NORTHEAST UTILITIES SYSTEM - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2003
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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 by check mark whether the registrants are accelerated filers (as
defined in Rule 12b-2 of the Exchange Act):

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, 2003
- ------------------------ -------------------------------
Northeast Utilities
Common shares, $5.00 par value 127,369,219 shares

The Connecticut Light and Power Company
Common stock, $10.00 par value 6,035,205 shares

Public Service Company of New Hampshire
Common stock, $1.00 par value 301 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:

NU COMPANIES OR SEGMENTS

Boulos....................... E.S. Boulos Company
CL&P......................... The Connecticut Light and Power Company
CRC.......................... CL&P Receivables Corporation
HWP.......................... Holyoke Water Power Company
NGC.......................... Northeast Generation Company
NGS.......................... Northeast Generation Services Company
NU or the company............ Northeast Utilities
NU Enterprises............... NU's competitive subsidiaries comprised of
Select Energy, NGC, SESI, NGS, HWP, and Woods
Network. For further information, see Note 7,
"Segment Information," to the consolidated
financial statements.
PSNH......................... Public Service Company of New Hampshire
RMS.......................... R. M. Services, Inc.
Select Energy................ Select Energy, Inc. (including its wholly owned
subsidiary SENY)
SENY......................... Select Energy New York, Inc.
SESI......................... Select Energy Services, Inc.
Utility Group................ NU's regulated utilities comprised of CL&P,
PSNH, WMECO, and Yankee Gas. For further
information, see Note 7, "Segment Information,"
to the consolidated financial statements.
WMECO........................ Western Massachusetts Electric Company
Woods Network................ Woods Network Services, Inc.
Yankee....................... Yankee Energy System, Inc.
Yankee Gas................... Yankee Gas Services Company

THIRD PARTIES

Bechtel...................... Bechtel Power Corporation
CVEC......................... Connecticut Valley Electric Company
CYAPC........................ Connecticut Yankee Atomic Power Company
MGT.......................... Meriden Gas Turbines, LLC
NRG.......................... NRG Energy, Inc.
NRG-PM....................... NRG Power Marketing, Inc.

REGULATORS

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

OTHER

ABO.......................... Accumulated Benefit Obligation
Act, the..................... Public Act No. 03-135
C&LM......................... Conservation and Load Management
CSC.......................... Connecticut Siting Council
CTA.......................... Competitive Transition Assessment
DE........................... Delivery Efficiency
DIG.......................... Derivative Implementation Group
EITF......................... Emerging Issues Task Force
EPS.......................... Earnings per Share
FASB......................... Financial Accounting Standards Board
FIN.......................... FASB Interpretation
Fitch........................ Fitch Ratings
FMCC......................... Federally Mandated Congestion Costs
GSC.......................... Generation Service Charge
IERM......................... Infrastructure Expansion Rate Mechanism
Incentive Plan............... Northeast Utilities Incentive Plan
ISO-NE....................... New England Independent System Operator
kWh.......................... Kilowatt-hour
LMP.......................... Locational Marginal Pricing
MW........................... Megawatts
NU 2002 Form 10-K............ The Northeast Utilities and Subsidiaries
combined 2002 Form 10-K as filed with the SEC
NYMEX........................ New York Mercantile Exchange
O&M.......................... Operation and Maintenance
Restructuring
Settlement................. "Agreement to Settle PSNH Restructuring"
RMR.......................... Reliability Must Run
SBC.......................... System Benefits Charge
SCRC......................... Stranded Cost Recovery Charge
SFAS......................... Statement of Financial Accounting Standards
SMD.......................... Standard Market Design
TSO.......................... Transitional Standard Offer
VIE.......................... Variable Interest Entity

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
----

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, 2003 and December 31, 2002............... 2

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2003 and 2002............................ 4

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2003 and 2002.......... 5

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

Independent Accountants' Report............................. 39

Notes to Consolidated Financial Statements
(unaudited - all companies).................................. 40

The Connecticut Light and Power Company
and Subsidiaries

Consolidated Balance Sheets -
September 30, 2003 and December 31, 2002............... 68

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2003 and 2002............................ 70

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2003 and 2002.......... 71

Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 72

Public Service Company of New Hampshire
and Subsidiaries

Consolidated Balance Sheets -
September 30, 2003 and December 31, 2002............... 78

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2003 and 2002............................ 80

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2003 and 2002.......... 81

Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 82

Western Massachusetts Electric Company
and Subsidiary

Consolidated Balance Sheets -
September 30, 2003 and December 31, 2002............... 88

Consolidated Statements of Income -
Three Months and Nine Months Ended
September 30, 2003 and 2002............................ 90

Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2003 and 2002.......... 91

Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 92

Item 3. Quantitative and Qualitative
Disclosures About Market Risk.......................... 95

Item 4. Controls and Procedures................................ 95

Part II. Other Information

Item 1. Legal Proceedings...................................... 96

Item 6. Exhibits and Reports on Form 8-K....................... 99

Signatures............................................................ 102

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

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

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 2003
reports on Form 10-Q and the NU 2002 Form 10-K.

FINANCIAL CONDITION

Overview
- --------

Consolidated: Northeast Utilities (NU or the company) earned $44 million, or
$0.35 per share in the third quarter of 2003, before the cumulative effect of
accounting change, compared with $48.6 million, or $0.38 per share, in the
third quarter of 2002. After the cumulative effect of an accounting change,
NU earned $39.2 million, or $0.31 a share, in the third quarter of 2003.
Third quarter 2003 results included a negative $4.7 million after-tax
cumulative effect of accounting change as a result of the adoption of
Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46,
"Consolidation of Variable Interest Entities," related to the consolidation
of R. M. Services, Inc. (RMS), a bill collection company that was once a
subsidiary of Yankee Energy System, Inc. (Yankee). NU merged with Yankee in
March 2000 and sold RMS in June 2001, retaining a preferred equity interest.
In connection with the adoption of FIN 46, effective July 1, 2003, NU was
required to consolidate RMS into NU's financial statements and adjusted its
equity interest as a cumulative effect of an accounting change.

Third quarter 2002 results included a net after-tax gain of $14.5 million, or
$0.11 per share, related to the elimination of certain reserves associated
with NU's ownership share of the Seabrook nuclear unit (Seabrook). NU sold
its 40.04 percent ownership share of Seabrook in November 2002.

For the first nine months of 2003, NU earned $126.3 million after the
cumulative effect of the accounting change, or $0.99 per share, compared with
net income of $96.1 million, or $0.74 per share, for the first nine months of
2002. The results for the first nine months of 2002 included elimination of
the aforementioned Seabrook reserves, as well as after-tax write-downs
totaling $10 million, or $0.08 per share, related to NU's investments in NEON
Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics) and
approximately $13 million, or $0.10 per share, of investment tax credits
related to divested generation reflected by Western Massachusetts Electric
Company (WMECO) as a result of a regulatory decision. The results for the
first nine months of 2003 did not include any similar write-downs or
investment tax credits. All per share amounts are reported on a fully
diluted basis.

Third quarter results benefited from improved results at NU Enterprises,
lower regulated company controllable operation and maintenance costs, and
lower interest costs. Those factors were offset by lower pension income and
the absence of earnings related to Seabrook.

Net income for NU Enterprises for the first nine months of 2003 was $24
million, or a $62.7 million increase in net income, compared to a loss of
$38.7 million for the first nine months of 2002. Net income for the first
nine months of 2003 for the Utility Group was $111 million, or a $47.5
million decrease from 2002 net income of $158.5 million. The reduction in
Utility Group net income was the result of the absence of approximately $13
million of investment tax credits that were reflected in the second quarter
of 2002 at WMECO, as well as lower pension income and the loss of net income
related to Seabrook in 2003 as compared to 2002. NU's earnings per share
also benefited modestly from its share repurchase program. NU repurchased
approximately 1.6 million shares at an average price of $14.14 in the first
quarter of 2003. There have been no further share repurchases in the second
or third quarters of 2003. NU had approximately 127 million shares
outstanding at September 30, 2003.

NU's revenues during the first nine months of 2003 increased to $5.2 billion
from $3.8 billion in the same period of 2002, or an increase of $1.4 billion.
Of the $1.4 billion increase in NU's revenues, $1.1 billion related to NU
Enterprises. NU Enterprises' wholesale revenues increased primarily due to
$400 million in higher requirements sales and $600 million in higher short-
term and non-requirements sales. A contributing factor to the higher short-
term sales is the change in settlement methodology at the New England
Independent System Operator (ISO-NE) as a result of the implementation of
Standard Market Design (SMD). The increase in revenues is also due to
increases in electric and firm natural gas sales at the Utility Group in 2003
as compared to 2002.

Utility Group: Utility Group net income was lower due to the absence of
approximately $13 million of investment tax credits that were reflected in
the second quarter of 2002 at WMECO, as well as lower pension income and the
loss of net income related to Seabrook. Lower pension income and the lack of
Seabrook earnings resulted in approximately a $13 million and a $9 million
decrease, respectively, in net income in 2003 as compared to 2002.

As a result of adjustments to estimated unbilled electric revenues, third
quarter 2003 Utility Group retail electric sales increased 4.9 percent in the
third quarter of 2003 compared to 2002. Absent that adjustment, Utility
Group retail electric sales would have decreased 0.3 percent. An adjustment
to estimated unbilled revenues had a negative impact on Yankee Gas Services
Company (Yankee Gas). Combined, the adjustments to estimated unbilled
revenues increased NU's net income by approximately $5.7 million in the third
quarter of 2003, resulting from a process to validate and update the
assumptions used to estimate unbilled revenues. For further information
regarding unbilled revenues, see "Critical Accounting Policies and Estimates
Updates - Adjustments to Estimates of Unbilled Revenues," included in this
Management's Discussion and Analysis.

Earnings before preferred dividends at The Connecticut Light and Power
Company (CL&P) totaled $30.4 million in the third quarter of 2003 and $63.2
million in the first nine months of 2003, compared to $29.3 million in the
third quarter of 2002 and $62.4 million in the first nine months of 2002.
Earnings for the three and nine months ended September 30, 2003 were
negatively impacted by lower pension income and lower earnings on a reduced
level of regulatory assets but were positively impacted by the adjustment to
the estimate of unbilled revenues.

Public Service Company of New Hampshire (PSNH) earned $12.6 million in the
third quarter of 2003 and $34.5 million in the first nine months of 2003,
compared to $19.5 million in the third quarter of 2002 and $46.4 million in
the first nine months of 2002. Lower PSNH net income resulted from higher
pension expense and a lower level of regulatory assets earning a return,
primarily due to the sale of Seabrook. These decreases were offset by an
increase to revenues as a result of an adjustment to the estimate of unbilled
revenues. The reduction in the level of net regulatory assets will continue
to negatively affect PSNH's 2003 to 2002 net income comparisons.
Additionally, net income for the first nine months of 2002 includes $4.2
million related to the positive resolution of certain contingencies related
to a PSNH regulatory proceeding.

Net income at WMECO was $5.2 million in the third quarter of 2003 and $13.9
million in the first nine months of 2003, compared to $4.7 million in the
third quarter of 2002 and $26.9 million in the first nine months of 2002.
The net income decrease in year to date 2003 earnings was due primarily to
the recognition of $13 million in investment tax credits in the second
quarter of 2002 as a result of a regulatory decision.

Yankee Gas lost $9.6 million in the third quarter of 2003 and earned $3.4
million in the first nine months of 2003, compared to a loss of $5.8 million
in the third quarter of 2002 and net income of $6.2 million in the first nine
months of 2002. Lower Yankee Gas earnings are primarily due to lower
revenues in the third quarter as a result of a downward adjustment in
estimated unbilled revenues offset by the positive impact of colder
temperatures in 2003 compared to 2002.

NU expects that pension income will decline from approximately $73 million in
2002 to approximately $32 million in 2003. Of the $41 million decline,
approximately 70 percent ($29 million) will reduce pre-tax earnings. The
remaining 30 percent ($12 million) relates to employees working on capital
projects and will be reflected as capital expenditures. The $29 million
increase in operating expenses is reflected evenly throughout the year and
has resulted in a decline of approximately $4.4 million in net income per
quarter during 2003.

NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy,
Inc. (Select Energy), Northeast Generation Company (NGC), Select Energy
Services, Inc. (SESI), Northeast Generation Services Company (NGS), and their
respective subsidiaries, and Woods Network Services, Inc. (Woods Network),
all of which are collectively referred to as "NU Enterprises." The ongoing
generation operations of Holyoke Water Power Company (HWP) are also included
in the results of NU Enterprises. NU Enterprises earned $6.9 million in the
third quarter of 2003 and $24 million in the first nine months of 2003,
compared to a loss of $9 million in the third quarter of 2002 and a loss of
$38.7 million in the first nine months of 2002. NU Enterprises' net income
improved due to better margins on wholesale and retail contracts, better
performance at NGC, which owns nearly 1,300 megawatts (MW) of primarily
hydroelectric and pumped storage generating capacity in Massachusetts and
Connecticut, and the absence of natural gas trading positions in 2003.
Natural gas trading positions in the first half of 2002 resulted in trading
losses. Over the past year, Select Energy has significantly reduced its
trading activities.

Select Energy's merchant energy business includes a wholesale business and a
retail marketing business. The wholesale business includes wholesale
origination, portfolio management and the operation of more than 1,400 MW of
pumped storage, hydroelectric and coal-fired generation assets. The
wholesale business earned $4.5 million in the third quarter of 2003 and $23.9
million in the first nine months of 2003, compared to losses of $2.4 million
in the third quarter of 2002 and $13.6 million in the first nine months of
2002. The wholesale business benefited from a return to normal precipitation
in western New England during the first nine months of 2003, compared with
the same period of 2002, which increased conventional hydroelectric output.
This increase in output resulted in $3.7 million of additional net income in
2003, as compared to 2002. The wholesale business also benefited from the
absence of natural gas trading losses in 2003.

The retail marketing business lost $1.6 million in the first nine months of
2003 compared to a loss of $26.3 million in the first nine months of 2002.
The 2003 improved retail results are primarily due to improved margins and
growth in retail electric sales along with improved management of gas retail
contracts.

The energy services businesses earned $0.2 million in the third quarter of
2003 and $2.1 million in the first nine months of 2003 compared to earnings
of $1.7 million in the third quarter of 2002 and $1.8 million in the first
nine months of 2002.

NU Enterprises parent costs totaled $0.2 million in the third quarter of 2003
and $0.4 million in the first nine months of 2003 compared to $0.2 million in
the third quarter of 2002 and $0.6 million in the first nine months of 2002.

Future Outlook
- --------------

Consolidated: NU has narrowed its forecasted earnings in 2003 to between
$1.20 per share and $1.30 per share from its previous forecast of between
$1.10 per share and $1.30 per share. That range excludes any potential
losses at Select Energy due to the ongoing dispute over locational marginal
pricing (LMP) costs, which are estimated to be $90 million. NU also has
established a forecasted earnings range of between $1.20 per share and $1.40
per share for 2004.

Utility Group: The forecasted earnings in 2003 reflect earnings of between
$1.10 per share and $1.15 per share at the Utility Group. The NU
consolidated earnings range of between $1.20 per share and $1.40 per share
for 2004 reflects earnings of between $1.08 and $1.20 per share at the
Utility Group.

The 2004 Utility Group earnings range is dependent on a number of factors,
including the outcome of state rate cases involving CL&P and PSNH and a
Federal Energy Regulatory Commission (FERC) rate case involving NU's
transmission tariffs. A final decision from the Connecticut Department of
Public Utility Control (DPUC) in CL&P's rate case is due on December 15, 2003
with new rates effective on January 1, 2004. The filing of a PSNH rate case
is expected by the end of this year with new rates effective on February 1,
2004. On October 22, 2003, the FERC preliminarily approved NU's requested
transmission tariff, allowing rates to go into effect on October 28, 2003,
subject to refund. This new formula tariff will provide NU with more timely
recovery of the costs associated with its transmission capital program.

NU Enterprises: The forecasted earnings in 2003 reflect earnings of between
$0.20 per share and $0.25 per share at NU Enterprises. The NU consolidated
earnings range of between $1.20 per share and $1.40 per share for 2004
reflects earnings of between $0.22 and $0.30 per share at NU Enterprises.

The 2003 NU Enterprises earnings range excludes any potential negative impact
on Select Energy from an ongoing LMP dispute involving Select Energy's
contract to provide CL&P with 50 percent of its standard offer service
through the end of 2003. The LMP dispute, now before an administrative law
judge at the FERC, relates to whether CL&P's standard offer suppliers,
including Select Energy, or CL&P's retail customers are responsible for
incremental costs associated with the implementation of SMD and LMP beginning
in March 2003. Select Energy's portion of these costs is $90 million. A
FERC decision is expected in 2004. For further information regarding the LMP
dispute, see "Impacts of Standard Market Design," in this Management's
Discussion and Analysis.

The 2004 earnings range of between $0.22 per share and $0.30 per share
represents earnings of between $28 million and $38 million. Management
estimates that between $24 million and $31 million of those earnings in 2004
will come from the wholesale and retail merchant energy business and between
$4 million and $7 million from the energy services business. Those ranges
are heavily dependent on NU Enterprises' ability to achieve targeted
wholesale and retail origination margins, successfully manage its contract
portfolios and achieve targeted growth in the services business.

Other: NU continues to project parent company debt and other expenses of
approximately $0.10 per share in 2003. The 2004 earnings range also reflects
$0.10 per share of parent company after-tax expenses, primarily related to
interest expense.

Liquidity
- ---------

Consolidated: NU's liquidity continues to be strong as NU had $118.1 million
of cash and cash equivalents on hand at September 30, 2003. NU's net cash
flows from operating activities decreased to $462.7 million in the first nine
months of 2003 from $472.3 million in the first nine months of 2002. The
decrease in cash flows from operating activities resulted from the payment of
$193 million of taxes, primarily on the gain on the sale of Seabrook,
increases in other uses of cash, which relate primarily to other regulatory
assets and increases in restricted cash, due to the placing of incremental
LMP costs collected into an escrow account beginning in July 2003. These
decreases were partially offset by a $35 million increase in income before
preferred dividends of subsidiaries combined with the positive impacts of
increased amortization from recovery of regulatory assets, lower pension
income, decreases in accounts receivable, and increases in accounts payable.

NU's liquidity was also enhanced by recent financings. On June 3, 2003, NU
issued $150 million of five-year notes at an interest rate of 3.3 percent.
The proceeds from the issuance of these notes were primarily used to
refinance Select Energy's short-term debt. On September 30, 2003, WMECO
issued $55 million of ten-year 5 percent notes, the proceeds from which WMECO
used to repay a similar level of borrowings from the NU system Money Pool.
On October 1, 2003, CL&P fixed the interest rate on $62 million of variable-
rate tax-exempt borrowings for five years at 3.35 percent. In the first nine
months of 2003, NU also repaid $33.6 million of long-term debt and $126.4
million of rate reduction bonds.

NU's capital expenditures totaled $386 million in the first nine months of
2003 compared to $327.3 million in the first nine months of 2002. NU
currently projects capital expenditures of approximately $600 million in
2003.

The level of common dividends totaled $54 million in the first nine months of
2003, compared with $50.2 million in the first nine months of 2002. The
increase in the level of common dividends resulted from NU paying two $0.1375
per share quarterly common dividends and one $0.15 per share quarterly common
dividend in the first nine months of 2003, compared to two $0.125 per share
quarterly common dividends and one $0.1375 per share quarterly common
dividend in the first nine months of 2002. On October 14, 2003, the NU Board
of Trustees declared a common dividend of $0.15 per share payable on
December 31, 2003, to shareholders of record on December 1, 2003. The dividend
increase was consistent with management's objective to continue to increase
the dividend level annually, subject to NU's ability to meet earnings targets
and the judgment of its Board of Trustees at the time the dividends are
declared.

In the third quarter 2003, Fitch Ratings (Fitch) raised the outlook of NU's
and CL&P's credit ratings to stable from negative. The change in outlook is
a result of Fitch's belief that the risks associated with CL&P's standard
offer service contract with NRG Energy, Inc. (NRG) had declined. For more
information on NRG see the "NRG Exposures" section of this Management's
Discussion and Analysis and Note 4B, "Commitments and Contingencies - NRG
Energy, Inc. Exposures," to the consolidated financial statements.

Utility Group: At September 30, 2003, NU's Utility Group had $10 million in
borrowings outstanding on its $300 million revolving credit line. This
credit line expires on November 11, 2003, and management expects to extend
this credit line from November 2003 through November 2004.

At September 30, 2003, CL&P had $40 million of accounts receivable and
unbilled revenues sold under its arrangement with a financial institution to
sell up to $100 million in accounts receivable and unbilled revenues. This
arrangement expires in July 2004. For more information regarding CL&P's
accounts receivable facility, see Note 1F, "Sale of Customer Receivables," to
the consolidated financial statements.

CL&P is seeking approval from its preferred shareholders to permanently amend
its charter to eliminate a requirement that unsecured debt represent no more
than 10 percent of total capitalization. At September 30, 2003, CL&P's
unsecured debt represented approximately 3 percent of CL&P's total
capitalization. CL&P is offering its preferred holders a payment of 1
percent of the $116.2 million par value of their shares if the preferred
holders vote in favor of the amendment and CL&P implements it. Preferred
holders of record as of September 30, 2003, are eligible to vote at a special
meeting, which will be held on November 25, 2003. Holders of at least two-
thirds of CL&P's approximately 2.3 million shares of preferred stock must
vote in favor of the change for it to pass. Management believes that CL&P
will benefit from such a change due to increased financial flexibility. In
the event that this change fails or if CL&P chooses not to implement it, CL&P
is also asking preferred holders to endorse another 10-year waiver that would
allow CL&P's unsecured debt to rise to 20 percent of total capitalization.
CL&P preferred holders approved a similar waiver in 1993 that is scheduled to
expire in March 2004.

Prior to July 1, 2003, CL&P recovered approximately $30 million of
incremental LMP costs from its customers and has withheld payment of these
incremental LMP costs from its standard offer service suppliers. This
positively impacted CL&P's liquidity. In July 2003, CL&P began depositing
new recoveries into an escrow account. Accordingly, further recovery of
these costs did not impact CL&P's liquidity. When the LMP dispute is
resolved, there will be a negative impact on CL&P's liquidity for the amounts
recovered but not deposited into the escrow account, as these amounts are
paid to standard offer service suppliers or returned to customers.

NU Enterprises: NU Enterprises had $30 million in borrowings and $123.2
million in letters of credit outstanding on NU parent's $350 million
revolving credit line. This credit line expires on November 11, 2003, and
management expects to extend this credit line from November 2003 through
November 2004.

At September 30, 2003, Select Energy has incurred and billed CL&P for
incremental LMP costs in the amount of approximately $71 million. As a
result of the LMP dispute, Select Energy has not received any amounts from
CL&P, which has negatively impacted Select Energy's liquidity. This negative
impact is expected to continue to increase until the resolution of the LMP
dispute.

Impacts of Standard Market Design
- ---------------------------------

Consolidated: On March 1, 2003, ISO-NE implemented SMD. As part of SMD, LMP
is now utilized to assign value and causation to transmission congestion and
line losses. Transmission congestion costs represent the additional costs
incurred due to the need to run uneconomic generating units in certain areas
that have transmission constraints, which prevent these areas from obtaining
alternative lower-cost generation. Line losses represent losses of
electricity as it is sent over transmission lines. The costs associated with
transmission congestion and line losses are now assigned to the pricing zone
in which they occur and the calculation of line losses is now based on an
economic formula. Prior to March 1, 2003, those costs were spread across
virtually all New England electric customers based on engineering data of
actual line losses experienced. As part of the implementation of SMD, ISO-NE
established eight separate pricing zones in New England: three in
Massachusetts and one in each of the five other New England states. The
three components of the LMP for each zone are 1) an energy cost, 2)
congestion costs and 3) line loss charges assigned to the zone. LMP is
increasing costs in zones that have inadequate or less cost-efficient
generation and/or transmission constraints, such as Connecticut, and
decreasing costs in zones that have sufficient or excess generation, such as
Maine. The implementation of SMD has also impacted pricing under wholesale
energy contracts depending on the energy delivery points chosen under those
contracts.

Utility Group: Connecticut has been designated a single pricing zone by ISO-
NE. For the seven-month period from March 1, 2003 through September 30,
2003, incremental LMP costs have totaled approximately $132.5 million,
including $71 million related to Select Energy. Approximately 70 percent of
these incremental costs (approximately $90 million, or approximately $13
million per month on average) were associated with line losses, with monthly
line losses ranging from $9.5 million to $17 million. LMP costs also include
approximately $41 million related to congestion costs for the seven-month
period with monthly congestion costs ranging from $0.2 million to $16.5
million.

In October 2003, incremental LMP costs amounted to approximately $13.7
million, including $8.6 million of line loss charges and $5.2 million of
congestion costs.

Management currently estimates that total incremental LMP costs for CL&P for
2003 will be approximately $180 million (approximately $120 million in line
losses and approximately $60 million in congestion costs). Actual
incremental LMP costs could be higher if congestion and line loss charges are
greater than anticipated as a result of unusual weather and other factors
management cannot predict.

CL&P's standard offer service contracts were executed in the fall of 1999
with the delivery points in the contracts at the suppliers' choice at any
point on the New England power pool. Prior to March 1, 2003, delivery by the
suppliers anywhere on the New England power pool resulted in the suppliers
being charged and paying their respective share of socialized congestion
costs. Subsequent to March 1, 2003, the delivery points chosen by the
suppliers have been zones with no or negative congestion and/or line losses.
Management believes that under the legal interpretation of the terms of its
standard offer service contracts with its standard offer suppliers, the
incremental costs associated with line losses and congestion between the
delivery points chosen by the suppliers and CL&P's service territory in
Connecticut are the responsibility of CL&P's customers.

The $132.5 million of incremental LMP costs incurred from March 1, 2003
through September 30, 2003 have been recorded as recoverable energy costs,
and approximately $95.6 million has been billed to CL&P's customers and
reflected in revenues through September 30, 2003. The remaining balance is
included in recoverable energy costs, which collectively is a component of
regulatory assets. Management believes that these congestion and line loss
charges are unavoidable, are part of the prudent cost of providing regulated
electric service in Connecticut and should be paid for by CL&P's customers.
Accordingly, CL&P sought and received approval on May 1, 2003, for recovery
of these costs through the energy adjustment clause (EAC), subject to refund.
CL&P began recovery of the March 2003 LMP costs in its May 2003 billings and
continues to bill LMP costs on a two-month lag.

The DPUC directed CL&P to pursue legal remedies against its standard offer
suppliers in an effort to assign liability for incremental LMP costs to those
suppliers. The DPUC indicated that it will support CL&P's efforts and that
CL&P's failure to aggressively pursue legal remedies may result in ultimate
disallowance of recovery of LMP-related costs. The DPUC also required CL&P
to obtain surety bonds, which are guaranteed by NU parent, for the $31.1
million of March 2003 and April 2003 incremental LMP costs. Amounts
collected from customers beginning with May 2003 incremental LMP costs that
were recovered in July 2003 were deposited into an escrow account. At
September 30, 2003, $45.8 million was deposited in the escrow account and is
included in restricted cash - LMP costs on the accompanying consolidated
balance sheet.

In response to the DPUC decision of May 1, 2003, CL&P has filed for a
declaratory judgment from the FERC to determine whether CL&P's standard offer
service suppliers are responsible for incremental LMP costs. Additionally,
CL&P has withheld payment of all $132.5 million of incremental LMP costs to
its standard offer service suppliers, pending resolution of this matter.
Hearings on this issue before a FERC administrative law judge occurred in
October 2003. As a result of these hearings, the parties agreed to a
settlement conference before a FERC settlement judge, which occurred from
November 4, 2003 to November 5, 2003. No settlement has been reached as of
November 7, 2003. Resolution of this issue by the FERC will likely occur in
2004, and a FERC administrative law judge decision may be issued in the
fourth quarter of 2003. Management continues to believe that these
incremental LMP costs will ultimately be recovered from its customers based
upon the legal interpretation of the standard offer supply contracts.
Management will continue to evaluate the likelihood of recovery of these
costs in the fourth quarter.

Another factor affecting the level of CL&P's operating costs is the
designation of certain generating units by ISO-NE as units needed for system
reliability. Some companies have applied to the FERC for "reliability must
run" (RMR) treatment for their units. There are two methods of RMR treatment
that have been allowed by the FERC, both of which allow these units
to receive cost of service-based payments in excess of their operational
energy costs, that recognize their reliability value. The two methods
allowed have provided certain generating units with the ability to collect
non-energy related costs through fixed cost payments and/or through the
submission of bid prices that include non-energy costs. The latter method
provided these units with a temporary safe harbor from the ISO-NE price cap
under certain circumstances. Prior to March 1, 2003, all RMR costs were
spread across New England with all utilities being billed by ISO-NE based
upon their share of New England's load. NU's regulated electric distribution
companies were responsible for approximately 25 percent of these costs.

Effective with the March 1, 2003 implementation of SMD, RMR costs were no
longer spread across New England but rather they were allocated to the
pricing zone in which the RMR unit is located. The only pricing zone
currently experiencing an RMR cost increase in which NU's regulated electric
distribution companies operate is Connecticut, where certain of the RMR units
reside. Prior to RMR, other reliability costs have been approved for recovery
by the DPUC in CL&P's 2001 Competitive Transition Assessment (CTA)
reconciliation filing. RMR costs incurred by CL&P during 2002 totaling $7.8
million have been fully recovered from customers and are subject to review in
CL&P's 2002 CTA reconciliation filing, which was filed on March 31, 2003.
For the nine-month period ended September 30, 2003, CL&P incurred $40.3 million
of RMR costs and recorded these costs as a regulatory asset. Management
believes that these costs will be recovered in CL&P's 2003 CTA reconciliation
filing.

As part of the SMD implementation on March 1, 2003, ISO-NE now calculates
line loss charges based on an economic formula and not on actual losses
experienced. To date, ISO-NE has not filed its methodology for determining
line loss charges with the FERC, and CL&P has been unable to verify the
validity or accuracy of ISO-NE's billings. Accordingly, on July 23, 2003,
CL&P filed a complaint with the FERC requesting that ISO-NE provide its
methodology for determining such charges. In October 2003, the FERC rejected
this complaint.

On July 25, 2003, CL&P filed with the DPUC a request for approval of a formal
recovery mechanism that would allow for the 2004 and beyond tracking and
recovery of all Federally Mandated Congestion Costs (FMCC) as outlined in
Connecticut Public Act No. 03-135 (the Act). The major cost components of
FMCC are congestion costs, line losses and RMR costs. Management anticipates
that this matter will be resolved by the DPUC by the end of 2003.

NU Enterprises: Select Energy continues to provide 50 percent of CL&P's
standard offer service. If it is ultimately concluded that some or all of
the incremental LMP costs, which began on March 1, 2003, are the
responsibility of the standard offer service suppliers, NU Enterprises' and
NU's pre-tax earnings for the nine months ended September 30, 2003, would be
reduced by up to $71 million with no incremental impact on Select Energy's
cash flows. Management currently expects Select Energy's share of
incremental LMP costs for 2003 to be approximately $90 million, depending on
the level of line losses and congestion costs experienced. Management
believes that these costs are not contractually Select Energy's
responsibility, but will continue to assess the collectibility of Select
Energy's accounts receivable from CL&P based on developments at the FERC.
Select Energy's standard offer service contract with CL&P expires on
December 31, 2003. NU Enterprises' and NU's 2003 earnings estimates do not
include the impact of these incremental LMP costs.

For information regarding commitments and contingencies related to the
accounting for the implementation of SMD, see Note 4A, "Commitments and
Contingencies - Restructuring and Rate Matters," to the consolidated
financial statements.

NRG Exposures
- -------------

Certain subsidiaries of NU have entered into various transactions with
subsidiaries of NRG. On May 14, 2003, NRG and certain of its subsidiaries
filed voluntary bankruptcy petitions in the United States Bankruptcy Court
for the Southern District of New York. NRG-related exposures to certain
subsidiaries of NU as a result of these transactions are as follows:

Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PM) has a
contract with CL&P to supply 45 percent of CL&P's standard offer service
load through December 31, 2003. NRG-PM attempted to terminate the contract
with CL&P, but the FERC ordered NRG-PM to continue serving CL&P under its
standard offer supplier contract. Subsequently, NRG-PM received a temporary
restraining order from the United States District Court for the Southern
District of New York (District Court) and stopped serving CL&P with standard
offer supply on June 12, 2003. NRG-PM was ultimately ordered by the FERC and
the District Court to resume serving CL&P's standard offer service load and
did so on July 2, 2003. During the period NRG-PM did not serve CL&P under
its standard offer service contract, CL&P purchased power from the spot market
at prices in excess of NRG-PM's contract price. This excess amounted to $7.9
million and was collected by CL&P from its customers. As a result of the
settlement described below, this amount will be collected from NRG-PM.

On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the
Office of Consumer Counsel and the attorney general of Connecticut entered
into a comprehensive settlement agreement. Under the settlement agreement,
which is subject to the approval of the bankruptcy court and the FERC, NRG
will continue to deliver power to CL&P under the terms and conditions of the
standard offer service contract through the end of its term, which is
December 31, 2003. The disputes relating to responsibility for incremental
LMP costs will be determined by the District Court and the FERC respectively,
with payment, if any, to be made to NRG from amounts withheld and to be
withheld from NRG by CL&P. CL&P will also retain the $7.9 million withheld
from NRG for replacement power purchased by CL&P during the period June 12,
2003 through July 2, 2003. The parties will exchange releases of all claims
relating to the standard offer service contract.

Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit
against NRG in Connecticut Superior Court seeking judgment for unpaid pre-
March 1, 2003, congestion charges under its standard offer supply contract.
On August 5, 2002, CL&P withheld the then unpaid congestion charges from
payments due to NRG for standard offer service and continues to withhold
these amounts. The total amount of congestion costs withheld from NRG was
$27.5 million. If it is ultimately concluded that CL&P is responsible for
pre-March 1, 2003 congestion costs, management believes CL&P would be allowed
to recover these costs from its customers.

Station Service: Since December 1999, CL&P has provided NRG's Connecticut
generating plants with station service, which includes energy and/or delivery
services provided when a generator is off-line or unable to satisfy its
station service requirements. Pursuant to the parties' interconnection
agreement dated July 1, 1999, CL&P provides this service at DPUC-approved
retail rates. NRG has disputed its obligation and has refused to pay CL&P
but has stated that it intends to assume the station service contract in
bankruptcy proceedings. NRG and CL&P stipulated to an order in bankruptcy
court requiring the determination of the amount owed by NRG for station
service under binding arbitration. If NRG assumes the contract, NRG will be
required to pay the amount determined in the arbitration to CL&P. Management
will continue to pursue recovery from NRG of the station service balance,
including $4.2 million NRG placed in an escrow account related to this
matter. During the second quarter of 2003, as a result of NRG's bankruptcy,
the amount due from NRG in excess of the escrow amount was reserved.
Management believes that amounts not collected from NRG are ultimately
recoverable from CL&P's customers. Therefore, a regulatory asset of $10.6
million was recorded. At September 30, 2003, NRG owed CL&P $15.4 million for
station service.

Through September 30, 2003, legal costs incurred by CL&P related to NRG's
bankruptcy amounted to $1.6 million. This amount has also been recorded as a
regulatory asset, and CL&P will continue to defer these legal costs as they
are incurred.

Meriden Gas Turbines, LLC: Yankee Gas, E.S. Boulos Company (Boulos), which
is a subsidiary of NGS, and CL&P have exposures to Meriden Gas Turbines, LLC
(MGT), an NRG subsidiary that is not included in NRG's voluntary bankruptcy
proceedings petition.

Yankee Gas has incurred and expended costs in excess of $16 million in the
construction of a natural gas pipeline to a generating plant that MGT was
constructing. Yankee Gas drew down on a $16 million letter of credit when
MGT stated that it was abandoning construction of the generating plant. NRG
has contested the draw down on the letter of credit in a lawsuit filed in
Connecticut Superior Court. Yankee Gas has a counterclaim pending against
MGT to recover additional monies in accordance with the contract that are in
excess of the $16 million letter of credit.

Boulos has a 50 percent interest in a joint venture that was building
switchyards for the MGT generating plant. To date, Boulos has $0.4 million
of accounts receivable from performing its 50 percent share of the joint
venture's work on the MGT. In addition, the joint venture has outstanding
payables of $2.6 million for which it has corresponding receivables from the
general contractor; Boulos' share equaling $1.3 million. The joint venture
has commenced a legal proceeding against the general contractor to collect
the amounts owed. The joint venture is also a party to a mechanics lien
foreclosure action in which one of its subcontractors is attempting to
foreclose upon a mechanics lien filed on the MGT generating plant. Boulos'
total exposure to NRG on this project is $1.7 million. MGT also currently
owes CL&P $0.5 million for work on the South Kensington switching station,
which was to be the interconnection point for the MGT generating plant.

Management does not expect that the resolution of the aforementioned MGT
disputes will have a material adverse effect on the financial condition or
results of operations of NU and its subsidiaries.

NU Enterprises
- --------------

Subsidiaries: NU Enterprises, Inc. is the parent company of Select Energy,
NGC, SESI, NGS, and their respective subsidiaries, and Woods Network, which
are collectively referred to as "NU Enterprises." The ongoing generation
operations of HWP are also included in the results of NU Enterprises. Select
Energy engages in wholesale and retail energy marketing activities and
limited energy trading activities for price discovery and risk management of
wholesale activities.

NU Enterprises includes 1,438 MW of generation capacity, consisting of 1,291
MW at NGC and 147 MW at HWP, which are used to support Select Energy's
merchant energy business.

In October 2003, NU revised an earlier application made to the SEC seeking to
expand its ability to support its unregulated businesses. The new
application primarily seeks to 1) reclassify Select Energy and Select Energy
New York, Inc. (SENY) as allowable retained businesses under the Public
Utility Holding Company Act of 1935 (1935 Act) not subject to the limitations
of a 15 percent capitalization test imposed by the Securities and Exchange
Commission's (SEC) 1935 Act Rule 58 (Rule 58 Investment Limit), 2) permit NU
to guarantee the obligations of its unregulated businesses up to $750 million
through September 30, 2006, and 3) increase its allowable investments in
exempt wholesale generators (EWGs) from $481 million to $1 billion. If
granted, the SEC's order would reduce the Rule 58 Investment Limit by the
amount of NU's investment in Select Energy and SENY at June 30, 2003, but not
limit NU's future investment in Select Energy and SENY. NU has no present
plans to significantly expand its EWG portfolio at this time. However, if an
investment opportunity becomes available, NU will be able to pursue it within
the new allowable EWG investment level. NU expects SEC approval in late 2003
or early 2004.

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.

Outlook: Financial performance at NU Enterprises improved significantly in
the first nine months of 2003 compared to the same period in 2002.

The wholesale business, which is part of NU Enterprises' merchant energy
business line, has obtained two significant contracts since the second
quarter of 2003. Select Energy has been awarded a contract to provide over
700 MW of default service to residential, commercial and industrial customers
of Massachusetts Electric Company and Nantucket Electric Company,
subsidiaries of National Grid Company. The contract period, which begins on
November 1, 2003 and runs through October 31, 2004, is expected to generate
revenues in excess of $100 million. The second contract calls for Select
Energy to provide approximately 40 MW of last resort service to customers of
Narragansett Electric Company from September 1, 2003 to August 31, 2004 with
expected revenues of approximately $6.5 million.

Management currently believes that the wholesale business will meet its 2003
net income estimate of between $27 and $30 million. To meet this estimate,
the wholesale business will need to successfully manage its portfolio of
contracts. For the first nine months of 2003, the wholesale business
produced net income of $23.9 million. The wholesale business is expected to
have net income in the fourth quarter of between $3 million and $6 million.

The second business included in NU Enterprises' merchant energy business is
the retail marketing business, which also improved its financial performance
in 2003 compared to 2002. For the first nine months of 2003, the retail
marketing business produced a net loss of $1.6 million compared with a net
loss of $26.3 million in 2002. Retail marketing is also expected to have a
net loss in the fourth quarter of between $0.4 million and $2.4 million
resulting in a net loss in the range of $2 million to $4 million for the
year.

Intercompany Transactions: For the first nine months of 2003, CL&P's standard
offer service purchases from Select Energy represented approximately $465
million of total NU Enterprises' revenues. Other transactions between CL&P
and Select Energy amounted to approximately $101 million in revenues for
Select Energy in the first nine months of 2003. Select Energy will continue
to provide standard offer service for its affiliate WMECO through December
31, 2003. WMECO's purchases from Select Energy represented approximately
$110 million of NU Enterprises' revenues in the first nine months of 2003.
These amounts are eliminated in consolidation. Total Select Energy wholesale
full requirements revenue for the first nine months of 2003 were $1.2
billion.

NU Enterprises' Market and Other Risks
- --------------------------------------

Overview: For further information on risk management activities, see
"Competitive Energy Subsidiaries' Market and Other Risks" in NU's combined
report on Form 10-K.

Risk management within Select Energy is organized by management to address
the market, credit and operational exposures arising from the company's
merchant energy business lines: wholesale (which includes limited energy
trading for market and price discovery purposes) and retail marketing. The
framework and degree to which these risks are managed and controlled is
consistent with the limitations imposed by NU's Board of Trustees as
established and communicated in NU's risk management policies and procedures.

Wholesale and Retail Marketing: Select Energy manages its portfolio of
wholesale and retail marketing contracts and assets to maximize value while
maintaining an acceptable level of risk. At forward market prices in effect
at September 30, 2003, the wholesale portfolio, which includes the CL&P
standard offer service contract that extends through December 31, 2003 and
other contracts that extend to 2013, had a positive fair value. This
positive fair value indicates a positive impact on Select Energy's gross
margin in the future. However, there may be significant volatility in the
energy commodities markets that may impact this position between now and when
the contracts are settled. Accordingly, there can be no assurances that
Select Energy will realize the gross margin corresponding to the present
positive fair value on its wholesale portfolio. 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.

Hedging: For information on derivatives used for hedging purposes and
nontrading derivatives, see Note 2, "Derivative Instruments, Market Risk and
Risk Management," to the consolidated financial statements.

Energy Trading Activities Within Wholesale: 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. Energy trading contracts
are recorded at fair value, and changes in fair value impact net income. Over
the past year, Select Energy has significantly reduced its trading
activities, and trading now mainly supports the wholesale business for price
discovery, market intelligence and deal execution.

At September 30, 2003, Select Energy had trading derivative assets of $89
million and trading derivative liabilities of $52.8 million on a counterparty-
by- counterparty basis, for a net positive position of $36.2 million for the
entire trading portfolio. These amounts are combined with other derivatives
and are included in derivative assets and derivative liabilities on the
accompanying consolidated balance sheets. Information regarding nontrading
and other derivatives is included in Note 2, "Derivative Instruments, Market
Risk and Risk Management," to the consolidated financial statements.

There can be no assurances that Select Energy will actually realize cash
corresponding to the present positive net fair value of its trading
portfolio. Numerous factors could either positively or negatively affect the
realization of the net fair value amount in cash. 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 business day. Controls are in place
segregating responsibilities between the individuals actually trading (front
office) and those confirming the trades (middle office). The determination
of the portfolio's fair value is the responsibility of the middle office
independent from the front office.

The methods used to determine the fair value of energy trading contracts are
identified and segregated in the table of fair value of contracts at
September 30, 2003. 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 market prices;
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. Select Energy currently has one contract for which fair value is
determined based upon an other valuation method. Broker quotes for
electricity are available through the year 2005. Broker quotes for natural
gas are available through 2013.

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. However, Select Energy has sourced
substantially all of the trading contracts that have maturities in excess of
four years. Because these contracts are sourced, changes in the value of
these contracts due to changes in commodity prices are not expected to impact
Select Energy's earnings.

As of and for the three and nine months ended September 30, 2003, 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.

- -------------------------------------------------------------------------------
Fair Value of Trading Contracts
- -------------------------------------------------------------------------------
(Millions of Dollars) At September 30, 2003
- -------------------------------------------------------------------------------
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 $ - $ 0.1 $ - $ 0.1
Prices provided by
external sources 7.9 8.8 16.5 33.2
Prices based on
models or other
valuation methods - 2.9 - 2.9
- -------------------------------------------------------------------------------
Totals $ 7.9 $11.8 $16.5 $36.2
- -------------------------------------------------------------------------------

The fair value of energy trading contracts decreased by $8.8 million from $45
million at June 30, 2003 to $36.2 million at September 30, 2003. The change
in fair value of contracts since June 30, 2003, primarily represents a credit
reserve established in the third quarter of 2003, which reduced the fair
value of contracts.

The fair value of energy trading contracts decreased by $4.8 million from $41
million at January 1, 2003 to $36.2 million at September 30, 2003. For the
nine months ended September 30, 2003, the change in fair value attributable
to changes in valuation techniques and assumptions was due to a change in the
discount rate management uses to determine the fair value of trading
contracts. In the second quarter of 2003, the rate was changed from a fixed
rate of 5 percent to a market-based LIBOR discount rate.

- -------------------------------------------------------------------------------
Total Fair Value
- -------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
(Millions of Dollars) September 30, 2003 September 30, 2003
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the beginning
of the period $45.0 $41.0
Contracts realized or otherwise
settled during the period (2.2) (7.2)
Fair value of new contracts
when entered into during
the period - -
Changes in fair value
attributable to changes in
valuation techniques and
assumptions - 2.3
Changes in fair value of
contracts (6.6) 0.1
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the end
of the period $36.2 $36.2
- -------------------------------------------------------------------------------

Changing Market: The breadth and depth of the market for energy trading and
marketing products in Select Energy's market continues to be 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, market pricing information is becoming less
readily available, and participants are more often unable 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. The decrease in
the number of counterparties participating in the market for long-term energy
contracts also continues to impact Select Energy's ability to estimate the
fair value of its long-term wholesale energy contracts.

Changes are occurring in the administration of transmission systems and
system operators in territories in which Select Energy does business.
Regional transmission organizations are being contemplated, and SMD was
implemented in New England on March 1, 2003. As more information regarding
these market changes becomes available, there could be additional adverse
effects that management cannot determine at this time.

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 advances, letters of credit, and parent guarantees), and the
use of standardized agreements that 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
contracts. 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. At September 30, 2003, approximately 80 percent of
Select Energy's counterparty credit exposure to wholesale and trading
counterparties was cash collateralized or rated BBB- or better. Another five
percent of the counterparty credit exposure was to unrated municipalities.

Asset Concentrations: At September 30, 2003, positions with two
counterparties collectively represented approximately $51 million, or 57
percent, of the $89 million trading derivative assets. The largest
counterparty's position is secured with letters of credit and cash
collateral. Select Energy holds an investment grade parent guarantee on the
second counterparty's position. None of the other counterparties represented
more than 10 percent of trading derivative assets at September 30, 2003.

Select Energy's 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 levels to sub-investment
grade, Select Energy could, under its present contracts, be asked to provide
approximately $237 million of collateral or letters of credit to various
unaffiliated counterparties and approximately $75 million to several
independent system operators and unaffiliated local distribution companies,
which management believes NU would currently be able to provide. NU's credit
ratings outlooks are currently stable or negative, but management does not
believe that at this time there is a significant risk of a ratings downgrade
to sub-investment grade levels.

Utility Group Business Development and Capital Expenditures
- -----------------------------------------------------------

On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000
volt transmission line project from Bethel, Connecticut to Norwalk,
Connecticut, proposed in October 2001 by CL&P. The configuration of the new
transmission line, enhancements to an existing 115,000 volt transmission
line, and work in related substations are estimated to cost approximately
$200 million. The line would help address the difficulties in serving the
load in southwest Connecticut that creates high LMP costs in Connecticut.
Unless judicial appeals delay the project, CL&P expects to begin construction
on portions of the project in the fourth quarter of 2003. This project is
exempt from the State of Connecticut's moratorium on the approval of new
electric and natural gas transmission projects. At September 30, 2003, CL&P
has capitalized approximately $13.1 million related to this project.

On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a
separate 345,000 volt transmission line from Norwalk, Connecticut to
Middletown, Connecticut. Estimated construction costs of this project are
approximately $620 million. CL&P will jointly site this project with UI and
CL&P will own 80 percent, or approximately $496 million, of the project.
This project is also exempt from the State of Connecticut's moratorium on the
approval of new electric and natural gas transmission projects. CL&P expects
the CSC to rule on the application in 2004 and for construction to take place
from 2005 through 2007. At September 30, 2003, CL&P has capitalized
approximately $7.6 million related to this project.

In September 2002, the CSC approved a plan to replace an undersea electric
transmission line between Norwalk, Connecticut and Northport - Long Island,
New York, at an estimated cost of $80 million. CL&P and the Long Island
Power Authority each own 50 percent of the line. The project still requires
federal and New York state approvals. Given the approval process, changing
pricing and operational rules in the New England and New York energy markets
and pending business issues between the parties, the expected in-service date
remains under evaluation. This project is also exempt from the State of
Connecticut's moratorium on the approval of new electric and natural gas
transmission projects. At September 30, 2003, CL&P has capitalized
approximately $5.9 million related to this project.

Yankee Gas had previously sought rate approval from the DPUC to build a 2.0
billion cubic foot liquefied natural gas storage and production facility in
Waterbury, Connecticut. On October 24, 2003, Yankee Gas received a draft
decision from the DPUC approving the construction and operation of a 1.2
billion cubic foot liquefied natural gas storage and production facility.
Construction of the facility, which is expected to take approximately three
years, could begin in early 2004. The draft decision allows for the deferral
of prudently incurred costs related to the project and requires Yankee Gas to
file a rate case to recover these investments when the facility is placed in
service. This project is also exempt from the State of Connecticut's
moratorium on the approval of new electric and natural gas transmission
projects. At September 30, 2003, Yankee Gas has capitalized approximately
$1.5 million related to this project. A final decision from the DPUC is
scheduled for November 2003.

In October 2003, the FERC approved the sale of Connecticut Valley Electric
Company's (CVEC) assets to PSNH. CVEC is a subsidiary of Central Vermont
Public Service Corporation (CVPS). The sale is expected to close in December
2003 and be effective January 1, 2004. The purchase price will be the book
value of CVEC's assets, currently estimated at approximately $9 million and
an additional $21 million to terminate the above-market wholesale power
purchase agreement CVEC has with CVPS. The $21 million payment will be
recovered over the next several years from PSNH's customers as a Part 3
stranded cost.

Restructuring and Rate Matters
- ------------------------------

Utility Group: On August 26, 2003, NU's electric operating companies filed
their first transmission rate case at the FERC since 1995. In the filing, NU
requested implementation of a formula rate that would allow recovery of
increasing transmission expenditures on a timelier basis and that the
changes, including a $23.7 million annual rate increase through 2004, take
effect on October 27, 2003. NU asked the FERC to maintain NU's existing
11.75 percent return on equity (ROE) until an ROE for the New England
Regional Transmission Organization (RTO) is established by the FERC. On
October 22, 2003, the FERC approved this filing implementing the proposed
rates subject to refund effective on October 28, 2003.

On October 31, 2003, ISO-NE, along with NU and six other New England
transmission companies, filed a proposal with the FERC to create a RTO for
New England. The RTO is intended to strengthen the independent and efficient
management of the region's power system while ensuring that consumers in New
England continue to have the most reliable system possible to realize the
benefits of a competitive wholesale market.

ISO-NE, as an RTO, will have a new independent governance structure, and will
also become the transmission provider for New England by exercising
operational control over New England's transmission facilities pursuant to a
detailed contractual arrangement with the New England transmission owners.
Under this contractual arrangement, the RTO will have clear authority to
direct the transmission owners to operate their facilities in a manner that
preserves system reliability, including requiring transmission owners to
expand existing transmission lines or build new ones when needed for
reliability. Transmission owners will retain their rights over revenue
requirements, rates and rate designs. The filing requests that the FERC
approve the RTO arrangements for an effective date of March 1, 2004.

In a separate filing made on November 4, 2003, NU along with six other New
England transmission owners requested, consistent with the FERC's pricing
policy for RTOs and Order 2000 compliant independent system operators, that
the FERC approve a single ROE for regional and local rates that would consist
of a base ROE as well as incentive adders of 50 basis points for joining an
RTO and 100 basis points for constructing new transmission facilities
approved by the RTO. If the FERC approves the request, the transmission
owners would receive a 13.3 percent ROE for existing transmission facilities
and a 14.3 percent ROE for new transmission facilities.

Connecticut - CL&P:

Public Act No. 03-135 and Rate Proceedings Rate Case: On June 25, 2003, the
Governor of Connecticut signed the Act into law. The Act amended
Connecticut's 1998 electric utility industry legislation. Among key
features, the Act created a Transitional Standard Offer (TSO) period from
2004 through 2006 that allows the base rate cap for customers to return to
1996 levels, which is an increase of up to 11.1 percent. If energy supply
costs exceed levels established in the TSO rate, these costs will be
recovered through an energy adjustment clause or through the FMCC charge in
the case of incremental LMP costs.

On July 1, 2003, CL&P made a filing with the DPUC to establish TSO service
and to set the TSO rates equal to December 31, 1996 total rate levels. Under
the Act, the DPUC must establish the TSO rates no later than December 15,
2003, with an effective date for the TSO rates of January 1, 2004.

To procure TSO service, an auction process was conducted by CL&P. On October
29, 2003, the auction process was completed and CL&P filed the results of the
auction process with the DPUC.

The Act also required CL&P to file a four-year transmission and distribution
plan with the DPUC. Accordingly, on August 1, 2003, CL&P filed a rate case
that amended rate schedules and proposed changes in electric distribution
service and transmission service rates to reflect a four-year plan for the
provision of such services. The amended rate schedules were designed to
increase CL&P's annual distribution component of revenues by the following
approximate amounts, beginning January 1, 2004, through January 1, 2007:

- -------------------------------------------------------------------------------
Incremental Percentage
Increase in
Year Incremental Increase Total TSO Rates
- -------------------------------------------------------------------------------
2004 $133.5 million 6.0%
2005 23.2 million 1.0%
2006 24.0 million 1.0%
2007 24.1 million 1.0%
- -------------------------------------------------------------------------------

In its rate case, CL&P cited the need for rate increases to recover 1)
increased costs of providing service, including higher pension and health
care costs, 2) an approximately $250 million per year capital program for
distribution, and 3) the recruitment and training of new workers as a result
of the aging of the current skilled electric craft worker population. CL&P
also requested a tracking mechanism that could annually adjust the electric
transmission rates to reflect FERC-approved transmission tariffs.

However, if the transmission rate tracking mechanism filing process does not
prove to be acceptable to the DPUC, CL&P proposed amended annual rate
schedules in its rate application that will be designed to adjust CL&P's
rates for transmission costs during the rate period.

Hearings on this filing were held in September 2003 and October 2003 with a
final decision expected to be issued in December 2003.

Seabrook Disposition of Proceeds: CL&P sold its share of the Seabrook nuclear
unit on November 1, 2002. CL&P received $37 million and recorded a gain on
the sale of approximately $16 million. The gain was recorded as a regulatory
liability and, when offset by the decommissioning top off and other
adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the proceeds
from the sale. This filing described CL&P's treatment of its share of the
proceeds from the sale. Hearings in this docket were held in September 2003,
and a final decision is scheduled to be issued in December 2003. Management
does not expect the final decision to have a material effect on CL&P's net
income or its financial position.

CTA and System Benefits Charge (SBC) Reconciliation: On April 3, 2003, CL&P
filed its annual CTA and SBC reconciliation with the DPUC. For the year
ended December 31, 2002, total CTA revenues and excess Generation Services
Charge (GSC) revenues exceeded the CTA revenue requirement by approximately
$93.5 million. This amount is recorded as a regulatory liability and is
included in other deferred credits on the accompanying consolidated balance
sheet. CL&P has proposed that a portion of the CTA/GSC overrecovery be
utilized to reduce the nuclear stranded cost regulatory asset and that the
remaining amount be carried forward through 2003. For the same period, SBC
revenues exceeded the SBC revenue requirement by approximately $22.4 million.
In compliance with a prior decision of the DPUC, a portion of the SBC
overrecovery was applied to regulatory assets, and the remaining overrecovery
of $18.6 million was applied to the CTA. Management expects a final decision
from the DPUC in this docket by the end of 2003. Management does not expect
the final decision to have a material effect on CL&P's net income or its
financial position.

Connecticut - Yankee Gas:

Infrastructure Expansion Rate Mechanism (IERM): On June 25, 2003, the DPUC
issued a final decision in the 2002 IERM docket. The DPUC concluded that the
basic concept of IERM is valid, appropriate and beneficial. The DPUC ordered
Yankee Gas to provide a credit to customers for 2002 and 2003 overrecoveries
during December 2003 through February 2004. As ordered, Yankee Gas submitted
a compliance filing with the DPUC on August 15, 2003 which included an
estimate of total overrecoveries for 2002 and 2003 of approximately $5.9
million. This amount has been recorded as a regulatory liability. On
September 11, 2003, the DPUC approved Yankee Gas' compliance filing,
including the calculation of the $5.9 million in estimated overrecoveries to
be refunded from December 2003 through February 2004.

On October 1, 2003, Yankee Gas filed with the DPUC its 2004 IERM compliance
filing. This filing is required annually on October 1 of each year to
provide a reconciliation of the system expansion program and the earnings
sharing mechanism projection. At this time, the DPUC has not issued a
schedule for this docket.

New Hampshire:

Transition Service: On September 12, 2003, in accordance with the "Agreement
to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH
filed for an updated transition service rate of $0.0513 per kilowatt-hour
(kWh), subject to adjustment, for commercial, industrial, and residential
customers for the period February 2004 through January 2005. The transition
service rate is $0.0467 per kWh for industrial customers and $0.0460 per kWh
for residential and small general service customers. Both rates are for the
period February 2003 through January 2004. In accordance with state law,
these rates are to be PSNH's actual, prudent and reasonable costs of
providing such power. Hearings are scheduled for late November 2003.

The transition service rates currently in effect are not fully recovering
PSNH's generation and purchased-power costs, including earning a return on
PSNH's generation investment. Transition service underrecoveries, in
addition to other stranded cost components of the Stranded Cost Recovery
Charge (SCRC), amounted to approximately $24 million since the start of
restructuring on May 1, 2001 through September 30, 2003. This amount
excludes the gain on the sale of Seabrook.

Delivery Rate Case: PSNH's delivery rates are fixed by the Restructuring
Settlement until February 1, 2004. Under the Restructuring Settlement, PSNH
is required to file a rate case by December 31, 2003 to determine PSNH's
delivery rates.

SCRC Reconciliation Filing: On May 1, 2003, PSNH filed a SCRC reconciliation
filing for the period January 1, 2002, through December 31, 2002 with the New
Hampshire Public Utilities Commission (NHPUC). This filing included the
reconciliation of stranded cost revenues with stranded costs, the
reconciliation of transition service revenues with transition service costs,
and a net proceeds calculation related to the sale of North Atlantic Energy
Corporation's share of Seabrook and the subsequent transfer of those net
proceeds to PSNH. Upon the completion of discovery and technical sessions
with NHPUC staff and the New Hampshire Office of the Consumer Advocate (OCA),
PSNH, the NHPUC Staff and the OCA entered into a stipulation and settlement
agreement that was filed with the NHPUC on September 15, 2003. An order from
the NHPUC approving the settlement agreement was received in October 2003.
The settlement agreement did not have a material impact on PSNH's net income
or its financial position.

Massachusetts:

Transition Cost Reconciliation: On March 31, 2003, WMECO filed its 2002
annual transition cost reconciliation with the Massachusetts Department of
Telecommunications and Energy (DTE). This filing reconciled the recovery of
generation-related stranded costs for calendar year 2002 and included the
renegotiated purchased power contract related to the Vermont Yankee nuclear
unit.

On July 15, 2003, the DTE issued a final order on WMECO's 2001 annual
transition cost reconciliation, which addressed WMECO's cost tracking
mechanisms. As part of that order, the DTE directed WMECO to revise its 2002
annual transition cost reconciliation filing. The revised filing was
submitted to the DTE on September 23, 2003. Hearings were held in October
2003, and a final decision from the DTE is expected in the first half of
2004. Management does not expect the outcome of this docket to have a
material adverse impact on WMECO's net income or its financial position.

For information regarding commitments and contingencies related to
restructuring and rate matters, see Note 4A, "Commitments and Contingencies -
Restructuring and Rate Matters," to the consolidated financial statements.

Critical Accounting Policies and Estimates Update
- -------------------------------------------------

Accounting for Incremental LMP Costs: The determination of whether CL&P's
retail customers or CL&P's standard offer service suppliers are responsible
for incremental LMP costs as a result of the implementation of the SMD in New
England and the impacts on Select Energy, NU Enterprises, CL&P and NU are
described in "Impacts of Standard Market Design" included in this Management
Discussion and Analysis.

There are significant accounting conclusions related to the incremental LMP
dispute. Management continues to believe that the incremental LMP costs
recorded as a regulatory asset are probable of future recovery from customers
and has recorded a regulatory asset for these costs on CL&P's financial
statements. Management must maintain this belief as CL&P argues before the
FERC that the incremental LMP costs should be the responsibility of the
standard offer suppliers as ordered by the DPUC. If at anytime before the
regulatory asset is fully recovered management cannot conclude that the costs
are probable of future recovery, then the remaining regulatory asset would be
written off. To the extent incremental LMP costs have been recovered through
the EAC, management must determine whether or not a regulatory liability is
required. Incremental LMP costs incurred and recovered are currently
included in accounts payable to the standard offer service suppliers. To the
extent CL&P is unable to collect these costs from its customers, CL&P would
not pay the suppliers for these costs which are included in accounts payable.
As a result, CL&P would have no negative earnings impact; rather Select
Energy would be required to write off its accounts receivable from CL&P and
record a corresponding loss.

Determining what party will ultimately be responsible for incremental LMP
costs requires a significant amount of judgment. Hearings on this issue
before a FERC administrative law judge occurred in October 2003. As a result
of these hearings, the parties agreed to a settlement conference before a
FERC settlement judge, which occurred from November 4, 2003 to November 5,
2003. No settlement has been reached as of November 7, 2003. Resolution of
this issue by the FERC will likely be in 2004, and a FERC administrative law
judge decision may be issued in the fourth quarter of 2003. At this point,
management believes that it is premature to record a reserve for incremental
LMP costs. Management continues to believe that these incremental LMP costs
will ultimately be recovered from CL&P's customers based upon its legal
interpretation of standard offer supply contracts. Management will continue
to evaluate the likelihood of recovery of these costs in the fourth quarter.
All developments through the time NU's 2003 annual report on Form 10-K is
filed will be evaluated, and any resulting impacts on the amounts included in
NU's financial statements will be reflected in 2003 earnings and the
December 31, 2003 consolidated balance sheet.

Adjustments to Estimates of Unbilled Revenues: Unbilled revenues represent
an estimate of electricity or gas delivered to customers that has not been
billed. Unbilled revenues represent assets on the balance sheet that become
accounts receivable in the following month as customers are billed. Billed
revenues are based on meter readings.

Unbilled revenues are estimated monthly using the requirements method. The
requirements method utilizes the total monthly volume of electricity or gas
delivered to the system and applies a delivery efficiency (DE) factor to
reduce the total monthly volume by an estimate of delivery losses to
calculate the total estimated monthly sales to customers. The total
estimated monthly sales amount less total monthly billed sales amount results
in a monthly estimate of unbilled sales. Small differences in the actual DE
factor to the estimated DE factor can have a significant impact on estimated
unbilled revenue amounts.

In the third quarter of 2003, the unbilled sales estimates for all Utility
Group companies were tested using the cycle method and will be tested at
least annually hereafter. The cycle method is historically more accurate
than the requirements method, when used in a mostly weather-neutral month.
The cycle method uses the billed sales from each meter reading cycle and an
estimate of unbilled days in each month based on the meter reading schedule.
The cycle method testing indicated that the estimate of total unbilled
revenues should be adjusted, which resulted in a net positive after-tax
earnings impact of approximately $5.7 million in the third quarter of 2003.
The positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million,
$3.3 million, and $0.3 million, respectively. There was a negative after-tax
impact on Yankee Gas of $5.1 million.

The estimate of unbilled revenues is sensitive to numerous factors that can
impact the amount of energy that is ultimately delivered to customers.
Estimating the impact of these factors is complex and requires management
judgment.

Energy Trading and Derivative Accounting: In April 2003, the FASB issued
Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities," which
amended existing derivative accounting guidance. SFAS No. 149 incorporates
interpretations that were included in previous Derivative Implementation
Group (DIG) guidance, clarifies certain conditions, and amends other existing
pronouncements. It was effective for contracts entered into or modified
after June 30, 2003. The new rules indicate that derivative contracts that
are subject to unplanned netting and can be settled for cash versus physical
delivery would no longer qualify for the normal purchases and sales
exception, which would require fair value accounting. Management has
determined that the adoption of SFAS No. 149 did not change NU's accounting
for wholesale and retail marketing contracts that were entered into prior to
July 1, 2003 or affect the ability of NU to elect the normal purchases and
sales exception.

Emerging Issues Task Force (EITF) Issue No. 03-11 "Reporting Gains and Losses
on Derivative Instruments That Are Subject to FASB Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities, and 'Not Held
for Trading Purposes' as Defined in EITF Issue No. 02-3, 'Issues related to
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities'" was derived from EITF Issue No. 02-3, which requires net
reporting in the income statement in revenues of energy trading activities.
Issue No. 03-11 addresses income statement classification of derivatives that
are not related to energy trading activities. Prior to Issue No. 03-11,
there was no specific accounting guidance that addressed the classification
in the income statement of Select Energy's retail marketing and wholesale
contracts, many of which are derivatives. The only applicable guidance was
EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as
an Agent." The indicators of gross revenue reporting include whether the
entity is the primary obligor in the arrangement, whether the entity has
inventory or credit risk, latitude in establishing price, and discretion in
supplier selection. Indicators of net revenue reporting are whether the
supplier is in the primary obligor in the arrangement, the entity earns a
fixed amount and the supplier has credit risk.

On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that
determining whether realized gains and losses on contracts that physically
deliver and are not held for trading purposes should be reported on a net or
gross basis is a matter of judgment that depends on the relevant facts and
circumstances. The EITF indicated that the indicators set forth in Issue No.
99-19 should continue to be considered and provided no new accounting
guidance. Additionally, the consensus recommends disclosure of where the
gains and losses are recorded in the income statement, and whether they are
presented on a net or gross basis. Issue No. 03-11 is effective for NU
prospectively on October 1, 2003.

Select Energy currently reports the settlement of short-term and long-term
derivative contracts that are not held for trading purposes on a gross basis,
generally with sales in revenues and purchases in expenses. Short-term sales
and purchases represent power that is purchased to serve full requirements
contracts but is ultimately not needed based on the actual load of the full
requirements customers. This excess power is sold to the independent system
operator or to other counterparties. Management is currently evaluating the
impact of the consensus in Issue No. 03-11 as it relates to income statement
classification of Select Energy's short-term energy purchases and sales.
Management will complete this evaluation in the fourth quarter in accordance
with Issue No. 03-11. If management determines that revenues and expenses
related to short-term sales and purchases should be reported net, then there
could be a significant reduction in both Select Energy's revenues and
expenses with no operating income or net income impact. For the first nine
months of 2003, short-term and non-requirements sales amounted to
approximately $600 million.

On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning
of "not clearly and closely related regarding contracts with a price
adjustment feature" as it relates to the election of the normal purchase and
sales exception to derivative accounting. The implementation of this
guidance is required for the fourth quarter of 2003 for NU. Management is
currently evaluating the impacts of Issue No. C-20, but believes that when it
is implemented, Issue No. C-20 will likely result in CL&P recording the fair
value of two existing power purchase contracts as derivative liabilities with
offsetting regulatory assets, as these contracts are part of stranded costs
and as management believes that these costs will continue to be recovered in
rates. Management's preliminary estimates of the fair values of these long-
term power purchase contracts indicate that the contracts have a combined
negative fair value of approximately $16 million.

Accounting for RMS Variable Interest Entity: On June 30, 2001, NU sold RMS
for $10 million in the form of convertible cumulative 5 percent preferred
stock and a warrant to buy 25 percent of the outstanding common stock of RMS
for $1,000 expiring in 2021. NU also agreed to guarantee a $3 million line
of credit for RMS through 2005. In the second and third quarters of 2003, RMS
began drawing on this line of credit and the balance outstanding at
September 30, 2003 was $0.5 million.

In January 2003, the FASB issued FIN 46 which was effective for NU on July 1,
2003 (NU did not electively delay implementation until the fourth quarter of
2003). RMS is a variable interest entity (VIE), as defined. FIN 46 requires
that the party to a VIE that absorbs the majority of the VIE's losses,
defined as the "primary beneficiary," consolidate the VIE. Upon adoption of
FIN 46, management determined that NU is the "primary beneficiary" of RMS
under FIN 46 and that NU is now required to consolidate RMS into NU's
financial statements. To consolidate RMS, NU adjusted the carrying value of
its preferred stock investment in RMS to the net book value of RMS. This
adjustment resulted in a negative $4.7 million after-tax cumulative effect of
accounting change. NU's remaining investment in RMS totaled $2.7 million at
September 30, 2003. NU has no other VIE's for which NU is defined as the
"primary beneficiary."

Goodwill Impairment Testing: NU conducts annual goodwill impairment testing
as of October 1st. Testing of current goodwill balances commenced in October
of 2003. Management does not expect that the completion of the impairment
testing in the fourth quarter of 2003 will result in an impairment loss.

Pension Plan Accounting: At December 31, 2002, the assets of the NU
noncontributory defined benefit plan (Plan) exceeded the accumulated benefit
obligation (ABO) by approximately $78 million. The ABO is the obligation for
employee service provided to date and does not assume future compensation
increases. At September 30, 2003, the estimated fair value of Plan assets
exceeded the December 31, 2002 ABO by approximately $220 million. If the
ABO, when remeasured next on December 31, 2003, exceeds the fair value of
Plan assets at that time, then NU would be required to record an additional
minimum pension liability.

Other Matters
- -------------

Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 4, "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.

Website: Additional financial information is available through NU's website
at www.nu.com.

RESULTS OF OPERATIONS - NU CONSOLIDATED

The components of significant income statement variances for the third
quarter of 2003 and the first nine months of 2003 are provided in the table
below.

Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $640 45% $1,360 35%

Operating Expenses:
Fuel, purchased and net
interchange power 595 70 1,204 55
Other operation 40 22 64 11
Maintenance (13) (18) (24) (12)
Depreciation - - (6) (4)
Amortization (5) (9) 48 56
Amortization of rate
reduction bonds 5 15 (1) (1)
Taxes other than income taxes 6 12 2 1
---- ---- ------ ----
Total operating expenses 628 48 1,287 37
---- ---- ------ ----

Operating income 12 10 73 22
---- ---- ------ ----

Interest expense, net (4) (6) (17) (8)
Other income/(loss), net (27) (85) (14) (70)
---- ---- ------ ----
Income before income tax expense (11) (14) 76 53
Income tax expense (7) (21) 41 97
Preferred dividends of subsidiaries - - - -
---- ---- ------ ----
Income before cumulative effect
of accounting change (4) (9) 35 36
Cumulative effect of accounting
change, net of tax benefit
of $2,553 (5) (100) (5) (100)
---- ---- ------ ----
Net Income $ (9) (19)% $ 30 31%
==== ==== ====== ====

Comparison of the Third Quarter of 2003 to the Third Quarter of 2002

Operating Revenues
Total revenues increased $640 million or 45 percent in the third quarter of
2003, compared with the same period in 2002, due to higher revenues from NU
Enterprises ($611 million after intercompany eliminations) and higher Utility
Group revenues ($29 million after intercompany eliminations).

NU Enterprises' revenue increase is primarily due to higher wholesale
revenues for Select Energy resulting from higher short-term sales. The
Utility Group revenue increase is primarily due to higher retail revenue
($121 million), partially offset by lower wholesale revenue ($88 million).
The regulated retail revenue increase is primarily due to CL&P's recovery of
incremental LMP costs ($69 million), increased electric sales volumes ($44
million) including a positive adjustment in estimated unbilled revenue and
higher price mix among customer classes ($11 million), partially offset by
lower revenues for Yankee ($4 million) primarily due to a downward adjustment
in estimated unbilled revenues. The total revenue impact of the unbilled
revenues adjustment was a positive $28 million. Regulated retail electric
kWh sales increased by 4.9 percent in the third quarter of 2003 after
reflecting adjustments to unbilled revenues. The regulated wholesale revenue
decrease is primarily due to lower PSNH sales as a result of owning less
generation due to the sale of Seabrook.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $595 million or
70 percent in the third quarter of 2003, primarily due to higher wholesale
energy purchases at NU Enterprises ($634 million after intercompany
eliminations), partially offset by lower purchased-power costs for the
Utility Group ($35 million after intercompany eliminations).

Other Operation
Other operation expense increased $40 million primarily due to higher
competitive business cost of goods sold expenses and higher expenses
resulting from business growth ($35 million), higher regulated business
administrative and general expenses ($6 million), primarily due to higher
health care costs and lower pension income, and higher RMR related
transmission expense ($3 million), partially offset by lower nuclear expense
resulting from the sale of Seabrook ($7 million).

Maintenance
Maintenance expense decreased $13 million primarily due to lower transmission
expenses at NU Enterprises ($6 million), lower regulated electric
distribution expenses primarily due to lower storm related expenses ($3
million), and lower nuclear expense due to the 2002 sale of Seabrook ($2
million).

Amortization
Amortization decreased $5 million in 2003, primarily due to lower recovery of
stranded costs by the Utility Group.

Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $5 million due to an increase
in the scheduled payment of principal.

Taxes Other Than Income Taxes
Taxes other than income taxes increased $6 million in the third quarter of
2003 primarily due to the recognition in 2002 of a Connecticut sales and use
tax audit settlement ($8 million), partially offset by a payment in 2002 to
compensate the Town of Waterford for lost property tax revenue as a result of
the sale of Millstone in 2001 ($3 million).

Interest Expense, Net
Interest expense, net decreased $4 million primarily due to lower interest at
NU parent and CL&P resulting from lower rates ($4 million) and lower North
Atlantic Energy Corporation (NAEC) interest due to the retirement of debt ($1
million), partially offset by higher competitive business interest as a
result of higher debt levels ($2 million).

Other Income/(Loss), Net
Other income/(loss), net decreased $27 million primarily due to the third
quarter 2002 elimination of certain reserves associated with NU's ownership
share of Seabrook ($25 million).

Income Tax Expense
Income tax expense decreased $7 million primarily due to lower taxable
income.

Cumulative Effect of Accounting Change, Net of Tax Benefit
The cumulative effect of accounting change, net of tax benefit was recorded
in the third quarter of 2003 in connection with the adoption of FIN 46,
effective July 1, 2003, which required NU to consolidate RMS into NU's
financial statements and adjusted its equity interest as a cumulative effect
of an accounting change.

Comparison of the First Nine Months of 2003 to the First Nine Months of 2002

Operating Revenues
Total revenues increased $1.4 billion or 35 percent in the first nine months
of 2003, compared with the same period in 2002, due to higher revenues from
NU Enterprises ($1.1 billion after intercompany eliminations) and higher
Utility Group revenues ($234 million after intercompany eliminations).

NU Enterprises' revenue increase is primarily due to higher wholesale
revenues for Select Energy resulting from the New Jersey basic generation
service and higher short-term sales. The Utility Group revenue increase is
primarily due to higher retail revenue ($311 million), partially offset by
lower wholesale revenue ($72 million). The regulated retail revenue increase
is primarily due to higher retail electric sales volumes ($121 million),
higher CL&P recovery of incremental LMP costs ($99 million), higher Yankee
Gas revenue resulting from higher purchased gas adjustment clause revenue
($47 million) and higher gas sales volumes ($22 million), and higher price
mix among customer classes for the regulated companies ($19 million).
Regulated retail electric kWh sales increased by 4.9 percent and firm natural
gas sales increased by 3.1 percent in 2003, both after the adjustments to
unbilled revenues. The regulated wholesale revenue decrease is primarily due
to lower PSNH 2003 sales as a result of the sale of Seabrook.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $1.2 billion or
55 percent in 2003, primarily due to higher wholesale energy purchases at NU
Enterprises ($1.2 billion after intercompany eliminations) and higher
purchased-power costs for the Utility Group ($33 million after intercompany
eliminations).

Other Operation
Other operation expense increased $64 million primarily due to higher
competitive business expenses resulting from business growth ($43 million),
higher RMR related transmission expense ($17 million), higher conservation
and load management expenditures ($14 million), and higher regulated business
administrative and general expenses ($11 million), primarily due to higher
health care costs and lower pension income, partially offset by lower nuclear
expense due to the sale of Seabrook ($27 million).

Maintenance
Maintenance expense decreased $24 million primarily due to lower nuclear
expense resulting from the sale of Seabrook ($24 million) and lower
competitive transmission expenses ($6 million), partially offset by higher
fossil production expenses resulting from PSNH generation maintenance
overhauls ($5 million).

Depreciation
Depreciation decreased $6 million in 2003 primarily due to lower
decommissioning and depreciation expenses resulting from 2002 depreciation of
Seabrook as compared to no 2003 depreciation ($8 million) and lower NU
Enterprises depreciation due to a study which resulted in lengthening the
useful lives of certain generation assets ($3 million), partially offset by
higher Utility Group depreciation resulting from higher plant balances.

Amortization
Amortization increased $48 million in 2003 primarily due to higher
amortization related to the Utility Group's recovery of stranded costs, in
part resulting from higher wholesale revenue from the sale of independent
power producer related energy.

Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds decreased $1 million due to the
scheduled payment of principal.

Taxes Other Than Income Taxes
Taxes other than income taxes increased $2 million primarily due to the
recognition in 2002 of a Connecticut sales and use tax audit settlement ($8
million), partially offset by a payment in 2002 to compensate the Town of
Waterford for lost property tax revenue as a result of the sale of Millstone
($3 million) and lower New Hampshire property taxes due to the sale of
Seabrook ($2 million).

Interest Expense, Net
Interest expense, net decreased $17 million primarily due to lower interest
for the regulated subsidiaries resulting from lower rates ($10 million),
lower interest at NU parent as a result of the interest rate swap related to
its $263 million fixed-rate senior notes ($7 million) and lower NAEC interest
due to the retirement of debt ($3 million), partially offset by higher
competitive business interest as a result of higher debt levels ($4 million).

Other Income/(Loss), Net
Other income/(loss), net decreased $14 million primarily due to the third
quarter 2002 elimination of certain reserves associated with NU's ownership
share of Seabrook ($25 million), partially offset by a charge in the first
quarter of 2002 reflecting a write-down of NU's investments in NEON and
Acumentrics ($15 million).

Income Tax Expense
Income tax expense increased $41 million due to higher taxable income and the
recording in 2002 of WMECO investment tax credits resulting from a regulatory
decision ($13 million).

Cumulative Effect of Accounting Change, Net of Tax Benefit
The cumulative effect of accounting change, net of tax benefit was recorded
in the third quarter of 2003 in connection with the adoption of FIN 46 which
required NU to consolidate RMS into NU's financial statements and adjust its
equity interest as a cumulative effect of an accounting change.

INDEPENDENT ACCOUNTANTS' REPORT

To the Board of Trustees and Shareholders
of Northeast Utilities:

We have reviewed the accompanying condensed consolidated balance sheet of
Northeast Utilities and subsidiaries ("the Company") as of September 30,
2003, and the related condensed consolidated statements of income for the
three-month and nine-month periods ended September 30, 2003 and 2002, and of
cash flows for the nine-month periods ended September 30, 2003 and 2002.
These interim financial statements are the responsibility of the Company's
management.

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

We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheets and
consolidated statements of capitalization of Northeast Utilities and
subsidiaries as of December 31, 2002 and 2001, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash flows,
and income taxes for the years then ended (not presented herein) and in our
report dated January 28, 2003 (February 27, 2003 as to Note 8A), we expressed
an unqualified opinion (which includes explanatory paragraphs with respect to
the Company's adoption in 2001 of Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities" as amended and its adoption in 2002 of Emerging Issues Task Force
Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" and SFAS No. 142 "Goodwill and Other Intangible
Assets") on those consolidated financial statements. In our opinion, the
information set forth in the accompanying condensed consolidated balance
sheet as of December 31, 2002 is fairly stated, in all material respects, in
relation to the consolidated balance sheet from which it has been derived.

/s/ Deloitte & Touche LLP
Deloitte & Touche LLP

Hartford, Connecticut
November 7, 2003

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 this complete report on Form 10-Q, the first and
second quarter 2003 reports on Form 10-Q, 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 2002 Form 10-K, and the current report
on Form 8-K dated September 30, 2003. The accompanying financial
statements contain, in the opinion of management, all adjustments
necessary to present fairly NU's and each NU company's financial
position at September 30, 2003, the results of operations for the
three-month and nine-month periods ended September 30, 2003 and
2002, and statements of cash flows for the nine-month periods ended
September 30, 2003 and 2002. All adjustments are of a normal,
recurring nature except those described in Note 1C. Due primarily
to the seasonality of NU's business, the results of operations and
statements of cash flows for the nine-month periods ended
September 30, 2003 and 2002, 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 of
America 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. Reclassifications
were made to regulatory asset and liability amounts and special
deposits on the accompanying consolidated balance sheets.
Reclassifications have also been made to the accompanying
consolidated statements of cash flows.

B. Regulatory Accounting

The accounting policies of NU's Utility Group conform to accounting
principles generally accepted in the United States of America
applicable to rate-regulated enterprises and historically 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."

The transmission and distribution businesses of CL&P, PSNH and
WMECO, along with PSNH's generation business and Yankee Gas
Services Company's (Yankee Gas) distribution business, continue to
be cost-of-service rate regulated, and management believes that the
application of SFAS No. 71 to that portion of those businesses
continues to be appropriate. Management also believes that it is
probable that NU's operating companies will recover their
investments in long-lived assets, including regulatory assets. In
addition, all material regulatory assets are earning an equity
return, except for securitized regulatory assets, which are not
supported by equity. The components of regulatory assets are as
follows:

- -------------------------------------------------------------------------------
At September 30, 2003
- -------------------------------------------------------------------------------
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
- -------------------------------------------------------------------------------
Recoverable nuclear costs $ 134.1 $ 65.9 $ 34.2 $ 34.0
Securitized assets 1,763.2 1,152.7 475.9 134.6
Income taxes, net 277.6 176.5 42.1 49.8
Unrecovered contractual
obligations 224.4 111.1 55.5 57.8
Recoverable energy costs 305.0 65.1 224.1 3.8
Other 243.4 91.0 140.2 (38.2)
- -------------------------------------------------------------------------------
Totals $2,947.7 $1,662.3 $972.0 $241.8
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
At December 31, 2002
- -------------------------------------------------------------------------------
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
- -------------------------------------------------------------------------------
Recoverable nuclear costs $ 85.4 $ 10.6 $ 36.8 $ 38.0
Securitized assets 1,891.8 1,244.5 505.4 141.9
Income taxes, net 331.9 170.5 96.5 54.2
Unrecovered contractual
obligations 239.3 116.8 58.7 63.8
Recoverable energy costs 299.6 49.3 241.7 4.3
Other 228.1 111.0 87.0 (18.5)
- -------------------------------------------------------------------------------
Totals $3,076.1 $1,702.7 $1,026.1 $283.7
- -------------------------------------------------------------------------------

At September 30, 2003 and December 31, 2002, the Utility Group also
maintained $71.6 million and $63.6 million, respectively, of
additional other regulatory assets primarily associated with Yankee
Gas.

Additionally, the Utility Group maintained $622.3 million and
$383.1 million of regulatory liabilities at September 30, 2003 and
December 31, 2002, respectively, primarily associated with CL&P's
Competitive Transition Assessment (CTA), Generation Service Charge
and System Benefits Charge (SBC) and PSNH's Stranded Cost Recovery
Charge (SCRC). These amounts are included in deferred credits and
other liabilities - other on the accompanying consolidated balance
sheets. Regulatory liabilities by Utility Group company are as
follows:

- -------------------------------------------------------------------------------
At September 30, 2003
- -------------------------------------------------------------------------------
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
- -------------------------------------------------------------------------------
Overrecoveries $622.3 $401.8 $178.2 $2.0
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
At December 31, 2002
- -------------------------------------------------------------------------------
(Millions of Dollars) NU Consolidated CL&P PSNH WMECO
- -------------------------------------------------------------------------------
Overrecoveries $383.1 $189.7 $187.1 $0.5
- -------------------------------------------------------------------------------

At September 30, 2003 and December 31, 2002, the Utility Group also
maintained $40.3 million and $5.8 million, respectively, of
additional other regulatory liabilities, primarily held by Yankee
Gas.

C. New Accounting Standards

Derivative Accounting: Effective January 1, 2001, NU adopted SFAS
No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended. In April 2003, the Financial Accounting
Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities," which amends
SFAS No. 133. This new statement incorporates interpretations that
were included in previous Derivative Implementation Group (DIG)
guidance, clarifies certain conditions, and amends other existing
pronouncements. It is effective for contracts entered into or
modified after June 30, 2003. The new rules indicate that
derivative contracts that are subject to unplanned netting and can
be settled for cash versus delivery would no longer qualify for the
normal purchases and sales exception, which would require fair
value accounting. Management has determined that the adoption of
SFAS No. 149 did not change NU's accounting for wholesale and
retail marketing contracts that were entered into prior to July 1,
2003, or the ability of NU to elect the normal purchases and sales
exception.

Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Gains
and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133, Accounting for Derivative Instruments and
Hedging Activities, and 'Not Held for Trading Purposes' as Defined
in EITF Issue No. 02-3, 'Issues related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities'" was
derived from EITF Issue No. 02-3, which requires net reporting in
the income statement in revenues of energy trading activities.
Issue No. 03-11 addresses income statement classification of
derivatives that are not related to energy trading activities.
Prior to Issue No. 03-11, there was no specific accounting guidance
that addressed the classification in the income statement of Select
Energy, Inc.'s (Select Energy) retail marketing and wholesale
contracts, many of which are derivatives. The only applicable
guidance was EITF Issue No. 99-19, "Reporting Revenue Gross as a
Principal versus Net as an Agent." The indicators of gross revenue
reporting include whether the entity is the primary obligor in the
arrangement, whether the entity has inventory or credit risk,
latitude in establishing price, and discretion in supplier
selection. Indicators of net revenue reporting are whether the
supplier is the primary obligor in the arrangement, the entity
earns a fixed amount and the supplier has credit risk.

On July 31, 2003, the EITF reached a consensus in Issue No. 03-11
that determining whether realized gains and losses on contracts
that physically deliver and are not held for trading purposes
should be reported on a net or gross basis is a matter of judgment
that depends on the relevant facts and circumstances. The EITF
indicated that the indicators set forth in Issue No. 99-19 should
continue to be considered and provided no new accounting guidance.
Additionally, the consensus recommends disclosure of where the
gains and losses are recorded in the income statement, and whether
they are presented on a net or gross basis. Issue No. 03-11 is
effective for NU prospectively on October 1, 2003.

Select Energy currently reports the settlement of short-term and
long-term derivative contracts that are not held for trading
purposes on a gross basis, generally with sales in revenues and
purchases in expenses. Short-term sales and purchases represent
power that is purchased to serve full requirements contracts but is
ultimately not needed based on the actual load of the full
requirements customers. This excess power is sold to the
independent system operator or to other counterparties. Management
is currently evaluating the impact of the consensus in Issue No. 03-
11 as it relates to income statement classification of Select
Energy's short-term energy purchases and sales. Management will
complete this evaluation in the fourth quarter in accordance with
Issue No. 03-11. If management determines that revenues and
expenses related to short-term sales and purchases should be
reported net, then there could be a significant reduction in both
Select Energy's revenues and expenses with no operating income or
net income impact. For the first nine months of 2003, short-term
and non-requirements sales amounted to approximately $600 million.

On June 25, 2003, the DIG cleared Issue No. C-20, which addressed
the meaning of "not clearly and closely related regarding contracts
with a price adjustment feature" as it relates to the election of
the normal purchase and sales exception to derivative accounting.
The implementation of this guidance is required for the fourth
quarter of 2003 for NU. Management is currently evaluating the
impacts of Issue No. C-20, but believes that when it is
implemented, Issue No. C-20 will likely result in CL&P recording
the fair value of two existing power purchase contracts as
derivative liabilities with offsetting regulatory assets, as these
contracts are part of stranded costs and as management believes
that these costs will continue to be recovered in rates.
Management's preliminary estimates of the fair values of these long-
term power purchase contracts indicate that the contracts have a
combined negative fair value of approximately $16 million.

Accounting for RMS Variable Interest Entity: On June 30, 2001, NU
sold R. M. Services, Inc. (RMS) for $10 million in the form of
convertible cumulative 5 percent preferred stock and a warrant to
buy 25 percent of the outstanding common stock of RMS for $1,000
expiring in 2021. NU also agreed to guarantee a $3 million line of
credit for RMS through 2005. In the second and third quarters of
2003, RMS has been drawing on this line of credit.

In January 2003, the FASB issued Interpretation No. (FIN) 46,
"Consolidation of Variable Interest Entities," which was effective
for NU on July 1, 2003. NU did not electively delay implementation
until December 31, 2003. RMS is a variable interest entity (VIE),
as defined. FIN 46 requires that the party to a VIE that absorbs
the majority of the VIE's losses, defined as the "primary
beneficiary," consolidate the VIE. Upon adoption of FIN 46,
management determined that NU was the "primary beneficiary" of RMS
under FIN 46 and that NU is now required to consolidate RMS into
NU's financial statements. To consolidate RMS, NU adjusted the
carrying value of its preferred stock investment in RMS to the net
book value of RMS. This adjustment resulted in a negative $4.7
million after-tax cumulative effect of accounting change. NU's
remaining investment in RMS totaled $2.7 million at September 30,
2003. NU has no other VIE's for which NU is defined as the
"primary beneficiary."

Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics
of Both Liabilities and Equity." SFAS No. 150 establishes
standards on how to classify and measure certain financial
instruments with characteristics of both liabilities and equity.
SFAS No. 150 is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise effective for NU for the
third quarter of 2003. As NU no longer has any preferred stock
subject to mandatory redemption outstanding, the adoption of SFAS
No. 150 did not have an impact on NU's consolidated financial
statements.

D. Stock-Based Compensation

NU maintains an Employee Stock Purchase Plan and other long-term,
stock-based incentive plans under the Northeast Utilities Incentive
Plan (Incentive Plan). NU accounts for these plans under the
recognition and measurement principles of Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related interpretations. No stock-based employee compensation
cost for stock options is reflected in net income, as all options
granted under those plans had an exercise price equal to or above
the market value of the underlying common stock on the date of
grant. At this time, NU has not elected to transition to expensing
stock options under the fair value-based method of accounting for
stock-based employee compensation. The following tables illustrate
the effect on net income and earnings per share (EPS) if NU had
applied the fair value recognition provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation," to stock-based employee
compensation related to stock options and NU's Employee Stock
Purchase Plan:

---------------------------------------------------------------------
For the Three Months Ended
---------------------------------------------------------------------
(Millions of Dollars, September 30, September 30,
except per share amounts) 2003 2002
---------------------------------------------------------------------
Net income, as reported $39.2 $48.6
Total stock-based employee
compensation expense
determined under
fair value-based method for
all awards, net of related (0.6) (1.1)
tax effects
---------------------------------------------------------------------
Pro forma net income $38.6 $47.5
---------------------------------------------------------------------
EPS:
Basic and fully
Diluted - as reported $ 0.31 $ 0.38
Basic and fully
Diluted - pro forma $ 0.30 $ 0.37
---------------------------------------------------------------------

---------------------------------------------------------------------
For the Nine Months Ended
---------------------------------------------------------------------
(Millions of Dollars, September 30, September 30,
except per share amounts) 2003 2002
---------------------------------------------------------------------
Net income, as reported $126.3 $96.1
Total stock-based employee
compensation expense
determined under
fair value-based method for
all awards, net of related (1.8) (3.4)
tax effects
---------------------------------------------------------------------
Pro forma net income $124.5 $92.7
---------------------------------------------------------------------
EPS:
Basic and fully
diluted - as reported $ 0.99 $ 0.74
Basic and fully
diluted - pro forma $ 0.98 $ 0.71
---------------------------------------------------------------------

During the nine-month period ended September 30, 2003, NU granted
approximately 384,000 shares of restricted stock under the
Incentive Plan. The shares granted had a value of $5.4 million
when granted. This amount was recorded in shareholders' equity.
For the nine months ended September 30, 2003, approximately $1.2
million was amortized to expense related to the restricted stock.
During the nine-month period ended September 30, 2003, no stock
options were awarded.

E. Other Income/(Loss), Net

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

---------------------------------------------------------------------
For the Nine Months Ended
---------------------------------------------------------------------
September 30, September 30,
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Investment write-downs $ - $(17.1)
Seabrook-related items - 23.3
Investment income 13.5 19.1
Other, net (7.5) (5.6)
---------------------------------------------------------------------
Totals $ 6.0 $ 19.7
---------------------------------------------------------------------

F. Sale of Customer Receivables

CL&P has an arrangement with a financial institution under which
CL&P can sell up to $100 million of accounts receivable and
unbilled revenues. At September 30, 2003, CL&P had sold accounts
receivable of $40 million to the financial institution with limited
recourse through CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. Additionally, at September 30, 2003, $6.4
million of assets were designated as collateral and restricted
under the agreement with CRC. Concentrations of credit risk to the
purchaser under this agreement with respect to the receivables are
limited due to CL&P's diverse customer base within its service
territory. At September 30, 2003, amounts sold to CRC from CL&P
but not sold to the financial institution totaling $215.6 million
are included in investments in securitizable assets on the
accompanying consolidated balance sheets. These amounts would be
excluded from CL&P's assets in the event of CL&P's bankruptcy. At
December 31, 2002, $40 million of accounts receivable were sold to
the financial institution. On July 9, 2003, CL&P renewed this
arrangement for a one-year period.

G. Guarantees

In November 2002, the FASB issued FIN 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," which requires disclosures
by a guarantor in its interim and annual financial statements about
its obligations under certain guarantees that it has issued and
clarifies that a guarantor is required to recognize, at the
inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing the guarantee.

NU provides credit assurance in the form of guarantees and letters
of credit in the normal course of business, primarily for the
financial performance obligations of NU Enterprises. NU would be
required to perform under these guarantees in the event of non-
performance by NU Enterprises, primarily Select Energy. At
September 30, 2003, the maximum level of exposure under guarantees
by NU, primarily on behalf of NU Enterprises, totaled approximately
$435 million. Additionally, NU had $123.2 million of letters of
credit issued for the benefit of NU Enterprises outstanding at
September 30, 2003. In conjunction with its investment in RMS, NU
guarantees a $3 million line of credit through 2005, of which $0.5
million was outstanding at September 30, 2003, which is included in
the $435 million total. Effective July 1, 2003, NU now consolidates
the financial statements of RMS with the NU financial statements.

Additionally, CL&P has obtained surety bonds in the amount of $31.1
million related to the March 2003 and April 2003 incremental
locational marginal pricing (LMP) costs to comply with a
Connecticut Department of Public Utility Control (DPUC) order. At
September 30, 2003, NU guaranteed $42.8 million of surety bonds for
NU subsidiaries, including the LMP-related surety bonds. This
amount is included in the total NU guarantee amount of
approximately $435 million. These surety bonds contain ratings
triggers that would require NU to post additional collateral in the
event that NU's ratings are downgraded.

NU currently has authorization from the Securities and Exchange
Commission (SEC) to provide up to $500 million of guarantees for NU
Enterprises through June 30, 2004, and has applied for authority to
increase this amount to $750 million through September 30, 2006.
The aforementioned surety bonds are subject to a separate $50
million SEC limitation apart from the current $500 million
guarantee limit. The amount of guarantees outstanding for
compliance with the SEC limit is approximately $258 million, which
is calculated using different criteria than the maximum level of
exposure of approximately $435 million required to be disclosed
under FIN 45. The $42.8 million of surety bonds is the same for
both SEC and FIN 45 purposes.

H. Adjustments to Estimates of Unbilled Revenues

Unbilled revenues represent an estimate of electricity or gas
delivered to customers that has not been billed. Unbilled revenues
represent assets on the balance sheet that become accounts
receivable in the following month as customers are billed. Billed
revenues are based on meter readings.

Unbilled revenues are estimated monthly using the requirements
method. The requirements method utilizes the total monthly volume
of electricity or gas delivered to the system and applies a
delivery efficiency (DE) factor to reduce the total monthly volume
by an estimate of delivery losses to calculate the total estimated
monthly sales to customers. The total estimated monthly sales
amount less total monthly billed sales amount results in a monthly
estimate of unbilled sales.

In the third quarter of 2003, the unbilled sales estimates for all
Utility Group companies were tested using the cycle method and will
be tested annually hereafter. The cycle method is historically
more accurate than the requirements method, when used in a mostly
weather-neutral month. The cycle method uses the billed sales from
each meter reading cycle and an estimate of unbilled days in each
month based on the meter reading schedule. The cycle method
resulted in an adjustment to the estimate of unbilled revenues that
had a net positive after-tax earnings impact of approximately $5.7
million in the third quarter of 2003. The positive after-tax
impacts on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million,
and $0.3 million, respectively. There was a negative after-tax
impact on Yankee Gas of $5.1 million.

I. Restricted Cash - LMP Costs and Special Deposits

Restricted cash - LMP costs represents incremental LMP cost amounts
that have been collected by CL&P and deposited into an escrow
account.

Special deposits primarily consist of collateral balances resulting
from Select Energy wholesale activities.

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

A. Derivative Instruments

Effective January 1, 2001, NU adopted SFAS No. 133, as amended by
SFAS No. 149 in April 2003. Derivatives that are utilized for
trading purposes are recorded at fair value with changes in fair
value included in net income. Other contracts that are derivatives
but do not meet the definition of a cash flow hedge and cannot be
designated as being used for normal purchases or normal sales are
also recorded at fair value with changes in fair value included in
net income. 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
generally recognized in accumulated other comprehensive income, a
component of equity, until the underlying transactions occur. For
those contracts that meet the definition of a derivative and meet
the fair value hedge requirements, the changes in fair value of the
effective portion of those contracts are generally recognized on
the balance sheet as both the hedge and the hedged item are
recorded at fair value. For contracts that meet the definition of
a derivative but do not meet the hedging requirements, and for the
ineffective portion of contracts that meet the cash flow hedge
requirements, the changes in fair value of those contracts are
recognized currently in net income. Derivative contracts that are
entered into as a normal purchase or sale, will result in physical
delivery, meet the definitions in SFAS No. 149, and are documented
as such, are recorded under accrual accounting.

For information regarding recent accounting changes related to
trading activities, see Note 1C, "New Accounting Standards," to the
consolidated financial statements.

During the first nine months of 2003, a negative $7.8 million, net
of tax, was reclassified from other comprehensive income in
connection with the consummation of the underlying hedged
transactions and recognized in net income. The related hedged
transactions were also recognized in net income. A negative $0.02
million, net of tax, was recognized in net income for those
derivatives that were determined to be ineffective and for the
ineffective portion of cash flow hedges. Also during the third
quarter of 2003, new cash flow hedge transactions were entered into
that hedge cash flows through 2005. As a result of these new
transactions and market value changes since January 1, 2003, other
comprehensive income decreased by $18.7 million, net of tax.
Accumulated other comprehensive income at September 30, 2003, was a
negative $3.2 million, net of tax (decrease to equity), relating to
hedged transactions, and it is estimated that negative $1.6 million
of this balance, net of tax, will be reclassified as an increase to
net income within the next twelve months. Cash flows from the
hedge contracts are reported in the same category as cash flows
from the underlying hedged transaction.

The tables below summarize the derivative assets and liabilities at
September 30, 2003 and December 31, 2002. These amounts do not
include premiums paid, which are recorded as prepayments and
amounted to $18.6 million and $26.7 million at September 30, 2003
and December 31, 2002, respectively. These amounts also do not
include premiums received, which are recorded as other current
liabilities and amounted to $15.8 million and $33.9 million at
September 30, 2003 and December 31, 2002, respectively. The
premium amounts relate primarily to energy trading activities.

---------------------------------------------------------------------
At September 30, 2003
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
Select Energy:
Trading $ 89.0 $(52.8) $36.2
Nontrading 3.6 (1.4) 2.2
Hedging 7.3 (11.7) (4.4)
---------------------------------------------------------------------
Yankee Gas:
Hedging 2.3 - 2.3
---------------------------------------------------------------------
NU Parent:
Hedging 1.6 - 1.6
---------------------------------------------------------------------
Total $103.8 $(65.9) $37.9
---------------------------------------------------------------------

---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
Select Energy:
Trading $102.9 $(61.9) $41.0
Nontrading 2.9 - 2.9
Hedging 22.8 (2.0) 20.8
---------------------------------------------------------------------
Yankee Gas:
Hedging 2.3 - 2.3
---------------------------------------------------------------------
Total $130.9 $(63.9) $67.0
---------------------------------------------------------------------

Select Energy Trading: To gather market intelligence and utilize
this information in risk management activities for the wholesale
business, Select Energy conducts limited energy trading activities
in electricity, natural gas and oil, and therefore, experiences net
open positions. Select Energy manages these open positions with
strict policies that limit its exposure to market risk and require
daily reporting to management of potential financial exposures.
Derivatives used in trading activities are recorded at fair value
and included in the consolidated balance sheets as derivative
assets or liabilities. Changes in fair value are recognized in
operating revenues in the consolidated statements of income in the
period of change. The net fair value positions of the trading
portfolio at September 30, 2003 and December 31, 2002 were assets
of $36.2 million and $41 million, respectively.

Select Energy's trading portfolio includes New York Mercantile
Exchange (NYMEX) futures and options, the fair value of which is
based on closing exchange prices; over-the-counter forwards and
options, the fair value of which is based on the mid-point of bid
and ask market prices; bilateral contracts for the purchase or sale
of electricity or natural gas, the fair value of which is
determined using available information from external sources; and a
long-term bilateral energy purchase contract, the fair value of
which is determined using a model. The trading portfolio also
includes a LIBOR-based interest rate swap to mitigate fair value
fluctuations from changes in the LIBOR-based discount rate used to
determine the fair value of certain trading contracts. Select
Energy's trading portfolio also includes transmission congestion
contracts. The fair value of certain transmission congestion
contracts is based on published market data. Market information
for other transmission congestion contracts is not available, and
those contracts cannot be reliably valued. Management believes the
amounts paid for these contracts, which total $4.6 million, are
equal to their fair value.

Select Energy Nontrading: Nontrading derivative contracts are used
for delivery of energy related to Select Energy's retail and
wholesale activities. These contracts are not entered into for
trading purposes, but are subject to fair value accounting because
these contracts are derivatives that cannot be designated as normal
purchases or sales, as defined. These contracts cannot be
designated as normal purchases or sales either because they are
included in the New York energy market that settles financially or
because the normal purchase and sale designation was not elected by
management. The net fair values of nontrading derivatives valued
at the mid-point of bid and ask market prices at September 30, 2003
and December 31, 2002 were assets of $2.2 million and $2.9 million,
respectively.

Select Energy Hedging: Select Energy utilizes derivative financial
and commodity instruments, including futures and forward contracts,
to reduce market risk associated with fluctuations in the price of
electricity and natural gas purchased to meet firm sales
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 retail supply
requirements. These derivatives have been designated as cash flow
hedging instruments and are used to reduce the market risk
associated with fluctuations in the price of electricity, natural
gas, or oil. A derivative that hedges exposure to the variable
cash flows of a forecasted transaction (a cash flow hedge) is
initially recorded at fair value with changes in fair value
recorded in accumulated other comprehensive income. Hedges impact
net income when the forecasted transaction being hedged occurs,
when hedge ineffectiveness is measured and recorded, when the
forecasted transaction being hedged is no longer probable of
occurring, or when there is accumulated other comprehensive loss
and the hedge and the forecasted transaction being hedged are in a
loss position on a combined basis.

Select Energy maintains natural gas service agreements with certain
customers to supply gas at fixed prices for terms extending through
2005. Select Energy has hedged its gas supply component of the
risk under these agreements through NYMEX futures contracts. Under
these contracts, which also extend through 2005, the purchase price
of a specified quantity of gas is effectively fixed over the term
of the gas service agreements. At September 30, 2003, the NYMEX
futures contracts had notional values of $81.9 million and were
recorded at fair value as a derivative liability of $1.7 million.

Other derivative liabilities, which are valued at the mid-point of
bid and ask market prices, include forwards, options and swaps to
hedge Select Energy's basic generation service contracts in the PJM
region and were recorded at fair value as derivative liabilities of
$5 million. Other derivative liabilities include futures, options
and swaps in the New England region, which were recorded as
derivative liabilities with a fair value of $4.2 million at
September 30, 2003.

SENY maintains hedges on its retail sales portfolio through 2004,
which were also valued at the mid-point of bid and ask market
prices and recorded at fair value as a derivative asset of $4.1
million at September 30, 2003.

Yankee Gas Hedging: 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 an unaffiliated customer is effectively fixed
over the term of the gas service agreement with that customer for a
period of time not extending beyond 2005. At September 30, 2003,
the commodity swap agreement had a notional value of $7.2 million
and was recorded at fair value as a derivative asset of $2.3
million with an offsetting fair value of the firm commitment
recorded in current liabilities in the accompanying consolidated
balance sheets.

NU Parent Hedging: In March of 2003, NU parent entered into a fixed
to floating interest rate swap on its $263 million, 7.25 percent
fixed-rate note that matures on April 1, 2012. As a perfectly
matched fair value hedge, the changes in fair value of the swap and
the hedged debt instrument are recorded on the balance sheet but
are equal and offsetting in the consolidated statements of income.
The cumulative change in the fair value of the hedged debt of $1.6
million is included as long-term debt on the consolidated balance
sheets. Additionally, the resulting changes in interest payments
made are recorded as adjustments to interest expense.

B. Market Risk Information

Select Energy utilizes the sensitivity analysis methodology to
disclose quantitative information for its commodity price risks.
Sensitivity analysis provides a presentation of the potential loss
of future net income, 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. 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, fair 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
fair value based on closing exchange prices.

Select Energy Trading Portfolio: At September 30, 2003, Select
Energy calculated the market price resulting from a 10 percent
change in forward market prices. That 10 percent change would
result in approximately a $0.3 million increase or decrease 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.

Select Energy Retail Marketing and Wholesale Portfolio: 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
that 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 quotes on the futures exchange.

Select Energy has determined a hypothetical change in the fair
value for its retail marketing and wholesale portfolio, which
includes cash flow hedges and electricity, natural gas and oil
contracts and generation assets, assuming a 10 percent change in
forward market prices. At September 30, 2003, a 10 percent change
in market price would have resulted in an increase or decrease in
fair value of approximately $3.5 million.

The impact of a change in electricity, natural gas and oil prices
on Select Energy's retail marketing and wholesale portfolio at
September 30, 2003, is not necessarily representative of the
results that will be realized when the commodities provided for in
these contracts are physically delivered.

C. Other Risk Management Activities

Interest Rate Risk Management: NU manages its interest rate risk
exposure in accordance with written policies and procedures by
maintaining a mix of fixed and variable rate debt. At
September 30, 2003, approximately 80 percent (70 percent including
the debt subject to the fixed to floating interest rate swap in
variable rate debt), of NU's long-term debt, including fees and
interest due for spent nuclear fuel disposal costs, is at a fixed
interest rate. The remaining long-term debt is variable-rate and
is subject to interest rate risk that could result in earnings
volatility. Assuming a one percentage point increase in NU's
variable interest rates, including the rate on debt subject to the
fixed to floating interest rate swap, annual interest expense would
have increased by $7.6 million. At September 30, 2003, NU parent
maintained a fixed to floating interest rate swap to manage the
risk associated with its $263 million of fixed-rate debt.

Credit Risk Management: 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 margin 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.

NU's Utility Group has a lower level of credit risk related to
providing electric and gas distribution service than NU
Enterprises.

Credit risks and market risks at NU Enterprises 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 fair value 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.

At September 30, 2003, Select Energy maintained collateral balances
from counterparties of $29.2 million. This amount is included in
both special deposits and other current liabilities on the
accompanying consolidated balance sheets.

3. GOODWILL AND OTHER INTANGIBLE ASSETS

Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which ended the amortization of goodwill and certain
intangible assets with indefinite useful lives. SFAS No. 142 also
required 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.
NU selected October 1 as the annual goodwill impairment testing date.
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 is less than the carrying amount of the goodwill.
Excluding adjustments to the purchase price allocation in July 2003
related to the acquisition of Woods Electrical Co., Inc. and Woods
Network Services, Inc. (Woods Network), there were no impairments or
adjustments to the goodwill balances during the nine-month periods ended
September 30, 2003 and 2002. These adjustments primarily related to
the recording of contingent payments based on certain earnings targets
that have been met, as defined in the purchase agreements.

NU's reporting units that maintain goodwill are generally consistent
with the operating segments underlying the reportable segments
identified in Note 7, "Segment Information," to the consolidated
financial statements. Consistent with the way management reviews the
operating results of its reporting units, NU's reporting units under the
NU Enterprises reportable segment include: 1) the wholesale and retail
business reporting unit, and 2) the services reporting unit. The
wholesale and retail business reporting unit is comprised of the
operations of Select Energy, Northeast Generation Company (NGC) and the
ongoing generation operations of Holyoke Water Power Company (HWP),
while the services reporting unit is comprised of the operations of
Select Energy Services, Inc. (SESI), Northeast Generation Services
Company (NGS) and Woods Network. As a result, NU's reporting units that
maintain goodwill are as follows: Yankee Gas, classified under the
Utility Group - gas reportable segment, the wholesale and retail
business reporting unit and the services reporting unit which are both
classified under the NU Enterprises reportable segment. The goodwill
balances of these reporting units are included in the table herein.

At September 30, 2003, NU maintained $319.9 million of goodwill that is
no longer being amortized, $15.5 million of identifiable intangible
assets and $8.5 million of intangible assets not subject to
amortization, totaling $343.9 million. At December 31, 2002, NU
maintained $321 million of goodwill that is no longer being amortized,
$18.1 million of identifiable intangible assets and $6.8 million of
intangible assets not subject to amortization, totaling $345.9 million.
These amounts are included on the consolidated balance sheets as
goodwill and other purchased intangible assets, net. A summary of NU's
goodwill balances at September 30, 2003 and December 31, 2002, by
reportable segment and reporting unit is as follows:

--------------------------------------------------------------------------
(Millions of Dollars) September 30, 2003 December 31, 2002
--------------------------------------------------------------------------
Utility Group - Gas:
Yankee Gas $287.6 $287.6
NU Enterprises:
Services 29.1 30.2
Wholesale and Retail Business 3.2 3.2
--------------------------------------------------------------------------
Totals $319.9 $321.0
--------------------------------------------------------------------------

At September 30, 2003 and December 31, 2002, NU's intangible assets and
related accumulated amortization consisted of the following:

--------------------------------------------------------------------------
At September 30, 2003
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $6.5 $11.2
Customer list 6.6 2.4 4.2
Customer backlog,
employment related
agreements and other 0.1 - 0.1
--------------------------------------------------------------------------
Totals $24.4 $8.9 $15.5
--------------------------------------------------------------------------
Intangible assets not subject
to amortization:
Customer relationships $ 5.2
Tradenames 3.3
---------------------------------------------
Totals $ 8.5
---------------------------------------------

--------------------------------------------------------------------------
At December 31, 2002
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $4.6 $13.1
Customer list 6.6 1.7 4.9
Customer backlog,
employment related
agreements and other 0.1 - 0.1
--------------------------------------------------------------------------
Totals $24.4 $6.3 $18.1
--------------------------------------------------------------------------
Intangible assets not
subject
to amortization:
Customer relationships $ 3.8
Tradenames 3.0
---------------------------------------------
Totals $ 6.8
---------------------------------------------

NU recorded amortization expense of $2.6 million and $1.1 million for
the nine months ended September 30, 2003 and 2002, 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 2004 through 2008 is
$3.6 million in 2004 through 2007 and no amortization expense in 2008.
These amounts may vary as acquisitions and dispositions occur in the
future.

4. COMMITMENTS AND CONTINGENCIES

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

Connecticut:

Implementation of Standard Market Design: On March 1, 2003, the
New England Independent System Operator (ISO-NE) implemented
standard market design (SMD). As part of SMD, LMP is utilized to
assign value and causation to transmission congestion and line
losses. Management believes that under the legal interpretation of
the terms of its standard offer service contracts with its standard
offer suppliers, the incremental costs associated with line losses
and congestion between the delivery points chosen by the suppliers
and CL&P's service territory in Connecticut are the responsibility
of CL&P's customers. Management believes that these congestion and
line loss charges are unavoidable, are part of the prudent cost of
providing regulated electric service in Connecticut and should be
paid for by CL&P's customers.

CL&P incurred $132.5 million of incremental LMP costs from March 1,
2003 through September 30, 2003. As incurred, these costs were
recorded as recoverable energy costs and are included in regulatory
assets on the accompanying consolidated balance sheets. CL&P
received approval for recovery of these costs through an additional
charge on customer bills and began recovering them on May 1, 2003,
subject to refund and on a two-month lag. Approximately $95.6
million has been recovered through September 30, 2003. This amount
is included in operating revenues and offset by amortization
expense.

If it is ultimately concluded that the incremental LMP costs are
the responsibility of the standard offer service suppliers, NU
Enterprises' pre-tax earnings for the nine months ended
September 30, 2003 would be reduced by approximately $71 million,
and CL&P would eliminate the accounts payable to the standard offer
service suppliers with a reduction to operating expenses. At the
same time, a regulatory liability in the same amount would be
recorded with a reduction to operating revenues. This amount could
be material and there would be an impact on NU's and NU
Enterprises' net income. Net income could be negatively impacted if
LMP recoveries are refunded to CL&P's customers with carrying
charges, which would result in interest expenses.

CL&P Disposition of Seabrook Proceeds: CL&P sold its share of the
Seabrook nuclear unit on November 1, 2002. CL&P received $37
million and recorded a gain on the sale of approximately $16
million. The gain was recorded as a regulatory liability and, when
offset by the decommissioning top off and other adjustments, will
be refunded to customers. On May 1, 2003, CL&P filed its
application with the DPUC for approval of the disposition of the
proceeds from the sale. This filing described CL&P's treatment of
its share of the proceeds from the sale. Hearings in this docket
were held in September and a final decision is scheduled to be issued
in December 2003. Management does not expect the final decision to
have a material effect on CL&P's net income or its financial
position.

CTA and SBC Reconciliation: On April 3, 2003, CL&P filed its
annual CTA and SBC reconciliation with the DPUC. For the year
ended December 31, 2002, total CTA revenues and excess Generation
Services Charge (GSC) revenues exceeded the CTA revenue requirement
by approximately $93.5 million. This amount is recorded as a
regulatory liability. CL&P has proposed that a portion of the
CTA/GSC overrecovery be utilized to reduce the nuclear stranded
cost regulatory asset and that the remaining amount be carried
forward through 2003. For the same period, SBC revenues exceeded
the SBC revenue requirement by approximately $22.4 million. In
compliance with a prior decision of the DPUC, a portion of the SBC
overrecovery was applied to regulatory assets, and the remaining
overrecovery of $18.6 million was applied to the CTA. Management
expects a final decision from the DPUC in this docket by the end of
2003. Management does not expect the final decision to have a
material effect on CL&P's net income or its financial position.

Massachusetts: On March 31, 2003, WMECO filed its 2002 annual
transition cost reconciliation with the Massachusetts Department of
Telecommunications and Energy (DTE). This filing reconciled the
recovery of generation-related stranded costs for calendar year
2002 and included the renegotiated purchased power contract related
to the Vermont Yankee nuclear unit.

On July 15, 2003, the DTE issued a final order on WMECO's 2001
annual transition cost reconciliation, which addressed WMECO's cost
tracking mechanisms. As part of that order, the DTE directed WMECO
to revise its 2002 annual transition cost reconciliation filing.
The revised filing was submitted to the DTE on September 23, 2003.
Hearings were held in October 2003, and a final decision from the
DTE is expected in the first half of 2004. Management does not
expect the outcome of this docket to have a material adverse impact
on WMECO's net income or its financial position.

B. NRG Energy, Inc. Exposures (CL&P, Yankee Gas, NGS)

Certain subsidiaries of NU, including CL&P, Yankee Gas and NGS,
have entered into transactions with NRG Energy, Inc. (NRG) and
certain of its subsidiaries. On May 14, 2003, NRG and certain of
its subsidiaries filed voluntary bankruptcy petitions. NRG-related
exposures to NU as a result of these transactions relate to 1) the
recovery of CL&P's station service billings from NRG, 2) NRG's
standard offer service contract with CL&P, 3) the recovery of
congestion charges incurred by NRG prior to the implementation of
SMD on March 1, 2003, and 4) the recovery of Yankee Gas', NGS' and
CL&P's expenditures that were incurred related to NRG's generating
plant construction project that is now abandoned. While it is
unable to determine the ultimate outcome of these issues,
management does not expect their resolution will have a material
adverse effect on NU's consolidated financial condition or results
of operations.

C. 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 $4.9 billion at
September 30, 2003, as follows (millions of dollars):

---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2003 $1,412.1
2004 2,345.2
2005 639.2
2006 283.0
2007 225.1
---------------------------------------------------------------------
Total $4,904.6
---------------------------------------------------------------------

Select Energy's purchase contract amounts can exceed the amount
expected to be reported in fuel, purchased and net interchange
power as energy trading purchases are classified net with the
corresponding revenues.

D. Deferred Contractual Obligation - Connecticut Yankee Atomic Power
Company (CYAPC) Decommissioning Dispute

In June 2003, CYAPC notified NU that it had terminated its contract
with Bechtel Power Corporation (Bechtel) for the decommissioning of
the Connecticut Yankee nuclear power plant. CYAPC terminated the
contract based on its determination that Bechtel's decommissioning
work has been incomplete and untimely and that Bechtel refused to
perform the remaining decommissioning work. NU's electric
operating subsidiaries collectively own 49.0 percent of CYAPC; CL&P
owns 34.5 percent, PSNH owns 5.0 percent and WMECO owns 9.5
percent.

NU has been notified by CYAPC that it is in the process of
preparing an update to the estimated cost to decommission
Connecticut Yankee. When completed, the new 2003 estimate will
reflect the new estimated cost and schedule to complete the
decommissioning, including the impacts of the Bechtel contract
termination. The new cost estimate is expected to increase
significantly from the previous decommissioning estimate that NU
received from CYAPC in 2002. CYAPC is seeking recovery of the
additional project completion costs and other damages from Bechtel
but may ultimately recover these costs through Federal Energy
Regulatory Commission (FERC)-approved rates charged to CL&P, PSNH
and WMECO. The increase in the CYAPC decommissioning cost estimate
will increase deferred contractual obligations. Past increases to
deferred contractual obligations have been reflected as regulatory
assets by CL&P, PSNH and WMECO for future recovery from retail
customers.

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

Total comprehensive income, which includes all comprehensive income
items by category, for the three months and nine months ended
September 30, 2003 and 2002 is as follows:

*Net income/(loss) after preferred dividends of subsidiaries.

Amounts included in the Other column primarily relate to NU parent,
Yankee Gas and Northeast Utilities Service Company.

Accumulated other comprehensive income fair value adjustments of NU's
qualified cash flow hedging instruments are as follows:

--------------------------------------------------------------------------
September 30, December 31,
(Millions of Dollars, Net of Tax) 2003 2002
--------------------------------------------------------------------------
Balance at beginning of period $15.5 $(36.9)
--------------------------------------------------------------------------
Hedged transactions recognized
into net income (7.8) 17.0
Change in fair value (1.5) 29.2
Cash flow transactions entered
into for the period (9.4) 6.2
--------------------------------------------------------------------------
Net change associated with the
current period hedging transactions (18.7) 52.4
--------------------------------------------------------------------------
Total fair value adjustments included
in accumulated other
comprehensive (loss)/income $(3.2) $15.5
--------------------------------------------------------------------------

Accumulated other comprehensive income items unrelated to NU's qualified
cash flow hedging instruments totaled $0.3 million in gains and $0.6
million in losses at September 30, 2003 and December 31, 2002,
respectively. These amounts primarily relate to unrealized gains and
losses on investments in marketable debt and equity securities.

6. 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 certain securities 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) 2003 2002
--------------------------------------------------------------------------
Income before preferred
dividends of subsidiaries $135.2 $100.3
Preferred dividends
of subsidiaries 4.2 4.2
--------------------------------------------------------------------------
Income before cumulative effect
of accounting change $131.0 $ 96.1
Cumulative effect of accounting
change, net of tax benefit (4.7) -
--------------------------------------------------------------------------
Net income $126.3 $ 96.1
--------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 126,976,161 129,508,840
Dilutive effect of employee
stock options 110,256 228,409
--------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 127,086,417 129,737,249
--------------------------------------------------------------------------
Basic and fully diluted EPS:
Income before cumulative effect
of accounting change $1.03 $0.74
Cumulative effect of accounting
change, net of tax benefit (0.04) -
--------------------------------------------------------------------------
Net income $0.99 $0.74
--------------------------------------------------------------------------

7. SEGMENT INFORMATION (NU)

NU is organized between the Utility Group and NU Enterprises based on
each segments' regulatory environment or lack thereof. The Utility
Group segment, including both electric and gas utilities, represents
approximately 65 percent and 82 percent of NU's total revenues for the
nine months ended September 30, 2003 and 2002, respectively, and
primarily includes the operations of the electric utilities, CL&P, PSNH
and WMECO, whose complete financial statements are included in NU's
combined report on Form 10-Q. The Utility Group - gas segment includes
the operations of Yankee Gas. Utility Group revenues from the sale of
electricity and natural gas primarily are derived from residential,
commercial and industrial customers and are not dependent on any single
customer.

The NU Enterprises segment includes Select Energy, NGC, SESI, NGS, and
their respective subsidiaries. The ongoing generation operations of HWP
and Woods Network are also included in the NU Enterprises segment.

On January 1, 2000, Select Energy began serving one half of CL&P's
standard offer load for a four-year period ending on December 31, 2003,
at fixed prices. Total Select Energy revenues from CL&P for CL&P's
standard offer load and for other transactions with CL&P, represented
approximately $566 million or 23 percent for the nine months ended
September 30, 2003 and approximately $473 million or 40 percent for the
nine months ended September 30, 2002, of total NU Enterprises' revenues.
Total CL&P purchases from NU Enterprises are eliminated in
consolidation. Select Energy also provides basic generation service in
the New Jersey market. Select Energy revenues related to these
contracts represented approximately $324 million or 13 percent of total
NU Enterprises' revenues for the nine months ended September 30, 2003.
Short-term sales to ISO-NE represented approximately $264 million or 11
percent of total NU Enterprises' revenues for the nine months ended
September 30, 2003. Additionally, WMECO's purchases from Select Energy
represented approximately $110 million and $8 million of total NU
Enterprises' revenues for the nine months ended September 30, 2003 and
2002, respectively. No other individual customer represented in excess
of 10 percent of NU Enterprises' revenues for the nine months ended
September 30, 2003 or 2002.

Eliminations and other in the following table includes the results for
Mode 1 Communications, Inc., an investor in a fiber-optic communications
network, the results of the nonenergy-related subsidiaries of Yankee
Energy System, Inc., (Yankee Energy Services Company, RMS, Yankee Energy
Financial Services, and NorConn Properties, Inc.) the companies' parent
and service companies, and the company's investment in Acumentrics
Corporation. Interest expense included in eliminations and other
primarily relates to the debt of NU parent. Inter-segment eliminations
of revenues and expenses are also included in eliminations and other.
Eliminations and other also includes NU's investment in RMS, which was
consolidated with NU effective July 1, 2003, resulting in a negative
$4.7 million net of tax cumulative effect of an accounting change.

- -------------------------------------------------------------------------------
For the Three Months Ended September 30, 2003
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $1,141.8 $30.6 $1,143.6 $(261.7) $2,054.3
Depreciation and
amortization (134.7) (5.7) (4.6) (0.6) (145.6)
Other operating
expenses (887.8) (37.4) (1,115.1) 261.3 (1,779.0)
- -------------------------------------------------------------------------------
Operating
income/(loss) 119.3 (12.5) 23.9 (1.0) 129.7
Interest
expense, net (42.8) (3.4) (13.5) (3.7) (63.4)
Other income/
(loss), net 2.7 (0.4) 1.3 1.1 4.7
Income tax
(expense)/
benefit (31.1) 6.7 (4.8) 3.5 (25.7)
Preferred
dividends (1.4) - - - (1.4)
- -------------------------------------------------------------------------------
Income/(loss)
before
cumulative
effect of
accounting
change 46.7 (9.6) 6.9 (0.1) 43.9
Cumulative effect
of accounting
change, net of
tax benefit - - - (4.7) (4.7)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 46.7 $(9.6) $ 6.9 $ (4.8) $ 39.2
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
For the Nine Months Ended September 30, 2003
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $3,130.3 $255.0 $2,499.1 $(684.1) $5,200.3
Depreciation and
amortization (365.3) (17.2) (14.8) (1.8) (399.1)
Other operating
expenses (2,454.8) (220.4) (2,409.6) 682.5 (4,402.3)
- -------------------------------------------------------------------------------
Operating
income /(loss) 310.2 17.4 74.7 (3.4) 398.9
Interest
expense, net (129.4) (9.9) (36.6) (10.6) (186.5)
Other income/
(loss), net 2.3 (1.4) 4.2 0.9 6.0
Income tax
(expense)/
benefit (71.3) (2.7) (18.3) 9.1 (83.2)
Preferred
dividends (4.2) - - - (4.2)
- -------------------------------------------------------------------------------
Income/(loss) before
cumulative
effect of
accounting change 107.6 3.4 24.0 (4.0) 131.0
Cumulative effect
of accounting
change, net of
tax benefit - - - (4.7) (4.7)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 107.6 $ 3.4 $ 24.0 $ (8.7) $ 126.3
- -------------------------------------------------------------------------------
Total assets $7,719.5 $958.2 $2,031.9 $(111.2) $10,598.4
- -------------------------------------------------------------------------------
Total
investments
in plant $ 322.8 $ 37.7 $ 13.1 $ 12.4 $ 386.0
- -------------------------------------------------------------------------------

- -------------------------------------------------------------------------------
For the Three Months Ended September 30, 2002
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $1,106.2 $ 37.8 $ 452.9 $(182.6) $1,414.3
Depreciation and
amortization (134.1) (5.8) (5.0) (0.7) (145.6)
Other operating
expenses (840.9) (37.6) (449.7) 177.5 (1,150.7)
- -------------------------------------------------------------------------------
Operating
income/(loss) 131.2 (5.6) (1.8) (5.8) 118.0
Interest
expense, net (46.6) (3.5) (11.1) (6.5) (67.7)
Other income/
(loss), net 31.3 (0.5) 0.2 1.1 32.1
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
- -------------------------------------------------------------------------------
Utility Group Eliminations
(Millions of --------------- NU and
Dollars) Electric Gas Enterprises Other Total
- -------------------------------------------------------------------------------
Operating
revenues $2,962.6 $192.8 $1,177.5 $(492.2) $3,840.7
Depreciation and
amortization (321.1) (18.1) (17.0) (1.6) (357.8)
Other operating
expenses (2,298.9) (152.9) (1,187.6) 483.0 (3,156.4)
- -------------------------------------------------------------------------------
Operating
income/(loss) 342.6 21.8 (27.1) (10.8) 326.5
Interest
expense, net (140.5) (10.9) (32.8) (19.4) (203.6)
Other income/
(loss), net 33.4 (0.5) (0.5) (12.7) 19.7
Income tax
(expense)/
benefit (79.0) (4.2) 21.7 19.2 (42.3)
Preferred
dividends (4.2) - - - (4.2)
- -------------------------------------------------------------------------------
Net income/
(loss) $ 152.3 $ 6.2 $ (38.7) $ (23.7) $ 96.1
- -------------------------------------------------------------------------------
Total
investments
in plant $ 250.5 $ 41.8 $ 18.1 $ 16.9 $ 327.3
- -------------------------------------------------------------------------------

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

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

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 2003 reports on
Form 10-Q, and the NU 2002 Form 10-K.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2003 and the first nine months of 2003 are provided in the table
below.

Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $110 16% $245 13%

Operating Expenses:
Fuel, purchased and
net interchange power 100 25 170 15
Other operation 8 10 36 16
Maintenance (5) (19) (5) (9)
Depreciation 2 8 4 5
Amortization of regulatory
assets, net (2) (8) 33 80
Amortization of rate
reduction bonds 3 10 4 6
Taxes other than income taxes 4 13 5 4
---- ---- ---- ----
Total operating expenses 110 18 247 15
---- ---- ---- ----

Operating income - - (2) (1)
---- ---- ---- ----

Interest expense, net (2) (6) (5) (6)
Other income, net (5) (66) (9) (67)
---- ---- ---- ----
Income before income tax expense (3) (6) (6) (6)
Income tax expense (4) (20) (7) (16)
---- ---- ---- ----
Net income $ 1 4% $ 1 1%
==== ==== ==== ====

Comparison of the Third Quarter of 2003 to the Third Quarter of 2002

Operating Revenues
Operating revenues increased $110 million or 16 percent in the third quarter
of 2003, compared with the same period in 2002, primarily due to higher
retail revenues resulting from the collection of incremental LMP costs
beginning in May 2003 ($69 million) and from higher retail sales ($33
million) which includes a positive adjustment in estimated unbilled revenue
of approximately $39 million. Retail sales increased 5.4 percent compared
with the same period in 2002 after reflecting adjustments to unbilled sales.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased by $100 million
or 25 percent in the third quarter of 2003, compared with the same period in
2002, primarily due to costs associated with SMD ($69 million) and higher
standard offer purchased power expense as a result of higher retail sales
($15 million).

Other Operation and Maintenance
Other operation and maintenance (O&M) expenses increased $3 million in the
third quarter of 2003, compared with the same period in 2002, primarily due
to higher administrative costs ($7 million) resulting from higher health care
costs and lower pension income and higher RMR related transmission expense
($3 million), partially offset by lower distribution costs ($5 million).

Depreciation
Depreciation expense increased $2 million primarily due to higher utility
plant balances in 2003 resulting from plant additions.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense decreased $2 million primarily
due to lower amortization of recoverable nuclear costs ($8 million),
partially offset by higher amortization related to the recovery of stranded
costs ($6 million).

Taxes Other Than Income Taxes
Taxes other than income taxes increased $4 million in the third quarter of
2003 due to the recognition in 2002 of a Connecticut sales and use tax audit
settlement ($7 million), partially offset by a payment in 2002 to compensate
the Town of Waterford for lost property tax revenue as a result of the sale
of Millstone ($3 million).

Interest Expense, Net
Interest expense, net decreased $2 million primarily due to lower interest on
rate reduction bonds.

Other Income, Net
Other income, net decreased $5 million primarily due to lower interest and
dividend income ($2 million), lower equity in earnings from the nuclear
entitlements ($2 million) and lower conservation and load management (C&LM)
incentive income ($1 million).

Income Tax Expense
Income tax expense decreased $4 million primarily due to lower taxable
income.

Comparison of the First Nine Months of 2003 to the First Nine Months of 2002

Operating Revenues
Operating revenues increased by $245 million or 13 percent in 2003, compared
with the same period in 2002, primarily due to higher retail revenues ($179
million) and higher wholesale revenues ($64 million). Retail revenues were
higher primarily due to the collection of incremental LMP costs beginning in
May 2003 ($99 million) and higher retail sales ($79 million) which includes a
positive adjustment in estimated unbilled revenue of approximately $39
million. Retail kilowatt-hour (kWh) sales increased by 4.8 percent in 2003
after reflecting adjustments to unbilled sales. Wholesale revenues were
higher primarily due to higher market prices in 2003.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $170 million or
15 percent in 2003, primarily due to incremental LMP costs which were
recovered from customers ($99 million) and higher standard offer purchases as
a result of higher retail sales ($42 million).

Other Operation and Maintenance
Other O&M expenses increased by $31 million primarily due to higher
administrative costs ($18 million) resulting from higher health care costs
and lower pension income, higher RMR related transmission costs ($17
million), higher C&LM expenses ($7 million), partially offset by lower
related nuclear expenses ($11 million) as a result of the final DPUC order
regarding the CL&P Millstone use of proceeds docket in the first quarter of
2003.

Depreciation
Depreciation expense increased $4 million primarily due to higher utility
plant balances in 2003 resulting from plant additions.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $33 million
primarily due to higher amortization related to the recovery of stranded
costs ($63 million), partially offset by lower amortization of recoverable
nuclear costs ($30 million).

Taxes Other Than Income Taxes
Taxes other than income taxes increased $5 million primarily due to the
recognition in 2002 of a Connecticut sales and use tax audit settlement ($7
million), partially offset by a payment in 2002 to compensate the Town of
Waterford for lost property tax revenue as a result of the sale of Millstone
($3 million).

Interest Expense, Net
Interest expense, net decreased $5 million primarily due to lower interest on
rate reduction bonds.

Other Income, Net
Other income, net decreased $9 million primarily due to lower interest and
dividend income ($3 million), lower equity in earnings from the nuclear
entitlements ($3 million) and lower C&LM incentive income ($2 million).

Income Tax Expense
Income tax expense decreased $7 million primarily due to lower taxable
income.

LIQUIDITY

CL&P's net cash flows provided by operating activities increased to $385.4
million for the nine months ended September 30, 2003 from $303.2 million for
the same period in 2002. Cash flows provided by operating activities
increased primarily due to the increase in the amortization of regulatory
assets related to the recovery of stranded costs and increases in working
capital items, offset by the placing of incremental LMP costs collected into
an escrow account beginning in July 2003.

On October 1, 2003, CL&P fixed the interest rate on $62 million of variable-
rate tax-exempt borrowings for five years at 3.35 percent.

CL&P's net cash flows used in investing activities increased to $251.9
million for the first nine months of 2003 from $109.6 million for the same
period in 2002. The increase is primarily due to higher capital expenditures
in 2003 and lower NU system Money Pool borrowings in 2003. CL&P's capital
expenditures totaled $224.8 million in the first nine months of 2003 compared
to $159.9 million in the first nine months of 2002.

Financing activities decreased in 2003 as a result of the repurchase of
common shares in 2002. In the first nine months of 2003, CL&P also repaid
$91.6 million of rate reduction bonds.

In the third quarter 2003, Fitch Ratings (Fitch) raised the outlook of CL&P's
credit ratings to stable from negative. The change in outlook is a result of
Fitch's belief that the risks associated with CL&P's standard offer service
contract with NRG had declined.

At September 30, 2003, CL&P had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line expires on
November 11, 2003, and management expects to extend this credit line from
November 2003 through November 2004.

At September 30, 2003, CL&P had $40 million of accounts receivable and
unbilled revenues sold under its arrangement with a financial institution to
sell up to $100 million in accounts receivable and unbilled revenues. This
arrangement expires in July 2004.

CL&P is seeking approval from its preferred shareholders to permanently amend
its charter to eliminate a requirement that unsecured debt represent no more
than 10 percent of total capitalization. CL&P is offering its preferred
holders a payment of 1 percent of the $116.2 million par value of their
shares if the preferred holders vote in favor of the amendment and CL&P
implements it. Preferred holders of record as of September 30, 2003, are
eligible to vote at a special meeting, which will be held on November 25,
2003. Holders of at least two-thirds of CL&P's approximately 2.3 million
shares of preferred stock must vote in favor of the change for it to pass.
Management believes that CL&P will benefit from such a change due to
increased financial flexibility. In the event that this change fails or if
CL&P chooses not to implement it, CL&P is also asking preferred holders to
endorse another 10-year waiver that would allow CL&P's unsecured debt to rise
to 20 percent of total capitalization. At September 30, 2003, CL&P's
unsecured debt represented approximately 3 percent of CL&P's total long-term
debt. CL&P preferred holders approved a similar waiver in 1993 that is
scheduled to expire in March 2004.

Prior to July 1, 2003, CL&P recovered approximately $30 million of
incremental LMP costs from its customers and has withheld payment of these
incremental LMP costs from its standard offer service suppliers. This
positively impacted CL&P's liquidity. In July 2003, CL&P began depositing
new recoveries into an escrow account. Accordingly, further recovery of
these costs did not impact CL&P's liquidity. When the LMP dispute is
resolved, there will be a negative impact on CL&P's liquidity for the amounts
recovered but not deposited into the escrow account, as these amounts are
paid to standard offer service suppliers or returned to customers.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

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

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 2003 reports on
Form 10-Q, and the NU 2002 Form 10-K.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2003 and for the first nine months of 2003 are provided in the
table below.

Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $(83) (26)% $(97) (12)%

Operating Expenses:
Fuel, purchased and
net interchange power (80) (42) (98) (21)
Other operation 2 5 6 6
Maintenance - - 5 11
Depreciation - - 2 5
Amortization of regulatory
assets, net (1) (7) 8 54
Amortization of rate
reduction bonds 2 32 (5) (15)
Taxes other than income taxes - - (2) (6)
---- ---- ---- ----
Total operating expenses (77) (27) (84) (12)
---- ---- ---- ----
Operating income (6) (15) (13) (12)
---- ---- ---- ----

Interest expense, net - - (2) (6)
Other income/(loss), net (1) (a) (2) (a)
---- ---- ---- ----
Income before income tax expense (7) (24) (13) (19)
Income tax expense - - (1) (5)
---- ---- ---- ----
Net income $ (7) (35)% $(12) (26)%
==== ==== ==== ====

(a) Percent greater than 100.

Comparison of the Third Quarter of 2003 to the Third Quarter of 2002

Operating Revenues
Total operating revenues decreased $83 million or 26 percent in the third
quarter of 2003 compared with the same period of 2002, due to lower wholesale
revenues primarily due to the impact of the sale of Seabrook ($99 million),
partially offset by higher retail revenue ($16 million) which includes a
positive adjustment in estimated unbilled revenue of approximately $6
million. Retail kWh sales increased by 4.8 percent in 2003 after reflecting
adjustments to unbilled sales.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $80 million
primarily due to lower purchased power expenses as a result of the absence of
Seabrook power contract costs and lower wholesale sales.

Other Operation and Maintenance
Other O&M expenses increased $2 million primarily due to higher
administrative costs primarily resulting from C&LM programs and low income
program costs ($2 million) and higher distribution expenses ($1 million),
partially offset by lower fossil production maintenance expense ($1 million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $1 million primarily due to
decreased recovery of stranded costs resulting from the reconciliation of
actual stranded cost revenues against actual stranded costs.

Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds increased $2 million due to the
scheduled repayment of principal.

Comparison of the First Nine Months of 2003 to the First Nine Months of 2002

Operating Revenues
Total operating revenues decreased $97 million or 12 percent in the first
nine months of 2003 compared with the same period of 2002, due to lower
wholesale revenues ($143 million) primarily due to the impact of the sale of
Seabrook, partially offset by higher retail revenue ($47 million) which
includes a positive adjustment in estimated unbilled revenue of approximately
$6 million. Retail kWh sales increased by 5.5 percent in 2003 after
reflecting adjustments to unbilled sales.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $98 million,
primarily due to lower purchased power expenses as a result of the absence of
Seabrook power contract costs and lower wholesale sales.

Other Operation and Maintenance
Other O&M expense increased $11 million primarily due to higher
administrative costs ($7 million) primarily resulting from C&LM programs and
low income program costs and higher fossil production maintenance expenses
($4 million).

Depreciation
Depreciation increased $2 million primarily due to additions to distribution,
generation and general plant assets.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $8 million primarily due to
increased recovery of stranded costs resulting from the reconciliation of
actual stranded cost revenues against actual stranded costs.

Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds decreased $5 million due to the
scheduled repayment of principal.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased $2 million primarily due to lower
property taxes.

Interest Expense, Net
Interest expense, net decreased $2 million primarily due to lower interest
costs associated with the refinancing of the pollution control revenue bonds.

Other Income/(Loss), Net
Other income/(loss), net decreased $2 million primarily due to increased
service fees associated with rate reduction bonds and lower gains on the
disposition of property in 2003.

Income Tax Expense
Income tax expense decreased $1 million primarily due to lower taxable
income.

LIQUIDITY

PSNH's net cash flows provided by operating activities totaled $50.2 million
for the nine months ended September 30, 2003, compared with $126.8 million
for the same period of 2002. Cash flows provided by operating activities
decreased due to changes in working capital items, primarily the payment of
taxes on the gain on the sale of Seabrook.

PSNH's net cash flows used in investing activities were $11 million for the
nine months ended September 30, 2003 compared with $94.9 million for the same
period in 2002. The decrease is primarily due to higher NU system Money Pool
borrowings in 2003. PSNH's capital expenditures totaled $77.4 million in the
first nine months of 2003 compared to $75.8 million in the first nine months
of 2002.

In the first nine months of 2003, PSNH also repaid $27.4 million of rate
reduction bonds.

At September 30, 2003, PSNH had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line expires on
November 11, 2003, and management expects to extend this credit line from
November 2003 through November 2004.

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

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

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 2003 reports on
Form 10-Q, the NU 2002 Form 10-K, and the current report on Form 8-K dated
September 30, 2003.

RESULTS OF OPERATIONS

The components of significant income statement variances for the third
quarter of 2003 and the first nine months of 2003 are provided in the table
below.

Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
------------------------------------
Third Nine
Quarter Percent Months Percent
------- ------- ------ -------

Operating Revenues $ 8 8% $ 19 7%

Operating Expenses:
Fuel, purchased and
net interchange power 5 11 10 7
Other operation 4 28 7 18
Maintenance - - - -
Depreciation - - (1) (5)
Amortization of regulatory
assets, net (1) (12) 7 25
Amortization of rate
reduction bonds - - - -
Taxes other than income taxes 1 41 1 12
---- ---- ---- ----
Total operating expenses 9 10 24 10
---- ---- ---- ----

Operating income (1) (7) (5) (13)
---- ---- ---- ----

Interest expense, net (1) (18) (1) (8)
Other income/(loss), net - - 3 (a)
---- ---- ---- ----
Income before income tax
expense/(benefit) - - (1) (3)
Income tax expense/(benefit) - - 12 (a)
---- ---- ---- ----
Net income $ - -% $(13) (49)%
==== ==== ==== ====

(a) Percent greater than 100.

Comparison of the Third Quarter of 2003 to the Third Quarter of 2002

Operating Revenues
Operating revenues increased $8 million or 8 percent in 2003, compared with
the same period in 2002, due to higher retail revenues ($7 million) and
higher wholesale revenues ($1 million). Retail revenues were higher
primarily due to an increase in the standard offer component of retail
delivery rates and higher retail sales which includes a positive adjustment
in estimated unbilled revenue of approximately $2 million. Retail kWh sales
were 1.9 percent higher after reflecting adjustments to unbilled sales.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $5 million
primarily due to higher standard offer purchases as a result of the higher
standard offer contract costs and the retail sales increase.

Other Operation
Other operation expenses increased $4 million primarily due to higher general
and administrative expenses resulting from higher health care costs and lower
pension income.

Comparison of the First Nine Months of 2003 to the First Nine Months of 2002

Operating Revenues
Operating revenues increased by $19 million or 7 percent in 2003, compared
with the same period in 2002, due to higher retail revenues ($13 million) and
higher wholesale revenues ($6 million). Retail revenues were higher
primarily due to an increase in the standard offer component of retail
delivery rates and higher retail sales which includes a positive adjustment
in estimated unbilled revenue of approximately $2 million. Retail kWh sales
were 3.9 percent higher after reflecting adjustments to unbilled sales.
Wholesale revenues were higher primarily due to higher wholesale sales.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $10 million
primarily due to higher standard offer purchases as a result of the retail
sales increase and the higher standard offer contract costs.

Other Operation
Other operation expenses increased $6 million primarily due to higher general
and administrative expenses resulting from higher health care costs and lower
pension income.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $7 million primarily
due to the higher recovery of stranded costs.

Other Income/(Loss), Net
Other income/(loss), net increased $3 million primarily due to the 2002
adjustment to the gain from the 1999 sale of the fossil units as a result of
a DTE decision in the annual stranded cost reconciliation filing for the
period ended December 31, 1999.

Income Tax Expense/(Benefit)
Income tax expense/(benefit) increased $12 million primarily due to the
recognition in 2002 of investment tax credits as a result of a 2002 DTE
decision.

LIQUIDITY

WMECO's net cash flows provided by operating activities increased to $52.3
million for the first nine months of 2003 from $20.7 million for the same
period of 2002. Net cash flows provided by operating activities increased
primarily due to changes in working capital items, primarily accounts
payable.

On September 30, 2003, WMECO issued $55 million of ten-year 5 percent notes,
the proceeds from which WMECO used to repay a similar level of borrowings
from the NU system Money Pool.

WMECO's net cash flows used in investing activities were $75 million for the
nine months ended September 30, 2003, compared with net cash flows provided
by investing activities of $7.1 million for the same period of 2002. The
change is primarily due to lower NU system Money Pool borrowings in 2003.
WMECO's capital expenditures totaled $20.7 million in the first nine months
of 2003 compared to $14.7 million in the first nine months of 2002.

In the first nine months of 2003, WMECO also repaid $7.4 million of rate
reduction bonds.

At September 30, 2003, WMECO had no borrowings outstanding on the Utility
Group's $300 million revolving credit line. This credit line expires on
November 11, 2003, and management expects to extend this credit line from
November 2003 through November 2004.

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," Note 2B, "Derivative Instruments, Market Risk and
Risk Management - Market Risk Information," and Note 2C, "Derivative
Instruments, Market Risk and Risk Management - Other Risk Management
Activities," to the consolidated financial statements 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 SEC. These evaluations were made under the supervision and
with the participation of management, including the companies' principal
executive officer and principal financial officer, as of the end of the
period covered by 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 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. Consolidated Edison, Inc. v. NU - Merger Appeals and Related Litigation
- United States District Court Litigation

This litigation consists of the consolidated civil lawsuits filed in the
United States District Court for the Southern District of New York (District
Court) by Consolidated Edison, Inc. (Con Edison) and NU regarding the parties
October 19, 1999 Agreement and Plan of Merger, as amended and restated as of
January 11, 2000 (Merger Agreement). In its amended complaint, Con Edison
alleges that NU failed to perform material obligations under the Merger
Agreement, that there has been a "Material Adverse Change" with respect to NU
and that certain conditions precedent to Con Edison's obligation to merge
with NU have not been and cannot be satisfied. (Con Edison's amended
complaint further asserts claims for fraud and negligent misrepresentation
which were dismissed on summary judgment on March 15, 2003.) In its
counterclaim, NU seeks damages in excess of $1 billion alleging that Con
Edison is in material breach of the Merger Agreement based on its repudiation
thereof and its refusal to proceed with the merger.

As of June 19, 2003, the parties' motions in limine in the District Court
case were fully briefed and are now pending before the District Court. Con
Edison's July 1, 2003 motion to dismiss NU's "lost premium" counterclaim has
also been fully briefed and is pending. On July 24, 2003, Robert Rimkoski
filed a motion to intervene. On August 7, 2003, NU filed a brief in
opposition to Mr. Rimkoski's motion to intervene. The motions in limine,
motion to dismiss and motion to intervene are scheduled to be heard by the
District Court on November 7, 2003.

2. NRG - Credit Rating Status

On May 14, 2003, NRG and various affiliates filed for Chapter 11 protection
in the United States Bankruptcy Court for the Southern District of New York
(Bankruptcy Court). The filing affects various relationships between NU
companies and NRG.

A. CL&P Standard Offer Contract

NRG's May 14, 2003, bankruptcy filing included a request by NRG Power
Marketing, Inc. (NRG-PM) to terminate service to CL&P under its standard
offer supply agreement (SOS Agreement). The Bankruptcy Court authorized NRG-
PM to reject the SOS Agreement, but the FERC directed NRG-PM to continue to
perform under its SOS Agreement until the FERC fully considers the matter.

Subsequently, the U.S. District Court for the Southern District of New York
issued a ruling deferring to the FERC on this matter. On July 18, 2003, NRG-
PM and the Creditors Committee filed an appeal with the U.S. Court of Appeals
for the Second Circuit to enjoin the FERC order; this appeal is currently
pending. On August 15, 2003, the FERC issued an order stating that NRG-PM
had failed to demonstrate that premature termination of its SOS Agreement
with CL&P would be in the public interest and, therefore, NRG-PM must
continue to perform under the SOS Agreement.

On September 15, 2003, NRG-PM and the Official Committee of Unsecured
Creditors for NRG and its debtor subsidiaries (Committee) requested rehearing
of the FERC's August 15, 2003, order and the FERC has not yet acted on that
request. NRG-PM and the Committee also have filed appeals of the FERC's June
25, 2003 order and August 15, 2003 order denying rehearing with the D.C.
District Court of Appeals.

B. Station Service

NRG has disputed its responsibility to pay for the provision of station
service by CL&P to NRG's Connecticut generating plants. The FERC issued a
decision on December 20, 2002, that NRG had agreed that station service from
CL&P would be subject to CL&P's applicable retail rates, and that states have
jurisdiction over the delivery of power to end users even where, as here,
power is not delivered via distribution facilities. NRG refused CL&P's
subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC
for a declaratory order enforcing the FERC's December 20, 2002, decision.
The DPUC proceeding was subsequently stayed due to the bankruptcy filing.

On September 18, 2003, the Bankruptcy Court approved the parties' stipulation
to submit the station service issue to arbitration for a determination of
liability and damages which will fix CL&P's claim in bankruptcy.

For additional information on certain matters involving NRG and its
affiliates, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and Note 4B, "NRG Energy, Inc. Exposures," within
the notes to the consolidated financial statements in this combined report on
Form 10-Q; "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Part II, Item 1. Legal Proceedings" in NU's
report on Form 10-Q for the quarters ended March 31, 2003, and June 30, 2003,
and "Part I, Item 1. Business - Rates and Electric Industry Restructuring -
Connecticut" and "Part I, Item 3. Legal Proceedings" in NU's 2003 annual
report on Form 10-K.

3. Connecticut Yankee Atomic Power Company Decommissioning Dispute

On June 13, 2003, CYAPC gave notice of the termination of its contract with
Bechtel for the decommissioning of the Connecticut Yankee nuclear power
plant. CYAPC terminated the contract, after the failure of settlement
discussions that occurred over an eight month period, due to Bechtel's
history of incomplete and untimely performance and refusal to perform
remaining decommissioning work. Under the agreement, Bechtel had 30 days to
remedy its defaults before the termination became effective.

On June 23, 2003, Bechtel filed a complaint against CYAPC in Connecticut
Superior Court in Middletown, Connecticut. Bechtel's complaint asserts a
number of claims and seeks a variety of remedies, including monetary and
punitive damages and rescission of the contract. Bechtel has since amended
its complaint to add claims for wrongful termination.

On August 22, 2003, CYAPC filed its answer and counterclaims, including
counts for breach of contract, negligent misrepresentation and breach of duty
of good faith and fair dealing. Bechtel has departed the site and the
decommissioning responsibility has been transitioned to CYAPC, which has
recommenced the decommissioning process.

NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC,
as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent.

For further information relating to this proceeding, see Note 4D, "Deferred
Contractual Obligation - Connecticut Yankee Atomic Power Company (CYAPC)
Decommissioning Dispute," within the notes to the consolidated financial
statements in this combined report of Form 10-Q.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Listing of Exhibits (NU)

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

15 Deloitte & Touche LLP Letter Regarding Unaudited Financial
Information

31 Certification of Michael G. Morris, Chairman, President and
Chief Executive Officer of Northeast Utilities, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002,
dated November 7, 2003

31.1 Certification of John H. Forsgren, Vice Chairman, Executive
Vice President and Chief Financial Officer of Northeast
Utilities, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002, dated November 7, 2003

32 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, 2003

(a) Listing of Exhibits (CL&P)

4.2.7.5 Compensation and Multiannual Mode Agreement among the
Connecticut Development Authority, The Connecticut Light
and Power Company and BNY Capital Markets, Inc. dated
September 23, 2003

4.2.8.2 Amendment No. 3 to the Amended and Restated Receivables
Purchase and Sales Agreement dated as of July 9, 2003
(CL&P and CRC)

31 Certification of Cheryl W. Grise, Chief Executive Officer
of The Connecticut Light and Power Company, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of
2002, dated November 7, 2003

31.1 Certification of John H. Forsgren, Executive Vice
President and Chief Financial Officer of The Connecticut
Light and Power Company, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002, dated November 7,
2003

32 Certification of Cheryl W. Grise, Chief Executive Officer
of The Connecticut Light and Power Company and John H.
Forsgren, Executive Vice President and Chief Financial
Officer of The Connecticut Light and Power 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, 2003

(a) Listing of Exhibits (PSNH)

31 Certification of Cheryl W. Grise, Chief Executive Officer
of Public Service Company of New Hampshire, as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of
2002, dated November 7, 2003

31.1 Certification of John H. Forsgren, Executive Vice
President and Chief Financial Officer of Public Service
Company of New Hampshire, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002, dated November 7,
2003

32 Certification of Cheryl W. Grise, Chief Executive
Officer of Public Service Company of New Hampshire and
John H. Forsgren, Executive Vice President and Chief
Financial Officer of Public Service Company of New
Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002, dated November 7, 2003

(a) Listing of Exhibits (WMECO)

4.4.3 Underwriting Agreement between WMECO and the Underwriters
named therein, dated September 25, 2003 (Exhibit 99.1,
WMECO Form 8-K filed October 8, 2003, File No. 0-7624)

4.4.4 Indenture Agreement between WMECO and the Bank of New
York, as Trustee, dated as of September 1, 2003 (Exhibit
99.2, WMECO Form 8-K filed October 8, 2003, File No. 0-
7624)

4.4.5 First Supplemental Indenture Agreement between WMECO and
the Bank of New York, as Trustee, dated as of
September 1, 2003 (Exhibit 99.3, WMECO Form 8-K filed
October 8, 2003, File No. 0-7624)

31 Certification of Cheryl W. Grise, Chief Executive
Officer of Western Massachusetts Electric Company, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002, dated November 7, 2003

31.1 Certification of John H. Forsgren, Executive Vice
President and Chief Financial Officer of Western
Massachusetts Electric Company, as adopted pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, dated
November 7, 2003

32 Certification of Cheryl W. Grise, Chief Executive Officer
of Western Massachusetts Electric Company and John H.
Forsgren, Executive Vice President and Chief Financial
Officer of Western Massachusetts Electric 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, 2003

(b) Reports on Form 8-K:

WMECO filed a current report on Form 8-K dated September 30, 2003,
disclosing:

o The completion of the issuance and sale to the public of $55 million
of 5 percent Senior Notes, Series A, due 2013.

SIGNATURE

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, 2003 By /s/ John H. Forsgren
---------------- -------------------------------------
John H. Forsgren
Vice Chairman,
Executive Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)

SIGNATURE

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, 2003 By /s/ John H.Forsgren
---------------- -------------------------------------
John H. Forsgren
Executive Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)

SIGNATURE

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, 2003 By /s/ John H. Forsgren
---------------- -------------------------------------
John H. Forsgren
Executive Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)

SIGNATURE

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, 2003 By /s/ John H. Forsgren
---------------- -------------------------------------
John H. Forsgren
Executive Vice President
and Chief Financial Officer
(for the Registrant and as
Principal Financial Officer)