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

Back to GetFilings.com

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 June 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 July 31, 2003
- ------------------------ ----------------------------
Northeast Utilities
Common shares, $5.00 par value 127,097,444 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
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

CVEC...................... Connecticut Valley Electric Company
MGT....................... Meriden Gas Turbines, LLC
NEON...................... NEON Communications, Inc.
NRG....................... NRG Energy, Inc.
NRG-PM.................... NRG Power Marketing, Inc.
PPL....................... PPL Corporation

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
CSC....................... Connecticut Siting Council
CTA....................... Competitive Transition Assessment
DIG....................... Derivative Implementation Group
EITF...................... Emerging Issues Task Force
EPS....................... Earnings per Share
FASB...................... Financial Accounting Standards Board
FMCC...................... Federally Mandated Congestion Costs
GSC....................... Generation Services Charge
IERM...................... Infrastructure Expansion Rate Mechanism
Incentive Plan............ Northeast Utilities Incentive Plan
IPPs...................... Independent Power Producers
ISO-NE.................... New England Independent System Operator
kWh....................... Kilowatt-hour
LMP....................... Locational Marginal Pricing
Moody's................... Moody's Investors Service
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

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 -
June 30, 2003 and December 31, 2002.................... 2

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2003 and 2002................................. 4

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2003 and 2002................ 5

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

Independent Accountants' Report............................. 33

Notes to Consolidated Financial Statements
(unaudited - all companies).................................. 34

The Connecticut Light and Power Company
and Subsidiaries

Consolidated Balance Sheets -
June 30, 2003 and December 31, 2002.................... 58

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2003 and 2002................................. 60

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2003 and 2002................ 61

Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 62

Public Service Company of New Hampshire
and Subsidiaries

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

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2003 and 2002................................. 70

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2003 and 2002................ 71

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

Western Massachusetts Electric Company
and Subsidiary

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

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2003 and 2002................................. 80

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2003 and 2002................ 81

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

Item 3. Quantitative and Qualitative
Disclosures About Market Risk.......................... 85

Item 4. Controls and Procedures................................ 85

Part II. Other Information

Item 1. Legal Proceedings...................................... 86

Item 4. Submission of Matters to a
Vote of Security Holders............................... 89

Item 6. Exhibits and Reports on Form 8-K....................... 90

Signatures............................................................ 93

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

NORTHEAST UTILITIES AND SUBSIDIARIES

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

This discussion should be read in conjunction with the consolidated financial
statements and footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q,
the NU 2002 Form 10-K, and the current report on Form 8-K dated May 14, 2003.

FINANCIAL CONDITION

Overview
- --------

Consolidated: Northeast Utilities (NU or the company) earned $26.9 million,
or $0.21 per share, in the second quarter of 2003, compared with net income
of $28.9 million, or $0.22 per share, in the second quarter of 2002. For the
first six months of 2003, NU earned $87.1 million, or $0.69 per share,
compared with net income of $47.5 million, or $0.37 per share, for the first
six months of 2002. The results for the first six months of 2002 included
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 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 six 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.

As more fully discussed below, the reduction of $2 million in second quarter
net income in 2003 as compared with the same period of 2002 was due to a
combination of factors, including lower Utility Group net income in the
second quarter of 2003 as compared to the same period of 2002, offset by
significantly improved results at NU Enterprises.

A turnaround in the operations of NU Enterprises resulted in a $46.8 million
increase in net income for the first six months of 2003 as compared with the
same period of 2002. Net income generated from the Utility Group decreased
$21.2 million in the first six months of 2003 as compared with the same
period of 2002. Net income for the six months ended June 30, 2002 also
included the impacts of the aforementioned after-tax write downs and
investment tax credits. 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 were
no share repurchases in the second quarter of 2003. NU had approximately
126.9 million shares outstanding at June 30, 2003. In May 2003, the NU Board
of Trustees authorized the repurchase of up to 10 million additional shares
through July 1, 2005.

NU's revenues during the first six months of 2003 increased to $3.1 billion
from $2.4 billion in the same period of 2002. The increase in revenues is
partially due to increases in electric and firm natural gas sales in 2003 as
compared to 2002 and higher wholesale marketing revenues at NU Enterprises.

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 the Seabrook nuclear unit, which was sold on
November 1, 2002. Lower pension income and the sale of Seabrook resulted in
approximately a $9 million and a $5 million decrease, respectively, in net
income in 2003 as compared to 2002.

The Utility Group benefited from higher sales volumes. Overall, regulated
retail electric sales increased 0.6 percent in the second quarter of 2003 and
4.9 percent in the first half of 2003, compared with the same periods of
2002. Firm natural gas sales at Yankee Gas Services Company (Yankee Gas)
increased 4.1 percent in the second quarter of 2003 and 13.6 percent in the
first half of 2003, compared with the same periods of 2002. Higher sales
volumes resulted in approximately a $10 million increase in net income in
2003 as compared to 2002.

Earnings before preferred dividends at The Connecticut Light and Power
Company (CL&P) totaled $6.1 million in the second quarter of 2003 and $32.8
million in the first half of 2003, compared with $11.4 million in the second
quarter of 2002 and $33.1 million in the first half of 2002. The lower
second quarter net income resulted from higher operation and maintenance
(O&M) expense levels due in part to lower pension income and lower earnings
on regulatory assets, offset by increased retail sales. The second quarter
of 2003 was also modestly impacted by the effect of an earnings sharing
formula under which half of CL&P's net income in excess of a 10.3 percent
return on equity is credited to customers in the form of additional
amortization of regulatory assets.

Public Service Company of New Hampshire (PSNH) earned $11.1 million in the
second quarter of 2003 and $21.9 million in the first half of 2003, compared
with $15.2 million in the second quarter of 2002 and $27 million in the first
half 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 on November 1, 2002. The reduction in net regulatory assets
will continue to negatively affect PSNH's 2003 to 2002 net income
comparisons. Additionally, second quarter 2002 net income includes $4.2
million for the positive resolution of certain contingencies related to a
PSNH regulatory proceeding.

Net income at WMECO was $2.6 million in the second quarter of 2003 and $8.7
million in the first half of 2003, compared with $15.3 million in the second
quarter of 2002 and $22.2 million in the first half of 2002. The primary
reason for the net income decline was the absence of approximately $13
million of investment tax credits related to divested generation that WMECO
reflected in the second quarter of 2002 as a result of a regulatory decision.

Yankee Energy System, Inc. (Yankee) lost $3 million in the second quarter of
2003 and earned $12.2 million in the first half of 2003, compared with a loss
of $0.5 million in the second quarter of 2002 and net income of $12.1 million
in the first half of 2002. Yankee benefited from colder temperatures, but
was negatively affected by lower pension income and a change in the estimate
of unbilled revenues.

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 pretax earnings. The
remaining 30 percent ($12 million) relates to employees working on capital
projects and will be reflected as higher capital expenditures. The $29
million increase in operating expenses is reflected evenly throughout the
year resulting 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., all of which are
collectively referred to as "NU Enterprises." Holyoke Water Power Company
(HWP) is also included in NU Enterprises. NU Enterprises earned $11.9
million in the second quarter of 2003 and $17.1 million in the first half of
2003, compared with a loss of $9.2 million in the second quarter of 2002 and
a loss of $29.7 million in the first half of 2002. NU Enterprises' net
income improved due to improved results in the wholesale marketing group, the
absence of energy trading losses, better performance in the retail energy and
services businesses, and increased hydroelectric plant output in the first
six months of 2003 compared with the same period of 2002.

Select Energy's wholesale marketing group includes wholesale origination,
portfolio management and the operation of more than 1,400 megawatts (MW) of
pumped storage, hydroelectric and coal-fired generation assets. The
wholesale marketing group earned $12.1 million in the second quarter of 2003
and $19.4 million in the first half of 2003, compared with $2.3 million in
the second quarter of 2002 and $6.4 million in the first half of 2002. The
wholesale marketing group's second quarter of 2003 results benefited from the
termination of contracts which had the impact of accelerating $2 million of
profits from the second half of 2003 and $0.3 million of profits from 2004
into the second quarter of 2003. With precipitation returning to more normal
levels, output has increased at NGC's Connecticut and Massachusetts
conventional hydroelectric plants by approximately 70,000 megawatt-hours in
the first six months of 2003 or by approximately 22 percent, compared to the
first six months of 2002. This resulted in $1.6 million of additional net
income in 2003 as compared to 2002.

Trading activities, which are part of risk management for the wholesale
marketing group, earned $0.5 million in the second quarter of 2003 and were
essentially breakeven in the first half of 2003 compared with losses of $7.5
million in the second quarter of 2002 and $17.6 million in the first half of
2002. Trading activities have been significantly reduced in size over the
past year.

The retail business lost $2.1 million in the second quarter of 2003 and $4.2
million in the first half of 2003 compared with losses of $4.4 million in the
second quarter of 2002 and $18.6 million in the first half of 2002. The 2003
improved retail results are primarily due to improved management of gas
retail contracts along with improved margins and growth in retail electric
sales.

The energy services businesses earned $1.4 million in the second quarter of
2003 and $1.9 million in the first half of 2003 compared with earnings of
$0.4 million in the second quarter of 2002 and $0.1 million in the first half
of 2002.

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

Consolidated: NU continues to project net income of between $1.10 per share
and $1.30 per share in 2003. Despite a strong first half of 2003, management
believes that a combination of more seasonable weather, lower pension income,
and the absence of Seabrook-related and other regulatory asset based earnings
will result in lower quarterly results in the third and fourth quarters of
2003 than those reported by NU in the second half of 2002.

Utility Group: The projected net income range of between $1.10 per share and
$1.30 per share continues to include net income of between $1.05 per share
and $1.15 per share at the Utility Group.

NU Enterprises: NU continues to project net income of between $0.15 per
share and $0.25 per share at NU Enterprises with the objective of finishing
2003 in the upper end of that range. This estimate assumes that Select
Energy will not bear any of the costs associated with the March 1, 2003
implementation of standard market design (SMD) and locational marginal
pricing (LMP) in New England, as this implementation affects Select Energy's
standard offer supply contract with CL&P.

From March 1, 2003 through June 30, 2003, pre-tax LMP costs related to Select
Energy's contract with CL&P totaled approximately $35 million, and by the end
of 2003, those costs are estimated to total between $85 million and $90
million. The issue of responsibility for LMP costs associated with all three
of CL&P's standard offer supply contracts is now before the Federal Energy
Regulatory Commission (FERC), and a decision is expected in early 2004.

NU also continues to project parent company debt and other expenses of
approximately $0.10 per share.

Liquidity
- ---------

Consolidated: NU's liquidity continues to be strong as NU had $57 million of
cash and cash equivalents on hand at June 30, 2003 while NU parent had $180.9
million invested in the NU system Money Pool. The Utility Group and NU
Enterprises have $192.4 million and $22.8 million of borrowings from the NU
system Money Pool, respectively, while other NU companies have $34.3 million
invested in the NU system Money Pool. NU's liquidity was enhanced on June 3,
2003, when 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 used to
refinance Select Energy's short-term debt to NU Parent and to provide short-
term financing to Select Energy.

NU's net cash flows from operating activities decreased to $220.8 million in
the first six months of 2003 from $347.2 million in the first six months of
2002. The decrease in cash flows from operating activities resulted from the
payment of $190.6 million of taxes, primarily on the gain on the sale of
Seabrook, combined with decreases in other working capital items. Working
capital items were impacted by reduced levels of accounts receivable and
accounts payable, primarily at Select Energy. These decreases were partially
offset by a $39.6 million increase in income before preferred dividends of
subsidiaries.

NU's capital expenditures totaled $236.7 million in the first six months of
2003 compared to $212.5 million in the first six months of 2002. NU
currently projects capital expenditures of approximately $600 million in
2003. In the first six months of 2003, NU also repaid $28.7 million of long-
term debt and $82.3 million of rate reduction bonds.

The level of common dividends totaled $34.9 million in the first six months
of 2003, compared with $32.4 million in the first six months of 2002. The
increase in the level of common dividends resulted from NU paying two $0.1375
per share quarterly common dividends in the first six months of 2003 compared
to two $0.125 per share quarterly dividends in the first six months of 2002.
On May 13, 2003, the NU Board of Trustees declared a dividend of $0.15 per
share payable on September 30, 2003, to shareholders of record on September
1, 2003. The 9.1 percent dividend increase was consistent with management's
expectation 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 second quarter, NU's credit ratings were placed on a negative outlook
by Moody's Investors Service (Moody's) and Fitch Ratings. CL&P has also been
put on a negative outlook by Moody's. The change in outlook from stable to
negative was the result of higher forecasted capital spending at CL&P and
efforts by NRG Energy, Inc. (NRG) to terminate its standard offer service
contract with CL&P. These changes in outlook had no material effect on NU's
liquidity, costs, or access to capital. 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 June 30, 2003, NU's Utility Group had no borrowings
outstanding on its $300 million revolving credit line. This credit line
matures on November 11, 2003, and management anticipates extending this
credit line.

On July 9, 2003, CL&P renewed an agreement for one year under which it can
access up to $100 million by selling certain of its accounts receivable and
unbilled revenues. At June 30, 2003, CL&P had $50 million of accounts
receivable and unbilled revenues sold under this arrangement. For more
information regarding CL&P's accounts receivable facility, see Note 1F, "Sale
of Customer Receivables," to the consolidated financial statements.

Through June 30, 2003, CL&P has 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 has
positively impacted CL&P's liquidity. In July 2003, CL&P began depositing
these recoveries into an escrow account. Accordingly, further recovery of
these costs will not impact CL&P's liquidity. When the issue of
responsibility for incremental LMP costs is resolved, which is expected to be
in early 2004, 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.

Effective May 31, 2003, PSNH bought out the power purchase obligations of 14
small independently owned hydroelectric plants in New Hampshire for $20.4
million, which was paid from cash flows from operations. The buy out
payments have been recorded as regulatory assets, and will be recovered,
including a return, over the remaining term of the initial contractual
arrangements as Part 2 stranded costs.

On June 27, 2003, the Massachusetts Department of Telecommunications and
Energy (DTE) issued an order allowing WMECO to issue up to $57.5 million of
long-term securities on or before December 31, 2003 to refinance short-term
debt and cover issuance costs. WMECO is expected to issue that debt in the
second half of 2003.

On July 1, 2003, Standard & Poor's initiated a BBB+ rating on Yankee Gas. On
July 25, 2003, Moody's initiated a Baa1 rating on Yankee Gas. Management
secured the rating to enhance Yankee Gas' financial relationships with its
gas suppliers and in anticipation of issuing new debt to finance the
construction of a liquefied natural gas storage facility and build out of its
gas distribution system.

NU Enterprises: NU Enterprises had $63 million in borrowings and $10.2
million in letters of credit outstanding on NU parent's $350 million
revolving credit line. This credit line matures on November 11, 2003, and
management anticipates extending this credit line. NU Enterprises
effectively refinanced a significant portion of its short-term debt from
associated companies into long-term advances from NU parent as a result of
the $150 million, five-year notes issued by NU in June 2003.

Select Energy has billed CL&P for incremental LMP costs in the amount of
approximately $35 million. 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 through the resolution of the
incremental LMP cost issue.

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

On March 1, 2003, the New England Independent System Operator (ISO-NE)
implemented SMD. As part of SMD, LMP is now utilized to assign value and
causation to transmission congestion and line losses. 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 load zone in which they occur. 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 even excess generation,
such as Maine. The implementation of SMD has impacted pricing under
wholesale energy contracts depending on the energy delivery points chosen
under those contracts.

Utility Group: Connecticut has been designated a single load zone by ISO-NE.
If high loads, transmission constraints and inadequate generation are
experienced, Connecticut could experience significant additional congestion
costs under SMD. ISO-NE estimated that the majority of congestion and its
costs would be in Connecticut, where approximately 80 percent is expected to
be paid by CL&P. CL&P began incurring these costs on March 1, 2003.

For the four-month period from March 1, 2003 through June 30, 2003,
incremental LMP costs have totaled approximately $62 million. Approximately
80 percent of these incremental costs (approximately $47 million, or
approximately $12.5 million per month on average) were associated with line
losses, with monthly line losses ranging from $9.9 million to $14.1 million.
Management expects comparable monthly line loss charges for the remainder of
2003. The LMP costs also include approximately $13 million related to
congestion costs for the four-month period with monthly congestion costs
ranging from $0.2 million to $6.1 million. The remaining $2 million of
incremental LMP costs incurred through June 30, 2003 related to energy price
differences between LMP zones. In July 2003, incremental LMP costs amounted
to approximately $25 million, including $16.6 million of line loss charges
and $8.4 million of congestion costs.

As a result of cooler than average temperatures to date, the congestion cost
component of LMP has not been as significant as originally anticipated.
However, line loss charges have been significant. Management currently
expects that incremental total LMP costs for CL&P for all of 2003 will be
between $170 million and $180 million. Actual incremental LMP costs could be
significantly 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.
The delivery points in the contracts are 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 $62 million of
incremental LMP costs incurred from March 1, 2003 through June 30, 2003 were
recorded as recoverable energy costs, and approximately $30 million has been
billed to customers and reflected in revenues. 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 filed for and has received approval on May 1, 2003, for
their recovery, subject to refund. CL&P began recovery of the March 2003 LMP
costs in its May 2003 billings and continues to bill LMP costs in its June
and July 2003 billings, collecting April and May 2003 LMP costs,
respectively.

The Connecticut Department of Public Utility Control's (DPUC) decision
regarding recovery of incremental LMP costs directed CL&P to pursue legal
remedies against its standard offer suppliers in an effort to assign
liability for incremental LMP costs to the 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 required CL&P to obtain surety bonds for the $31.1
million of March 2003 and April 2003 incremental LMP costs. These surety
bonds are guaranteed by NU parent. Incremental LMP costs beginning with the
May 2003 amounts which were billed to customers in July will be deposited in
an escrow account as billings of these amounts are collected.

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 $62 million of incremental LMP costs to its
standard offer service suppliers, pending resolution of this matter. Final
briefs before the FERC are due in November 2003, and a decision from the FERC
is expected in early 2004.

Another factor affecting the level of CL&P costs is the designation of
certain generating units by ISO-NE as units needed for system reliability.
Some companies owning such units have applied to the FERC for "reliability
must run" (RMR) treatment. RMR treatment allows these units to receive cost
of service-based payments that recognize their reliability value. 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, and 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 allocated to the load zone in
which the RMR unit is located. At present, the only load zone that is
experiencing an RMR cost increase in which NU's regulated electric
distribution companies operate is Connecticut. Reliability costs have been
previously approved for recovery by the DPUC in generation service charge
costs, which were reviewed by the DPUC in CL&P's 2001 Competitive Transition
Assessment (CTA) reconciliation filing. RMR costs incurred during 2002
totaling $7.8 million have been recovered from customers to date and are
subject to review in CL&P's 2002 CTA reconciliation filing, which was filed
on March 31, 2003. For the six-month period ended June 30, 2003, CL&P
incurred $17.9 million of RMR costs.

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. Interventions and answers are due
on August 12, 2003. Management cannot predict the outcome or effect of this
proceeding on CL&P.

PPL Corporation (PPL) and NRG Power Marketing, Inc. (NRG-PM) have sought RMR
treatment from FERC for certain of their Connecticut units. PPL's request is
still pending. NRG-PM's request for full cost of service recovery was
denied; however, FERC did permit recovery of certain "going forward"
maintenance costs, a temporary safe harbor from the ISO-NE price cap under
certain circumstances, and the ability to set the energy price at certain
times. The increase in RMR costs as a result of PPL's and NRG's requests has
not been significant. At this time, management cannot determine CL&P's
exposure to RMR costs or the impact on incremental LMP costs as a result of
these requests.

On July 25, 2003, CL&P filed with the DPUC a request for approval of a formal
recovery mechanism that would allow for the 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. It is anticipated that the DPUC will open
a formal review of CL&P's proposal with a final resolution on the matter
expected by the end of 2003.

NU Enterprises: Select Energy currently serves 50 percent of CL&P's standard
offer service. If it is ultimately concluded that the incremental LMP costs,
which began on March 1, 2003, are the responsibility of the standard offer
service suppliers, NU Enterprises' pre-tax earnings for the six months ended
June 30, 2003 would be reduced by approximately $35 million. Management
currently expects Select Energy's share of incremental LMP costs for 2003 to
be between $85 million and $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 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 net
income estimates do not include incremental LMP costs.

SMD impacted the delivery points in many wholesale marketing contracts and in
some trading contracts. At June 30, 2003, Select Energy has resolved most of
the suppliers' choice delivery points in contracts, and this issue is not
expected to materially affect Select Energy.

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
certain subsidiaries of NRG. On May 14, 2003, NRG filed a voluntary
bankruptcy petition. NRG-related exposures to certain subsidiaries of NU as
a result of these transactions are as follows:

Standard Offer Service Contract: NRG has a contract with CL&P to supply 45
percent of CL&P's standard offer service load through December 31, 2003. NRG
attempted to terminate the contract with CL&P, but the FERC ordered NRG to
continue serving CL&P under its standard offer supplier contract.
Subsequently, NRG received a temporary order from the United States District
Court and on June 12, 2003 stopped serving CL&P with standard offer supply.
NRG was ultimately ordered by the FERC to resume serving CL&P's standard
offer service load and did so on July 2, 2003. During the period NRG 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's contract price. This
excess amounted to $7.9 million and was recorded as recoverable energy costs,
which CL&P began billing to customers August 1, 2003. Management will pursue
recovery of these costs from NRG, and if these costs are ultimately collected
from NRG, then CL&P would refund any portion of the $7.9 million previously
paid by them.

Station Service: CL&P provides NRG with station service, which is electric
service when a generator is off-line or unable to satisfy its station service
requirements, at DPUC-approved retail rates. NRG objects to being billed at
retail rates and has refused to pay 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 expects to continue to
seek recovery from NRG; however, 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.

Through June 30, 2003, legal costs incurred by CL&P related to NRG's
bankruptcy amounted to $0.4 million. This amount has been recorded as a
regulatory asset, and NU will continue to defer these legal costs as they are
incurred.

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. CL&P has continued to
withhold these charges on a monthly basis, netting the standard offer
supplier payments with the congestion costs. The total amount of congestion
costs withheld from NRG is $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.

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
petition.

Yankee Gas made capital expenditures in excess of $16 million for 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 indicated that it was
abandoning construction of the generating plant. NRG has contested the draw
down on the letter of credit. 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. Boulos is owed $2.6 million as a
result of Boulos' work through the joint venture. The joint venture has
commenced a legal proceeding against the general contractor to collect what
is 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. 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.

Management cannot predict the resolution of the exposures to NRG at this
time. For further information regarding these NRG exposures, see Note 4B,
"Commitments and Contingencies - NRG Energy, Inc. Exposures," to the
consolidated financial statements and Part II, Item 1, "Legal Proceedings,"
included in this combined report on Form 10-Q.

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

Subsidiaries: NU Enterprises, Inc. is the parent company of Select Energy,
NGC, SESI, NGS, and their respective subsidiaries, and Woods Network
Services, Inc., which are collectively referred to as "NU Enterprises." HWP
is also included in 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 marketing 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
wholesale marketing business.

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, mechanical, and engineering contracting services.

Outlook: Financial performance at NU Enterprises improved significantly in
the first half of 2003 compared to 2002.

The wholesale marketing business obtained several new contracts since the
first quarter of 2003. Select Energy has been awarded electric supply
contracts by the Maine Public Utilities Commission to provide standard offer
service to large commercial and industrial customers of Central Maine Power
Company and Bangor Hydro Electric Company. Approximately 160 MW will be
provided, and revenues are expected to total approximately $30 million during
the contract period, which begins on September 1, 2003 and runs through
February 2004. Over 400 MW of default service with NSTAR subsidiaries Boston
Edison Company, Commonwealth Electric Light and Cambridge Electric Light
began July 1, 2003 and runs through June 30, 2004. Revenues are expected to
exceed $100 million. Also, on July 1, 2003, Select Energy began serving
under a contract with affiliate WMECO to supply a portion of its default
service through December 31, 2003. A contract to supply default service with
Fitchburg Gas and Electric Company began June 1, 2003 and runs through
November 30, 2003. Both contracts serve commercial and industrial customers,
and Select Energy expects approximately $6 million in combined revenues from
those transactions.

Management currently believes that the wholesale marketing business will
generate the wholesale origination margins required to support NU
Enterprises' 2003 net income estimate. Essentially all of the wholesale
origination margins needed to support NU Enterprises' 2003 net income
estimate has been contracted by June 30, 2003. To meet the net income
estimate, the wholesale marketing business will need to successfully manage
its portfolio of contracts to retain the estimated origination margins.

The retail marketing business also improved its financial performance in 2003
compared to 2002. At June 30, 2003, approximately 50 percent of the retail
origination margins needed to cover projected costs and achieve break-even
performance in 2003 has been contracted. Retail gas customers have continued
to be hesitant to commit to long-term contracts during this period of high
prices. Select Energy is serving many of these customers on a month-to-month
basis at relatively low margins. Although market conditions are beginning to
improve, management currently believes that the retail marketing business
line will be below its net income target for 2003. The retail marketing
business will have to be successfully managed to realize the estimated margin
for the contracts in its retail marketing portfolio.

Intercompany Transactions: CL&P's standard offer service purchases from
Select Energy represented approximately $280 million of total NU Enterprises'
revenues for the first six months of 2003. Other transactions between CL&P
and Select Energy amounted to approximately $69 million in revenues for
Select Energy in the first six 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 $68 million of total NU Enterprises' revenues in the first six
months of 2003. These amounts are eliminated in consolidation.

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
business lines: wholesale marketing (including limited trading) 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 June 30, 2003, the wholesale marketing portfolio, which includes the CL&P
standard offer service contract that extends through 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 marketing 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 Marketing: 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.

At June 30, 2003, Select Energy had trading derivative assets of $141 million
and trading derivative liabilities of $96 million on a counterparty-by-
counterparty basis, for a net positive position of $45 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 the 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 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 June 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; 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. These transactions
are modeled using available market information, generally accepted gas to
electricity heat rate conversion models, or the Blacks option pricing model.
Select Energy currently has one contract for which fair value is determined
based on a model. This contract expires in 2006 and the last year of the
contract, including an option component, had a fair value of $4 million at
June 30, 2003. Broker quotes for electricity are available through the year
2005, and models are generally used for the years 2006 and thereafter.
Broker quotes for natural gas are available through 2013.

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.

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

As of and for the three months ended June 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 June 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 $(3.0) $ 0.1 $ - $(2.9)
Prices provided by
external sources 11.0 14.4 18.5 43.9
Prices based on
models or other
valuation methods - 4.0 - 4.0
- -------------------------------------------------------------------------------
Totals $ 8.0 $18.5 $18.5 $45.0
- -------------------------------------------------------------------------------

The fair value of energy trading contracts decreased by $0.8 million from
$45.8 million at March 31, 2003 to $45 million at June 30, 2003. Contracts
realized or otherwise settled during the period of $2.2 million includes
the termination of a contract with a positive fair value at March 31, 2003
of $5.7 million. The change in fair value attributable to changes in
valuation techniques and assumptions is 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 Six Months Ended
(Millions of Dollars) June 30, 2003 June 30, 2003
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the beginning
of the period $45.8 $41.0
Contracts realized or otherwise (2.2) (5.0)
settled during the period
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 2.3
Changes in fair value of
contracts (0.9) 6.7
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the end
of the period $45.0 $45.0
- -------------------------------------------------------------------------------

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, 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 continues to impact Select Energy's ability to estimate
the fair value of its long-term wholesale marketing 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
trading activities. The appropriateness of these limits is subject to
continuing review. Concentrations among these counterparties may impact
Select Energy's overall exposure to credit risk, either positively or
negatively, in that the counterparties may be similarly affected by changes
to economic, regulatory or other conditions. At June 30, 2003, approximately
80 percent of Select Energy's counterparty credit exposure to wholesale
marketing and trading counterparties was cash collateralized or rated BBB- or
better. Another three percent of the counterparty credit exposure was to
unrated municipalities.

Asset Concentrations: At June 30, 2003, positions with three counterparties
collectively represented approximately $75 million, or 53 percent, of the
$141 million trading derivative assets. The largest counterparty's position
is secured with letters of credit, cash collateral, and investment grade
parent guarantees. Select Energy holds an investment grade parent guarantee
on the second counterparty's position. The third counterparty is an unrated
generation entity as to which Select Energy does not hold collateral or
guarantees. None of the other counterparties represented more than 10
percent of trading derivative assets.

Exposures to Bankruptcies: Select Energy does not have a significant level
of exposure to Mirant Americas Energy Marketing, LP, NRG, or PG&E Energy
Trading - Power, L.P., all of which are in bankruptcy at this time. At this
time, Select Energy does not have significant credit exposure to other
entities that are not in bankruptcy but have below investment grade ratings.

Select Energy Credit: A number of Select Energy's contracts require the
posting of additional collateral in the form of cash or letters of credit in
the event NU's ratings were to decline and in increasing amounts dependent
upon the severity of the decline. At NU's present investment grade ratings,
Select Energy has not had to post any collateral based on credit downgrades.
Were NU's unsecured ratings to decline two to three levels to sub-investment
grade, Select Energy could, under its present contracts, be asked to provide
approximately $274 million of collateral or letters of credit to various
unaffiliated counterparties and approximately $82 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.

Business Development and Capital Expenditures
- ---------------------------------------------

Utility Group: 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 2003. This project is
exempt from the State of Connecticut's imposed moratorium on the approval of
new electric and natural gas transmission projects. At June 30, 2003, CL&P
has capitalized approximately $10.6 million related to this project.

CL&P expects to file for approval of a separate 345,000 volt transmission
line from Norwalk, Connecticut to Middletown, Connecticut in the third
quarter of 2003. Estimated construction costs of this project are
approximately $500 million. CL&P will jointly site this project with United
Illuminating, and CL&P will own 80 percent, or approximately $400 million, of
the project. This project is also exempt from the State of Connecticut's
imposed moratorium on the approval of new electric and natural gas
transmission projects. At June 30, 2003, CL&P has capitalized approximately
$4.9 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 approximately 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 is currently under evaluation. This project is also
exempt from the State of Connecticut's imposed moratorium on the approval of
new electric and natural gas transmission projects. At June 30, 2003, CL&P
has capitalized approximately $5.4 million related to this project.

Yankee Gas is seeking to obtain rate approval from the DPUC to build a two
billion cubic foot liquefied natural gas storage and production facility in
Waterbury, Connecticut. Hearings were held in March 2003, and a final
decision is expected in the third quarter of 2003. If approved, construction
of the facility, which is expected to cost approximately $60 million, could
begin in late 2003 or in early 2004. This project is also exempt from the
State of Connecticut's imposed moratorium on the approval of new electric and
natural gas transmission projects. At June 30, 2003, Yankee Gas has
capitalized approximately $1.1 million related to this project.

On May 23, 2003, the New Hampshire Public Utilities Commission (NHPUC)
approved PSNH's acquisition of the assets of Connecticut Valley Electric
Company (CVEC). The acquisition of CVEC's assets will add 25 MW of new load
to PSNH and approximately 10,000 customers in 13 towns. The CVEC transaction
is still subject to approval by the FERC and is expected to close in December
2003. 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 a high-cost purchase power contract CVEC has with Central Vermont
Public Service, its parent company. The $21 million payment will be
recovered over the next several years from PSNH's customers as a Part 3
stranded cost.

Utility Group Restructuring and Rate Matters
- --------------------------------------------

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, an increase of up to 11.1 percent. If energy supply costs
exceed levels established in the TSO rate, they will be recovered through an
energy adjustment clause or through the FMCC charge in the case of
incremental LMP costs. Neither the energy adjustment clause nor the FMCC
charge are subject to the base rate cap. Accordingly, the ultimate rate
increase for customers could exceed 11.1 percent.

The Act also requires that the utilities be allowed to recover from customers
who do not choose an alternative supplier their full cost of procuring power
and allows those utilities to earn at least a 0.50 mill fee on power
purchases during the TSO period. That fee can increase to 0.75 mills if the
utility beats certain regional benchmarks. One mill is equal to one-tenth of
a cent. All procurement compensation is excluded from review of a utility's
rates and earnings sharing mechanism calculations.

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. Under the
plan, CL&P expects to acquire competitively priced supply this fall for TSO
beyond December 31, 2003, when its current standard offer supplier contracts
expire.

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
Incremental Increase/(Decrease) in
Year Increase/(Decrease) 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 distribution capital
program, 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.

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 of the Seabrook nuclear unit. Hearings in this docket
are scheduled for the third quarter of 2003 with a final decision scheduled
to be issued in December 2003.

Energy Conservation Program: As a result of difficulty balancing the 2003
through 2005 state budget, the State of Connecticut has proposed redirecting
funds collected through a 3 mill energy conservation adder on retail electric
bills to the state's general fund. If approved as part of a final state
budget, the change could reduce CL&P net income, as CL&P is currently allowed
to earn an incentive on its energy conservation programs. In 2002, that
incentive added approximately $3.3 million to CL&P's net income. In mid-
2003, in anticipation of a reduction in those programs, CL&P reduced its
workforce by approximately 60 employees involved in delivering energy
conservation programs to customers.

CL&P is working with state officials and other parties to find ways to
restore, at least partially, the funding for these programs. One way under
consideration would be to use securitization to generate approximately two-
thirds of such funding for two years, which would also permit the continued
opportunity for CL&P to earn incentives.

Earnings Sharing: CL&P continues to be subject to the earnings sharing
mechanism implemented by the DPUC, under which CL&P's net income in excess of
a 10.3 percent return on equity is shared equally by shareholders and
ratepayers. For the twelve-month period ended June 30, 2003, CL&P earned in
excess of a 10.3 percent return on equity and recorded an associated
regulatory liability. CL&P expects to make its earnings sharing filing with
the DPUC in August 2003.

Competitive Transition Assessment 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 has
been 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 decision from the DPUC in this docket by the end of
2003.

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 decision
approved 10 of the 22 proposed IERM projects and encouraged Yankee Gas to
seek recovery of the costs of these projects in its next rate case. The DPUC
ordered Yankee Gas to provide a credit to customers for 2002 and 2003
overrecoveries estimated at $3.6 million during December 2003 through
February 2004. This amount has been recorded as a regulatory liability.

New Hampshire:

Transition Service: On February 1, 2003, in accordance with the "Agreement
to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH
raised the transition service rate for commercial, industrial, and
residential customers. These rates are not fully recovering its 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 $29 million. 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
NHPUC. Hearings in this docket are scheduled for October 2003 with an order
expected by the end of 2003. Management does not expect the outcome of this
docket to have a material adverse impact on PSNH's net income or its
financial position.

Renegotiation of Power Purchase Obligations: Under New Hampshire law, PSNH
is encouraged to enter into negotiations with independent power producers
(IPPs) to terminate or renegotiate over-market power purchase obligations. On
May 22, 2003, the NHPUC issued an order approving a stipulation and
settlement between PSNH, the NHPUC staff, the Office of Consumer Advocate,
owners of fourteen small hydroelectric IPPs and the Town of Goffstown, New
Hampshire. On May 30, 2003, under the terms of this settlement, PSNH made
lump sum payments totaling $20.4 million to the fourteen IPPs, in exchange
for the termination of the existing long-term power purchase obligations
between PSNH and these IPPs effective on May 31, 2003. PSNH continues to
have an obligation under state and federal law to purchase the output from
these fourteen IPPs. However, these purchases will be made at lower prices.
The buy out payments have been recorded as regulatory assets, and will be
recovered, including a return, over the remaining term of the initial
contractual arrangements as Part 2 stranded costs. The estimated savings of
the negotiated buyout is approximately $5 million, of which PSNH is entitled
to retain 20 percent. PSNH's 20 percent of the savings amount will be
recognized as income over the remaining terms of the contracts.

Massachusetts:

Transition Cost Reconciliation: On March 31, 2003, WMECO filed its 2002
annual transition cost reconciliation with the 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. Proceedings in this docket are expected to begin in the
second half of 2003. Management does not expect the outcome of this docket
to have a material adverse impact on WMECO's net income or its financial
position.

Default Service: On May 21, 2003, the DTE approved WMECO's default service
price of $0.068 per kilowatt-hour (kWh) for the period July 1, 2003, through
December 31, 2003. For the period of January 1, 2003, through June 30, 2003,
WMECO's default service price was $0.051 per kWh.

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

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 June 30, 2003, the estimated fair value of Plan assets
exceeded the December 31, 2002 ABO by approximately $170 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.

Energy Trading and Derivative Accounting: In April 2003, the Financial
Accounting Standards Board (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
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 is evaluating the impacts of SFAS No. 149,
particularly the definition of "subject to unplanned netting." This could
impact Select Energy's wholesale marketing contracts that currently qualify
for the normal purchases and sales exception. Since most supply contracts
can be settled for cash, and most delivery contracts cannot, this could
result in asymmetrical accounting.

There are three potential outcomes for the implementation of the guidance in
SFAS No. 149. There could be no change in NU's accounting, and accrual
accounting would continue with earnings recorded as energy is delivered. A
second outcome could result in Select Energy's supply contracts being
recorded at fair value and being treated as cash flow hedges. Under this
outcome, the fair value of the contracts would be recorded as derivative
assets or liabilities with offsets recorded to accumulated other
comprehensive income, which is a component of equity. The third outcome
could be that Select Energy's supply contracts would be recorded at fair
value with changes in fair value impacting net income, but delivery contracts
would likely remain on accrual accounting.

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.

When implemented, DIG Issue No. C-20 may result in CL&P recording the fair
value of two existing contracts as derivative liabilities with offsetting
regulatory assets, as these contracts are part of stranded costs, and
management believes that these costs will continue to be recoverable in
rates.

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 second
quarter of 2003 and the first six months of 2003 are provided in the table
below.

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

Operating Revenues $316 28% $719 30%

Operating Expenses:
Fuel, purchased and
net interchange power 267 43 609 45
Other operation 32 16 24 6
Maintenance (5) (7) (12) (9)
Depreciation (3) (5) (6) (5)
Amortization 16 (a) 53 (a)
Amortization of rate reduction bonds 1 2 (6) (8)
Taxes other than income taxes (3) (6) (4) (3)
---- --- ---- ---
Total operating expenses 305 29 658 30
---- --- ---- ---

Operating income 11 12 61 29
---- --- ---- ---

Interest expense, net (10) (14) (13) (9)
Other income/(loss), net (1) (54) 14 (a)
---- --- ---- ---
Income before income tax expense 20 74 88 (a)
Income tax expense 22 (a) 48 (a)
Preferred dividends of subsidiaries - - - -
---- --- ---- ---
Net income $ (2) (7)% $ 40 83%
==== === ==== ===
(a) Percent greater than 100.

Comparison of the Second Quarter of 2003 to the Second Quarter of 2002

Operating Revenues
Total revenues increased $316 million or 28 percent in the second quarter of
2003, compared with the same period in 2002, due to higher revenues from NU
Enterprises ($284 million after intercompany eliminations) and higher Utility
Group revenues ($32 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 ($70 million), partially offset by
lower wholesale revenue ($37 million). The regulated retail revenue increase
is primarily due to CL&P's recovery of incremental LMP costs ($30 million),
higher Yankee revenue resulting from higher purchased gas adjustment clause
revenues ($18 million), increased sales volumes ($4 million) and higher price
mix among customer classes ($11 million) for the regulated companies.
Regulated retail electric kWh sales increased by 0.6 percent and firm natural
gas sales increased by 4.1 percent in the second quarter of 2003. 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 $267 million or
43 percent in the second quarter of 2003, primarily due to higher wholesale
energy purchases at NU Enterprises ($293 million after intercompany
eliminations), partially offset by lower purchased-power costs for the
Utility Group ($22 million after intercompany eliminations).

Other Operation
Other operation expense increased $32 million primarily due to higher
competitive business expenses resulting from business growth ($20 million),
higher RMR related transmission expense ($15 million), and higher regulated
business administrative and general expenses resulting from higher health
care costs and lower pension income ($8 million), partially offset by lower
nuclear expense resulting from the sale of Seabrook ($11 million).

Maintenance
Maintenance expense decreased $5 million primarily due to lower nuclear
expense resulting from the sale of Seabrook ($14 million), partially offset
by higher fossil production expenses resulting from maintenance overhauls ($5
million) and higher electric distribution and transmission expense ($3
million).

Depreciation
Depreciation decreased $3 million in 2003 primarily due to lower
decommissioning and depreciation expenses, resulting from the sale of
Seabrook in the last quarter of 2002 ($3 million).

Amortization
Amortization increased $16 million in 2003, primarily due to higher
amortization related to the Utility Group's recovery of stranded costs ($18
million), partially offset by the decrease in amortization of C&LM incentives
($1 million).

Interest Expense, Net
Interest expense, net decreased $10 million primarily due to lower interest
at NU parent as a result of the interest rate swap related to its $263
million fixed-rate senior notes ($7 million), lower CL&P interest resulting
from lower rates ($2 million) and lower North Atlantic Energy Corporation
(NAEC) interest due to the retirement of debt ($1 million), partially offset
by higher competitive businesses interest as a result of higher debt levels
($1 million).

Income Tax Expense
Income tax expense increased $22 million due to higher taxable income and the
recording in 2002 of WMECO investment tax credits resulting from a regulatory
decision ($13 million).

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

Operating Revenues
Total revenues increased $719 million or 30 percent in the first six months
of 2003, compared with the same period in 2002, due to higher revenues from
NU Enterprises ($515 million after intercompany eliminations) and higher
Utility Group revenues ($205 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 ($189 million) and higher wholesale
revenue ($17 million). The regulated retail revenue increase is primarily
due to higher retail electric sales volumes ($79 million), higher CL&P
recovery of incremental LMP costs ($30 million), higher Yankee revenue
resulting from higher purchased gas adjustment clause revenue ($44 million)
and higher sales volumes ($29 million), and higher price mix among customer
classes for the regulated companies ($5 million). Regulated retail electric
kWh sales increased by 4.9 percent and firm natural gas sales increased by
13.6 percent in 2003. The regulated wholesale revenue increase is primarily
due to higher prices in 2003, partially offset by lower PSNH 2003 sales as a
result of less owned generation since the sale of Seabrook.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased $609 million or
45 percent in 2003, primarily due to higher wholesale energy purchases at NU
Enterprises ($550 million after intercompany eliminations) and higher
purchased-power costs for the Utility Group ($67 million after intercompany
eliminations), primarily due to Yankee Gas' higher sales and higher gas
prices ($59 million).

Other Operation
Other operation expense increased $24 million primarily due to higher RMR
related transmission expense ($14 million), higher regulated business
administrative and general expenses resulting from higher health care costs
and lower pension income ($15 million), and higher competitive business
expenses resulting from business growth ($6 million), partially offset by
lower nuclear expense resulting from the sale of Seabrook ($20 million).

Maintenance
Maintenance expense decreased $12 million primarily due to lower nuclear
expense resulting from the sale of Seabrook ($22 million) partially offset by
hydroelectric and fossil production expenses resulting from maintenance
overhauls ($5 million) and higher electric distribution and transmission
expenses ($6 million).

Depreciation
Depreciation decreased $6 million in 2003 primarily due to lower
decommissioning and depreciation expenses resulting from the sale of Seabrook
in the last quarter of 2002 ($5 million), lower NU Enterprises' depreciation
resulting from 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 $53 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 IPP related
energy.

Interest Expense, Net
Interest expense, net decreased $13 million primarily due to lower interest
at NU parent as a result of the interest rate swap related to its $263
million fixed-rate senior notes ($5 million), lower interest for the
regulated subsidiaries resulting from lower rates ($6.5 million) and lower
NAEC interest due to the retirement of debt ($2 million), partially offset by
higher competitive businesses interest as a result of higher debt levels ($1
million).

Other Income/(Loss), Net
Other income/(loss), net increased $14 million primarily due to a charge in
the first quarter of 2002 reflecting a write-down of NU's investments in NEON
and Acumetrics ($15 million).

Income Tax Expense
Income tax expense increased $48 million due to higher taxable income and the
recording in 2002 of WMECO investment tax credits resulting from a regulatory
decision ($13 million).

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 June 30, 2003, and
the related condensed consolidated statements of income for the three-month
and six-month periods ended June 30, 2003 and 2002, and of cash flows for the
six-month periods ended June 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
August 8, 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 Form 10-Q, the First Quarter 2003
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 May 14, 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 June 30, 2003, the results
of operations for the three-month and six-month periods ended
June 30, 2003 and 2002, and statements of cash flows for the six-
month periods ended June 30, 2003 and 2002. All adjustments are of
a normal, recurring nature except those described in Note 4A. Due
primarily to the seasonality of NU's business, the results of
operations and statements of cash flows for the six-month periods
ended June 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 and Assets

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 the
application of SFAS No. 71 to that portion of those businesses
continues to be appropriate. Management also believes 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 NU's regulatory assets are
as follows:

---------------------------------------------------------------------
June 30, December 31,
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Recoverable nuclear costs $ 136.3 $ 85.4
Securitized regulatory assets 1,808.7 1,891.8
Income taxes, net 278.9 331.9
Unrecovered contractual
obligations 231.5 239.3
Recoverable energy costs, net 309.0 299.6
Other 228.9 228.1
---------------------------------------------------------------------
Totals $2,993.3 $3,076.1
---------------------------------------------------------------------

Additionally, the Utility Group maintained $396 million and $136.5
million of regulatory liabilities at June 30, 2003 and December 31,
2002, respectively, primarily associated with CL&P's Competitive
Transition Assessment, Generation Services Charge and System
Benefits Charge 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.

C. New Accounting Standards

Energy Trading and Risk Management Activities: In October 2002, the
Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) reached consensuses on EITF Issue No. 02-3,
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities."

One consensus rescinded EITF Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities
for Energy Trading Activities," under which Select Energy, Inc.
(Select Energy) previously accounted for energy trading activities.
This consensus requires companies engaged in energy trading
activities to discontinue fair value accounting effective January 1,
2003, for contracts that do not meet the definition of a
derivative. NU adopted this consensus effective October 1, 2002.

The second consensus requires that companies engaged in energy
trading activities classify revenues and expenses associated with
energy trading contracts on a net basis in revenues effective
January 1, 2003. NU decided to transition to net reporting
effective July 1, 2002, before this consensus was reached by the
EITF.

The three-month and six-month periods ended June 30, 2002, reflect
net reporting. The effects of this reporting for the three-month
and six-month periods ended June 30, 2002, which have been
previously reported, are as follows:

---------------------------------------------------------------------
Operating Fuel, Purchased and
(Millions of Dollars) Revenues Net Interchange Power
---------------------------------------------------------------------
Three Months Ended June 30, 2002:
---------------------------------------------------------------------
Operating Revenues:
As previously
reported $1,673.2 $1,158.4
---------------------------------------------------------------------
Impact of
reclassification (531.3) (531.3)
---------------------------------------------------------------------
As currently
reported $1,141.9 $ 627.1
---------------------------------------------------------------------
Six Months Ended June 30, 2002:
---------------------------------------------------------------------
Operating Revenues:
As previously
reported $3,583.9 $2,511.2
Impact of
reclassification (1,157.5) (1,157.5)
---------------------------------------------------------------------
As currently
reported $2,426.4 $1,353.7
---------------------------------------------------------------------

In July 2003, the EITF reached a consensus on Issue No. 03-11,
"Reporting Realized 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 Involved in
Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management
Activities"." The EITF did not change any existing accounting
guidance and did not introduce new guidance addressing this issue.

Derivative Accounting: Effective January 1, 2001, NU adopted SFAS
No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended. In April 2003, the 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
is evaluating the impacts of SFAS No. 149, particularly the
definition of "subject to unplanned netting." This could impact
Select Energy's wholesale marketing contracts that currently
qualify for the normal purchases and sales exception.

On June 25, 2003 the DIG cleared Issue No. C-20 "Interpretation of
the Meaning of Not Clearly and Closely Related in Paragraph 10(b)
regarding Contracts with a Price Adjustment Feature." Management
is evaluating the impact of DIG Issue No. C-20 on the consolidated
financial statements, but does not believe that there will be a
significant impact as a result of this issue. DIG Issue No. C-20
is effective for NU on October 1, 2003.

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, management currently
does not expect the adoption of SFAS No. 150 to 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, June 30, June 30,
except per share amounts) 2003 2002
---------------------------------------------------------------------
Net income, as reported $26.9 $28.9
Total stock-based employee
compensation expense
determined under
fair value-based method for
all awards, net of related
tax effects (0.6) (1.1)
---------------------------------------------------------------------
Pro forma net income $26.3 $27.8
---------------------------------------------------------------------
Earnings per share:
Basic and fully
diluted - as reported $ 0.21 $ 0.22
Basic and fully
diluted - pro forma $ 0.21 $ 0.21
---------------------------------------------------------------------

---------------------------------------------------------------------
For the Six Months Ended
---------------------------------------------------------------------
(Millions of Dollars, June 30, June 30,
except per share amounts) 2003 2002
---------------------------------------------------------------------
Net income, as reported $87.1 $47.5
Total stock-based employee
compensation expense
determined under
fair value-based method for
all awards, net of related
tax effects (1.2) (2.2)
---------------------------------------------------------------------
Pro forma net income $85.9 $45.3
---------------------------------------------------------------------
Earnings per share:
Basic and fully
diluted - as reported $ 0.69 $ 0.37
Basic and fully
diluted - pro forma $ 0.68 $ 0.35
---------------------------------------------------------------------

During the six-month period ended June 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 to shareholders' equity.
For the six months ended June 30, 2003, approximately $0.8 million
was expensed related to the restricted stock. During the six-month
period ended June 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 Six Months Ended
---------------------------------------------------------------------
June 30, June 30,
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Investment write-downs $ - $(17.1)
Investment income 7.9 10.4
Other, net (6.6) (5.6)
---------------------------------------------------------------------
Totals $ 1.3 $(12.3)
---------------------------------------------------------------------

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 June 30, 2003, CL&P had sold accounts
receivable of $50 million to the financial institution with limited
recourse through CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. Additionally, at June 30, 2003, $4.8 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 June 30, 2003, amounts sold to CRC from CL&P but not sold to the
financial institution totaling $146.5 million are included in
investments in securitizable assets on the accompanying
consolidated balance sheets. 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 one year.

G. Guarantees

In November 2002, the FASB issued FASB Interpretation No. (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. At June 30, 2003, the maximum level
of exposure under guarantees by NU, primarily on behalf of NU
Enterprises, totaled $421.8 million. The majority of the
guarantees to NU Enterprises are for Select Energy. Additionally,
NU had $10.2 million of letters of credit issued for the benefit of
NU Enterprises outstanding at June 30, 2003. In conjunction with
its investment in R.M. Services, Inc., NU guarantees a $3 million
line of credit through 2005, of which $0.5 million was outstanding
at June 30, 2003 and is included in the $421.8 million.

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 the DPUC's
order. At June 30, 2003, NU guaranteed $42.8 million of surety
bonds for NU subsidiaries, including the LMP-related surety bonds.
The $42.8 million is included in NU's total guarantees of $421.8
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 September 30, 2003, and has applied for
authority to increase this amount to $750 million through
September 30, 2005. NU has also applied to the SEC for authority to
extend the $500 million limit to June 30, 2004 in the event the SEC
does not act on the $750 million request by September 30, 2003. The
aforementioned surety bonds are subject to a separate $50 million
SEC limitation apart from the $500 million guarantee limit. The
amount of guarantees outstanding for compliance with the SEC limit
is approximately $283 million, which is calculated using different
criteria than the maximum level of exposure of $421.8 million
required to be disclosed under FIN 45. The $42.8 million of surety
bonds is the same for SEC and FIN 45 purposes.

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.
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 and will result in physical delivery, 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 six months of 2003, a negative $9 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 transaction was also
recognized in net income. A negative $0.3 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 second 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 $13.9 million, net of tax. Accumulated other comprehensive
income at June 30, 2003, was a positive $1.6 million, net of tax
(increase to equity), relating to hedged transactions, and it is
estimated that $0.4 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
June 30, 2003 and December 31, 2002. These amounts do not include
premiums paid, which are recorded as prepayments and amounted to
$24.8 million and $26.7 million at June 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 $20.3 million and $33.9 million at June 30, 2003 and
December 31, 2002, respectively. The premium amounts relate
primarily to energy trading activities.

---------------------------------------------------------------------
At June 30, 2003
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
Select Energy:
Trading $141.0 $ (96.0) $45.0
Nontrading 2.9 (0.5) 2.4
Hedging 14.8 (10.8) 4.0
---------------------------------------------------------------------
Yankee Gas:
Hedging 3.6 - 3.6
---------------------------------------------------------------------
NU Parent:
Hedging 12.0 - 12.0
---------------------------------------------------------------------
Total $174.3 $(107.3) $67.0
---------------------------------------------------------------------

---------------------------------------------------------------------
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
marketing business, Select Energy conducts 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 exposure. 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 June 30, 2003 and December 31, 2002 were
assets of $45 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; 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 an option
component of a bilateral energy purchase contract, the fair value
of which is determined with the Blacks option pricing model.
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 $9.1 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 marketing 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 at June
30, 2003 and December 31, 2002 were assets of $2.4 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 June 30, 2003, the NYMEX futures
contracts had notional values of $26.7 million and were recorded at
fair value as a derivative asset of $3.4 million, net of tax.

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 June 30, 2003, the
commodity swap agreement had a notional value of $8.2 million and
was recorded at fair value as a derivative asset of $3.6 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 change in the fair value of the hedged debt of $12
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.

On April 28, 2003, NU parent entered into a derivative to
effectively lock the United States Treasury component of the
interest rate on $125 million of its $150 million five-year fixed
rate notes that were issued on June 3, 2003. As interest rates
have declined since the notes were priced and the hedge was
terminated on May 29, 2003, NU parent paid $3.9 million to the
counterparties and included a loss of $3.9 million in accumulated
other comprehensive income. The $3.9 million will be amortized to
interest expense over the five-year term of the notes.

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 June 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 $1.2 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 and Wholesale Marketing 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 quoted prices on the futures
exchange.

Select Energy has determined a hypothetical change in the fair
value for its retail and wholesale marketing 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 June 30, 2003, a 10 percent change in
market price would have resulted in an increase or decrease in fair
value of approximately $7.1 million.

The impact of a change in electricity, natural gas and oil prices
on Select Energy's retail and wholesale marketing portfolio at
June 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 June 30,
2003, approximately 80 percent (69 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 June 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 June 30, 2003, Select Energy maintained collateral balances from
counterparties of $39.6 million. This amount is included in
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.
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.
There were no impairments or adjustments to the goodwill balances during
the six-month periods ended June 30, 2003 and 2002.

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 marketing
reporting unit, 2) the retail marketing reporting unit, and 3) the
services reporting unit. The wholesale marketing and retail marketing
reporting units are comprised of the operations of Select Energy,
Northeast Generation Company (NGC) and 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 Services, Inc. (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 marketing 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 June 30, 2003, NU maintained $321 million of goodwill that is no
longer being amortized, $16.3 million of identifiable intangible assets
and $6.8 million of intangible assets not subject to amortization,
totaling $344.1 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 June 30, 2003 and December 31, 2002, by reportable segment and
reporting unit is as follows:

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

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

--------------------------------------------------------------------------
At June 30, 2003
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $5.9 $11.8
Customer list 6.6 2.2 4.4
Customer backlog and
employment related
agreements 0.1 - 0.1
--------------------------------------------------------------------------
Totals $24.4 $8.1 $16.3
--------------------------------------------------------------------------
Intangible assets not
subject
to amortization:
Customer relationships $ 3.8
Tradenames 3.0
-------------------------------------------------
Totals $ 6.8
-------------------------------------------------

--------------------------------------------------------------------------
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 and
employment related
agreements 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 $1.8 million and $0.8 million for
the six months ended June 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. Utility Group Restructuring and Rate Matters (CL&P, PSNH, WMECO)

Connecticut: On March 1, 2003, the New England Independent System
Operator 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
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 that these
costs should be paid for by customers.

CL&P incurred $62 million of incremental LMP costs from March 1,
2003 through June 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 $30 million has
been recovered through June 30, 2003. This amount is included in
operating revenues and offset by amortization.

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 six months ended June 30,
2003 would be reduced by approximately $35 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 to NU's and NU Enterprises'
net income, but there would be no impact on CL&P's net income.

New Hampshire: 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. Hearings in
this docket are scheduled for October 2003 with an order expected
by the end of 2003. Management does not expect the outcome of this
docket to have a material adverse impact on PSNH'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. Proceedings in this docket are
expected to begin in the second half of 2003. 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 various transactions with subsidiaries of NRG
Energy, Inc. (NRG). On May 14, 2003, NRG filed a voluntary
bankruptcy petition. 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' and NGS' capital expenditures that were
incurred related to NRG's generating plant that is now abandoned.
While it is unable to determine the ultimate outcome of these
issues, management does not expect that the resolution of the
transactions with NRG will have a material adverse effect on NU's
consolidated financial condition or results of operations. For
further information, see Part II, Item 1, "Legal Proceedings,"
included in this combined report on Form 10-Q.

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 $5.4 billion at June 30,
2003 as follows (millions of dollars):

---------------------------------------------------------------------
Year
---------------------------------------------------------------------
2003 $2,667.8
2004 1,657.0
2005 594.3
2006 260.0
2007 221.4
---------------------------------------------------------------------
Total $5,400.5
---------------------------------------------------------------------

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.

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

Total comprehensive income, which includes all comprehensive income
items, is as follows:

--------------------------------------------------------------------------
Six Months Ended June 30,
--------------------------------------------------------------------------
(Millions of Dollars) 2003 2002
--------------------------------------------------------------------------
NU consolidated $73.9 $81.4
CL&P 30.1 30.4
PSNH 21.9 26.5
WMECO 8.7 22.2
--------------------------------------------------------------------------

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

--------------------------------------------------------------------------
June 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 (9.0) 17.0
Change in fair value 2.3 29.2
Cash flow transactions entered
into for the period (7.2) 6.2
--------------------------------------------------------------------------
Net change associated with the
current period hedging transactions (13.9) 52.4
--------------------------------------------------------------------------
Total fair value adjustments included
in accumulated other
comprehensive income $ 1.6 $ 15.5
--------------------------------------------------------------------------

Accumulated other comprehensive income items unrelated to NU's qualified
cash flow hedging instruments totaled $0.2 million in gains and $0.6
million in losses at June 30, 2003 and December 31, 2002, respectively.
These amounts relate to unrealized gains and losses on investments in
marketable debt and equity instruments.

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, Six Months Ended June 30,
except share information) 2003 2002
--------------------------------------------------------------------------
Income before preferred
dividends of subsidiaries $89.9 $50.3
Preferred dividends
of subsidiaries 2.8 2.8
--------------------------------------------------------------------------
Net income $87.1 $47.5
--------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 126,880,397 129,590,899
Dilutive effect of employee
stock options 102,506 280,596
--------------------------------------------------------------------------
Fully diluted EPS common shares
outstanding (average) 126,982,903 129,871,495
--------------------------------------------------------------------------
Basic and fully diluted EPS $0.69 $0.37
--------------------------------------------------------------------------

7. SEGMENT INFORMATION (NU)

NU is organized between the Utility Group and NU Enterprises based on
the regulatory environment of each segment. The Utility Group segment,
including both electric and gas utilities, represents approximately 70
percent and 83 percent of NU's total revenues for the six months ended
June 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. 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 $349 million or 26 percent for the six months ended June
30, 2003 and approximately $304 million or 42 percent for the six months
ended June 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 $213.7
million or 16 percent of total NU Enterprises' revenues for the six
months ended June 30, 2003. Additionally, WMECO's purchases from Select
Energy represented approximately $68.2 million and $1.3 million of total
NU Enterprises' revenues for the six months ended June 30, 2003 and
2002, respectively. No other individual customer represented in excess
of 10 percent of NU Enterprises' revenues for the six months ended
June 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. 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.

- ---------------------------------------------------------------------------
For the Three Months Ended June 30, 2003
- ---------------------------------------------------------------------------
Utility Group Eliminations
(Millions of ------------- NU and
Dollars) Electric Gas Enterprises Other Total
- ---------------------------------------------------------------------------
Operating
revenues $923.8 $ 72.2 $665.7 $(204.2) $1,457.5
Depreciation and
amortization (95.8) (5.8) (5.3) (0.6) (107.5)
Other operating
expenses (752.3) (66.9) (629.6) 203.9 (1,244.9)
- ---------------------------------------------------------------------------
Operating
income/(loss) 75.7 (0.5) 30.8 (0.9) 105.1
Interest
expense, net (42.9) (3.4) (12.0) (1.2) (59.5)
Other (loss)/
income, net (0.1) (0.5) 2.4 (1.0) 0.8
Income tax
(expense)/
benefit (12.7) 1.5 (9.3) 2.4 (18.1)
Preferred
dividends (1.4) - - - (1.4)
- ---------------------------------------------------------------------------
Net income/
(loss) $ 18.6 $ (2.9) $ 11.9 $ (0.7) $ 26.9
- ---------------------------------------------------------------------------

- ---------------------------------------------------------------------------
For the Six Months Ended June 30, 2003
- ---------------------------------------------------------------------------
Utility Group Eliminations
(Millions of ------------- NU and
Dollars) Electric Gas Enterprises Other Total
- ---------------------------------------------------------------------------
Operating
revenues $1,989.2 $224.4 $1,355.5 $(423.1) $ 3,146.0
Depreciation and
amortization (230.7) (11.4) (10.2) (1.2) (253.5)
Other operating
expenses (1,567.6) (183.0) (1,294.5) 421.7 (2,623.4)
- ---------------------------------------------------------------------------
Operating
income /(loss) 190.9 30.0 50.8 (2.6) 269.1
Interest
expense, net (86.5) (6.6) (23.1) (6.8) (123.0)
Other (loss)/
income, net (0.5) (1.0) 2.9 (0.1) 1.3
Income tax
(expense)/
benefit (40.1) (9.4) (13.5) 5.5 (57.5)
Preferred
dividends (2.8) - - - (2.8)
- ---------------------------------------------------------------------------
Net income/
(loss) $ 61.0 $ 13.0 $ 17.1 $ (4.0) $ 87.1
- ---------------------------------------------------------------------------
Total assets $7,534.1 $953.2 $2,013.0 $ (80.6) $10,419.7
- ---------------------------------------------------------------------------
Total
investments
in plant $ 20l.1 $ 22.8 $ 8.2 $ 4.6 $ 236.7
- ---------------------------------------------------------------------------

- ---------------------------------------------------------------------------
For the Three Months Ended June 30, 2002
- ---------------------------------------------------------------------------
Utility Group Eliminations
(Millions of ------------- NU and
Dollars) Electric Gas Enterprises Other Total
- ---------------------------------------------------------------------------
Operating
revenues $915.7 $50.6 $323.3 $(147.7) $1,141.9
Depreciation and
amortization (82.3) (5.8) (5.1) (0.6) (93.8)
Other operating
expenses (735.7) (42.6) (322.7) 146.9 (954.1)
- ---------------------------------------------------------------------------
Operating
income/(loss) 97.7 2.2 (4.5) (1.4) 94.0
Interest
expense, net (46.1) (3.6) (10.7) (8.6) (69.0)
Other (loss)/
income, net (0.9) 0.4 0.3 1.9 1.7
Income tax
(expense)/
benefit (5.8) 0.4 5.7 3.3 3.6
Preferred
dividends (1.4) - - - (1.4)
- ---------------------------------------------------------------------------
Net income/
(loss) $ 43.5 $(0.6) $ (9.2) $ (4.8) $ 28.9
- ---------------------------------------------------------------------------

- ---------------------------------------------------------------------------
For the Six Months Ended June 30, 2002
- ---------------------------------------------------------------------------
Utility Group Eliminations
(Millions of ------------- NU and
Dollars) Electric Gas Enterprises Other Total
- ---------------------------------------------------------------------------
Operating
revenues $1,856.3 $154.9 $724.6 $(309.4) $2,426.4
Depreciation and
amortization (187.0) (12.4) (11.9) (1.1) (212.4)
Other operating
expenses (1,458.1) (115.2) (737.8) 305.4 (2,005.7)
- ---------------------------------------------------------------------------
Operating
income /(loss) 211.2 27.3 (25.1) (5.1) 208.3
Interest
expense, net (93.9) (7.4) (21.8) (12.8) (135.9)
Other income/
(loss), net 2.2 (0.1) (0.6) (13.8) (12.3)
Income tax
(expense)/
benefit (33.4) (7.9) 17.8 13.7 (9.8)
Preferred
dividends (2.8) - - - (2.8)
- ---------------------------------------------------------------------------
Net income/
(loss) $ 83.3 $ 11.9 $(29.7) $ (18.0) $ 47.5
- ---------------------------------------------------------------------------
Total
investments
in plant $ 168.3 $ 20.6 $ 13.9 $ 9.7 $ 212.5
- ---------------------------------------------------------------------------

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

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

CL&P is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, the NU 2002
Form 10-K, and the current report on Form 8-K dated May 14, 2003.

RESULTS OF OPERATIONS

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

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

Operating Revenues $ 34 6% $135 11%

Operating Expenses:
Fuel, purchased and
net interchange power 9 3 70 10
Other operation 22 28 28 19
Maintenance 3 17 (1) (1)
Depreciation - - 2 4
Amortization of regulatory
assets, net 5 27 35 (a)
Amortization of rate reduction bonds 2 11 2 4
Taxes other than income taxes - - 1 1
---- ---- ---- ----
Total operating expenses 41 8 137 13
---- ---- ---- ----

Operating income (7) (16) (2) (2)
---- ---- ---- ----

Interest expense, net (2) (6) (3) (6)
Other income, net (2) (55) (4) (68)
Income before income tax expense (7) (38) (3) (5)
Income tax expense (2) (23) (3) (12)
---- ---- ---- ----
Net income $ (5) (47)% $ - -%
==== ==== ==== ====

(a) Percent greater than 100.

Comparison of the Second Quarter of 2003 to the Second Quarter of 2002

Operating Revenues
Operating revenues increased $34 million or 6 percent in the second 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 ($30 million).

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased by $9 million or
3 percent in the second quarter of 2003, compared with the same period in
2002, primarily due to costs associated with SMD.

Other Operation and Maintenance
Other operation and maintenance (O&M) expenses increased $25 million in the
second quarter of 2003, compared with the same period in 2002, primarily due
to higher reliability must run (RMR) related transmission costs ($15
million), higher distribution costs ($5 million) and higher administrative
costs resulting from higher healthcare costs and lower pension income ($5
million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $5 million primarily
due to higher amortization related to the recovery of stranded costs ($15
million), partially offset by lower amortization of recoverable nuclear costs
($8 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 $2 million primarily due to lower conservation
and load management (C&LM) incentive income.

Income Tax Expense
Income tax expense decreased $2 million primarily due to lower book taxable
income.

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

Operating Revenues
Operating revenues increased by $135 million or 11 percent in 2003, compared
with the same period in 2002, primarily due to higher retail revenues ($77
million) and higher wholesale revenues ($55 million). Retail revenues were
higher primarily due to the collection of incremental LMP costs beginning in
May 2003 ($30 million) and higher retail sales ($48 million). Retail
kilowatt-hour (kWh) sales increased by 4.4 percent in 2003, of which 2.7
percent was related to weather. 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 $70 million or 10
percent in 2003, primarily due to incremental LMP costs which were recovered
from customers ($30 million) and higher standard offer purchases as a result
of higher retail sales.

Other Operation and Maintenance
Other O&M expenses increased by $27 million primarily due to higher RMR
related transmission costs ($14 million), higher administrative costs
resulting from higher healthcare costs and lower pension income ($10 million)
and higher transmission and distribution expenses ($12 million), partially
offset by lower related nuclear expenses ($10 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 $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 increased $35 million
primarily due to higher amortization related to the recovery of stranded
costs ($58 million), partially offset by lower amortization of recoverable
nuclear costs ($22 million).

Interest Expense, Net
Interest expense, net decreased $3 million primarily due to lower interest on
rate reduction bonds.

Other Income, Net
Other income, net decreased $4 million primarily due to lower interest and
dividend income ($1 million), lower C&LM incentive income ($1 million), and
higher charitable donations made in 2003 ($1 million).

Income Tax Expense
Income tax expense decreased $3 million primarily due to lower book taxable
income.

LIQUIDITY

At June 30, 2003, CL&P had no borrowings outstanding on the Utility Group's
$300 million revolving credit line. This credit line matures on November 11,
2003 and management anticipates extending this credit line.

CL&P has been put on a negative outlook by Moody's Investor Services.
On July 9, 2003, CL&P renewed an agreement for one year under which it can
access up to $100 million by selling certain of its accounts receivable and
unbilled revenues. At June 30, 2003, CL&P had $50 million of accounts
receivable and unbilled revenues sold under this arrangement. For more
information regarding CL&P's accounts receivable facility, see Note 1F, "Sale
of Customer Receivables," to the consolidated financial statements.

Through June 30, 2003, CL&P has 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 has
positively impacted CL&P's liquidity. In July 2003, CL&P began depositing
these recoveries into an escrow account. Accordingly, further recovery of
these costs will not impact CL&P's liquidity. When the issue of
responsibility for incremental LMP costs is resolved, which is expected to be
in early 2004, 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.

CL&P's net cash flows provided by operating activities increased to $209.2
million for the six months ended June 30, 2003 from $161.8 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.

CL&P's net cash flows used in investing activities increased to $124.1
million for the first six months of 2003 from $44.2 million for the same
period in 2002. The increase is primarily due to lower NU system Money Pool
borrowings in 2003.

Financing activities decreased in 2003 as a result of the repurchase of
common shares in 2002.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

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

PSNH is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, and the NU
2002 Form 10-K.

RESULTS OF OPERATIONS

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

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

Operating Revenue $(29) (12)% ($14) (3)%

Operating Expenses:
Fuel, purchased and
net interchange power (36) (24) (18) (7)
Other operation 6 18 5 7
Maintenance 4 23 5 15
Depreciation - - 1 5
(Overrecovery)/amortization
of regulatory assets, net 7 32 9 (a)
Amortization of rate reduction bonds (2) (15) (8) (30)
Taxes other than income taxes (1) (9) (1) (8)
---- ---- ---- ----
Total operating expenses (22) (10) (7) (2)
---- ---- ---- ----

Operating Income (7) (20) (7) (10)
---- ---- ---- ----

Interest expense, net - - (2) (7)
Other loss, net - - (1) (a)
---- ---- ---- ----
Income before income tax expense (7) (29) (6) (15)
Income tax expense (3) (31) (1) (8)
---- ---- ---- ----
Net income $ (4) (27)% $ (5) (19)%
==== ==== ==== ====
(a) Percent greater than 100.

Comparison of the Second Quarter of 2003 to the Second Quarter of 2002

Operating Revenues
Total operating revenues decreased $29 million or 12 percent in the second
quarter of 2003 compared with the same period of 2002, due to lower wholesale
revenues primarily due to the impact of less owned generation since the sale
of Seabrook ($39 million), partially offset by higher retail revenue ($11
million). Retail kWh sales increased by 3.6 percent in 2003.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $36 million
primarily due to lower purchased power expenses as a result of the absence of
Seabrook Power contracts costs and lower wholesale sales.

Other Operation and Maintenance
Other O&M expenses increased $10 million primarily due to higher maintenance
costs resulting from fossil production maintenance overhauls
($6 million) and higher administrative cost primarily resulting from higher
healthcare costs and lower pension income expense ($5 million), partially
offset by lower transmission and distribution expenses ($2 million).

(Overrecovery)/Amortization of Regulatory Assets, Net
(Overrecovery)/amortization of regulatory assets, net increased $7 million
primarily due to increased recovery of stranded costs resulting from the SCRC
reconciliation of stranded cost revenues against actual stranded costs.

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

Taxes Other Than Income Taxes
Taxes other than income taxes decreased $1 million primarily due to lower
property tax.

Income Tax Expense
Income tax expense decreased $3 million primarily due to lower book taxable
income.

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

Operating Revenues
Total operating revenues decreased $14 million or 3 percent in the first six
months of 2003 compared with the same period of 2002, due to lower wholesale
revenues ($44 million), primarily due to the impact of less owned generation
since the sale of Seabrook, partially offset by higher retail revenue ($31
million). Retail kWh sales increased by 5.9 percent in 2003.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense decreased $18 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 $10 million primarily due to higher maintenance
costs resulting from fossil production maintenance overhauls ($6 million) and
higher administrative cost primarily resulting from lower pension income ($5
million), partially offset by lower transmission and distribution expenses
($3 million).

Depreciation
Depreciation increased $1 million primarily due to additions to distribution,
generation and general plant assets.

(Overrecovery)/Amortization of Regulatory Assets, Net
(Overrecovery)/amortization of regulatory assets, net increased $9 million
primarily due to increased recovery of stranded costs resulting from the SCRC
reconciliation of stranded cost revenues against actual stranded costs.

Amortization of Rate Reduction Bonds
Amortization of rate reduction bonds decreased $8 million due to the
scheduled amortization of principal.

Taxes Other Than Income Taxes
Taxes other than income taxes decreased $1 million primarily due to lower
property tax.

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

Other Loss, Net
Other loss, net decreased $1 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 book taxable
income.

LIQUIDITY

At June 30, 2003, PSNH had no borrowings outstanding on the Utility Group's
$300 million revolving credit line. This credit line matures on November 11,
2003 and management anticipates extending this credit line.

Effective May 31, 2003, PSNH bought out the power purchase obligations of 14
small independently owned hydroelectric plants in New Hampshire for $20.4
million paid from cash flows from operations. The buy out payments have been
recorded as regulatory assets, and will be recovered, including a return,
over the remaining term of the initial contractual arrangements as Part 2
stranded costs.

PSNH's net cash flows used in operating activities totaled $6.8 million for
the six months ended June 30, 2003, compared with net cash flows provided by
operating activities of $65.5 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 provided by investing activities were $26.4 million for
the six months ended June 30, 2003 compared with net cash flows used in
investing activities of $43.8 million for the same period in 2002. The
change is primarily due to higher NU system Money Pool borrowings in 2003.

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

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

WMECO is a wholly owned subsidiary of NU. This discussion should be read in
conjunction with NU's management's discussion and analysis of financial
condition and results of operations, consolidated financial statements and
footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, and the NU
2002 Form 10-K.

RESULTS OF OPERATIONS

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

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

Operating Revenues $ 3 3% $ 11 6%

Operating Expenses:
Fuel, purchased and
net interchange power 2 4 5 5
Other operation - - 3 12
Maintenance - - - -
Depreciation (1) (21) (1) (8)
Amortization of regulatory
assets, net 5 74 8 56
Amortization of rate reduction bonds - - - -
Taxes other than income taxes - - - -
---- --- ---- ---
Total operating expenses 6 7 15 10
---- --- ---- ---

Operating income (3) (29) (4) (16)
---- --- ---- ---

Interest expense, net - - - -
Other loss, net 2 91 3 93
---- --- ---- ---
Income before income tax
expense/(benefit) (1) (16) (1) (7)
Income tax expense/(benefit) 12 (a) 13 (a)
---- --- ---- ---
Net income $(13) (83)% $(14) (61)%
==== === ==== ===

(a) Percent greater than 100.

Comparison of the Second Quarter of 2003 to the Second Quarter of 2002

Operating Revenues
Operating revenues increased $3 million or 3 percent in 2003, compared with
the same period in 2002, due to higher retail revenues ($2 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 slightly higher sales. Retail kWh sales were 0.5 percent
higher. 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 $2 million
primarily due to higher standard offer purchases as a result of the higher
standard offer contract cost and the retail sales increase.

Depreciation
Depreciation expense decreased $1 million primarily due to the 2002
adjustment for certain software projects ($1 million).

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $5 million due to a
higher recovery of stranded costs through the stranded cost reconciliation.

Other Loss, Net
Other loss, net increased $2 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 ending
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 the 2002 DTE
stranded cost decision ($13 million).

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

Operating Revenues
Operating revenues increased by $11 million or 6 percent in 2003, compared
with the same period in 2002, due to higher retail revenues ($6 million) and
higher wholesale revenues ($5 million). Retail revenues were higher primarily
due to an increase in the standard offer component of retail delivery rates
and higher retail sales. Retail kWh sales were 5 percent higher. 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 $5 million
primarily due to higher standard offer purchases as a result of the retail
sales increase and the higher standard offer contract cost.

Other Operation
Other operation expenses increased $3 million primarily due to higher general
and administrative expenses resulting from higher healthcare costs and lower
pension income.

Depreciation
Depreciation expense decreased $1 million primarily due to the 2002
adjustment for certain software projects.

Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net expense increased $8 million primarily
due to the higher recovery of stranded costs through the stranded cost
reconciliation.

Other Loss, Net
Other 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 ending
December 31, 1999.

Income Tax Expense/(Benefit)
Income tax expense/(benefit) increased $13 million primarily due to the
recognition in 2002 of investment tax credits as a result of the 2002 DTE
decision.

LIQUIDITY

At June 30, 2003, WMECO had no borrowings outstanding on the Utility Group's
$300 million revolving credit line. This credit line matures on November 11,
2003 and management anticipates extending this credit line.

On June 27, 2003, the DTE issued an order allowing WMECO to issue up to $57.5
million of long-term securities on or before December 31, 2003 to refinance
short-term debt and cover issuance costs. WMECO is expected to issue that
debt in the second half of 2003.

WMECO's net cash flows provided by operating activities increased to $38.9
million for the first six months of 2003 from $13.6 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, offset by a decrease in net income of $13.6 million.

WMECO's net cash flows used in investing activities were $19.1 million for
the six months ended June 30, 2003, compared with net cash flows provided by
investing activities of $17.9 million for the same period of 2002. The
change is primarily due to lower NU system Money Pool borrowings in 2003.

Financing activities decreased in 2003 as a result of the repurchase of
common shares in 2002.

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. (Con Edison) v. NU - Merger Appeals and
Related Litigation

A. 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 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 had been 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.

B. Shareholders' Class Action

On May 16, 2003, a class action complaint was filed in the Supreme Court of
the State of New York on behalf of "all holders of shares of NU common stock
as of 4:00 pm on March 5, 2001," as third party beneficiaries of the Merger
Agreement seeking compensatory damages, plus interest and costs, against Con
Edison for breach of the Merger Agreement. The named plaintiff, Robert
Rimkoski, allegedly sold his NU shares on March 7, 2001, two days after Con
Edison's refusal to consummate the merger with NU was made public. NU was
not named as a party.

On June 4, 2003, NU filed a motion to intervene and request for stay of
proceedings in the shareholders' class action. Plaintiff Rimkoski has
requested that the decision on this motion be postponed pending the outcome
of his July 24, 2003 motion to intervene in the aforementioned District Court
case.

2. Millstone Station - Damage to Fish Population
Lawsuits

This litigation involves claims by four fisherman (Maderia, Medeiros,
Engelmann and Stepski) against Northeast Nuclear Energy Company (NNECO) and
Northeast Utilities Service Company in connection with the operation of
Millstone and the alleged damage to their fishing livelihood caused by
Millstone's operations as well as claims by a citizen group (Connecticut
Coalition Against Millstone) that the National Pollutant Discharge
Elimination System permit and related authorizations issued to Millstone by
the Connecticut Department of Environmental Protection were invalid and were
improperly transferred from NNECO to Dominion Nuclear Connecticut upon the
sale of Millstone in 2001.

On May 30, 2003, following an order by the court imposing sanctions on
plaintiffs relating to discovery issues, plaintiffs' counsel withdrew one of
the fisherman cases, claiming it was under duress as a result of coercion by
the defendants, their attorney and the court. On June 30, 2003, plaintiffs'
counsel requested defendants' consent to reopen the suit and waiver of court-
ordered sanctions. Defendants have objected to any such action. A decision
by the Connecticut Supreme Court is pending on plaintiffs appeal in the
permit transfer matter.

3. NRG - Credit Rating Status

On May 14, 2004, NRG and various affiliates filed for Chapter 11 protection
in the Federal District 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 Service 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 Federal Energy Regulatory Commission
(FERC) has directed NRG-PM to continue to perform under its SOS Agreement
until the FERC fully considers the matter.

On June 12, 2003, the District Court authorized NRG-PM to cease performance
under its SOS Agreement pending the District Court's final order on this
matter. On June 25, 2003, the FERC upheld its prior orders stating that the
terms of the SOS Agreement do not (at this time) authorize NRG-PM to
terminate the SOS Agreement and ordered that a hearing be convened. In the
interim, the FERC directed NRG-PM to continue to supply power to CL&P under
the SOS Agreement until the FERC determines whether NRG-PM's decision to
cease performance was justified. A decision on this matter is expected in
October 2003. On June 30, 2003, the District Court vacated its prior
decision and concluded that the FERC was the appropriate forum in which to
resolve the dispute concerning service under the SOS Agreement, and dismissed
NRG-PM's request for authorization to cease performance under the SOS
Agreement.

On July 3, 2003, NRG-PM petitioned the FERC to stay its June 25, 2003
decision and the FERC denied NRG-PM's motion on July 9, 2003. In addition,
on July 8, 2003, NRG-PM petitioned the United States Court of Appeals for the
D.C. Circuit to stay the FERC's June 25, 2003 decision ordering NRG-PM to
continue to perform under the SOS Agreement. On July 9, 2003, the Official
Committee of Unsecured Creditors in the NRG bankruptcy proceeding filed with
the United States Court of Appeals for the D.C. Circuit a petition for a writ
of mandamus or an injunction requesting that the court direct the FERC to
vacate its June 25, 2003 decision (FERC Decision) or to stay the FERC
Decision. On July 16, 2003, the United States Court of Appeals for the D.C.
Circuit (i) denied NRG's motion to stay the FERC Decision and (ii) denied the
Official Committee of Unsecured Creditor's petition for a writ of mandamus or
an injunction.

On July 18, 2003, NRG-PM filed with the Second Circuit Court of Appeals (i)
an appeal of the United States District Court's June 30, 2003 order and (ii)
an emergency request for an injunction of the FERC Decision pending the
Second Circuit's review of the appeal. On July 18, 2003, the Official
Committee of Unsecured Creditors also filed with the Second Circuit Court of
Appeals an emergency motion asking that court to stay the FERC Decision. On
July 28, 2003, CL&P filed its opposition to the motions of NRG-PM and the
Official Committee of Unsecured Creditors.

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
Connecticut Department of Public Utility Control (DPUC) for a declaratory
order enforcing the FERC's December 20, 2002 decision. The DPUC proceeding is
pending, and is currently stayed due to the bankruptcy filing.

On June 19, 2003, CL&P petitioned the Bankruptcy Court for relief from the
automatic stay provision of the Bankruptcy Code so that CL&P could continue
to pursue declaratory relief from the DPUC. NRG is scheduled to file its
response to CL&P's petition on July 24, 2003, and a hearing on this matter
has been scheduled for August 6, 2003.

For additional information on certain matters involving NRG and its
affiliates, see "Management's Discussion and Analysis of Financial Condition
- - NRG Exposures" and Note 4B, "NRG Energy, Inc. Exposures," within the notes
to consolidated financial statements included in this combined report on Form
10-Q; "Part II, Item 1. Legal Proceedings" in NU's report on Form 10-Q for
the quarter ended March 31, 2003; "Part I, Item 1. Business - Rates and
Electric Industry Restructuring - Connecticut Rates and Restructuring" and
"Part I, Item 3. Legal Proceedings" in NU's 2002 annual report on Form 10-K.

4. Connecticut Yankee Atomic Power Company Decommissioning Dispute

On June 13, 2003, Connecticut Yankee Atomic Power Company (CYAPC) gave notice
of the termination of its contract with Bechtel Power Corporation (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. CYAPC's response to the
complaint was due by August 7, 2003.

NU's operating subsidiaries collectively own 49 percent of CYAPC, as follows:
CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

NU. At the Annual Meeting of Shareholders of NU held on May 13, 2003 the
following eleven nominees were elected to serve on the Board of Trustees by
the votes set forth below:

For Withheld Total

1. Richard H. Booth 100,216,327 6,103,987 106,320,314
2. Cotton M. Cleveland 85,248,207 21,072,107 106,320,314
3. Sanford Cloud, Jr. 102,882,936 3,437,378 106,320,314
4. James F. Cordes 102,973,312 3,347,002 106,320,314
5. E. Gail de Planque 100,133,434 6,186,880 106,320,314
6. John H. Forsgren 102,821,277 3,499,037 106,320,314
7. John G. Graham 102,832,280 3,488,034 106,320,314
8. Elizabeth T. Kennan 100,063,326 6,256,988 106,320,314
9. Michael G. Morris 102,277,455 4,042,859 106,320,314
10. Robert E. Patricelli 102,815,001 3,505,313 106,320,314
11. John F. Swope 100,116,272 6,204,042 106,320,314

NU's shareholders also ratified the Board of Trustees' selection of Deloitte
& Touche LLP to serve as independent auditors of NU and its subsidiaries for
2003. The vote ratifying such selection was 101,371,839 votes in favor and
4,362,344 votes against, with 586,131 abstentions and broker nonvotes.

NU's shareholders also voted to amend the Declaration of Trust of Northeast
Utilities to eliminate the provision calling for Northeast Utilities to
appoint a transfer agent and registrar for the common shares to be located in
Boston, Massachusetts. The vote approving such amendment was 103,806,356
votes in favor and 1,492,217 votes against, with 1,021,741 abstentions and
broker nonvotes.

NU's shareholders also voted to re-approve the material terms of the
performance goals under the Northeast Utilities Incentive Plan. The vote of
such re-approval was 97,918,833 votes in favor and 7,102,173 votes against,
with 1,299,308 abstentions and broker nonvotes.

CL&P. In a written Consent in Lieu of an Annual Meeting of Stockholders of
CL&P (Consent) dated June 18, 2003, stockholders voted to fix the number of
directors for the ensuing year at three. The vote fixing the number of
directors at three was 6,035,205 shares in favor, representing 100 percent of
the issued and outstanding shares of common stock of CL&P. Through the
Consent, the following three directors were elected, each by a vote of
6,035,205 shares in favor, to serve on the Board of Directors for the ensuing
year: David H. Boguslawski, Cheryl W. Grise, and Leon J. Olivier.

PSNH. In a written Consent in Lieu of an Annual Meeting of Stockholders of
PSNH (Consent) dated June 18, 2003, stockholders voted to fix the number of
directors for the ensuing year at five. The vote fixing the number of
directors at five was 301 shares in favor, representing 100 percent of the
issued and outstanding shares of common stock of PSNH. Through the Consent
the following five directors were elected, each by a vote of 301 shares in
favor, to serve on the Board of Directors for the ensuing year: David H.
Boguslawski, John H. Forsgren, Cheryl W. Grise, Gary A. Long, and Michael G.
Morris.

WMECO. In a written Consent in Lieu of an Annual Meeting of Stockholders of
WMECO (Consent) dated June 18, 2003, stockholders voted to fix the number of
directors for the ensuing year at five. The vote fixing the number of
directors at five was 434,653 shares in favor, representing 100 percent of
the issued and outstanding shares of common stock of WMECO. Through the
Consent the following five directors were elected, each by a vote of 434,653
shares in favor, to serve on the Board of Directors for the ensuing year:
David H. Boguslawski, John H. Forsgren, Cheryl W. Grise, Kerry J. Kuhlman,
and Michael G. Morris.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Listing of Exhibits (NU)

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

3.1.1 Declaration of Trust of NU, as amended through May 13,
2003. (Exhibit 4.1 to NU Form S-8 filed June 11,
2003, File No. 333-106008)

4.1.3.2 Second Supplemental Indenture dated as of June 1, 2003,
between NU and the Bank of New York as Trustee, relating
to $150 million of Senior Notes, Series B, due 2008.
(Exhibit A-1.3 to NU 35-CERT filed June 6, 2003,
File No. 70-10051)

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 August 8, 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 August 8, 2003

32 Certification of Michael G. Morris, Chairman, President
and Chief Executive Officer of Northeast Utilities (the
registrant) 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 August 8, 2003

(a) Listing of Exhibits (CL&P)

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 August 8, 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 August 8, 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
August 8, 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 August 8, 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 August 8, 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
August 8, 2003

(a) Listing of Exhibits (WMECO)

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 August 8, 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 August 8, 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 August 8, 2003

(b) Reports on Form 8-K:

NU and CL&P filed current reports on Form 8-K dated May 14, 2003, disclosing:

o The filing by NRG and certain of its affiliates, including NRG-PM Inc.,
of voluntary petitions for reorganization under the bankruptcy code in the
southern district of New York.

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: August 8, 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: August 8, 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.

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

Date: August 8, 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: August 8, 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)