths of contracts to buy and sell energy vary in
duration from daily/hourly to several years. At any point in time the
wholesale and retail marketing portfolio may be long (purchases exceed sales)
or short (sales exceed purchases). Portfolio and risk management disciplines
with established policies and procedures are used to manage exposures to
market risks. At forward market prices in effect at September 30, 2002, the
wholesale marketing portfolio, which includes the CL&P standard offer service
contract and other contracts that extend to 2013, had a positive mark-to-
market position. This positive mark-to-market position will impact Select
Energy's gross margin in the future. However, there is significant
volatility in the energy commodities market that will impact this position
between now and when the contracts are settled. Portfolio volatility
reflects fluctuations in value due to changes in energy prices in the region,
new transactions entered into during the period and positions settling during
the period. Accordingly, there can be no assurances that Select Energy will
realize the gross margin corresponding to the present positive mark-to-market
position on its wholesale marketing portfolios. The gross margin realized
could be at a level that is not sufficient to cover Select Energy's other
operating costs, including the cost of corporate overhead.

Wholesale and retail marketing transactions, including the full requirements
contracts, are intended to be part of Select Energy's normal purchases and
sales and are recognized on the accrual basis of accounting.

Hedging: Select Energy utilizes derivative financial and commodity
instruments (derivatives), including futures and forward contracts, to reduce
market risk associated with fluctuations in the price of electricity and
natural gas sold under firm commitments. Select Energy also utilizes
derivatives, including price swap agreements, call and put option contracts,
and futures and forward contracts, to manage the market risk associated with
a portion of its anticipated supply requirements. These derivative
instruments have been designated as cash flow hedging instruments. Cash flow
hedges are recorded as assets or liabilities and included in accumulated
other comprehensive income, which is a component of equity. These activities
impact Select Energy's earnings when the forecasted hedged transaction is
settled, when hedge ineffectiveness is measured and recorded, when the hedge
is terminated and the forecasted transaction is expected to be break-even or
less, or when the forecasted hedged transaction is no longer probable of
occurring.

During the third quarter of 2002, Select Energy determined that cash flow
hedges related to the CL&P standard offer service contract were ineffective.
In the third quarter, as a result of this ineffectiveness, Select Energy
transferred $3.9 million from accumulated other comprehensive income to
expense on the income statement related to these cash flow hedges. In
September 2002, Select Energy terminated these cash flow hedges and realized
pre-tax income of $5.6 million.

Energy Trading: Select Energy's trading of energy contracts is accounted for
using the mark-to-market method under EITF Issue No. 98-10, "Accounting for
Energy Trading and Risk Management Activities." Energy trading transactions
at Select Energy include financial transactions and physical delivery
transactions for electricity, natural gas and oil in which Select Energy is
attempting to profit from changes in market prices. For information
regarding changes in accounting for energy trading transactions that will
impact Select Energy in the future, see Note 1C, "New Accounting Standards,"
to the consolidated financial statements. As of September 30, 2002, Select
Energy had unrealized gains on mark-to-market trading transactions of $135.1
million and unrealized losses on mark-to-market trading transactions of $53.4
million on a counterparty-by-counterparty basis, for a net positive position
of $81.7 million on the entire trading portfolio. Additional information on
the trading contract portfolio is included in the following tables. There
can be no assurances that Select Energy will actually realize cash
corresponding to the present positive net mark-to-market amount on its
trading contracts. Numerous factors could either positively or negatively
affect the realization in cash of the net mark-to-market amount. These
include the volatility of commodity prices, changes in market design or
settlement mechanisms, the outcome of future transactions, the performance of
counterparties and other factors.

Select Energy has policies and procedures requiring all trading positions to
be marked-to-market at the end of each trading day. Controls are in place
segregating responsibilities between individuals actually trading (front
office) and those confirming the trades (middle office). The mark-to-market
calculations are performed by individuals in the middle office independent
from the front office. The methods used to mark-to-market energy trading
contracts are identified and segregated in the table of fair value of
contracts at September 30, 2002. A description of each method is as follows:
1) prices actively quoted primarily represent New York Mercantile Exchange
futures and options that are marked to closing exchange prices; 2) prices
provided by external sources primarily include over-the-counter forwards and
options, including bilateral contracts for the purchase or sale of
electricity or natural gas, and are marked to the mid-point of bid and ask
quotes; and 3) prices based on models or other valuation methods primarily
include forwards and options and other transactions for which specific quotes
are not available. Long-term electric power prices are modeled using
available information from external sources based on recent transactions and
validated with a gas forward curve with an estimated heat rate conversion.
Broker quotes are available through the year 2005, and models are used for
the years 2006 and thereafter.

Generally, valuations of short-term contracts derived from quotes or other
external sources are more reliable should there be a need to liquidate the
contracts, while valuations based on models or other methods for longer-term
contracts are less certain. Accordingly, there is a risk that contracts will
not be realized at the amounts recorded.

As of and for the three and nine months ended September 30, 2002, the sources
of the fair value of trading contracts and the changes in fair value of these
trading contracts are included in the following tables. Intercompany
transactions are eliminated and not reflected in the amounts below.

- -------------------------------------------------------------------------------
(Millions of Dollars) Fair Value of Contracts at September 30, 2002
- -------------------------------------------------------------------------------
Maturity Maturity of Maturity in Total
Less than One to Four Excess of Fair
Sources of Fair Value One Year Years Four Years Value
- -------------------------------------------------------------------------------
Prices actively quoted $ 1.8 $ 1.6 $ - $ 3.4
Prices provided by
external sources 12.2 35.5 15.0 62.7
Prices based on
models or other
valuation methods - 7.0 8.6 15.6
- -------------------------------------------------------------------------------
Totals $14.0 $44.1 $23.6 $81.7
- -------------------------------------------------------------------------------

At June 30, 2002, the mark-to-market of trading contracts maturing in less
than one year with prices based on models or other valuation methods was a
negative $1.9 million. During the third quarter of 2002, prices from
external sources became available to mark these contracts to market. These
contracts are now valued at a positive $1.6 million. $2.5 million of the
$3.5 million change in value is included in the following table as a change
in fair value attributable to changes in valuation techniques and
assumptions. Additionally, during the third quarter market information
regarding certain long-term contracts with prices based on models or other
valuation methods became available based on recent transactions. Select
Energy used this market information in determining the estimated fair value
of these contracts as of September 30, 2002. The result was a decrease in
value of $4.1 million, which is also included in the following table as a
change in fair value attributable to changes in valuation techniques and
assumptions. The positive $2.5 million change and the negative $4.1 million
change are reflected in the negative $1.6 million in the table below.

The decrease in the number of counterparties participating in the market for
long-term energy contracts continues to impact Select Energy's ability to
determine the estimated value of its long-term energy contracts.

- -------------------------------------------------------------------------------
(Millions of Dollars) Total Fair Value
- -------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
- -------------------------------------------------------------------------------
Fair value of contracts
outstanding at the beginning
of the period $75.5 $56.4
Contracts realized or otherwise
settled during the period (5.0) (2.9)
Fair value of new contracts when
entered into during the period - 13.7
Changes in fair values
attributable to changes in
valuation techniques and
assumptions (1.6) (6.0)
Changes in fair value of contracts 12.8 20.5
- -------------------------------------------------------------------------------
Fair value of contracts
outstanding at the end
of the period $81.7 $81.7
- -------------------------------------------------------------------------------

During the first quarter of 2002, Select Energy terminated certain long-term
energy contracts. Coincident with these contract terminations, new contracts
were entered into with different terms and conditions. Select Energy also
entered into other new contracts with existing counterparties. These new
energy trading contracts are derivatives, and collectively they had a
positive mark-to-market of $13.7 million when entered into and $14.8 million
as of September 30, 2002.

As indicated in the table above, the fair value of energy trading contracts
increased $25.3 million from $56.4 million as of January 1, 2002 to $81.7
million as of September 30, 2002. This increase, which is more than offset
by realized losses on positions taken and closed in 2002, is included in
Select Energy's gross margin and included in the $16 million to $19 million
the trading operations are expected to lose for 2002.

Counterparty Credit: Counterparty credit risk relates to the risk of loss
that Select Energy would incur as a result of non-performance by
counterparties pursuant to the terms of their contractual obligations.
Select Energy has established written credit policies with regard to its
counterparties to minimize overall credit risk. These policies require an
evaluation of potential counterparties' financial conditions (including
credit ratings), collateral requirements under certain circumstances
(including cash in advance, letters of credit, and parent guarantees), and
the use of standardized agreements, which allow for the netting of positive
and negative exposures associated with a single counterparty. This
evaluation results in establishing credit limits prior to Select Energy
entering into trading activities. The appropriateness of these limits is
subject to continuing review. Concentrations among these counterparties may
impact Select Energy's overall exposure to credit risk, either positively or
negatively, in that the counterparties may be similarly affected by changes
to economic, regulatory or other conditions. As of September 30, 2002,
approximately 70 percent of Select Energy's counterparty credit exposure to
wholesale marketing and trading counterparties is cash collateralized or
rated BBB- or better. More than two-thirds of the remaining credit exposure
is to unrated municipalities.

As of September 30, 2002, two counterparties collectively represented
approximately 33 percent of the $135.1 million unrealized gains on mark-to-
market transactions. Select Energy believes the risk associated with
collecting amounts from these counterparties is minimal, primarily due to
collateral balances or other security maintained.

Select Energy Credit: A number of Select Energy's contracts require the
posting of additional collateral in the form of cash or letters of credit in
the event NU's ratings were to decline and in increasing amounts dependent
upon the severity of the decline. At NU's present investment grade ratings,
Select Energy has not had to post any collateral based on credit downgrades.
Were NU's unsecured ratings to decline two to three notches to sub-investment
grade, Select Energy would, under its present contracts, have to provide
approximately $162 million of collateral to various counterparties, which NU,
under present circumstances, would be able to provide Select Energy from
available sources of funds. NU's ratings are currently stable, and
management does not believe that at this time there is a significant risk of
a ratings downgrade to sub-investment grade levels.

Changing Market: The breadth and depth of the market for energy trading and
marketing products in Select Energy's market has been adversely affected by
the withdrawal or financial weakening of a number of companies who have
historically done significant amounts of business with Select Energy. In
general, the market for such products has become shorter term in nature, with
less liquidity and participants less able to meet Select Energy's credit
standards without providing cash or letter of credit support. Select Energy
is being adversely affected by these factors, and there could be a continuing
adverse impact on Select Energy's business prospects.

Changes are occurring in the administration of transmission systems in
territories in which Select Energy does business. Regional transmission
organizations are being contemplated, and other changes are occurring within
transmission regions. For example, the implementation of a standard market
design in New England is expected to occur in 2003, and will create
challenges and opportunities for Select Energy. The impact of standard
market design implementation on Select Energy's existing positions cannot yet
be determined but could have an adverse effect.

For further information regarding Select Energy's activities and risks see
Note 4, "Market Risk and Risk Management Instruments," and Note 6,
"Comprehensive Income," to the consolidated financial statements.

Business Development and Capital Expenditures

NU's capital expenditures totaled $327.3 million in the first nine months of
2002, compared with $318 million in the first nine months of 2001. NU
currently projects year end 2002 capital expenditures to approximate $500
million, approximately $100 million lower than the company had projected at
the beginning of 2002. The primary reasons for the lower 2002 capital
expenditure projection are delays in commencing work on high voltage electric
transmission projects and lower projected capital spending at Yankee Gas.
Those changes have been partially offset by increased capital expenditures
for CL&P's electric distribution system.

In 2001, CL&P announced plans for three high voltage transmission projects in
southwestern Connecticut. The Connecticut Siting Council (CSC) approved the
first project, replacement of an existing 138,000 volt line between Norwalk,
Connecticut and Northport - Long Island, New York, in September 2002.
Additional approvals are required from federal and New York state agencies.
CL&P currently expects to complete the manufacture and installation of the
cable in 2003 and early 2004, respectively. CL&P would share the $80 million
cost of this project with the Long Island Power Authority (LIPA), which
jointly owns the existing cable. As of September 30, 2002, CL&P has
capitalized approximately $3.8 million related to this project.

For the second project, CL&P proposed building a new 345,000 volt
transmission line facility along an existing right-of-way between Norwalk,
Connecticut and Bethel, Connecticut at an estimated cost of $135 million.
The restart of CSC hearings on that project has been postponed until at least
November 2002, and a decision is now expected in April 2003. As of
September 30, 2002, CL&P has capitalized approximately $1.3 million related
to this project. In May 2002, legislation was adopted in Connecticut
authorizing a moratorium on the approval of additional electric and natural
gas transmission crossings of Long Island Sound, which included a delay of
decisions on the Bethel to Norwalk project and established task forces to
study certain issues associated with siting electric and natural gas lines.
As a result, no decision can be made by the CSC any earlier than February 1,
2003. The aforementioned CL&P-LIPA replacement cable is exempt from the
moratorium.

For the third project, CL&P announced plans for a separate $400 million
345,000 volt transmission line between Norwalk, Connecticut and Middletown,
Connecticut. CL&P expects to apply to the CSC for approval of the project in
2003. As of September 30, 2002, CL&P has capitalized approximately $4.4
million related to this project.

Merchant Energy Company Counterparty Exposures

Certain subsidiaries of NU have entered into various transactions with
subsidiaries of NRG Energy, Inc. (NRG). NRG's credit rating has been
downgraded to below investment grade by all three major rating agencies, and
is presently in default on debt service payments.

CL&P - Standard Offer Supply: NRG's subsidiary, NRG Power Marketing, Inc.
(NRG-PM), is under contract to supply a significant portion of CL&P's
standard offer service requirement through December 31, 2003. NRG-PM is
currently in default under the credit rating standards in the CL&P standard
offer service contract. At the present time, CL&P has not terminated the
contract for purposes of supply continuity, and NRG-PM continues to deliver
standard offer supply service. CL&P continues to evaluate NRG-PM's ability
to meet its obligations under the standard offer service contract. If NRG-PM
ceases to deliver supply under the contract, CL&P would immediately seek
alternate sources of energy to serve NRG-PM's portion of the standard offer
service requirement. The price of this replacement supply could be greater
than the current contract price. See below for management's discussion of
the recovery of these costs from ratepayers.

CL&P - Congestion Charges: Shortly after beginning to provide standard offer
service to CL&P, NRG-PM ceased paying CL&P for congestion charges. In view
of the deterioration of NRG-PM's financial condition, CL&P exercised its
right of offset to withhold past due congestion costs from the July 2002 and
subsequent standard offer payments to NRG-PM pending the outcome of
litigation between the parties concerning contractual liability for
congestion costs in the United States District Court for the District of
Connecticut. See NU's 2001 Form 10-K, Item 3, "Legal Proceedings," for
further information on this litigation.

CL&P - Station Service: Under a Federal Energy Regulatory Commission (FERC)
approved interconnection agreement with NRG, CL&P is providing station
electric service to NRG's Connecticut subsidiaries at a standard retail rate.
The NRG subsidiaries use this service when they are not generating at their
plants. CL&P has been billing the NRG subsidiaries for this service since
2000. NRG has disputed and refused to pay all such billings, claiming that
CL&P should not be utilizing a retail rate. Billings through September 30,
2002, amounted to approximately $12 million. CL&P has filed with the FERC to
resolve this dispute. The outcome of this proceeding cannot be predicted,
and management continues to evaluate the collectibility of the amounts in
dispute as well as the financial condition of NRG and its subsidiaries.

Yankee Gas: In 2002, both the Connecticut Department of Public Utility
Control (DPUC) and the CSC approved construction of a natural gas pipeline
and other gas distribution facilities by Yankee Gas to a 544 megawatt
generating plant that Meriden Gas Turbines LLC (MGT), an NRG subsidiary, was
constructing in Meriden, Connecticut. In October 2002, MGT notified Yankee
Gas that it was permanently shutting down or abandoning construction of the
generating plant. As a result, Yankee Gas immediately drew upon the full
amount of a $16 million irrevocable letter of credit issued for the
accounting of MGT. MGT has since disputed Yankee Gas's interpretation of the
circumstances leading to the exercise of the irrevocable letter of credit and
the appropriateness of the draw. Yankee Gas and MGT are currently discussing
several options to address and remedy these contract disputes while
preserving the project investment.

Select Energy: Select Energy entered into certain energy trading contracts
with NRG-PM. During the third quarter, Select Energy terminated those
contracts as a result of failure to provide adequate financial assurances
under those contracts by NRG-PM. In connection with the termination, Select
Energy paid NRG-PM $3.1 million to close out the transactions. NRG-PM has
disputed the amount owed and believes an additional $5.3 million is due.

NGS: E.S. Boulos Company, a subsidiary of NGS, entered into a joint venture
arrangement with an unaffiliated entity under which each party is a 50
percent owner. This joint venture is one of several subcontractors
performing work on the generating plant that MGT was constructing. As
discussed above, construction of this generating facility has been
permanently shut down or abandoned. As a result of the situation and the
uncertainty with respect to the completion of the plant, NGS has financial
exposure of approximately $1.7 million related to collection of accounts
receivable and settlements of other obligations. NGS is pursuing various
options to minimize this financial exposure, including the filing of liens
against the construction company and MGT.

Management does not expect that the resolution of these disputes will have a
material adverse effect on the NU's and its subsidiaries' financial condition
or results of operations. Additionally, NU and its subsidiaries do not have
a significant level of exposure to other merchant energy companies.

Restructuring and Rate Matters

Connecticut - CL&P: In 2002, 50 percent of CL&P's standard offer service
requirements are served by Select Energy, 40 percent by NRG-PM and 10 percent
by an affiliate of Duke Energy Corporation (Duke). In 2003, Select Energy
will continue to serve 50 percent of CL&P's standard offer service
requirements, but the percentage served by NRG-PM will rise to 45 percent,
and the amount served by Duke will decline to 5 percent.

As discussed above, CL&P continues to evaluate NRG-PM's ability to meet its
obligations under the standard offer service contract. If CL&P is required
to seek an alternate source of supply, CL&P would pursue recovery of any
additional costs associated with obtaining such supply from NRG-PM pursuant
to the contract and may be required to seek DPUC approval to flow through any
such costs to customers. Management believes that recovery of these costs is
consistent with the provisions of Connecticut's electric utility
restructuring legislation and with the DPUC's prior decisions.

On September 27, 2001, CL&P filed its application with the DPUC for approval
of the disposition of the proceeds from the sale of the Millstone units to
Dominion Nuclear Connecticut, Inc. (DNCI). This application described and
requested DPUC approval for CL&P's treatment of its share of the proceeds
from the sale. The company hopes to receive a decision from the DPUC in
2002.

On May 17, 2002, CL&P filed an application with the DPUC for the approval of
the auction results in the sale of Seabrook to a subsidiary of FPL. The
proceeds from the sale of Seabrook unit 1 will be utilized to offset stranded
costs. Hearings were held in July 2002, and a final decision approving the
sale was issued in September 2002.

Connecticut - Yankee Gas: On October 1, 2002 Yankee Gas filed supplemental
testimony and exhibits to its original Infrastructure Expansion Rate
Mechanism (IERM) filing with the DPUC on August 1, 2002. This IERM filing
reflected those 2001 through 2003 system expansion projects that Yankee Gas
has undertaken or plans to undertake by June 30, 2003, and that meet certain
financial criteria outlined by the DPUC. Yankee Gas is currently proposing
no IERM charge for 2003, that current rates remain unchanged and that the
projected 2003 revenue requirement be carried forward to the 2004 IERM
period. A final decision from the DPUC regarding this filing is scheduled
for the first quarter of 2003.

New Hampshire: In July 2001, the New Hampshire Public Utilities Commission
(NHPUC) opened a docket to review the fuel and purchased-power adjustment
clause (FPPAC) costs incurred between August 2, 1999, and April 30, 2001.
Hearings at the NHPUC concluded in June 2002, and PSNH filed its closing
brief with the NHPUC in July 2002. Under the "Agreement to Settle PSNH
Restructuring," FPPAC deferrals are recovered as a Part 3 stranded cost
through the stranded cost recovery charge. Management believes the
recoverability of these costs is probable and expects the NHPUC will issue
its order by the end of 2002.

On June 28, 2002, PSNH made its first stranded cost recovery charge
reconciliation filing with the NHPUC for the period May 1, 2001, through
December 31, 2001. This filing reconciles stranded cost revenues against
actual stranded cost charges with any difference being recovered or deferred.
Included in the stranded cost charges are the net generation revenues and
generation costs for the filing period. Where generation revenues exceed
costs, additional stranded costs were amortized; where generation costs
exceed revenues, costs were deferred for future recovery. The generation
costs included in this filing are subject to a prudence review by the NHPUC,
and hearings have been scheduled for early 2003. Management does not expect
this prudence review to have a material impact on PSNH's earnings.

On September 12, 2002, the NHPUC issued a final decision approving the
auction results in the sale of Seabrook to a subsidiary of FPL. On November
1, 2002, CL&P and NAEC consummated the sale of their 40.04 percent combined
ownership interest in Seabrook to a subsidiary of FPL. CL&P, NAEC and
certain other of the joint owners collectively sold 88.2 percent of Seabrook
to FPL. Following the sale of NAEC's share of Seabrook, the proceeds
received by NAEC, after NAEC repays its debt, will be refunded to PSNH
through the Seabrook Power Contracts. PSNH will use the proceeds received
from NAEC to recover stranded costs and repay debt with remaining amounts
being available to be returned to NU. As part of the sale, FPL assumed
responsibility for decommissioning Seabrook.

Massachusetts: On March 30, 2001, WMECO filed its second annual stranded cost
reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO
filed its 2001 annual transition cost reconciliation with the DTE. This
filing reconciles the recovery of stranded generation costs for calendar year
2001 and includes sales proceeds from WMECO's portion of the Millstone units,
the impact of securitization and approximately a $13 million benefit to
ratepayers from WMECO's nuclear performance-based ratemaking process. On
July 8, 2002, WMECO submitted a compliance filing in accordance with the
DTE's June 7, 2002, order in WMECO's 1998 through 1999 stranded cost
reconciliation proceedings. This filing reflected changes to the 1998
through 1999 reconciliations as agreed to by WMECO and/or ordered by the DTE
and also included a revised transition charge filing for 2000 and 2001 to
reflect the June 7, 2002 order.

Subsequent to the July 8, 2002 filing, WMECO and the office of the
Massachusetts Attorney General have participated in settlement discussions
with regard to all transition charge issues for the 1998 through 2001
reconciliations. WMECO hopes to reach an agreement by the end of 2002.

On July 1, 2002, WMECO completed a competitive bid process for a six-month
contract from July 1, 2002 to December 31, 2002, to serve approximately 100
MW of WMECO default service. Affiliate Select Energy was the winner of the
bid process and estimates that this contract will result in approximately
$13.2 million of revenues in 2002.

For further information regarding commitments and contingencies related to
restructuring and rate matters, see Note 2A, "Commitments and Contingencies -
Restructuring and Rate Matters," to the consolidated financial statements.

Nuclear Plant Performance and Other Matters

Seabrook: Seabrook operated at a capacity factor of 89 percent through the
first nine months of 2002. Seabrook returned to service on June 1, 2002,
after the completion of a 28-day scheduled refueling outage that began on
May 4, 2002. Excluding the scheduled refueling outage, Seabrook operated at a
capacity factor of 92 percent through the first nine months of 2002. On
November 1, 2002, CL&P, NAEC, and certain other joint owners consummated the
sale of their ownership interests in Seabrook to FPL.

Other Matters

Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 2, "Commitments and Contingencies,"
to the consolidated financial statements.

Forward Looking Statements: This discussion and analysis includes forward
looking statements, which are statements of future expectations and not facts
including, but not limited to, statements regarding future earnings,
refinancings, regulatory proceedings, the use of proceeds from restructuring,
and the recovery of operating costs. Words such as estimates, expects,
anticipates, intends, plans, and similar expressions identify forward looking
statements. Actual results or outcomes could differ materially as a result
of further actions by state and federal regulatory bodies, competition and
industry restructuring, changes in economic conditions, changes in weather
patterns, changes in laws, developments in legal or public policy doctrines,
technological developments, volatility in electric and natural gas commodity
markets, and other presently unknown or unforeseen factors.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2002 and the first nine months of 2002 are provided in the table
below. The following table also includes the effects of the reclassification
of trading revenues and expenses, which has been retroactively applied to all
periods presented. For further information regarding this accounting change,
see Note 1C, "New Accounting Standards," to the consolidated financial
statements.

Income Statement Variances
(Millions of Dollars)
2002 over/(under) 2001
-----------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $(169) (11)% $(900) (19)%

Operating Expenses:
Fuel, purchased and
net interchange power (188) (19) (747) (26)
Other operation (11) (5) (12) (2)
Maintenance 9 14 (14) (7)
Depreciation 5 11 (7) (5)
Amortization 3 3 (690) (77)
Taxes other than income taxes 8 20 6 4
Gain on sale of utility plant - - 644 100
----- ---- ----- ----
Total operating expenses (174) (12) (820) (19)
----- ---- ----- ----
Operating income 5 4 (80) (20)
----- ---- ----- ----

Other income, net 14 81 (170) (90)
Interest expense, net (2) (4) (5) (3)
----- ---- ----- ----
Income before income tax expense 21 36 (245) (63)
Income tax expense 7 29 (124) (75)
Preferred dividends of subsidiaries - - (2) (32)
----- ---- ----- ----
Income before cumulative effect of
accounting change 14 40 (119) (56)
----- ---- ----- ----
Cumulative effect of accounting
change, net of tax benefit - - 22 100
----- ---- ----- ----
Net income $ 14 40% $ (97) (50)%
===== ==== ===== ====

Comparison of the Third Quarter of 2002 to the Third Quarter of 2001

Operating Revenues
Total revenues decreased by $169 million or 11 percent in the third quarter
of 2002, compared with the same period in 2001, primarily due to lower
competitive energy revenues ($181 million, after intercompany eliminations),
partially offset by higher regulated revenues ($11 million).

The competitive energy companies' revenue decrease is primarily due to lower
wholesale marketing revenues for Select Energy from full requirements
contracts. The regulated revenue increase is primarily due to higher retail
sales ($36 million), partially offset by lower revenue due to the net
decrease in the WMECO standard offer energy rates ($21 million) and lower
wholesale sales of energy and capacity ($10 million). Regulated retail
electric kilowatt-hour (kWh) sales increased by 6.4 percent, and firm natural
gas volume sales increased by 1.7 percent in the third quarter of 2002.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased in 2002,
primarily due to lower costs of goods sold for wholesale marketing activities
at the competitive businesses.

Other Operation and Maintenance
Other operation expense decreased $11 million in the third quarter of 2002,
primarily due to lower competitive energy service companies' expenses
associated with the costs of goods sold. Maintenance expense is higher due
to higher transmission costs for the competitive companies due to increased
load responsibilities.

Depreciation
Depreciation increased in 2002 due to higher regulated plant balances
resulting from the recent level of construction expenditures.

Taxes Other Than Income Taxes
Taxes other than income taxes increased primarily due to the favorable 2001
property tax settlement with the City of Meriden which decreased the 2001
amount by $14 million, partially offset by the recognition in 2002 of a
Connecticut sales and use tax audit settlement for the years 1993 through
2001 ($8 million).

Other Income, Net
Other income, net increased primarily due to the elimination of reserves
associated with NU's ownership shares of Seabrook unit 2 in 2002 ($25
million), partially offset by the recording in 2001 of interest related to
the City of Meriden property tax settlement ($6 million) and the 2001
recording of interest related to an income tax settlement ($6 million).

Income Tax Expense
Income tax expense increased due to higher taxable income.

Comparison of the First Nine Months of 2002 to the First Nine Months of 2001

Operating Revenues
Total revenues decreased by $900 million or 19 percent in the first nine
months of 2002, compared with the same period in 2001, primarily due to lower
competitive energy revenues ($497 million after intercompany eliminations),
and lower regulated subsidiaries revenues due to lower wholesale revenues
($258 million), and lower regulated retail revenues ($145 million).

The competitive energy companies' revenue decrease is primarily due to lower
wholesale marketing revenues from Select Energy from full requirements
contracts. The decrease in regulated wholesale revenues is due to lower PSNH
wholesale sales ($77 million), the 2001 revenue associated with the sale of
Millstone output ($42 million) and lower sales associated with other
purchased-power contracts ($107 million). The regulated retail revenue
decrease is due to rate decreases for PSNH and the decrease in the WMECO
standard offer energy rate ($84 million), lower Yankee revenue due to a lower
purchased gas adjustment clause rate ($61 million) and a combination of the
rate decrease and lower gas sales ($28 million), partially offset by an
increase for CL&P resulting from the collection of deferred fuel costs ($24
million) and higher retail electric sales ($5 million). Regulated retail
electric kWh sales increased by 0.6 percent, and firm natural gas volume
sales decreased by 7.9 percent in 2002.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased in 2002,
primarily due to lower wholesale sales from the competitive businesses ($472
million) and lower purchased-power costs for the regulated subsidiaries ($274
million).

Other Operation and Maintenance
Other operation and maintenance (O&M) expenses decreased $26 million in 2002,
primarily due to lower expenses associated with the regulated businesses ($48
million), partially offset by higher costs of goods sold for the competitive
energy companies ($23 million).

The regulated O&M decrease is primarily due to lower nuclear expenses as a
result of the sale of the Millstone units at the end of the first quarter in
2001 ($48 million), lower distribution costs ($6 million), lower
administration and general expenses ($6 million) and lower fossil and
hydroelectric expenses ($2 million), partially offset by higher charges from
the ISO for capacity, reliability and availability ($13 million).

Depreciation
Depreciation decreased in 2002 primarily due to the Millstone units
decommissioning expenses recorded in 2001 ($7 million), lower NAEC expense
due to the 2001 buydown which reduced plant balances ($3 million), lower
Yankee expense resulting from lower depreciation allowed in the 2001 rate
decision ($3 million), and lower competitive energy companies' expense
resulting from generation assets life extensions ($1 million), partially
offset by higher expense resulting from higher regulated balances ($7
million).

Amortization
Amortization decreased in 2002, primarily due to the amortization of the gain
in 2001 related to the sale of the Millstone units ($644 million), higher
amortization in 2001 related to recovery of the Millstone investment ($45
million) and the NAEC discontinuance of amortizing Seabrook deferred return
in 2001 as a result of PSNH's restructuring ($16 million), partially offset
by higher amortization related to the regulated companies' recovery of
stranded costs ($15 million).

Taxes Other Than Income Taxes
Taxes other than income taxes increased primarily due to the favorable 2001
property tax settlement with the City of Meriden which decreased the 2001
amount by $14 million, partially offset by the recognition in 2002 of a
Connecticut sales and use tax audit settlement for the years 1993 through
2001 ($8 million).

Gain on Sale of Utility Plant
In 2001, NU recorded gains on the sale of CL&P's and WMECO's ownership
interests in the Millstone units. A corresponding amount of amortization
expense was recorded.

Other (Loss)/Income, Net
Other (loss)/income, net decreased primarily due to NU's 2001 recognition of
a gain in connection with the sale of Millstone units to DNCI ($202 million
pre-tax), a 2002 charge reflecting a write-down in NU's investment in NEON
($15 million pre-tax), by the recording in 2001 of interest related to the City
of Meriden property tax settlement ($6 million) and the 2001 recording of
interest related to an income tax settlement ($6 million) and the gain on the
disposition of property for PSNH in 2001 ($3 million), partially offset by a
2001 noncash charge related to the forward purchase of NU common shares ($35
million) and the elimination of reserves associated with NU's ownership
shares of Seabrook unit 2 in 2002 ($25 million).

Income Tax Expense
Income tax expense decreased in 2002, primarily due to the recognition of
WMECO investment tax credits in the second quarter of 2002 and the tax
impacts of the Millstone sale in 2001.

Cumulative Effect of Accounting Change, Net of Tax Benefit
The cumulative effect of accounting change, net of tax benefit, recorded in
2001, represents the effect of the adoption of SFAS No. 133, as amended ($22
million).

INDEPENDENT ACCOUNTANTS' REPORT

To the Board of Trustees
Northeast Utilities
Berlin, Connecticut

We have reviewed the accompanying condensed consolidated balance sheet of
Northeast Utilities and subsidiaries ("the Company") as of September 30,
2002, and the related condensed consolidated statements of income for the
three-month and nine-month periods then ended and the related condensed
consolidated statement of cash flows for the nine-month period then ended.
These financial statements are the responsibility of the Company's
management.

We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures
to financial data and of making inquiries of persons responsible for
financial and accounting matters. It is substantially less in scope than an
audit conducted in accordance with auditing standards generally accepted in
the United States of America, the objective of which is the expression of an
opinion regarding the financial statements taken as a whole. Accordingly, we
do not express such an opinion.

Based on our review, we are not aware of any material modifications that
should be made to such condensed consolidated financial statements for them
to be in conformity with accounting principles generally accepted in the
United States of America.

/s/ Deloitte & Touche LLP
Deloitte & Touche LLP

Hartford, Connecticut
November 7, 2002

Northeast Utilities and Subsidiaries
The Connecticut Light and Power Company and Subsidiaries
Public Service Company of New Hampshire and Subsidiaries
Western Massachusetts Electric Company and Subsidiary

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

A. Presentation

The accompanying unaudited financial statements should be read in
conjunction with the management's discussion and analysis of
financial condition and results of operations in this Form 10-Q,
the First and Second Quarter 2002 Form 10-Qs and the Annual Reports
of Northeast Utilities (NU or the company), The Connecticut Light
and Power Company (CL&P), Public Service Company of New Hampshire
(PSNH), and Western Massachusetts Electric Company (WMECO), which
were filed as part of the NU 2001 Form 10-K, and the current
reports on Form 8-K dated July 23, 2002, August 2, 2002, August 14,
2002, October 8, 2002, and October 21, 2002. The accompanying
financial statements contain, in the opinion of management, all
adjustments necessary to present fairly NU's and each NU system
company's financial position as of September 30, 2002, the results
of operations for the three-month and nine-month periods ended
September 30, 2002 and 2001, and statements of cash flows for the
nine-month periods ended September 30, 2002 and 2001. All
adjustments are of a normal, recurring nature except those
described in Notes 1C and 2. Due primarily to the seasonality of
NU's business, the results of operations for the three-month and
nine-month periods ended September 30, 2002 and 2001, and
statements of cash flows for the nine-month periods ended
September 30, 2002 and 2001, are not indicative of the results
expected for a full year.

The consolidated financial statements of NU and of its
subsidiaries, as applicable, include the accounts of all their
respective subsidiaries. Intercompany transactions have been
eliminated in consolidation.

The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of
contingent liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.

Certain reclassifications of prior period data have been made to
conform with the current period presentation.

B. Regulatory Accounting and Assets

The accounting policies of the NU system regulated operating
companies conform to accounting principles generally accepted in
the United States applicable to rate-regulated enterprises and
reflect the effects of the rate-making process in accordance with
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation."
CL&P's, PSNH's and WMECO's transmission and distribution businesses
continue to be cost-of-service rate regulated, and management
believes the application of SFAS No. 71 to those portions of those
businesses continues to be appropriate. Management also believes it
is probable that the NU system operating companies will recover
their investments in long-lived assets, including regulatory
assets. In addition, all material regulatory assets are earning a
return, except for securitized regulatory assets. The components
of the NU system companies' regulatory assets are as follows:

---------------------------------------------------------------------
September 30, December 31,
(Millions of Dollars) 2002 2001
---------------------------------------------------------------------
Recoverable nuclear costs $ 193.7 $ 231.6
Securitized regulatory assets 1,926.5 2,004.1
Income taxes, net 311.4 312.8
Unrecovered contractual obligations 70.3 78.3
Recoverable energy costs, net 307.6 327.2
Other 279.8 333.5
---------------------------------------------------------------------
Totals $3,089.3 $3,287.5
---------------------------------------------------------------------

C. New Accounting Standards

Asset Retirement Obligations: In June 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting
for Asset Retirement Obligations." This statement requires that
legal obligations associated with the retirement of property, plant
and equipment be recognized as a liability at fair value when
incurred when a reasonable estimate of the fair value can be made.
SFAS No. 143 is effective for NU's 2003 calendar year, and
management is in the process of assessing the impact of SFAS No.
143 on NU's consolidated financial statements. Upon adoption of
SFAS No. 143, there may be an impact on NU's consolidated financial
statements which management has not determined at this time.

Energy Trading and Risk Management Activities: In June 2002, the
Emerging Issues Task Force (EITF) of the FASB reached a consensus
on EITF Issue No. 02-3, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities," requiring energy
trading companies to classify revenues and expenses associated with
certain energy trading contracts on a net basis within revenues,
rather than recording the gross revenues and expenses.

NU currently accounts for energy trading activities using the mark-
to-market method under EITF Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities." EITF Issue No. 98-10
allows energy trading activities to be presented as revenues and as
expenses or on a net basis in revenues in the statements of income.
Effective July 1, 2002, NU adopted net reporting of revenues and
expenses as allowed by EITF Issue No. 98-10. Prior to July 1,
2002, NU presented energy trading activities as revenues and
expenses as allowed by EITF Issue No. 98-10. The adoption of net
reporting was applied retroactively to all periods presented but will
have no effect on net income.

The three and nine months ended September 30, 2002, reflect net
reporting. The revenues and expenses impacted relate to energy
trading contracts that physically settle which were previously
recorded as operating revenues for sales and fuel, purchased and
net interchange power for the costs of the sales. The effects of
this reporting for the three and nine months ended September 30,
2001, which have been previously reported, are as follows:

---------------------------------------------------------------------
Competitive Energy NU
Subsidiaries Consolidated
---------------------------------------------------------------------
Three Nine Three Nine
(Millions of Dollars) Months Months Months Months
---------------------------------------------------------------------
Operating Revenues:
As previously
reported $777.2 $2,101.5 $1,723.9 $5,107.7
Impact of
reclassification (193.2) (438.0) (193.2) (438.0)
---------------------------------------------------------------------
As currently
reported $584.0 $1,663.5 $1,530.7 $4,669.7
---------------------------------------------------------------------

---------------------------------------------------------------------
Competitive Energy NU
Subsidiaries Consolidated
---------------------------------------------------------------------
Three Nine Three Nine
(Millions of Dollars) Months Months Months Months
---------------------------------------------------------------------
Fuel, Purchased and
Net Interchange Power:
As previously
reported $719.0 $1,863.8 $1,178.3 $3,318.9
Impact of
reclassificaton (193.2) (438.0) (193.2) (438.0)
---------------------------------------------------------------------
As currently
reported $525.8 $1,425.8 $ 985.1 $2,880.9
---------------------------------------------------------------------

On October 25, 2002, the EITF reached additional consensuses in
EITF Issue No. 02-3. These consensuses supercede the consensus the
EITF reached in June 2002. The first consensus rescinds EITF Issue
No. 98-10, under which Select Energy, Inc. (Select Energy)
currently accounts for energy trading activities. The consensus
will require energy trading companies to follow SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as
amended, for energy trading activities and to discontinue mark-to-
market accounting for contracts that are not derivatives.
Management is currently evaluating the extent of trading contracts
that are not derivatives. The second consensus requires net
reporting of derivative energy trading activities effective
January 1, 2003. Management has already adopted net reporting of
trading activities and will continue to evaluate EITF Issue No.
02-3 as additional guidance becomes available.

D. Other (Loss)/Income, Net

The components of NU's other (loss)/income, net items are as
follows:

---------------------------------------------------------------------
For the Nine Months Ended
---------------------------------------------------------------------
September 30, September 30,
(Millions of Dollars) 2002 2001
---------------------------------------------------------------------
Loss on investments $(17.1) $ -
Gain related to Millstone sale - 201.9
Loss on share
repurchase contracts - (35.4)
Seabrook-related 23.3 -
Other, net 13.5 24.1
---------------------------------------------------------------------
Totals $ 19.7 $190.6
---------------------------------------------------------------------

E. Change in Estimated Useful Lives

In the second quarter of 2002, NU conducted studies of the
depreciable lives of certain generation and software assets
maintained by the competitive energy subsidiaries. The impact of
these studies was to lengthen the useful lives of those generation
assets by 20 years to an average of 58 remaining years and to
shorten the useful lives of that software to 1.5 remaining years
effective for the second quarter of 2002. As a result of these
studies, NU's operating expenses decreased by approximately $3
million since the beginning of the second quarter of 2002.

F. Sale of Customer Receivables

As of September 30, 2002, CL&P had sold accounts receivable of $40
million to a subsidiary of Citigroup, Inc. with limited recourse
through the CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. Additionally as of September 30, 2002, $4.2
million of assets were designated as collateral under the agreement
with the CRC. Concentrations of credit risk to the purchaser under
the this agreement with respect to the receivables are limited due
to CL&P's diverse customer base within its service territory.

2. COMMITMENTS AND CONTINGENCIES

A. Restructuring and Rate Matters (CL&P, PSNH, WMECO)

Connecticut: On September 27, 2001, CL&P filed its application with
the Connecticut Department of Public Utility Control (DPUC) for
approval of the disposition of the proceeds in the amount of
approximately $1.2 billion from the sale of the Millstone units to
a subsidiary of Dominion Resources, Inc., Dominion Nuclear
Connecticut, Inc. (DNCI). This application described and requested
DPUC approval for CL&P's treatment of its share of the proceeds
from the sale. In accordance with Connecticut's electric utility
industry restructuring legislation, CL&P was required to utilize
any gains from the Millstone sale to offset stranded costs. There
are certain contingencies related to this filing regarding the
potential disallowance of what management believes were prudently
incurred costs. Management believes the recoverability of these
costs is probable. The company hopes to receive a decision from
the DPUC in 2002.

New Hampshire: In July 2001, the New Hampshire Public Utilities
Commission (NHPUC) opened a docket to review the fuel and purchased-
power adjustment clause (FPPAC) costs incurred between August 2,
1999, and April 30, 2001. Hearings at the NHPUC concluded in June
2002, and PSNH filed its closing brief with the NHPUC in July 2002.
Under the "Agreement to Settle PSNH Restructuring," FPPAC deferrals
are recovered as a Part 3 stranded cost through the stranded cost
recovery charge. Management believes the recoverability of these
costs is probable and expects the NHPUC will issue its order by the
end of 2002.

On June 28, 2002, PSNH made its first stranded cost recovery charge
reconciliation filing with the NHPUC for the period May 1, 2001,
through December 31, 2001. This filing reconciles stranded cost
revenues against actual stranded cost charges with any difference
being recovered or deferred. Included in the stranded cost charges
are the net generation revenues and generation costs for the filing
period. Where generation revenues exceed costs, additional
stranded costs were amortized; where generation costs exceed
revenues, costs were deferred for future recovery. The generation
costs included in this filing are subject to a prudence review by
the NHPUC, and hearings have been scheduled for early 2003.
Management does not expect this prudence review to have a material
impact on PSNH's earnings.

Massachusetts: On March 30, 2001, WMECO filed its second annual
stranded cost reconciliation with the Massachusetts Department of
Telecommunications and Energy (DTE) for calendar year 2000. On
March 29, 2002, WMECO filed its 2001 annual transition cost
reconciliation with the DTE. This filing reconciles the recovery
of stranded generation costs for calendar year 2001 and includes
sales proceeds from WMECO's portion of the Millstone units, the
impact of securitization and approximately a $13 million benefit to
ratepayers from WMECO's nuclear performance-based ratemaking
process. On July 8, 2002, WMECO submitted a compliance filing in
accordance with the DTE's June 7, 2002, order in WMECO's 1998
through 1999 stranded cost reconciliation proceedings. This filing
reflected changes to the 1998 through 1999 reconciliations as
agreed to by WMECO and/or ordered by the DTE and also included a
revised transition charge filing for 2000 and 2001 to reflect the
June 7, 2002 order.

Subsequent to the July 8, 2002 filing, WMECO and the office of the
Massachusetts Attorney General have participated in settlement
discussions with regard to all transition charge issues for the
1998 through 2001 reconciliations. WMECO hopes to reach an
agreement by the end of 2002.

B. Long-Term Contractual Arrangements (Select Energy)

Select Energy maintains long-term agreements to purchase energy in
the normal course of business as part of its portfolio of resources
to meet its actual or expected sales commitments. The aggregate
amount of these purchase contracts was $4.3 billion at September 30,
2002. These contracts extend through 2006 as follows (millions
of dollars):

---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2002 $1,496.5
2003 2,110.2
2004 405.4
2005 240.4
2006 68.4
---------------------------------------------------------------------
Total $4,320.9
---------------------------------------------------------------------

C. Other Investments

Yankee Energy Services Company (YESCO), a subsidiary of Yankee
Energy System, Inc. (Yankee), received a note receivable of $4.7
million from BMC Energy LLC (BMC Energy) in connection with the
sale of certain renewable energy generation assets in 2001. On
October 28, 2002, NU, on behalf of YESCO, delivered to BMC Energy a
notice of an event of default with respect to the note. Under the
terms of such note, BMC Energy has an obligation to provide certain
financial information to determine the extent to which current cash
flows are available to service the outstanding note balance of $4.7
million. If the event of default is not remedied by November 29,
2002, pursuant to the terms of note, all obligations will become
immediately due and payable. YESCO is currently evaluating the
recoverability of the note through either payments on the note or
reacquisition of assets.

3. GOODWILL AND OTHER INTANGIBLE ASSETS

Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which ceases amortization of goodwill and certain
intangible assets with indefinite useful lives. SFAS No. 142 also
requires that goodwill and intangible assets deemed to have indefinite
useful lives be reviewed for impairment upon adoption of SFAS No. 142
and at least annually thereafter by applying a fair value-based test.
Under SFAS No. 142, goodwill impairment is deemed to exist if the net
book value of a reporting unit exceeds its estimated fair value and if
the implied fair value of goodwill based on the estimated fair value of
the reporting unit exceeds the carrying amount of the goodwill.

In July 2002, the competitive energy subsidiaries acquired certain assets
and assumed certain liabilities of Woods Electrical Co., Inc., an
electrical services company and Woods Network Services, Inc., a
telecommunications, construction and service company, for an aggregate
purchase price of $15.3 million. The aggregate purchase price consisted
of $3.3 million of tangible net assets, $0.5 million of intangible assets
subject to amortization with a weighted average amortization period of
2.6 years, $5 million of intangible assets not subject to amortization,
and $6.5 million of goodwill. This purchase price allocation is
preliminary and subject to adjustment. Financial results of the acquired
companies are included in NU's results of operations since July 1, 2002.

The goodwill recognized in these transactions in the aggregate amount of
$6.5 million was assigned to the competitive energy subsidiaries
reportable segment and is expected to be fully deductible for tax
purposes. Additionally, as part of these purchase agreements an
additional payment of not more than $9.2 million would be contingently
payable by 2005 if certain earnings targets are met. Any contingent
payments made will be accounted for as part of the purchase price.

Inclusive of the aforementioned acquisitions, as of September 30, 2002,
NU maintains $319.4 million of goodwill that is no longer being
amortized, $19.5 million of identifiable intangible assets which
continue to be amortized over a period ranging from one to 15 years with
a weighted average amortization period of 14.7 years and $5 million of
intangible assets not subject to amortization. These amounts are
included on the consolidated balance sheets as goodwill and other
purchased intangible assets, net.

NU's reporting units that maintain goodwill are generally consistent
with the operating segments underlying the reportable segments
identified in Note 8, "Segment Information," and are as follows: Yankee
Gas Services Company (Yankee Gas), Select Energy Services, Inc. (SESI),
Northeast Generation Services Company (NGS), NU Enterprises, Inc. (NUEI
Parent), and YESCO. Yankee Gas is included in the regulated utilities -
gas reportable segment and SESI, NGS, NUEI Parent, and YESCO are
included in the competitive energy subsidiaries segment. The goodwill
balances of these reporting units are included in the table below.

NU has completed its initial impairment analysis for all reporting units
that maintained goodwill upon adoption of SFAS No. 142 and has
determined that no impairment exists. In completing this analysis, the
fair values of the reporting units were estimated using both discounted
cash flow methodologies and an analysis of comparable companies or
transactions.

A summary of NU's goodwill as of September 30, 2002, by reportable
segment and reporting unit is as follows (millions of dollars):

--------------------------------------------
Goodwill
(Millions of Dollars) Balance
--------------------------------------------
Regulated
Utilities - Gas:
Yankee Gas $287.6

Competitive Energy
Subsidiaries:
SESI 18.0
NGS 11.7
NUEI Parent 1.7
YESCO 0.4
--------------------------------------------
Total $319.4
--------------------------------------------

Except for the aforementioned acquisitions, there were no impairments or
adjustments to these goodwill balances since January 1, 2002.

As of September 30, 2002 and December 31, 2001, NU's intangible assets
and related accumulated amortization consisted of the following:

--------------------------------------------------------------------------
As of September 30, 2002
--------------------------------------------------------------------------
(Millions of Gross Accumulated Net
Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets
subject to
amortization:
Exclusivity
agreement $17.7 $3.9 $13.8
Customer list 6.6 1.4 5.2
Employment
related
agreements
and other 0.5 - 0.5
--------------------------------------------------------------------------
Totals $24.8 $5.3 $19.5
--------------------------------------------------------------------------
Intangible assets
not subject to
amortization:
Customer
relationships $ 2.0
Tradenames 3.0
--------------------------------------------------------------------------
Totals $ 5.0
--------------------------------------------------------------------------

--------------------------------------------------------------------------
As of December 31, 2001
--------------------------------------------------------------------------
(Millions of Gross Accumulated Net
Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets
subject to
amortization:
Exclusivity
agreement $17.7 $3.1 $14.6
Customer list 6.6 1.1 5.5
--------------------------------------------------------------------------
Totals $24.3 $4.2 $20.1
--------------------------------------------------------------------------

NU recorded amortization expense of $1.1 million and $1.2 million during
the first nine months of 2002 and 2001, respectively, related to these
intangible assets. Based on the current amount of intangible assets
subject to amortization, the estimated annual amortization expense for
each of the succeeding 5 years from 2003 through 2007 is $1.8 million,
$1.8 million, $1.7 million, $1.6 million, and $1.6 million,
respectively. These amounts may vary as purchase price allocations are
finalized and acquisitions and dispositions occur in the future.

The results for the three months and nine months ended September 30,
2001, on a historical basis, do not reflect the provisions of SFAS No.
142. Had NU adopted SFAS No. 142 on January 1, 2001, historical net
income and basic and fully diluted earnings per share (EPS) amounts
would have been adjusted as follows:

--------------------------------------------------------------------------
Fully
(Millions of Dollars, except Net Basic Diluted
share information) Income EPS EPS
--------------------------------------------------------------------------
Three Months Ended
September 30, 2001:
--------------------------------------------------------------------------
Reported net income $34.6 $0.26 $0.26
Add back: goodwill
amortization 2.3 0.02 0.02
--------------------------------------------------------------------------
Adjusted net income $36.9 $0.28 $0.28
--------------------------------------------------------------------------
Three Months Ended
September 30, 2002:
--------------------------------------------------------------------------
Reported net income $48.6 $0.38 $0.38
--------------------------------------------------------------------------

--------------------------------------------------------------------------
Fully
(Millions of Dollars, except Net Basic Diluted
share information) Income EPS EPS
--------------------------------------------------------------------------
Nine Months Ended
September 30, 2001:
--------------------------------------------------------------------------
Reported net income $193.5 $1.41 $1.41
Add back: goodwill
amortization 6.8 0.05 0.05
--------------------------------------------------------------------------
Adjusted net income $200.3 $1.46 $1.46
--------------------------------------------------------------------------
Nine Months Ended
September 30, 2002:
--------------------------------------------------------------------------
Reported net income $ 96.1 $0.74 $0.74
--------------------------------------------------------------------------

4. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS (NU, Select Energy,
Yankee Gas)

Derivative Instruments: Effective January 1, 2001, NU adopted SFAS No.
133, as amended. For those contracts that meet the definition of a
derivative and meet the cash flow hedge requirements, the changes in the
fair value of the effective portion of those contracts are recognized in
accumulated other comprehensive income until the underlying transactions
occur. For contracts that meet the definition of a derivative but do
not meet the hedging requirements and for the ineffective portion of
those that meet the hedging requirements, the changes in fair value of
those contracts are recognized currently in earnings. Commodity
derivatives that are utilized for trading purposes are currently
accounted for using the mark-to-market method, under EITF Issue No. 98-
10, with changes in fair value included in earnings. For information
regarding the rescission of EITF Issue No. 98-10, see Note 1C, "New
Accounting Standards."

There have been changes to interpretations of SFAS No. 133 and the FASB
continues to consider changes and amendments which could affect the
recording and disclosure of derivative and hedging activities.

Competitive Energy Subsidiaries: Select Energy provides both full
requirement energy services to its customers and engages in energy
trading and marketing activities. Select Energy manages its exposure to
risk from its contractual commitments and provides risk management
services to its customers through forward contracts, futures, over-the-
counter swap agreements, and options (commodity derivatives).

Select Energy has utilized the sensitivity analysis methodology to
disclose quantitative information for its commodity price risks.
Sensitivity analysis provides a presentation of the potential loss of
future earnings, fair values or cash flows from market risk-sensitive
instruments over a selected time period due to one or more hypothetical
changes in commodity prices, or other similar price changes.

Commodity Price Risk - Trading Activities: As a market participant in
the Northeast United States, Select Energy conducts commodity-trading
activities in electricity and its related products, natural gas and oil,
and therefore, experiences net open positions. Select Energy manages
these open positions with strict policies which limit its exposure to
market risk and require daily reporting to management of potential
financial exposure. Under EITF Issue No. 98-10, these instruments are
currently adjusted to market value, and the unrealized gains and losses
are recognized in income in the current period in the consolidated
statements of income in operating revenues, and in the consolidated
balance sheets as unrealized gains and losses on mark-to-market
transactions. The net mark-to-market positions at September 30, 2002
and December 31, 2001, were assets of $81.7 million and $56.4 million,
respectively.

Under sensitivity analysis, the fair value of the portfolio is a
function of the underlying commodity, contract prices and market prices
represented by each derivative commodity contract. For swaps, forward
contracts and options, market value reflects management's best estimates
considering over-the-counter quotations, time value and volatility
factors of the underlying commitments. Exchange-traded futures and
options are recorded at market based on closing exchange prices.

As of September 30, 2002, Select Energy has calculated the market price
resulting from a 10 percent unfavorable change in forward market prices.
That 10 percent change would result in approximately a $3.3 million
decline in the fair value of the Select Energy trading portfolio. In
the normal course of business, Select Energy also faces risks that are
either nonfinancial or nonquantifiable. Such risks principally include
credit risk, which is not reflected in this sensitivity analysis.

Commodity Price Risk - Nontrading Derivative Activities: Select Energy
utilizes derivative financial and commodity instruments (derivatives),
including futures and forward contracts, to reduce market risk
associated with fluctuations in the price of electricity and natural gas
sold under firm commitments to certain customers. Select Energy also
utilizes derivatives, including price swap agreements, call and put
option contracts, and futures and forward contracts, to manage the
market risk associated with a portion of its anticipated supply
requirements. These derivative instruments have been designated as cash
flow hedging instruments.

When conducting sensitivity analyses of the change in the fair value of
Select Energy's electricity, natural gas and oil nontrading derivatives
portfolio, which would result from a hypothetical change in the future
market price of electricity, natural gas and oil, the fair values of the
contracts are determined from models which take into account estimated
future market prices of electricity, natural gas and oil, the volatility
of the market prices in each period, as well as the time value factors
of the underlying commitments. In most instances, market prices and
volatility are determined from quoted prices on the futures exchange.

Select Energy has determined a hypothetical change in the fair value for
its nontrading derivatives and electricity, natural gas and oil
contracts, assuming a 10 percent unfavorable change in forward market
prices. As of September 30, 2002, an unfavorable 10 percent change in
market price would have resulted in a decline in fair value of
approximately $15 million.

The impact of a change in electricity, natural gas and oil prices on
Select Energy's nontrading derivatives contracts on September 30, 2002,
is not necessarily representative of the results that will be realized
when these contracts are physically delivered.

Select Energy also maintains natural gas service agreements with certain
customers to supply gas at fixed prices for terms extending through
2004. Select Energy has hedged its gas supply risk under these
agreements through New York Mercantile Exchange (NYMEX) contracts.
Under these contracts, the purchase price of a specified quantity of gas
is effectively fixed over the term of the gas service agreements, which
also extend through 2004. As of September 30, 2002, the NYMEX contracts
had a notional value of $50.3 million and a mark-to-market asset value
of $4.7 million.

Regulated Entities:

Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a
master swap agreement with a financial counterparty to purchase gas at
fixed prices. Under this master swap agreement, the purchase price of a
specified quantity of gas for two customers, an affiliate of the Rand-
Whitney Group, Inc. and Kimberly Clark Corporation, is effectively fixed
over the term of the gas service agreements with those customers for a
period of time not extending beyond 2005. As of September 30, 2002, the
commodity swap agreement had a notional value of $12.3 million and a
mark-to-market asset value of $0.8 million, which is included in the
$6.9 million reported for accumulated other comprehensive income related
to hedging activities.

Other Interest Rate and Credit Risk Activities:

Interest Rate Risk - Nontrading Activities: NU manages its interest
rate risk exposure by maintaining a mix of fixed and variable rate debt.
As of September 30, 2002, approximately 79 percent of NU's long-term
debt, including the current portion, is at a fixed interest rate. The
remaining long-term debt is variable-rate and is subject to interest
rate risk. Assuming a one percentage point increase in NU's variable
interest rates, annual interest expense would have increased by $4.9
million.

Credit Risk: Credit risk relates to the risk of loss that NU would incur
as a result of non-performance by counterparties pursuant to the terms
of their contractual obligations. NU serves a wide variety of customers
and suppliers that include independent power producers, industrial
companies, gas and electric utilities, oil and gas producers, financial
institutions, and other energy marketers. Margin accounts exist within
this diverse group, and NU realizes interest receipts and payments
related to balances outstanding in these accounts. This wide customer
and supplier mix generates a need for a variety of contractual
structures, products and terms which, in turn, requires NU to manage the
portfolio of market risk inherent in those transactions in a manner
consistent with the parameters established by NU's risk management
process. Market risks at the competitive energy subsidiaries are
monitored regularly by a Risk Oversight Council operating outside of the
business units that create or actively manage these risk exposures to
ensure compliance with NU's stated risk management policies.

NU tracks and re-balances the risk in its portfolio in accordance with
mark-to-market and other risk management methodologies that utilize
forward price curves in the energy markets to estimate the size and
probability of future potential exposure.

NYMEX traded futures and option contracts are guaranteed by the NYMEX
and have a lower credit risk. Select Energy has established written
credit policies with regard to its counterparties to minimize overall
credit risk on all types of transactions. These policies require an
evaluation of potential counterparties' financial conditions (including
credit ratings), collateral requirements under certain circumstances
(including cash in advance, letters of credit, and parent guarantees),
and the use of standardized agreements, which allow for the netting of
positive and negative exposures associated with a single counterparty.
This evaluation results in establishing credit limits prior to NU
entering into trading activities. The appropriateness of these limits
is subject to continuing review. Concentrations among these
counterparties may impact NU's overall exposure to credit risk, either
positively or negatively, in that the counterparties may be similarly
affected by changes to economic, regulatory or other conditions.

5. NUCLEAR GENERATION ASSETS DIVESTITURE (NU, CL&P, NAEC)

In the third quarter of 2002, CL&P and North Atlantic Energy Corporation
(NAEC) received regulatory approvals for the sale of Seabrook from the
DPUC and the NHPUC. As a result of these approvals, CL&P and NAEC
eliminated $0.6 million and $13.9 million, respectively, on an after-tax
basis, of reserves related to their respective ownership shares of
certain Seabrook assets.

On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04
percent combined ownership interest in Seabrook to a subsidiary of FPL
Group, Inc. (FPL). CL&P, NAEC and certain other of the joint owners
collectively sold 88.2 percent of Seabrook to FPL. The NU system
received approximately $384 million of cash proceeds from the sale
subject to certain true-up adjustments, and a portion of these proceeds
were used to repay all $90 million of NAEC's outstanding debt, and will
be used to return all NAEC's equity, which totaled $55.7 million as of
September 30, 2002, to NU and pay between $90 million and $100 million
in taxes. The remaining proceeds received by NAEC were refunded to PSNH
through the Seabrook Power Contracts. As part of the sale, FPL assumed
responsibility for decommissioning Seabrook.

On October 10, 2000, NU reached an agreement with Baycorp Holdings, Ltd.
(Baycorp), a 15 percent joint owner of Seabrook, under which NU
guaranteed a minimum sale price and NU and Baycorp would share the
excess proceeds if the sale of Seabrook resulted in proceeds of more
than $87.2 million related to the sale of this 15 percent ownership
interest. The agreement also limited any top-off amount required to be
funded by Baycorp for decommissioning as part of the sale process. In
connection with this agreement, NU received approximately $14 million in
the fourth quarter of 2002.

6. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO)

Total comprehensive income, which includes all comprehensive income
items, for the NU system is as follows:

--------------------------------------------------------------------------
Nine Months Ended September 30,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------
NU consolidated $134.6 $158.8
CL&P 57.8 71.3
PSNH 45.8 63.4
WMECO 26.8 7.9
--------------------------------------------------------------------------

Accumulated other comprehensive income/(loss) mark-to-market adjustments
of NU's qualified cash flow hedging instruments are as follows:

--------------------------------------------------------------------------
(Millions of Dollars, Net of Tax)
--------------------------------------------------------------------------
Balance at January 1, 2002 $(36.9)
--------------------------------------------------------------------------
Hedged transactions recognized into earnings 19.5
Change in fair value 23.0
Cash flow transactions entered into for the period 1.3
--------------------------------------------------------------------------
Net change associated with the current period
hedging transactions 43.8
-------------------------------------------------------------------------
Total mark-to-market adjustments included in
accumulated other comprehensive income
at September 30, 2002 $ 6.9
--------------------------------------------------------------------------

Accumulated other comprehensive income items unrelated to NU's qualified
cash flow hedging instruments totaled $4.4 million in income and $0.8
million in losses as of January 1, 2002, and September 30, 2002,
respectively.

During the third quarter of 2002, Select Energy determined that cash
flow hedges related to the CL&P standard offer service contract were
ineffective. In the third quarter, as a result of this ineffectiveness,
Select Energy transferred $3.9 million from accumulated other
comprehensive income to expense on the income statement related to these
cash flow hedges. In September 2002, Select Energy terminated these
cash flow hedges and realized pre-tax income of $5.6 million.

7. EARNINGS PER SHARE (NU)

EPS is computed based upon the weighted average number of common shares
outstanding during each period. Diluted EPS is computed on the basis of
the weighted average number of common shares outstanding plus the
potential dilutive effect if stock options granted under the NU
Incentive Plan are converted into common stock.

The following table sets forth the components of basic and fully diluted
EPS:

--------------------------------------------------------------------------
(Millions of Dollars, Nine Months Ended September 30,
except share information) 2002 2001
--------------------------------------------------------------------------
Income before preferred
dividends of subsidiaries $100.3 $222.1
Preferred dividends
of subsidiaries 4.2 6.2
-------------------------------------------------------------------------
Income before cumulative effect
of accounting change $ 96.1 $215.9
Cumulative effect
of accounting change,
net of tax benefit - (22.4)
--------------------------------------------------------------------------
Net income $ 96.1 $193.5
--------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 129,508,840 137,120,689
Dilutive effect of employee
stock options 228,409 337,005
--------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 129,737,249 137,457,694
--------------------------------------------------------------------------
Basic and fully diluted EPS:
Income before cumulative effect
of accounting change $0.74 $1.57
Cumulative effect
of accounting change,
net of tax benefit - (0.16)
--------------------------------------------------------------------------
Net income $0.74 $1.41
--------------------------------------------------------------------------

8. SEGMENT INFORMATION (NU)

The NU system is organized between regulated utilities (electric and
gas) and competitive energy subsidiaries. The regulated utilities
segment represents approximately 84 percent and 76 percent of the NU
system's total revenues for the nine months ended September 30, 2002 and
2001, respectively, and is comprised of several business units. The
reclassification of trading revenues and expenses, which has been
retroactively applied to all periods presented, resulted in an increase
in these percentages from amounts reported in prior periods.

Regulated utilities revenues primarily are derived from residential,
commercial and industrial customers and are not dependent on any single
customer. In 2002, the competitive energy subsidiaries segment had one
customer with revenues in excess of 10 percent of its total revenues,
which was CL&P. The total purchases by CL&P represented approximately
43 percent of total competitive energy subsidiaries' revenues for the
nine months ended September 30, 2002. In 2001, the total purchases by
two customers, NSTAR and CL&P, represented approximately 15 percent and
30 percent, respectively, of total competitive energy subsidiaries'
revenues for the nine months ended September 30, 2001. Total CL&P
purchases from the competitive energy subsidiaries are eliminated in
consolidation.

The competitive energy subsidiaries segment in the following table
includes SESI, a provider of energy management, demand-side management
and related consulting services for commercial, industrial and
institutional electric companies and electric utility companies; Holyoke
Water Power Company, a company engaged in the production of electric
power; Northeast Generation Company, a corporation that acquires and
manages generation facilities; NGS, a corporation that maintains and
services fossil or hydroelectric facilities and provides third-party
electrical and engineering contracting services, and Select Energy, a
corporation engaged in the trading, marketing, transportation, storage,
and sale of energy commodities, at wholesale, in designated geographical
areas and in the marketing of energy products to retail customers.

Other in the following table includes the results for Mode 1
Communications, Inc., an investor in a fiber-optic communications
network. Other also includes the results of the nonenergy related
subsidiaries of Yankee. Interest expense included in Other primarily
relates to the debt of NU parent. Inter-segment eliminations of
revenues and expenses are also included in Other.

- -------------------------------------------------------------------------------
For the Three Months Ended September 30, 2002
- -------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
(Millions of ------------------- Energy and
Dollars) Electric Gas Subsidiaries Other Total
- -------------------------------------------------------------------------------
Operating
revenues $1,106.2 $ 37.8 $ 396.0 $(179.0) $ 1,361.0
Operating
expenses (975.0) (43.4) (397.8) 173.2 (1,243.0)
- -------------------------------------------------------------------------------
Operating
income/
(loss) 131.2 (5.6) (1.8) (5.8) 118.0
Other income/
(loss), net 31.3 (0.5) 0.2 1.1 32.1
Interest
expense, net (46.6) (3.5) (11.1) (6.5) (67.7)
Income tax
(expense)/
benefit (45.5) 3.8 3.7 5.6 (32.4)
Preferred
dividends (1.4) - - - (1.4)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 69.0 $ (5.8) $ (9.0) $ (5.6) $ 48.6
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
For the Nine Months Ended September 30, 2002
- -------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
(Millions of ------------------- Energy and
Dollars) Electric Gas Subsidiaries Other Total
- -------------------------------------------------------------------------------
Operating
revenues $2,962.6 $192.8 $1,107.3 $(492.6) $ 3,770.1
Operating
expenses (2,620.0) (171.0) (1,133.8) 481.2 (3,443.6)
- -------------------------------------------------------------------------------
Operating
income/
(loss) 342.6 21.8 (26.5) (11.4) 326.5
Other income/
(loss), net 33.4 (0.5) (3.0) (10.2) 19.7
Interest
expense, net (140.5) (10.9) (32.9) (19.3) (203.6)
Income tax
(expense)/
benefit (79.0) (4.2) 22.5 18.4 (42.3)
Preferred
dividends (4.2) - - - (4.2)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 152.3 $ 6.2 $ (39.9) $ (22.5) $ 96.1
- -------------------------------------------------------------------------------
Total assets $7,973.7 $893.6 $1,854.5 $(405.6) $10,316.2
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
For the Three Months Ended September 30, 2001
- -------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
(Millions of ------------------- Energy and
Dollars) Electric Gas Subsidiaries Other Total
- -------------------------------------------------------------------------------
Operating
revenues $1,083.9 $ 39.5 $ 584.0 $ (176.7) $ 1,530.7
Operating
expenses (955.4) (34.7) (592.0) 164.8 (1,417.3)
- -------------------------------------------------------------------------------
Operating
income/
(loss) 128.5 4.8 (8.0) (11.9) 113.4
Other income,
net 5.0 3.8 2.1 6.8 17.7
Interest
expense, net (53.5) (3.6) (9.2) (4.0) (70.3)
Income tax
(expense)/
benefit (35.5) (1.8) 5.4 6.7 (25.2)
Preferred
dividends (1.0) - - - (1.0)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 43.5 $ 3.2 $ (9.7) $ (2.4) $ 34.6
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
For the Nine Months Ended September 30, 2001
- -------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
(Millions of ------------------- Energy and
Dollars) Electric Gas Subsidiaries Other Total
- -------------------------------------------------------------------------------
Operating
revenues $3,284.0 $279.9 $1,663.5 $ (557.7) $ 4,669.7
Operating
expenses (2,918.0) (248.5) (1,636.2) 539.4 (4,263.3)
- -------------------------------------------------------------------------------
Operating
income/
(loss) 366.0 31.4 27.3 (18.3) 406.4
Other income,
net 72.2 3.7 5.4 109.3 190.6
Interest
expense, net (148.3) (10.6) (32.2) (17.9) (209.0)
Income tax
expense (129.2) (10.6) (0.9) (25.3) (166.0)
Preferred
dividends (6.1) - - - (6.1)
- -------------------------------------------------------------------------------
Income/(loss)
before
cumulative
effect of
accounting
change 154.6 13.9 (0.4) 47.8 215.9
Cumulative
effect of
accounting
change,
net of
tax benefit - - (22.0) (0.4) (22.4)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 154.6 $ 13.9 $ (22.4) $ 47.4 $ 193.5
- -------------------------------------------------------------------------------
Total assets $9,176.9 $867.6 $1,526.7 $(1,279.1) $10,292.1
- -------------------------------------------------------------------------------

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

Management's Discussion and Analysis of
Financial Condition and Results of Operations

CL&P is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs,
current report on Form 8-K dated October 21, 2002, and the NU 2001 Form 10-K.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2002 and the first nine months of 2002 are provided in the table
below.

Income Statement Variances
(Millions of Dollars)
2002 over/(under) 2001
-----------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $12 2% $(146) (7)%

Operating Expenses:
Fuel, purchased and
net interchange power 11 3 (50) (4)
Other operation 6 9 (9) (4)
Maintenance - - (33) (37)
Depreciation 2 9 - -
Amortization (14) (22) (569) (83)
Taxes other than income taxes (3) (9) 6 5
Gain on sale of utility plant - - 523 100
--- --- ---- ---
Total operating expenses 2 - (132) (7)
--- --- ---- ---

Operating income 10 16 (14) (7)

Other income, net - - (25) (64)
Interest expense, net (2) (8) - -
--- --- ---- ---
Income before income tax expense 12 34 (39) (27)
Income tax expense 2 12 (25) (36)
--- --- ---- ---
Net income $10 56% $(14) (18)%
=== === ==== ===

Comparison of the Third Quarter of 2002 to the Third Quarter of 2001

Operating Revenues
Operating revenues increased by $12 million or 2 percent in the third quarter
of 2002, primarily due to higher retail revenues ($40 million), partially
offset by lower wholesale revenues ($22 million). Retail revenues increased
due to higher retail sales of 7.6 percent compared to the same period in
2001. Wholesale revenues were lower primarily due to lower sales of energy
and capacity ($15 million), and lower revenue from market based contracts ($5
million).

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in the third
quarter of 2002, primarily due to the retail sales increase and the 2002
amortization of deferred fuel expenses.

Other Operation
Other operation expense increased by $6 million in the third quarter of 2002,
primarily due to higher transmission expenses ($4 million) and higher
administrative and general expenses ($2 million).

Depreciation
Depreciation expense increased in the third quarter of 2002 due to higher
utility plant balances.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased in the third quarter of 2002
due to lower amortizations related to the recovery of stranded costs ($8
million), and lower amortization of the nuclear investment ($6 million).

Taxes Other Than Income Taxes
Taxes other than income taxes decreased in the third quarter of 2002 due to
the recognition in 2002 of a Connecticut sales and use tax audit settlement
for years 1993-2001 ($7 million), partially offset by the 2001 recognition of
a property tax settlement with the City of Meriden.

Interest Expense, Net
Interest expense decreased in the third quarter of 2002, primarily due to the
reacquisitions and retirements of long-term debt in 2001, and lower interest
paid on rate reduction bonds.

Income Tax Expense
Income tax expense increased in the third quarter of 2002 due to higher book
taxable income.

Comparison of the First Nine Months of 2002 to the First Nine Months of 2001

Operating Revenues
Operating revenues decreased by $146 million or 7 percent in 2002, primarily
due to lower wholesale and other revenues ($183 million), partially offset by
higher retail revenues ($37 million). Wholesale revenues were lower due to
the sale of the Millstone units in the first quarter of 2001 ($62 million),
lower revenues from sales of energy and capacity ($70 million) resulting from
the buyout of cogenerator purchase contracts and lower wholesale market
prices, and lower revenue from market based contracts ($24 million). Retail
revenues were higher due to the recovery of previously deferred fuel costs
($24 million) and higher sales. Retail sales were 1.4 percent higher than
last year.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased by $50 million in
2002, due to lower purchased-power costs resulting from the buydown and
buyout of various cogeneration contracts ($46 million), lower market-based
contracts ($20 million) and lower nuclear fuel expense ($7 million),
partially offset by the 2002 amortization of deferred fuel expenses which are
being recovered ($24 million).

Other Operation and Maintenance
Other O&M expense decreased by $42 million in 2002, primarily due to lower
nuclear expenses as a result of the sale of the Millstone units at the end of
the first quarter of 2001 ($51 million), partially offset by higher
administrative and general expenses ($7 million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased in 2002, primarily due to
higher amortization in 2001 related to the sale of the Millstone units ($523
million), lower amortization of the nuclear investment ($42 million), and
lower amortizations related to the recovery of stranded costs ($2 million).

Taxes Other Than Income Taxes
Taxes other than income taxes increased in 2002, primarily due to the DPUC's
order for CL&P to compensate the Town of Waterford for its loss of property
tax revenue resulting from electric utility restructuring ($20 million),
partially offset by the recognition of a Connecticut sales and use tax audit
settlement for years 1993-2001 ($7 million), decreases in payroll taxes ($3
million) and local property taxes ($2 million). CL&P is recovering through
rates the additional property tax payments to the Town of Waterford.

Gain on Sale of Utility Plant
In 2001, CL&P recorded a gain on the sale of its ownership share in the
Millstone units. A corresponding amount of amortization expense was
recorded.

Other Income, Net
Other income, net decreased in 2002, primarily due to the gain recognized in
2001 on the sale of the Millstone units ($29 million).

Income Tax Expense
Income tax expense decreased in 2002 primarily due to lower book taxable
income.

LIQUIDITY

CL&P expects its cash position to further improve in the fourth quarter of
2002 due to the sale of CL&P's 4.06 percent share of Seabrook on November 1,
2002. The net gain from the sale related to CL&P's share of Seabrook
primarily will be used to offset stranded costs, and the cash proceeds
received by CL&P will be used to meet its capital requirements.

CL&P had no significant financing activity in the third quarter 2002. In
November 2002, NU expects to decrease to $300 million from $350 million a
line of credit for its regulated subsidiaries, including CL&P. CL&P did not
have any borrowings outstanding under this facility as of September 30, 2002.

CL&P projects a modest level of system financings over the next three months
to six months. CL&P is currently contemplating the issuance of up to $200
million of debt to refinance its prior spent nuclear fuel obligations
pursuant to the Nuclear Waste Policy Act of 1982 for nuclear fuel burned
prior to April 6, 1983.

CL&P's net cash flows provided by operating activities increased to $303.2
million in the first nine months of 2002, compared with net cash flows
provided by operating activities of $67.8 million during the same period of
2001. Cash flows provided by operating activities increased primarily due to
taxes payable in 2001 in connection with the sale of the Millstone units.
Also contributing to the increase is the amortization of recoverable energy
costs in 2002 compared with deferrals in 2001. Changes in working capital
items also contributed to the increase.

There was a lower level of investing and financing activities in the first
nine months of 2002, as compared to the same period of 2001, primarily due to
the sale of the Millstone units, the buyout and buydown of independent power
producer contracts, and the issuance rate reduction certificates in 2001.
The level of common dividends totaled $45.1 million in the first nine months
of 2002 and 2001.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

Management's Discussion and Analysis of
Financial Condition and Results of Operations

PSNH is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs,
current report on Form 8-K dated October 21, 2002, and the NU 2001 Form 10-K.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2002 and the first nine months of 2002 are provided in the table
below.

Income Statement Variances
(Millions of Dollars)
2002 over/(under) 2001
-----------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $25 8% $(111) (12)%

Operating Expenses:
Fuel, purchased and
net interchange power 23 14 (125) (21)
Other operation 2 7 (1) (1)
Maintenance 1 10 (1) (3)
Depreciation 2 27 1 2
Amortization of regulatory
assets, net 1 4 9 24
Taxes other than income taxes - - (3) (11)
--- --- ---- ---
Total operating expenses 29 12 (120) (15)
--- --- ---- ---

Operating income (4) (10) 9 9
--- --- ---- ---

Other income, net - - (40) (a)
Interest expense, net (3) (22) 1 4
--- --- ---- ---
Income before income tax expense (1) (5) (32) (31)
Income tax expense 1 6 (13) (35)
--- --- ---- ---
Net income $(2) (10)% $(19) (29)%
=== === ==== ===
(a) Percent greater than 100.

Comparison of the Third Quarter of 2002 to the Third Quarter of 2001

Operating Revenues
Total operating revenues increased $25 million or 8 percent in the third
quarter of 2002 compared with the same period of 2001, primarily due to
higher wholesale revenues from sales of capacity and energy primarily due to
a reduction in prices and a lower volume of bilateral transactions and sales
of excess capacity and energy ($15 million) and higher retail revenues ($10
million) due to higher retail sales. Retail kilowatt-hour (kWh) sales
increased by 4.5 percent in the third quarter of 2002.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 2002,
primarily due to higher wholesale and retail sales.

Other Operation and Maintenance
Other O&M expense increased $3 million in 2002, primarily due to higher
maintenance costs associated with the generating plants ($2 million) and
higher administrative and general costs ($1 million).

Depreciation
Depreciation increased in 2002, primarily due to the new Energy Park
facility.

Interest Expense
Interest expense decreased $3 million in 2002, primarily due to the December
2001 refinancing of long-term debt at lower rates.

Comparison of the First Nine Months of 2002 to the First Nine Months of 2001

Operating Revenues
Total operating revenues decreased $111 million or 12 percent in the first
nine months 2002 compared with the same period of 2001, primarily due to
lower retail revenues ($35 million) and lower wholesale revenues from sales
of capacity and energy ($77 million) primarily due to a reduction in prices
and a lower volume of bilateral transactions and sales of excess capacity and
energy. Retail revenues decreased primarily due to a rate decrease on May 1,
2001 ($25 million) and lower retail sales ($10 million). Retail kWh sales
decreased by 1.7 percent in 2002.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $125 million or
21 percent in 2002, primarily due to lower wholesale and retail sales.

Other Operation and Maintenance
Other O&M expense decreased ($2 million) in 2002, primarily due to lower
operating costs for the fossil plants ($2 million) and lower nuclear expense
($2 million), which were partially offset by higher transmission and dispatch
costs ($2 million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased in 2002, due to higher
amortizations resulting from restructuring in 2001.

Taxes Other than Income Taxes
Taxes other than income taxes decreased $3 million in 2002, primarily due to
lower New Hampshire franchise taxes.

Other Income, Net
Other income, net decreased in 2002, primarily due to the sale of Millstone 3
in 2001 ($26 million), a gain on the disposition of property in 2001 ($4
million) and lower interest and dividend income in 2002 ($3 million).

Interest Expense
Interest expense increased in 2002, primarily due the issuance of rate
reduction bonds in April 2001 and January 2002, partially offset by the
December 2001 refinancing of long-term debt at lower rates.

Income Tax Expense
Income tax expense decreased in 2002, primarily due to the sale of Millstone
3 in 2001.

LIQUIDITY

PSNH expects its cash position to further improve in the fourth quarter of
2002 due to the sale of NAEC's 35.98 percent share of Seabrook on November 1,
2002. Following the sale of NAEC's share of Seabrook, PSNH will use the
proceeds refunded from NAEC to recover stranded costs and repay
approximately $60 million of debt with any remaining amounts being available
to be returned to NU.

PSNH had no significant financing activity in the third quarter of 2002. In
November 2002, NU expects to decrease to $300 million from $350 million a
line of credit for its regulated subsidiaries, including PSNH. As of
September 30, 2002, PSNH had $55 million outstanding under this facility.

PSNH's net cash flows provided by operating activities decreased to $121.6
million in the first nine months of 2002, compared with $227.1 million during
the same period of 2001. Cash flows provided by operating activities
decreased primarily due to the tax impact related to the buydown of the
Seabrook Power Contracts during 2001. Additionally, cash flows provided by
operating activities decreased as a result of a $19.1 million decrease in net
income in 2002. These decreases were partially offset by higher net
amortization of recoverable energy costs in 2002 as compared to net deferrals
in 2001.

There was a lower level of investing and financing activities in the first
nine months of 2002, as compared to the same period of 2001, primarily due to
the issuance of rate reduction bonds and the buydown of the Seabrook Power
Contracts in 2001. In 2002, PSNH issued $50 million of rate reduction bonds.
The level of common dividends totaled $24.5 million in the first nine months
of 2002 and $27 million in the first nine months of 2001.

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

Management's Discussion and Analysis of
Financial Condition and Results of Operations

WMECO is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs,
current report on Form 8-K dated October 21, 2002, and the NU 2001 Form 10-K.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2002 and the first nine months of 2002 are provided in the table
below.

Income Statement Variances
(Millions of Dollars)
2002 over/(under) 2001
-----------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $(25) (21)% $ (92) (25)%

Operating Expenses:
Fuel, purchased and
net interchange power (29) (38) (105) (43)
Other operation (8) (40) (14) (27)
Maintenance - - (6) (38)
Depreciation - - - -
Amortization 14 (a) (92) (73)
Taxes other than income taxes - - (2) (23)
Gain on sale of utility plant - - 121 100
---- --- ----- ---
Total operating expenses (23) (21) (98) (29)
---- --- ----- ---

Operating income (2) (15) 6 18
---- --- ----- ---

Other income, net 4 (a) 1 38
Interest expense, net - - (1) (5)
---- --- ----- ---
Income before income tax expense 2 24 8 44
Income tax expense 1 27 (10) (a)
---- --- ----- ---
Net income $ 1 22% $ 18 (a)%
==== === ===== ===

(a) Percent greater than 100.

Comparison of the Third Quarter of 2002 to the Third Quarter of 2001

Operating Revenues
Operating revenues decreased by $25 million or 21 percent in 2002, primarily
due to lower retail revenues ($21 million) and lower wholesale and other
revenues ($4 million). Retail revenues were lower primarily due to a
decrease in the standard offer service rate resulting from a competitive bid
process required by the DTE ($30 million) partially offset by an increase in
the transition charge rate ($9 million) and higher distribution revenues from
higher sales. The decrease in revenues related to the decrease in the
standard offer service rate is offset by a corresponding decrease in fuel,
purchased and net interchange power. Retail sales increased by 5.3 percent.
Wholesale revenues were lower primarily due to the expiring of long-term
contracts ($2 million).

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased in 2002,
primarily due to the lower supply price for standard offer service ($29
million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased in the third quarter of 2002
primarily due to higher amortizations related to the recovery of stranded
costs ($12 million).

Other Operation
Other operation expense decreased by $8 million in 2002 primarily due to a
one-time pension charge in 2001 ($6 million).

Other Income, Net
Other income, net increased in 2002, primarily due to environmental costs
recorded in 2001.

Comparison of the First Nine Months of 2002 to the First Nine Months of 2001

Operating Revenues
Operating revenues decreased by $92 million or 25 percent in 2002, primarily
due to lower retail revenues ($57 million) and lower wholesale and other
revenues ($35 million). Retail revenues were lower primarily due to a
decrease in the standard offer service rate resulting from a competitive bid
process required by the DTE ($84 million) partially offset by an increase in
the transition charge rate ($23 million) and higher distribution revenues.
The decrease in revenues related to the decrease in the standard offer
service rate is offset by a corresponding decrease in fuel, purchased and net
interchange power. Retail sales increased by 0.8 percent. Wholesale
revenues were lower primarily due to lower sales of energy and capacity due
to buydown and buyout of various cogenerator contracts ($13 million), the
inclusion in 2001 of revenue from the output of the Millstone units ($14
million) and lower sales of Vermont Yankee ($4 million). The buydown and
buyout of cogeneration contracts has a corresponding decrease in fuel,
purchased and net interchange power.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased in 2002,
primarily due to the lower supply price for standard offer service ($85
million), the buydown and buyout of various cogeneration contracts ($12
million) and lower nuclear fuel expense ($4 million).

Other Operation and Maintenance
Other O&M expense decreased by $19 million in 2002, primarily due to lack of
nuclear expenses in 2002 as a result of the sale of Millstone units at the
end of the first quarter in 2001 ($12 million) and lower general and
administrative expenses ($6 million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased in 2002 ($92 million)
primarily due to the amortization in 2001 related to the sale of the
Millstone units ($121 million) offset by higher amortizations in 2002 related
to the recovery of stranded costs ($31 million).

Gain on Sale of Utility Plant
In 2001, WMECO recorded a gain on the sale of its ownership share in the
Millstone units. A corresponding amount of amortization expense was
recorded.

Income Tax Expense
Income tax expense decreased in 2002 primarily due to the recognition in 2002
of investment tax credits as a result of a regulatory decision ($13 million).

LIQUIDITY

WMECO had no significant financing activities in the third quarter of 2002.
In November 2002, NU expects to decrease to $300 million from $350 million a
line of credit for its regulated subsidiaries, including WMECO. As of
September 30, 2002, WMECO had $55 million outstanding under this facility.

WMECO projects a modest level of system financings over the next three months
to six months. WMECO has applied to the DTE to issue $100 million of debt to
refinance existing short-term debt and its prior spent nuclear fuel
obligations pursuant to the Nuclear Waste Policy Act of 1982 for nuclear fuel
burned prior to April 6, 1983.

WMECO's net cash flows provided by operating activities decreased to $20.7
million in the first nine months of 2002, compared with $79.3 million during
the same period of 2001. Changes in working capital items were the primary
drivers of the decrease.

There was a lower level of investing and financing activities in the first
nine months of 2002, as compared to the same period of 2001, primarily due to
the sale of the Millstone units, the buyout and buydown of independent power
producer contracts, and the issuance of rate reduction certificates in 2001.
The level of common dividends totaled $12 million in the first nine months of
2002 and $9 million in the first nine months of 2001.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The quantitative and qualitative disclosures about market risk are set forth
in "Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations," herein.

ITEM 4. CONTROLS AND PROCEDURES

NU, CL&P, PSNH and WMECO (collectively, the companies) evaluated the design
and operation of their disclosure controls and procedures to determine
whether they are effective in ensuring that the disclosure of required
information is timely made in accordance with the Exchange Act and the rules
and forms of the Securities and Exchange Commission (SEC). These evaluations
were made under the supervision and with the participation of management,
including the companies' principal executive officer and principal financial
officer, within the 90-day period prior to the filing of this Quarterly
Report on Form 10-Q. The principal executive officer and principal financial
officer have concluded, based on their review, that the companies' disclosure
controls and procedures, as defined at Exchange Act Rules 13a-14(c) and 15(d)-
14(c), are effective to ensure that information required to be disclosed by
the companies in reports that it files under the Exchange Act is recorded,
processed, summarized, and reported within the time periods specified in SEC
rules and forms. No significant changes were made to the companies' internal
controls or other factors that could significantly affect these controls
subsequent to the date of their evaluation.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

1. Bridgeport Energy, LLC v. Northeast Utilities Service Company and Select
Energy, Inc.

In July 2001, Select Energy filed a lawsuit against Bridgeport Energy, LLC
(Bridgeport) (a subsidiary of Duke Energy) in Connecticut Superior Court
regarding termination of a July 1998 contract to purchase installed
capability (ICAP) from Bridgeport. The contract, which had been assigned to
Select Energy by Holyoke Power and Electric Company, contained a termination
clause allowing either party to terminate if the Federal Energy Regulatory
Commission (FERC), NEPOOL or the Independent System Operator - New England
(ISO - New England) either eliminated ICAP or made material changes to ICAP
which affected the parties and such changes could not be resolved through
negotiation. Select Energy sought to terminate the contract under the
termination clause after ISO - New England filed with FERC to eliminate the
ICAP product. Bridgeport filed a lawsuit shortly thereafter alleging Select
Energy was in default under the contract and requesting damages for the
remainder of the contract.

The complaints have been transferred to the complex litigation docket of the
court with a scheduling order contemplating a trial in October 2003. The
parties are engaged in discovery.

Select Energy has also requested that the court strike the portion of
Bridgeport's complaint alleging that Select Energy engaged in unfair trade
practices under Connecticut law. Bridgeport has scheduled a series of
depositions of Northeast Utilities Service Company (NUSCO) and Select Energy
personnel to be completed by December 6, 2002. Non-binding mediation
occurred on October 17, 2002, but no settlement has been reached.

2. Millstone Station - Damage to Fish Population Lawsuits

On April 26, 2000, a lawsuit was filed in Hartford Superior Court naming as
defendants the Commissioner of the Connecticut Department of Environmental
Protection (DEP), Northeast Nuclear Energy Company (NNECO) and NUSCO. This
lawsuit, brought by the Connecticut Coalition Against Millstone (CCAM), the
Long Island Coalition Against Millstone, The Connecticut Green Party, Don't
Waste Connecticut and the STAR Foundation, challenged the validity of
previously issued DEP emergency and temporary authorizations allowing
Millstone to discharge wastewater not expressly authorized by the facility's
water discharge National Pollutant Discharge Elimination System Permit (NPDES
Permit). On October 16, 2000, this matter was dismissed by the Superior
Court. The plaintiffs filed an appeal of the dismissal with the Connecticut
Appellate Court. On June 26, 2002, the Appellate Court granted NUSCO's
motion to dismiss the appeal as moot. On August 6, 2002, CCAM moved to
reopen this appeal with the Appellate Court. CCAM's motion was denied on
September 11, 2002, and CCAM has requested the Connecticut Supreme Court to
hear an appeal of the Appellate Court decision.

3. Sale of Millstone to Dominion Nuclear Connecticut, Inc.

In March 2001, CCAM filed suit against the DEP, NNECO and DNCI challenging
the validity of Millstone's NPDES Permit and a previously issued DEP
emergency authorization allowing Millstone to discharge wastewater not
expressly authorized by the facility's NPDES Permit. The suit also
challenged DEP's authority to transfer both Millstone's NPDES Permit and
emergency authorization to DNCI. In July 2001, this matter was dismissed by
the Connecticut Superior Court and in August 2001, CCAM filed an appeal with
the Connecticut Appellate Court. On September 20, 2002, the Connecticut
Supreme Court assigned the matter to itself. The suit has not yet been
scheduled for oral argument.

4. Federal Energy Regulatory Commission - Installed Capability Deficiency
Charge

In July 2001, NU filed an appeal of the FERC orders imposing a $0.17 per
kilowatt-month ICAP charge from August 1, 2000 to April 1, 2001. In December
2001, FERC denied rehearing of its order allowing the $0.17 rate during the
court-imposed stay period, April through August 2001. NU appealed this
decision to the First Circuit Court of Appeals (First Circuit) and on
October 4, 2002, the First Circuit denied the appeal.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Listing of Exhibits (NU)

Exhibit No. Description
----------- -----------

10.38.4 Arrangement with Respect to Seabrook

10.38.5 Employment Agreement with Michael Morris dated as of
August 20, 2002

15 Deloitte & Touche LLP Letter Regarding Unaudited
Financial Information

99.1 Certification of Michael G. Morris, Chairman, President
and Chief Executive Officer of Northeast Utilities and
John H. Forsgren, Vice Chairman, Executive Vice President
and Chief Financial Officer of Northeast Utilities,
pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, dated
November 7, 2002

(a) Listing of Exhibits (CL&P)

4.2.7.4 Amendment No. 2 to the Standby Bond Purchase
Agreement dated as of September 9, 2002, among CL&P, The
Bank of New York, and the Participating Banks referred to
therein

99.1 Certification of Cheryl W. Grise, Chief Executive Officer
of The Connecticut Light and Power Company (the Company)
and John H. Forsgren, Executive Vice President and Chief
Financial Officer of Northeast Utilities Service Company,
as Agent for the Company, pursuant to 18 U.S.C. Section
1350 as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002, dated November 7, 2002

(a) Listing of Exhibits (PSNH)

99.1 Certification of Cheryl W. Grise, Chief
Executive Officer of Public Service Company of New
Hampshire (the Company) and John H. Forsgren, Executive
Vice President and Chief Financial Officer of Northeast
Utilities Service Company, as Agent for the Company,
pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, dated
November 7, 2002

(a) Listing of Exhibits (WMECO)

99.1 Certification of Cheryl W. Grise, Chief Executive Officer
of Western Massachusetts Electric Company (the Company)
and John H. Forsgren, Executive Vice President and Chief
Financial Officer of Northeast Utilities Service Company,
as Agent for the Company, pursuant to 18 U.S.C. Section
1350 as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002, dated November 7, 2002

(b) Reports on Form 8-K:

NU filed a current report on Form 8-K dated July 23, 2002, disclosing:

o NU's earnings press release for the second quarter and six months ended
June 30, 2002.

NU filed a current report on Form 8-K dated August 2, 2002, disclosing:

o NU's submission to the SEC of certain Statements under Oath of the
Principal Executive Officer and Principal Financial Officer in accordance
with the SEC's June 27, 2002 Order requiring the filing of sworn
statements pursuant to Section 21(a)(1) of the Securities and Exchange
Act of 1934.

NU filed a current report on Form 8-K dated August 14, 2002, disclosing:

o NU's submission to the SEC of certain Statements under Oath of the
Principal Executive Officer and Principal Financial Officer in accordance
with the SEC's June 27, 2002 Order requiring the filing of sworn
statements pursuant to Section 21(a)(1) of the Securities and Exchange Act
of 1934.

NU filed a current report on Form 8-K dated October 8, 2002, disclosing:

o NU's announcement of the lowering of its 2002 earnings guidance and the
declaration of a regular common dividend.

NU filed a current report on Form 8-K dated October 21, 2002, disclosing:

o NU's earnings press release for the third quarter and nine months ended
September 30, 2002.

NU, CL&P, PSNH, and WMECO filed current reports on Form 8-K dated October 21,
2002, disclosing:

o Presentation information related to earnings guidance for 2002 and 2003.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf
by the undersigned hereunto duly authorized.

NORTHEAST UTILITIES
-------------------
Registrant

Date: November 7, 2002 By /s/ John H. Forsgren
---------------- --------------------------------------
John H. Forsgren
Vice Chairman,
Executive Vice President
and Chief Financial Officer

Date: November 7, 2002 By /s/ John P. Stack
---------------- --------------------------------------
John P. Stack
Vice President - Accounting
and Controller

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Michael G. Morris, Chairman, President and Chief Executive Officer of
Northeast Utilities (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this quarterly
report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ Michael G. Morris
(Signature)
Michael G. Morris
Chairman, President and Chief Executive Officer

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John H. Forsgren, Vice Chairman, Executive Vice President and Chief
Financial Officer of Northeast Utilities (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ John H. Forsgren
(Signature)
John H. Forsgren
Vice Chairman, Executive Vice President and
Chief Financial Officer

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf
by the undersigned hereunto duly authorized.

THE CONNECTICUT LIGHT AND POWER COMPANY
---------------------------------------
Registrant

Date: November 7, 2002 By /s/ Randy A. Shoop
---------------- --------------------------------------
Randy A. Shoop
Treasurer

Date: November 7, 2002 By /s/ John P. Stack
---------------- --------------------------------------
John P. Stack
Vice President - Accounting
and Controller

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power
Company (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John H. Forsgren, Executive Vice President and Chief Financial Officer of
Northeast Utilities Service Company as Agent for The Connecticut Light and
Power Company (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer of
Northeast Utilities Service Company,
as Agent for the Company

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf
by the undersigned hereunto duly authorized.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
---------------------------------------
Registrant

Date: November 7, 2002 By /s/ David R. McHale
---------------- --------------------------------------
David R. McHale
Vice President and Treasurer

Date: November 7, 2002 By /s/ John P. Stack
---------------- --------------------------------------
John P. Stack
Vice President - Accounting
and Controller

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grise, Chief Executive Officer of Public Service Company of New
Hampshire (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John H. Forsgren, Executive Vice President and Chief Financial Officer of
Northeast Utilities Service Company as Agent for Public Service Company of
New Hampshire (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer of
Northeast Utilities Service Company,
as Agent for the Company

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf
by the undersigned hereunto duly authorized.

WESTERN MASSACHUSETTS ELECTRIC COMPANY
--------------------------------------
Registrant

Date: November 7, 2002 By /s/ David R. McHale
---------------- --------------------------------------
David R. McHale
Vice President and Treasurer

Date: November 7, 2002 By /s/ John P. Stack
---------------- --------------------------------------
John P. Stack
Vice President - Accounting
and Controller

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric
Company (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer

CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John H. Forsgren, Executive Vice President and Chief Financial Officer of
Northeast Utilities Service Company as Agent for Western Massachusetts
Electric Company (the Company), certify that:

1. I have reviewed this quarterly report on Form 10-Q of the Company;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the Evaluation Date); and

c) presented in this quarterly report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls;
and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: November 7, 2002

/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer of
Northeast Utilities Service Company,
as Agent for the Company