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
                                             ------------------
                                     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
                              -----------------

                                                                          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)
<Table>
<Caption>
                                                            September 30,      December 31,
                                                                2003               2002
                                                           ---------------    ---------------
                                                                (Thousands of Dollars)
<S>                                                       <C>                <C>
ASSETS
------
Current Assets:
  Cash and cash equivalents                               $       118,138    $        54,678
  Restricted cash - LMP costs                                      45,760               -
  Special deposits                                                 75,657             43,261
  Investments in securitizable assets                             215,592            178,908
  Receivables, net                                                637,039            767,089
  Unbilled revenues                                                95,498            126,236
  Fuel, materials and supplies, at average cost                   160,400            119,853
  Derivative assets                                               103,768            130,929
  Prepayments and other                                            81,556            110,261
                                                          ---------------    ---------------
                                                                1,533,408          1,531,215
                                                          ---------------    ---------------
Property, Plant and Equipment:
  Electric utility                                              5,360,649          5,141,951
  Gas utility                                                     708,986            679,055
  Competitive energy                                              886,478            866,294
  Other                                                           209,040            205,115
                                                          ---------------    ---------------
                                                                7,165,153          6,892,415
    Less: Accumulated depreciation                              2,564,544          2,484,613
                                                          ---------------    ---------------
                                                                4,600,609          4,407,802
  Construction work in progress                                   374,691            320,567
                                                          ---------------    ---------------
                                                                4,975,300          4,728,369
                                                          ---------------    ---------------
Deferred Debits and Other Assets:
  Regulatory assets                                             2,947,670          3,076,095
  Goodwill and other purchased intangible assets, net             343,904            345,867
  Prepaid pension                                                 352,668            328,890
  Other                                                           445,418            433,444
                                                          ---------------    ---------------
                                                                4,089,660          4,184,296
                                                          ---------------    ---------------

Total Assets                                              $    10,598,368    $    10,443,880
                                                          ===============    ===============
</Table>

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



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
                                                            September 30,       December 31,
                                                                2003                2002
                                                          ---------------     ---------------
                                                                (Thousands of Dollars)
<S>                                                       <C>                <C>
LIABILITIES AND CAPITALIZATION
------------------------------

Current Liabilities:
  Notes payable to banks                                  $        40,000    $        56,000
  Long-term debt - current portion                                 59,327             56,906
  Accounts payable                                                787,024            776,219
  Accrued taxes                                                    68,816            141,667
  Accrued interest                                                 57,820             40,597
  Derivative liabilities                                           65,866             63,900
  Other                                                           205,501            208,680
                                                          ----------------   ---------------
                                                                1,284,354          1,343,969
                                                          ---------------    ---------------

Rate Reduction Bonds                                            1,772,637          1,899,312
                                                          ---------------    ---------------

Deferred Credits and Other Liabilities:
  Accumulated deferred income taxes                             1,362,713          1,436,507
  Accumulated deferred investment tax credits                     103,607            106,471
  Deferred contractual obligations                                321,197            354,469
  Other                                                           878,146            689,287
                                                          ---------------    ---------------
                                                                2,665,663          2,586,734
                                                          ---------------    ---------------
Capitalization:
  Long-Term Debt                                                2,505,222          2,287,144
                                                          ---------------    ---------------

  Preferred Stock - Nonredeemable                                 116,200            116,200
                                                          ---------------    ---------------

  Common Shareholders' Equity:
    Common shares, $5 par value - authorized
     225,000,000 shares; 150,098,023 shares issued
     and 127,254,402 shares outstanding in 2003 and
     149,375,847 shares issued and 127,562,031 shares
     outstanding in 2002                                          750,492            746,879
    Capital surplus, paid in                                    1,106,466          1,108,338
    Deferred contribution plan - employee stock
      ownership plan                                              (76,970)           (87,746)
    Retained earnings                                             837,963            765,611
    Accumulated other comprehensive (loss)/income                  (2,862)            14,927
    Treasury stock, 19,518,023 shares in 2003
      and 18,022,415 shares in 2002                              (360,797)          (337,488)
                                                          ---------------    ---------------
  Common Shareholders' Equity                                   2,254,292          2,210,521
                                                          ---------------    ---------------
Total Capitalization                                            4,875,714          4,613,865
                                                          ---------------    ---------------
Commitments and Contingencies (Note 4)

Total Liabilities and Capitalization                      $    10,598,368    $    10,443,880
                                                          ===============    ===============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
                                                                  Three Months Ended               Nine Months Ended
                                                                     September 30,                    September 30,
                                                           --------------------------------  ------------------------------
                                                                  2003            2002             2003            2002
                                                           ---------------   --------------  --------------   -------------


<S>                                                          <C>            <C>              <C>             <C>
Operating Revenues                                           $   2,054,274  $    1,414,304   $    5,200,252  $    3,840,693
                                                             -------------  --------------   --------------  --------------
Operating Expenses:
  Operation -
     Fuel, purchased and net interchange power                   1,445,482         850,757        3,408,712       2,204,434
     Other                                                         224,606         184,110          645,156         580,865
  Maintenance                                                       55,687          68,271          169,859         194,032
  Depreciation                                                      50,879          50,946          151,044         156,757
  Amortization                                                      53,995          59,160          132,791          85,114
  Amortization of rate reduction bonds                              40,729          35,380          115,232         116,016
  Taxes other than income taxes                                     53,169          47,585          178,603         177,043
                                                             -------------  --------------   --------------  --------------
       Total operating expenses                                  1,924,547       1,296,209        4,801,397       3,514,261
                                                             -------------  --------------   --------------  --------------
Operating Income                                                   129,727         118,095          398,855         326,432

Interest Expense:
  Interest on long-term debt                                        32,010          34,137           93,496         101,500
  Interest on rate reduction bonds                                  26,863          28,751           82,088          87,539
  Other interest                                                     4,474           4,825           10,835          14,569
                                                             -------------  --------------   --------------  --------------
       Interest expense, net                                        63,347          67,713          186,419         203,608
                                                             -------------  --------------   --------------  --------------
Other Income, Net                                                    4,678          32,059            6,008          19,715
                                                             -------------  --------------   --------------  --------------
Income Before Income Tax Expense                                    71,058          82,441          218,444         142,539
Income Tax Expense                                                  25,689          32,476           83,223          42,296
                                                             -------------  --------------   --------------  --------------
Income Before Preferred Dividends of Subsidiaries                   45,369          49,965          135,221         100,243
Preferred Dividends of Subsidiaries                                  1,390           1,390            4,169           4,169
                                                             -------------  --------------   --------------  --------------
Income Before Cumulative Effect of Accounting Change                43,979          48,575          131,052          96,074
Cumulative effect of accounting change,
  net of tax benefit of $2,553                                      (4,741)            -             (4,741)            -
                                                             -------------  --------------   --------------  --------------
Net Income                                                   $      39,238  $       48,575   $      126,311  $       96,074
                                                             =============  ==============   ==============  ==============

Basic and Fully Diluted Earnings Per Common Share:
  Income Before Cumulative Effect of Accounting Change       $        0.35  $         0.38   $         1.03  $         0.74
  Cumulative effect of accounting change,
    net of tax benefit                                               (0.04)            -              (0.04)            -
                                                             -------------  --------------   --------------  --------------
Basic and Fully Diluted Earnings Per Common Share            $        0.31  $         0.38   $         0.99  $         0.74
                                                             =============  ==============   ==============  ==============
Basic Common Shares Outstanding (average)                      127,167,690     129,344,724      126,976,161     129,508,840
                                                             =============  ==============   ==============  ==============
Fully Diluted Common Shares Outstanding (average)              127,303,973     129,508,794      127,086,417     129,737,249
                                                             =============  ==============   ==============  ==============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.



NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<Table>
<Caption>

                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                            ------------------------------
                                                                                 2003             2002
                                                                            -------------    -------------
                                                                                (Thousands of Dollars)
<S>                                                                            <C>              <C>
Operating Activities:
  Income before preferred dividends of subsidiaries                            $  135,221       $  100,243
  Adjustments to reconcile to net cash flows
   provided by operating activities:
    Depreciation                                                                  151,044          156,757
    Deferred income taxes and investment tax credits, net                         (48,815)         (54,207)
    Amortization                                                                  132,791           85,114
    Amortization of rate reduction bonds                                          115,232          116,016
    (Deferral)/amortization of recoverable energy costs                            (5,480)          19,557
    Prepaid pension                                                               (23,778)         (55,436)
    Cumulative effect of an accounting change                                      (4,741)             -
    Regulatory recoveries                                                         117,138           48,915
    Other sources of cash                                                          14,911           73,241
    Other uses of cash                                                           (122,284)         (57,044)
  Changes in current assets and liabilities:
    Restricted cash - LMP costs                                                   (45,760)             -
    Receivables and unbilled revenues, net                                        160,789           29,223
    Fuel, materials and supplies                                                  (40,548)         (23,285)
    Accounts payable                                                               10,805          (52,846)
    Accrued taxes                                                                 (72,851)          23,754
    Investments in securitizable assets                                           (36,684)          49,570
    Other current assets and liabilities (excludes cash)                           25,686           12,678
                                                                               ----------       ----------
Net cash flows provided by operating activities                                   462,676          472,250
                                                                               ----------       ----------

Investing Activities:
  Investments in plant:
    Electric, gas and other utility plant                                        (372,854)        (308,757)
    Competitive energy assets                                                     (13,144)         (18,128)
    Nuclear fuel                                                                      -               (434)
                                                                               ----------       ----------
  Cash flows used for investments in plant                                       (385,998)        (327,319)
  Buyout/buydown of IPP contracts                                                 (20,437)          (5,152)
  Payment for acquisitions, net of cash acquired                                      -            (15,300)
  Other investment activities, net                                                  8,777            6,957
                                                                               ----------       ----------
Net cash flows used in investing activities                                      (397,658)        (340,814)
                                                                               ----------       ----------

Financing Activities:
  Issuance of common shares                                                         9,940            7,445
  Repurchase of common shares                                                     (23,209)         (30,136)
  Issuance of long-term debt                                                      250,384          263,000
  Issuance of rate reduction bonds                                                    -             50,000
  Retirement of rate reduction bonds                                             (126,374)        (132,883)
  Net (decrease)/increase in short-term debt                                      (16,000)          25,233
  Reacquisitions and retirements of long-term debt                                (33,607)        (285,146)
  Cash dividends on preferred stock                                                (4,169)          (4,169)
  Cash dividends on common shares                                                 (53,959)         (50,164)
  Other financing activities, net                                                  (4,564)            (548)
                                                                               ----------       ----------
Net cash flows used in financing activities                                        (1,558)        (157,368)
                                                                               ----------       ----------
Net increase/(decrease) in cash and cash equivalents                               63,460          (25,932)
Cash and cash equivalents - beginning of period                                    54,678           96,658
                                                                               ----------       ----------
Cash and cash equivalents - end of period                                      $  118,138       $   70,726
                                                                               ==========       ==========

</Table>

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:

<Table>
<Caption>
------------------------------------------------------------------------------------
                                Three Months Ended September 30, 2003
------------------------------------------------------------------------------------
                                                                   NU
(Millions of Dollars)         NU     CL&P    PSNH    WMECO    Enterprises    Other
------------------------------------------------------------------------------------
<S>                         <C>      <C>     <C>      <C>         <C>       <C>
Net income/(loss)*          $ 39.2   $29.0   $12.6    $5.2        $6.9      $(14.5)
------------------------------------------------------------------------------------
Comprehensive income items:
  Qualified cash flow
    hedging instruments       (4.9)    -       -       -         (4.9)         -
  Unrealized gains on
    securities                 0.2     -       -       -           -           0.2
------------------------------------------------------------------------------------
Net change of
  comprehensive income items  (4.7)    -       -       -         (4.9)         0.2
------------------------------------------------------------------------------------
Total comprehensive
  income/(loss)             $ 34.5   $29.0    $12.6   $5.2       $2.0       $(14.3)
------------------------------------------------------------------------------------
</Table>

<Table>
<Caption>
------------------------------------------------------------------------------------
                                    Nine Months Ended September 30, 2003
------------------------------------------------------------------------------------
                                                                   NU
(Millions of Dollars)         NU     CL&P    PSNH    WMECO    Enterprises    Other
------------------------------------------------------------------------------------
<S>                         <C>      <C>     <C>     <C>         <C>        <C>
Net income/(loss)*          $126.3   $59.0   $34.5   $13.9       $24.0      $ (5.1)
------------------------------------------------------------------------------------
Comprehensive income items:
  Qualified cash flow
    hedging instruments      (18.7)    -       -       -         (14.7)       (4.0)
  Unrealized gains on
    securities                 0.9     0.1     0.1     -           -           0.7
------------------------------------------------------------------------------------
Net change of
  comprehensive income items (17.8)    0.1     0.1     -         (14.7)       (3.3)
------------------------------------------------------------------------------------
Total comprehensive
  income/(loss)             $108.5   $59.1   $34.6   $13.9       $ 9.3      $ (8.4)
------------------------------------------------------------------------------------
</Table>

<Table>
<Caption>
------------------------------------------------------------------------------------
                                Three Months Ended September 30, 2002
------------------------------------------------------------------------------------
                                                                   NU
(Millions of Dollars)         NU     CL&P    PSNH    WMECO    Enterprises    Other
------------------------------------------------------------------------------------
<S>                         <C>      <C>     <C>     <C>         <C>        <C>
Net income/(loss)*          $ 48.6   $27.9   $19.5   $ 4.7       $(9.0)    $   5.5
------------------------------------------------------------------------------------
Comprehensive income items:
  Qualified cash flow
    hedging instruments        5.5     -       -       -           5.4         0.1
  Unrealized gains on
    securities                (0.8)   (0.5)   (0.2)   (0.1)        -           -
------------------------------------------------------------------------------------
Net change of
  comprehensive income items   4.7    (0.5)   (0.2)   (0.1)        5.4         0.1
------------------------------------------------------------------------------------
Total comprehensive
  income/(loss)             $ 53.3   $27.4   $19.3   $ 4.6       $(3.6)    $   5.6
------------------------------------------------------------------------------------
</Table>


<Table>
<Caption>
------------------------------------------------------------------------------------
                                Nine Months Ended September 30, 2002
------------------------------------------------------------------------------------
                                                                   NU
(Millions of Dollars)         NU     CL&P    PSNH    WMECO    Enterprises    Other
------------------------------------------------------------------------------------
<S>                         <C>      <C>     <C>     <C>         <C>        <C>
Net income/(loss)*          $ 96.1   $58.2   $46.4   $26.9       $(38.7)    $  3.3
------------------------------------------------------------------------------------
Comprehensive income items:
  Qualified cash flow
    hedging instruments       43.7     -       -       -           38.0        5.7
  Unrealized gains on
    securities                (1.2)   (0.5)   (0.6)   (0.1)         -           -
------------------------------------------------------------------------------------
Net change of
  comprehensive income items  42.5    (0.5)   (0.6)   (0.1)        38.0        5.7
------------------------------------------------------------------------------------
Total comprehensive
  income/(loss)             $138.6   $57.7   $45.8   $26.8       $ (0.7)    $  9.0
------------------------------------------------------------------------------------
</Table>

*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)
<Table>
<Caption>
                                                          September 30,      December 31,
                                                               2003              2002
                                                         ----------------  ----------------
                                                               (Thousands of Dollars)
<S>                                                      <C>               <C>
ASSETS
------

Current Assets:
  Cash                                                   $        7,324    $          159
  Restricted cash - LMP costs                                    45,760               -
  Investments in securitizable assets                           215,592           178,908
  Receivables, net                                               62,896            88,001
  Accounts receivable from affiliated companies                  47,978            51,060
  Unbilled revenues                                               7,422             5,801
  Notes receivable from affiliated companies                     26,175             1,900
  Fuel, materials and supplies, at average cost                  30,033            32,379
  Prepayments and other                                          22,770            19,407
                                                         --------------    --------------
                                                                465,950           377,615
                                                         --------------    --------------
Property, Plant and Equipment:
  Electric utility                                            3,281,684         3,139,128
     Less: Accumulated depreciation                           1,159,189         1,113,991
                                                         --------------    --------------
                                                              2,122,495         2,025,137
  Construction work in progress                                 217,233           153,556
                                                         --------------    --------------
                                                              2,339,728         2,178,693
                                                         --------------    --------------

Deferred Debits and Other Assets:
  Regulatory assets                                           1,662,347         1,702,677
  Prepaid pension                                               297,888           276,173
  Other                                                         114,855            96,925
                                                         --------------    --------------
                                                              2,075,090         2,075,775
                                                         --------------    --------------

Total Assets                                             $    4,880,768    $    4,632,083
                                                         ==============    ==============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>
                                                          September 30,      December 31,
                                                               2003              2002
                                                         ----------------  ----------------
                                                               (Thousands of Dollars)
<S>                                                      <C>               <C>
LIABILITIES AND CAPITALIZATION
------------------------------

Current Liabilities:
  Accounts payable                                       $      238,833    $      174,890
  Accounts payable to affiliated companies                      196,393           117,904
  Accrued taxes                                                  59,908            34,350
  Accrued interest                                                9,956            10,077
  Other                                                          47,871            48,495
                                                         --------------    --------------
                                                                552,961           385,716
                                                         --------------    --------------

Rate Reduction Bonds                                          1,153,822         1,245,728
                                                         --------------    --------------
Deferred Credits and Other Liabilities:
  Accumulated deferred income taxes                             713,133           756,461
  Accumulated deferred investment tax credits                    91,516            93,408
  Deferred contractual obligations                              212,604           234,537
  Other                                                         486,533           276,325
                                                         --------------    --------------
                                                              1,503,786         1,360,731
                                                         --------------    --------------
Capitalization:
  Long-Term Debt                                                829,647           827,866
                                                         --------------    --------------
  Preferred Stock - Nonredeemable                               116,200           116,200
                                                         --------------    --------------
  Common Stockholder's Equity:
    Common stock, $10 par value - authorized
     24,500,000 shares; 6,035,205 shares outstanding
     in 2003 and 2002                                            60,352            60,352
    Capital surplus, paid in                                    326,703           327,299
    Retained earnings                                           337,547           308,554
    Accumulated other comprehensive loss                           (250)             (363)
                                                         --------------    --------------
  Common Stockholder's Equity                                   724,352           695,842
                                                         --------------    --------------
Total Capitalization                                          1,670,199         1,639,908
                                                         --------------    --------------

Commitments and Contingencies (Note 4)

Total Liabilities and Capitalization                     $    4,880,768    $    4,632,083
                                                         ==============    ==============
</Table>
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)
<Table>
<Caption>
                                                                 Three Months Ended             Nine Months Ended
                                                                   September 30,                  September 30,
                                                          -----------------------------  -----------------------------
                                                               2003           2002            2003           2002
                                                          -------------- --------------  -------------- --------------
                                                                             (Thousands of Dollars)

<S>                                                       <C>            <C>             <C>            <C>
Operating Revenues                                        $    797,896   $    687,938    $  2,119,080   $  1,874,089
                                                          ------------   ------------    ------------   ------------
Operating Expenses:
  Operation -
     Fuel, purchased and net interchange power                 506,369        406,194       1,279,785      1,109,391
     Other                                                      88,757         80,834         265,524        229,610
  Maintenance                                                   19,388         23,949          51,242         56,217
  Depreciation                                                  26,500         24,445          77,827         73,851
  Amortization of regulatory assets, net                        23,971         26,163          74,218         41,232
  Amortization of rate reduction bonds                          27,664         25,120          78,483         74,197
  Taxes other than income taxes                                 32,096         28,287         111,464        107,006
                                                          ------------   ------------    ------------   ------------
    Total operating expenses                                   724,745        614,992       1,938,543      1,691,504
                                                          ------------   ------------    ------------   ------------
Operating Income                                                73,151         72,946         180,537        182,585

Interest Expense:
  Interest on long-term debt                                     9,567         10,682          29,579         31,071
  Interest on rate reduction bonds                              17,398         18,789          53,304         57,273
  Other interest                                                 1,238            648           1,994          1,963
                                                          ------------   ------------    ------------   ------------
    Interest expense, net                                       28,203         30,119          84,877         90,307
                                                          ------------   ------------    ------------   ------------
Other Income, Net                                                2,652          7,911           4,615         14,094
                                                          ------------   ------------    ------------   ------------
Income Before Income Tax Expense                                47,600         50,738         100,275        106,372
Income Tax Expense                                              17,169         21,441          37,058         43,984
                                                          ------------   ------------    ------------   ------------
Net Income                                                $     30,431   $     29,297    $     63,217   $     62,388
                                                          ============   ============    ============   ============
</Table>
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)
<Table>
<Caption>

                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                            ------------------------------
                                                                                 2003             2002
                                                                            -------------    -------------
                                                                                 (Thousands of Dollars)
<S>                                                                          <C>              <C>
Operating Activities:
  Net income                                                                 $   63,217       $   62,388
  Adjustments to reconcile to net cash flows
   provided by operating activities:
    Depreciation                                                                 77,827           73,851
    Deferred income taxes and investment tax credits, net                       (52,396)         (59,570)
    (Deferral)/amortization of recoverable energy costs                         (15,733)          23,463
    Amortization of regulatory assets, net                                       74,218           41,232
    Amortization of rate reduction bonds                                         78,483           74,197
    Prepaid pension                                                             (21,715)         (38,506)
    Regulatory recoveries                                                       117,279           82,350
    Other uses of cash                                                          (55,152)         (34,656)
    Other sources of cash                                                         8,957           16,804
  Changes in current assets and liabilities:
    Restricted cash - LMP costs                                                 (45,760)             -
    Receivables and unbilled revenues, net                                       26,566          (49,146)
    Fuel, materials and supplies                                                  2,346             (925)
    Accounts payable                                                            142,432           60,995
    Accrued taxes                                                                25,558            2,493
    Investments in securitizable assets                                         (36,684)          49,570
    Other current assets and liabilities (excludes cash)                         (4,063)          (1,383)
                                                                             ----------       ----------
Net cash flows provided by operating activities                                 385,380          303,157
                                                                             ----------       ----------

Investing Activities:
  Investments in plant                                                         (224,757)        (159,946)
  NU system Money Pool (lending)/borrowing                                      (24,275)          51,000
  Other investment activities, net                                               (2,896)            (683)
                                                                             ----------       ----------
Net cash flows used in investing activities                                    (251,928)        (109,629)
                                                                             ----------       ----------

Financing Activities:
  Repurchase of common shares                                                       -            (49,996)
  Retirement of rate reduction bonds                                            (91,606)         (86,819)
  Cash dividends on preferred stock                                              (4,169)          (4,169)
  Cash dividends on common stock                                                (30,055)         (45,091)
  Other financing activities, net                                                  (457)            (399)
                                                                             ----------       ----------
Net cash flows used in financing activities                                    (126,287)        (186,474)
                                                                             ----------       ----------
Net increase in cash                                                              7,165            7,054
Cash - beginning of period                                                          159              773
                                                                             ----------       ----------
Cash - end of period                                                         $    7,324       $    7,827
                                                                             ==========       ==========
</Table>

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)
<Table>
<Caption>

                                                           September 30,    December 31,
                                                               2003             2002
                                                          ---------------- --------------
                                                               (Thousands of Dollars)
<S>                                                       <C>              <C>
ASSETS
------

Current Assets:
  Cash                                                    $       5,782    $       5,319
  Receivables, net                                               68,966           68,204
  Accounts receivable from affiliated companies                     152            9,667
  Unbilled revenues                                              35,450           32,004
  Notes receivable from affiliated companies                        -             23,000
  Fuel, materials and supplies, at average cost                  52,087           49,182
  Prepayments and other                                          17,257           10,032
                                                          -------------    -------------
                                                                179,694          197,408
                                                          -------------    -------------
Property, Plant and Equipment:
  Electric utility                                            1,495,740        1,431,774
  Other                                                           6,180            6,195
                                                          -------------    -------------
                                                              1,501,920        1,437,969
     Less: Accumulated depreciation                             718,860          715,800
                                                          -------------    -------------
                                                                783,060          722,169
  Construction work in progress                                  37,105           50,547
                                                          -------------    -------------
                                                                820,165          772,716
                                                          -------------    -------------
Deferred Debits and Other Assets:
  Regulatory assets                                             972,042        1,026,043
  Other                                                          66,437           92,280
                                                          -------------    -------------
                                                              1,038,479        1,118,323
                                                          -------------    -------------

Total Assets                                              $   2,038,338    $   2,088,447
                                                          =============    =============

</Table>
The accompanying notes are an integral part of these consolidated financial
statements.


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>

                                                             September 30,      December 31,
                                                                  2003              2002
                                                            ---------------   ---------------
                                                                 (Thousands of Dollars)
<S>                                                         <C>               <C>
LIABILITIES AND CAPITALIZATION
------------------------------

Current Liabilities:
  Notes payable to affiliated companies                     $       53,500    $          -
  Accounts payable                                                  35,709            54,588
  Accounts payable to affiliated companies                           3,212             4,008
  Accrued taxes                                                     23,222            65,317
  Accrued interest                                                  14,437            11,333
  Unremitted rate reduction bond collections                        12,636            25,555
  Other                                                             17,513            12,674
                                                            --------------    --------------
                                                                   160,229           173,475
                                                            --------------    --------------

Rate Reduction Bonds                                               483,432           510,841
                                                            --------------    --------------

Deferred Credits and Other Liabilities:
  Accumulated deferred income taxes                                339,791           359,910
  Accumulated deferred investment tax credits                        2,242             2,680
  Deferred contractual obligations                                  50,790            56,165
  Accrued pension                                                   43,080            37,933
  Other                                                            206,638           218,328
                                                            --------------    --------------
                                                                   642,541           675,016
                                                            --------------    --------------
Capitalization:
  Long-Term Debt                                                   407,285           407,285
                                                            --------------    --------------
  Common Stockholder's Equity:
    Common stock, $1 par value - authorized
     100,000,000 shares; 301 shares outstanding
     in 2003 and 2002                                                  -                 -
    Capital surplus, paid in                                       126,608           126,937
    Retained earnings                                              218,292           194,998
    Accumulated other comprehensive loss                               (49)             (105)
                                                            --------------    --------------
  Common Stockholder's Equity                                      344,851           321,830
                                                            --------------    --------------
Total Capitalization                                               752,136           729,115
                                                            --------------    --------------
Commitments and Contingencies (Note 4)

Total Liabilities and Capitalization                        $    2,038,338    $    2,088,447
                                                            ==============    ==============
</Table>
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)
<Table>
<Caption>
                                                                  Three Months Ended           Nine Months Ended
                                                                     September 30,               September 30,
                                                             --------------------------   -------------------------
                                                                 2003          2002           2003          2002
                                                             --------------------------   -------------------------
                                                             (Thousands of Dollars)


<S>                                                           <C>           <C>           <C>           <C>
Operating Revenues                                           $   241,829   $   324,818    $   718,988   $   816,113
                                                             -----------   -----------    -----------   -----------
Operating Expenses:
  Operation -
     Fuel, purchased and net interchange power                   110,121       190,152        362,581       460,575
     Other                                                        34,874        33,309        100,382        94,315
  Maintenance                                                     13,512        13,342         50,689        45,585
  Depreciation                                                    10,963        10,377         32,290        30,681
  Amortization of regulatory assets, net                          18,264        19,742         22,415        14,532
  Amortization of rate reduction bonds                            10,666         8,071         29,422        34,739
  Taxes other than income taxes                                    8,655         8,896         25,384        27,003
                                                             -----------   -----------    -----------   -----------
    Total operating expenses                                     207,055       283,889        623,163       707,430
                                                             -----------   -----------    -----------   -----------
Operating Income                                                  34,774        40,929         95,825       108,683

Interest Expense:
  Interest on long-term debt                                       3,942         3,895         11,642        12,725
  Interest on rate reduction bonds                                 7,237         7,584         21,981        23,022
  Other interest                                                     313           622            925         1,120
                                                             -----------   -----------    -----------   -----------
    Interest expense, net                                         11,492        12,101         34,548        36,867
                                                             -----------   -----------    -----------   -----------
Other (Loss)/Income, Net                                          (1,186)          231         (3,570)         (887)
                                                             -----------   -----------    -----------   -----------
Income Before Income Tax Expense                                  22,096        29,059         57,707        70,929
Income Tax Expense                                                 9,483         9,577         23,213        24,487
                                                             -----------   -----------    -----------   -----------
Net Income                                                   $    12,613   $    19,482    $    34,494   $    46,442
                                                             ===========   ===========    ===========   ===========
</Table>
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)
<Table>
<Caption>

                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                            ------------------------------
                                                                                 2003             2002
                                                                            -------------    -------------
                                                                                 (Thousands of Dollars)
<S>                                                                          <C>              <C>
Operating activities:
  Net income                                                                 $   34,494       $   46,442
  Adjustments to reconcile to net cash flows
   provided by operating activities:
    Depreciation                                                                 32,290           30,681
    Deferred income taxes and investment tax credits, net                        (3,602)         (17,446)
    Amortization of recoverable energy costs                                     17,541           12,494
    Amortization of regulatory assets, net                                       22,415           14,532
    Amortization of rate reduction bonds                                         29,422           34,739
    Regulatory recoveries                                                        (1,593)         (25,529)
    Other sources of cash                                                        20,675           22,347
    Other uses of cash                                                          (29,932)         (21,724)
  Changes in current assets and liabilities:
    Receivables and unbilled revenues, net                                        5,307            7,496
    Fuel, materials and supplies                                                 (2,905)           1,520
    Accounts payable                                                            (19,673)         (15,081)
    Accrued taxes                                                               (42,095)          24,963
    Other current assets and liabilities (excludes cash)                        (12,126)          11,365
                                                                            -----------      -----------
Net cash flows provided by operating activities                                  50,218          126,799
                                                                            -----------      -----------

Investing Activities:
  Investments in plant                                                          (77,373)         (75,817)
  NU system Money Pool borrowing/(lending)                                       76,500           (5,800)
  Buyout/buydown of IPP contracts                                               (20,437)          (5,152)
  Other investment activities, net                                               10,316           (8,179)
                                                                            -----------      -----------
Net cash flows used in investing activities                                     (10,994)         (94,948)
                                                                            -----------      -----------

Financing Activities:
  Issuance of rate reduction bonds                                                  -             50,000
  Retirement of rate reduction bonds                                            (27,409)         (38,727)
  Net decrease in short-term debt                                                   -             (5,500)
  Cash dividends on common stock                                                (11,200)         (24,500)
  Other financing activities, net                                                  (152)         (13,885)
                                                                            -----------      -----------
Net cash flows used in financing activities                                     (38,761)         (32,612)
                                                                            -----------      -----------
Net increase/(decrease) in cash                                                     463             (761)
Cash - beginning of period                                                        5,319            1,479
                                                                            -----------      -----------
Cash - end of period                                                        $     5,782      $       718
                                                                            ===========      ===========
</Table>
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)
<Table>
<Caption>

                                                           September 30,     December 31,
                                                                2003             2002
                                                          --------------    -------------
                                                               (Thousands of Dollars)
<S>                                                       <C>               <C>
ASSETS
------

Current Assets:
  Cash                                                    $            1    $         123
  Receivables, net                                                37,480           42,203
  Accounts receivable from affiliated companies                    2,458            6,354
  Taxes receivable                                                 1,218              -
  Unbilled revenues                                                9,811            8,944
  Fuel, materials and supplies, at average cost                    2,370            1,821
  Prepayments and other                                              967            1,470
                                                          --------------    -------------
                                                                  54,305           60,915
                                                          --------------    -------------
Property, Plant and Equipment:
  Electric utility                                               602,915          590,153
     Less: Accumulated depreciation                              201,984          195,804
                                                          --------------    -------------
                                                                 400,931          394,349
  Construction work in progress                                   16,125           11,860
                                                          --------------    -------------
                                                                 417,056          406,209
                                                          --------------    -------------

Deferred Debits and Other Assets:
  Regulatory assets                                              241,798          283,702
  Prepaid pension                                                 73,321           67,516
  Other                                                           21,011           18,304
                                                          --------------    -------------
                                                                 336,130          369,522
                                                          --------------    -------------

Total Assets                                              $      807,491    $     836,646
                                                          ==============    =============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
<Table>
<Caption>

                                                         September 30,   December 31,
                                                             2003            2002
                                                        --------------   ------------
                                                            (Thousands of Dollars)
<S>                                                     <C>             <C>
LIABILITIES AND CAPITALIZATION
------------------------------

Current Liabilities:
  Notes payable to banks                                $         -     $       7,000
  Notes payable to affiliated companies                        32,200          85,900
  Accounts payable                                             19,106          17,730
  Accounts payable to affiliated companies                     12,088           6,218
  Accrued taxes                                                   412           4,334
  Accrued interest                                              1,045           2,059
  Other                                                        10,097           8,005
                                                        -------------   -------------
                                                               74,948         131,246
                                                        -------------   -------------

Rate Reduction Bonds                                          135,383         142,742
                                                        -------------   -------------

Deferred Credits and Other Liabilities:
  Accumulated deferred income taxes                           208,719         222,065
  Accumulated deferred investment tax credits                   3,410           3,662
  Deferred contractual obligations                             57,804          63,767
  Other                                                        16,467          13,213
                                                        -------------   -------------
                                                              286,400         302,707
                                                        -------------   -------------
Capitalization:
  Long-Term Debt                                              157,077         101,991
                                                        -------------   -------------
  Common Stockholder's Equity:
    Common stock, $25 par value - authorized
     1,072,471 shares; 434,653 shares outstanding
     in 2003 and 2002                                          10,866          10,866
    Capital surplus, paid in                                   69,568          69,712
    Retained earnings                                          73,317          77,476
    Accumulated other comprehensive loss                          (68)            (94)
                                                        -------------   -------------
  Common Stockholder's Equity                                 153,683         157,960
                                                        -------------   -------------
Total Capitalization                                          310,760         259,951
                                                        -------------   -------------

Commitments and Contingencies (Note 4)

Total Liabilities and Capitalization                    $     807,491   $     836,646
                                                        =============   =============
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.



WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
                                                      Three Months Ended           Nine Months Ended
                                                         September 30,                September 30,
                                                  --------------------------   -------------------------
                                                      2003          2002           2003          2002
                                                  -----------   ------------   -----------   -----------
                                                                  (Thousands of Dollars)
<S>                                                <C>           <C>            <C>           <C>

Operating Revenues                                $   103,365   $    95,684    $   297,816   $   278,880
                                                  -----------   -----------    -----------   -----------
Operating Expenses:
  Operation -
     Fuel, purchased and net interchange power         52,194        46,927        150,361       140,510
     Other                                             16,070        12,516         43,611        37,083
  Maintenance                                           3,785         3,798         10,378        10,029
  Depreciation                                          3,544         3,415         10,530        11,038
  Amortization of regulatory assets, net               10,647        12,092         32,819        26,277
  Amortization of rate reduction bonds                  2,399         2,189          7,327         7,080
  Taxes other than income taxes                         3,134         2,223          8,943         7,966
                                                  -----------   -----------    -----------   -----------
        Total operating expenses                       91,773        83,160        263,969       239,983
                                                  -----------   -----------    -----------   -----------
Operating Income                                       11,592        12,524         33,847        38,897

Interest Expense:
  Interest on long-term debt                              767           880          2,303         2,172
  Interest on rate reduction bonds                      2,228         2,379          6,803         7,245
  Other interest                                          127           542            848         1,377
                                                  -----------   -----------    -----------   -----------
     Interest expense, net                              3,122         3,801          9,954        10,794
                                                  -----------   -----------    -----------   -----------
Other Income/(Loss), Net                                1,213           742            986        (2,342)
                                                  -----------   -----------    -----------   -----------
Income Before Income Tax Expense/(Benefit)              9,683         9,465         24,879        25,761
Income Tax Expense/(Benefit)                            4,488         4,735         11,030        (1,181)
                                                  -----------   -----------    -----------   -----------
Net Income                                        $     5,195   $     4,730    $    13,849   $    26,942
                                                  ===========   ===========    ===========   ===========
</Table>
The accompanying notes are an integral part of these consolidated financial
statements.


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<Table>
<Caption>

                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                            ------------------------------
                                                                                 2003             2002
                                                                            ------------       -----------
                                                                                (Thousands of Dollars)
<S>                                                                          <C>                <C>
Operating Activities:
  Net income                                                                 $   13,849         $   26,942
  Adjustments to reconcile to net cash flows
   provided by operating activities:
    Depreciation                                                                 10,530             11,038
    Deferred income taxes and investment tax credits, net                       (11,272)           (19,312)
    Amortization of recoverable energy costs                                        448                322
    Amortization of regulatory assets, net                                       32,819             26,277
    Amortization of rate reduction bonds                                          7,327              7,080
    Prepaid pension                                                              (5,805)           (10,264)
    Regulatory recoveries                                                         2,879              8,849
    Other sources of cash                                                         1,800             16,580
    Other uses of cash                                                          (11,183)           (35,675)
  Changes in current assets and liabilities:
    Receivables and unbilled revenues, net                                        7,752              9,771
    Fuel, materials and supplies                                                   (548)              (232)
    Accounts payable                                                              7,246            (23,839)
    Accrued taxes                                                                (3,922)             1,089
    Other current assets and liabilities (excludes cash)                            384              2,039
                                                                             ----------         ----------
Net cash flows provided by operating activities                                  52,304             20,665
                                                                             ----------         ----------
Investing Activities:
  Investments in plant                                                          (20,661)           (14,739)
  NU system Money Pool (lending)/borrowing                                      (53,700)            20,500
  Other investment activities, net                                                 (676)             1,334
                                                                             ----------         ----------
Net cash flows (used in)/provided by investing activities                       (75,037)             7,095
                                                                             ----------         ----------
Financing Activities:
  Issuance of long-term debt                                                     55,000                -
  Repurchase of common shares                                                       -              (13,999)
  Retirement of rate reduction bonds                                             (7,359)            (7,337)
  Net (decrease)/increase in short-term debt                                     (7,000)             5,000
  Cash dividends on common stock                                                (18,008)           (12,005)
  Other financing activities, net                                                   (22)               (17)
                                                                             ----------         ----------
Net cash flows provided by/(used in) financing activities                        22,611            (28,358)
                                                                             ----------         ----------
Net decrease in cash                                                               (122)              (598)
Cash - beginning of period                                                          123                599
                                                                             ----------         ----------
Cash - end of period                                                         $        1         $        1
                                                                             ==========         ==========
</Table>
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)