CONNECTICUT LIGHT & POWER CO - 10-Q Quarterly Report

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FORM 10-Q

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

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

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

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

For the transition period from ________ to ________

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

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

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

1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03105-0330
Telephone: (603) 669-4000

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

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

Yes X No
--- ---

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

Company - Class of Stock Outstanding at July 31, 2002
- ------------------------ ----------------------------
Northeast Utilities
Common shares, $5.00 par value 129,345,783 shares

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

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

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

GLOSSARY OF TERMS

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

COMPANIES

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

NUCLEAR UNIT

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

REGULATORS

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

OTHER

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

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

TABLE OF CONTENTS
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Page
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Part I. Financial Information

Item 1. 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, 2002 and December 31, 2001.................. 2

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2002 and 2001............................... 4

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002 and 2001.............. 5

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

Independent Accountants' Report...................... 24

Report of Independent Public Accountants............. 25

Notes to Financial Statements
(unaudited - all companies)............................... 26

The Connecticut Light and Power Company
and Subsidiaries

Consolidated Balance Sheets -
June 30, 2002 and December 31, 2001.................. 42

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2002 and 2001............................... 44

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002 and 2001.............. 45

Management's Discussion and Analysis of
Financial Condition and Results of Operations........ 46

Public Service Company of New Hampshire
and Subsidiaries

Consolidated Balance Sheets -
June 30, 2002 and December 31, 2001................. 52

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2002 and 2001.............................. 54

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002 and 2001............. 55

Management's Discussion and Analysis of
Financial Condition and Results of Operations....... 56

Western Massachusetts Electric Company and Subsidiary

Consolidated Balance Sheets -
June 30, 2002 and December 31, 2001................. 62

Consolidated Statements of Income -
Three Months and Six Months Ended
June 30, 2002 and 2001.............................. 64

Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002 and 2001............. 65

Management's Discussion and Analysis of
Financial Condition and Results of Operations....... 66

Item 3. Quantitative and Qualitative
Disclosures About Market Risk....................... 69

Part II. Other Information

Item 1. Legal Proceedings.............................. 70

Item 4. Submission of Matters to a
Vote of Security Holders....................... 71

Item 6. Exhibits and Reports on Form 8-K............... 72

Signatures......................................................... 74

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 2002 Form 10-Q, current reports on Form 8-K dated April 23,
2002, June 17, 2002, July 23, 2002, and August 2, 2002, and the 2001
Form 10-K.

FINANCIAL CONDITION

Overview

Northeast Utilities and subsidiaries (NU or the company) reported
earnings of $28.9 million, or $0.22 per share on a fully diluted basis,
in the second quarter of 2002, compared with earnings of $46.7 million,
or $0.35 per share on a fully diluted basis, in the same period of 2001.
For the first six months of 2002, NU reported earnings of $47.5 million,
or $0.37 per share on a fully diluted basis compared with earnings of
$158.9 million, or $1.14 per share on a fully diluted basis in the same
period of 2001.

In the first quarter of 2002, NU recorded after-tax charges of $10
million, or $0.08 per share, primarily associated with NU's investment
in NEON Communications, Inc. (NEON), a Massachusetts-based provider of
high-bandwidth fiber optic telecommunications services. Although NEON
filed a reorganization plan in June 2002 in United States Bankruptcy
Court in Delaware, NU believes its remaining $5 million investment in
NEON is realizable since the plan calls for NU to retain a 7 percent
share of NEON's post-bankruptcy equity. Excluding the first quarter
charges, NU earned $57.5 million, or $0.45 per share on a fully
diluted basis, in the first six months of 2002.

In the first six months of 2001, NU recorded several items related to
the sale of Millstone nuclear units in March 2001, the adoption of
Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as
amended, and the forward repurchase of 10.1 million NU common shares.
Absent those items, NU earned $38.7 million, or $0.29 per share on a
fully diluted basis, in the second quarter of 2001, and $91.9 million,
or $0.67 per share on a fully diluted basis, in the first six months
of 2001.

The decline in NU's second quarter 2002 earnings is primarily due to
weaker results at the competitive energy subsidiaries. In the second
quarter of 2002, those businesses lost $9.3 million, compared with
earnings of $13.6 million in the second quarter of 2001. These weaker
results are related primarily to April 2002 losses on natural gas
trading and low early spring river flows, which curtailed production
at its conventional hydroelectric plants.

Revenues in the first six months of 2002 increased to $3.6 billion
from $3.4 billion in the same period of 2001, primarily due to higher
sales at NU's competitive energy subsidiaries. Revenues for NU's
competitive energy subsidiaries will be reduced as a result of
recently released accounting guidance related to the classification of
revenues and expenses associated with energy trading contracts. In
June 2002, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board reached a consensus on EITF Issue No. 02-3,
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." The EITF requires energy trading companies to
record revenues and expenses associated with energy trading contracts
on a net basis, rather than recording the gross revenues and expenses.
This change is retroactive to all periods presented, but will have no
effect on net income. NU will adopt the statement for the third
quarter of 2002. As a result, NU now estimates that its revenues for
the first six months of 2002 will be reduced to $2.5 billion from the
$3.6 billion reflected in the accompanying consolidated statements of
income. Management is in the process of determining the impact EITF
Issue No. 02-3 will have on prior periods.

NU's 2002 results also declined as a result of lower regulated
electric and natural gas sales during the second quarter of 2002 and
the first six months of 2002, resulting from mild winter and early
spring weather and lower industrial electric sales. Regulated
industrial electric sales decreased 10.8 percent in the first six
months of 2002, compared with the same periods of 2001. The most
significant decline in industrial electric sales was at Public Service
Company of New Hampshire (PSNH). All major PSNH industrial sectors
experienced sales declines in 2002, but the most significant involved
paper products, where one major customer began generating its own
electricity and another is in the process of reorganizing. Overall,
regulated electric sales decreased 0.9 percent during the second
quarter of 2002 and 2.5 percent during the first six months of 2002,
compared with the same periods of 2001.

Partially offsetting lower sales were lower financing costs and a
lower share count. NU had approximately 129.8 million shares
outstanding as of June 30, 2002, compared with 133.9 million shares
outstanding as of June 30, 2001. NU has repurchased approximately
850,000 shares for the first six months of 2002, and has Board of
Trustees authorization to repurchase approximately 10 million
additional shares by June 30, 2003. NU repurchased approximately an
additional 600,000 shares at an average price of $15.17 through
July 31, 2002.

Earnings before preferred dividends at The Connecticut Light and Power
Company (CL&P), NU's largest regulated subsidiary, totaled $11.4
million in the second quarter of 2002 and $33.1 million in the first
six months of 2002, compared with $18.8 million in the second quarter
of 2001 and $57.1 million in the first six months of 2001. The lower
2002 earnings were primarily due to an after-tax gain of $19.1 million
recorded in the first quarter of 2001 as a result of the Millstone
sale.

Combined earnings before preferred dividends at PSNH and North
Atlantic Energy Corporation (NAEC) totaled $18.1 million in the second
quarter of 2002 and $30.8 million in the first six months of 2002,
compared with earnings of $19.6 million in the second quarter of 2001
and $54.3 million in the first six months of 2001. The lower 2002
earnings were primarily due to an after-tax gain of $15.5 million
recorded in the first quarter of 2001 associated with the sale of
PSNH's share of the Millstone 3 nuclear unit and to a greater than 10
percent retail rate reduction that took effect on May 1, 2001, in
connection with industry restructuring.

Earnings before preferred dividends at Western Massachusetts Electric
Company (WMECO) totaled $15.3 million in the second quarter of 2002
and $22.2 million in the first six months of 2002, compared with
earnings of $1.5 million in the second quarter of 2001 and earnings of
$4.8 million in the first six months of 2001. The higher 2002
earnings were primarily due to the recognition in 2002 of
approximately $13 million in tax credits as a result of a regulatory
decision received during the second quarter of 2002 and due to a first
quarter 2001 refueling outage at the Millstone 3 nuclear unit.

Yankee Energy System, Inc. (Yankee) lost $0.5 million in the second
quarter of 2002 and earned $12.1 million in the first
six months of 2002, compared with a loss of $6.8 million in the second
quarter of 2001 and earnings of $8.9 million in the first six months
of 2001. The increase in Yankee's earnings during 2002 is primarily
due to continued strong control of operation and maintenance (O&M)
costs and a reduction in goodwill amortization expense.

Future Outlook

Despite the weaker results at its competitive energy subsidiaries, NU
is maintaining its updated earnings guidance. On June 17, 2002, NU
reported that the upper end of its previous earnings range of $1.40 to
$1.65 a share was unachievable. NU believes that the lower end of the
earnings range remains achievable, excluding significant items such as
1) the $10 million after-tax charges related to NEON and Acumentrics
Corporation (Acumentrics), and 2) the expected consolidated after-tax
gains of between $25 million and $30 million, related to the proposed
sale of the NU system's 40.04 percent ownership interest in the
Seabrook nuclear unit and to the elimination of certain Seabrook
related reserves. Management anticipates these gains will be
recognized during 2002.

On April 15, 2002, CL&P, NAEC and certain other unaffiliated joint
owners reached an agreement to sell approximately 88.2 percent of the
Seabrook nuclear unit to a subsidiary of the FPL Group, Inc. (FPL) for
$836.6 million. The aforementioned gain on the sale of Seabrook
relates to an agreement between NU and other unaffiliated companies in
connection with the sale of those companies' shares of Seabrook.

To meet its earnings target, NU needs to have a return to more
seasonable weather patterns in its service territories, which has
occurred during July 2002, significantly better performance at its
competitive energy subsidiaries, regulatory relief on certain
outstanding issues and continued strong control of nonfuel O&M costs.

Liquidity

NU maintained a high level of liquidity throughout the first half of
2002, and maintaining liquidity remains a significant focus for NU.
As of June 30, 2002, NU had $94 million in cash and cash equivalents
on hand. NU expects its cash position to further improve late in the
fourth quarter of 2002 when management expects the sale of CL&P's and
NAEC's 40.04 percent share of Seabrook to close. Of the approximately
$400 million of total cash proceeds NU expects to receive from the
Seabrook sale, a portion of these proceeds will be used to repay all
$90 million of NAEC's outstanding debt, return all NAEC's equity,
which totaled $38.8 million as of June 30, 2002, to NU and pay between
$90 million and $100 million in taxes. Following the sale of NAEC's
share of Seabrook, the Seabrook Power Contracts between PSNH and NAEC
will be terminated. PSNH will use the proceeds received from NAEC
from this contract termination to amortize stranded costs more
quickly, repay debt and return additional equity capital to NU. The
net gain from the sale related to CL&P's share of Seabrook primarily
will be used to offset stranded costs, and the cash proceeds received
by CL&P will be used to meet its capital requirements.

NU had little financing activity in the second quarter of 2002, other
than the refinancing of $263 million of senior unsecured notes on
April 4, 2002. The new notes bear interest at 7.25 percent and mature
on April 1, 2012. Proceeds from the refinancing were used to redeem a
similar amount of variable rate notes that were issued on February 28,
2001.

NU's regulated subsidiaries have a $350 million unsecured revolving
credit facility under which a total of $120 million was outstanding as
of June 30, 2002. This total includes $45 million, $45 million, and
$30 million outstanding for PSNH, WMECO and Yankee, respectively.

NU parent has a separate $300 million unsecured revolving credit
facility under which a total of $80 million of direct borrowings and
$114.7 million of letters of credit were outstanding as of June 30,
2002. This total includes $60 million, $10 million, and $10 million
advanced by NU parent through the NU System Money Pool to Select
Energy, Inc. (Select Energy) Northeast Generation Services Company
(NGS) and Select Energy Services, Inc. (SESI), respectively. The
$114.7 million represents letters of credit issued to counterparties
with whom Select Energy has energy contracts and to other parties.

Both the regulated subsidiaries and NU parent revolving credit
facilities expire in November 2002. As a result of NU's improved
credit ratings and strong liquidity, management does not anticipate
any difficulty renewing these credit arrangements. Additionally, NAEC
has a separate unsecured term credit agreement for $90 million of
which $90 million was outstanding as of June 30, 2002. This term
credit agreement expires on November 8, 2002, and may also need to be
extended based on the timing of the closing on the sale of Seabrook.

NU's net cash flows provided by operating activities increased to
$347.2 million in the first six months of 2002, compared with $204.9
million during the same period of 2001. Cash flows provided by
operating activities increased primarily due to increased receipts
received on accounts receivable balances during the first six months
of 2002, compared with the same period of 2001. This increase was
partially offset by a $136.2 million decrease in income before
preferred dividends. A portion of the decrease in income before
preferred dividends does not impact cash flows from operations because
the decrease is comprised of certain charges during the first six
months of 2002 associated with NEON and Acumentrics and certain items
recorded during the first six months of 2001 associated with the
adoption of SFAS No. 133, as amended, and the forward purchase of 10.1
million NU common shares. The decrease in income before preferred
dividends is also due to weaker results at the competitive energy
subsidiaries and lower regulated electric and natural gas sales. Also
an increase in payments made on accounts payable balances in the first
six months of 2002 compared to the first six months of 2001 resulted
in decreasing cash flows from operations.

There were fewer investing and financing activities in the first half
of 2002, as compared to the same period of 2001, primarily due to the
sale of the Millstone units, the buyout and buydown of independent
power producer contracts, and the issuance of CL&P, PSNH and WMECO
rate reduction certificates and bonds in 2001. The level of NU's
common dividends totaled $32.4 million in the first six months of 2002,
compared with $28.8 million in the same period of 2001. This increase
was a result of NU paying a $0.10 per share quarterly common dividend in
the first two quarters of 2001 and a $0.125 per share quarterly common
dividend in the last two quarters of 2001 and the first two quarters of
2002, partially offset by a lower share count.

On May 14, 2002, NU's Board of Trustees approved payment of a
quarterly cash dividend of $0.1375 per share, payable on September 30,
2002, to shareholders of record as of September 1, 2002. This
increase is consistent with the company's announced intention of
raising the dividend by 10 percent annually with a target payout of 50
percent of regulated company earnings. Such a program will be
dependent upon numerous factors, including NU's ability to meet
earnings targets and the judgment of its Board of Trustees at the
time. For the twelve months ended June 30, 2002, NU's regulated
operating companies, CL&P, PSNH, WMECO, NAEC and Yankee Gas Services
Company (Yankee Gas) earned $207.8 million. Assuming annualized
common dividends of $0.1375 per share and approximately 129.8 million
NU common shares outstanding at June 30, 2002, this level of common
dividends represents approximately a 34 percent payout of total
combined earnings of NU's regulated operating companies.

Competitive Energy Subsidiaries

NU's competitive energy subsidiaries had a loss of $30.9 million for
the first six months of 2002, compared with earnings of $9.4 million
before the cumulative effect of an accounting change related to the
adoption of SFAS No. 133, as amended, for the first six months of
2001. Unconsolidated revenues for the competitive energy subsidiaries
totaled approximately $1.9 billion for the first six months of 2002,
compared with $1.3 billion for the first six months of 2001. The
increased revenues are primarily the result of increased trading
volumes of certain types of energy products and the acquisition of
Select Energy New York, Inc. (SENY). For the third quarter of 2002, NU
will implement EITF Issue No. 02-3. EITF Issue No. 02-3 requires
energy trading companies to record revenues and expenses associated
with the energy trading contracts on a net basis, rather than
recording the gross revenues and expenses. NU estimates that its
competitive energy revenues and expenses for the first six months of
2002 will be reduced to $800 million from the $1.9 billion included in
the accompanying consolidated statements of income. CL&P's standard
offer purchases from Select Energy represented $304 million of total
competitive energy subsidiaries' revenues for the first six months of
2002, compared with $326.7 million for the first six months of 2001.
These amounts are eliminated in consolidation.

NU's competitive energy subsidiaries own 1,439 megawatts (MW) of
generation capacity, consisting of 1,292 MW at Northeast Generation
Company (NGC) and 147 MW at Holyoke Water Power Company (HWP). These
businesses also include wholesale and retail energy marketing and
trading organizations which buy and sell electricity, natural gas, and
other fuels. On June 17, 2002, the air circuit breaker in one of
NGC's four 270-megawatt pumped storage units at Northfield Mountain
was damaged by fire. The unit is expected to remain out of service
until late summer, pending repairs to the circuit breaker and the
generator. Northfield Mountain's other three units were not damaged and
continue to operate. NGC carries property insurance with a $1 million
deductible and business interruption insurance that commences after 60
days. As a result, the fire is not expected to have a material effect
on NU's or NGC's financial position or results of operations.

In the second quarter of 2002, NU conducted studies of the depreciable
lives of certain generation and software assets maintained by the
competitive energy subsidiaries. The impact of these studies was to
lengthen the useful lives of the generation assets by 20 years to an
average of 58 remaining years and to shorten the useful lives of the
software to 1.5 remaining years effective for the second quarter of
2002. As a result of these studies, NU's consolidated depreciation
expense decreased by approximately $1.5 million for the second quarter
of 2002 and is expected to decrease by approximately $5.8 million
annually.

The competitive energy subsidiaries also include SESI, which 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, and NGS,
which operates and maintains NGC's and HWP's generation assets and
provides third-party contracting services for power plants and large
industrial facilities. Consistent with its business strategy, the
competitive energy subsidiaries acquired an electrical services
company and a telecommunications company in July 2002. These
companies are expected to generate approximately $35 million in
revenues in 2003.

Competitive Energy Subsidiaries' Market and Other Risks

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

A significant portion of Select Energy's wholesale marketing business
is providing energy to full requirements customers, primarily
regulated distribution companies. Under full requirements contract
terms, the supplier is required to provide the total energy
requirement for the customers' load at all times. A key component of
Select Energy's risk management strategy is focused on managing the
volume and price risks of full requirements contracts. These risks
include significant fluctuations in supply and demand due to numerous
factors such as weather, plant availability, transmission congestion,
and potentially volatile price fluctuations. Select Energy's first
quarter 2002 results were negatively impacted by weather patterns that
resulted in contracted supply exceeding demand.

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

The competitive energy subsidiaries manage their portfolio of
contracts and assets to maximize value and minimize associated risks.
The lengths of contracts to buy and sell energy vary in duration from
daily/hourly to several years. At any point in time, as noted previously,
the portfolio may be long (purchases exceed sales) or short (sales
exceed purchases). Portfolio and risk management disciplines, with
established policies and procedures, are used to manage exposures to
market risks. At forward market prices in effect at June 30, 2002, the
accrual accounting portfolio, which includes the CL&P standard offer
contract, had a positive mark-to-market position. There is significant
volatility in the energy commodities market. This position fluctuates in
value due to changes in energy prices in the region, new transactions
entered into during the period and positions settling during the period.

Select Energy also engages in the trading of commodity derivatives,
which are accounted for using the mark-to-market method under EITF
Issue No. 98-10, "Accounting for Energy Trading and Risk Management
Activities." Energy trading transactions at Select Energy include
financial transactions and physical delivery transactions for
electricity, natural gas and oil in which Select Energy is attempting
to profit from changes in market prices.

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

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

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, in increasing amounts dependent
upon the severity of the decline. At NU's present investment grade
ratings, Select Energy has not had to post any collateral based on credit
downgrades. Were NU's unsecured ratings to decline two to three
notches to sub-investment grade, Select Energy would, under its
present contracts, have to provide approximately $88 million of
collateral to various counterparties, which NU, under present
circumstances, would be able to provide Select Energy from available
sources of funds. NU's ratings are currently stable and management
does not believe that at this time there is a risk of a ratings downgrade
to subinvestment grade levels.

The breadth and depth of the market for energy trading and marketing
products in Select Energy's market has been adversely affected by the
withdrawal or financial weakening of a number of companies who have
historically done significant amounts of business with Select Energy.
In general, the market for such products has become shorter term in
nature, with less liquidity and participants less able to meet Select
Energy's credit standards without providing cash or letter of credit
support. While Select Energy's core marketing and trading business
has not been materially adversely affected by these factors to date,
should these trends continue and worsen, there could be some adverse
impact on Select Energy's business prospects.

As of June 30, 2002, Select Energy had unrealized net gains on mark-to-
market transactions of $125 million and unrealized net losses on mark-
to-market transactions of $49.5 million on a counterparty-by-
counterparty basis. Also as of June 30, 2002, two counterparties
collectively represented approximately 37 percent of the unrealized
net gains on mark-to-market transactions. Management believes the
risk associated with collecting amounts from these counterparties is
minimal, primarily due to collateral balances maintained.

As of and for the three and six months ended June 30, 2002, the
sources of the fair value of these trading contracts and the change in
fair value of these trading contracts are as follows:

- -------------------------------------------------------------------------------
(Millions of Dollars) Fair Value of Contracts at June 30, 2002
- -------------------------------------------------------------------------------
Maturity Maturity of Maturity in Total
Less than One to Four Excess of Fair
Sources of Fair Value One Year Years Four Years Value
- -------------------------------------------------------------------------------
Prices actively quoted $(2.8) $ 6.5 $ - $ 3.7
Prices provided by
external sources 9.5 32.7 15.6 57.8
Prices based on
models or other
valuation methods (1.9) 3.1 12.8 14.0
- -------------------------------------------------------------------------------
Totals $ 4.8 $42.3 $28.4 $75.5
- -------------------------------------------------------------------------------

At March 31, 2001, the mark-to-market of contracts maturing in less
than one year was negative $6.7 million. During the second quarter of
2002, a significant portion of the negative fair value of contracts as
of March 31, 2002, with maturities less than one year was realized.
Also during the second quarter of 2002, the availability of external
sources of prices to value contracts with maturities in excess of four
years decreased as a result of the decrease in liquidity in the market
for long-term contracts. Contracts with a fair value of $5.2 million at
March 31, 2002, and included at that time in contracts valued with prices
provided by external sources are now valued based on models or other
valuation methods. The fair value at June 30, 2002, is estimated to
be $12.8 million. The $7.6 million change in fair value is included
in the table below as a change in fair value attributable to changes
in valuation techniques and assumptions.

- -------------------------------------------------------------------------------
(Millions of Dollars) Total Fair Value
- -------------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, 2002 June 30, 2002
- -------------------------------------------------------------------------------
Fair value of contracts outstanding
at the beginning of the period $57.5 $ 56.4
Contracts realized or otherwise
settled during the period 3.4 2.1
Fair value of new contracts when
entered into during the period - 11.6
Changes in fair values
attributable to changes in
valuation techniques and
assumptions 7.6 (4.4)
Changes in fair value of contracts 7.0 9.8
- -------------------------------------------------------------------------------
Fair value of contracts
outstanding at the end of
the period (June 30, 2002) $75.5 $75.5
- -------------------------------------------------------------------------------

During the first three months of 2002, the competitive energy subsidiaries
terminated certain long-term energy contracts. Coincident with the
terminations, new contracts were entered into with different terms and
conditions. These new contracts are derivatives and had a positive mark-
to-market of $11.6 million when entered into and $9.5 million as of
June 30, 2002.

For further information see Note 4, "Market Risk and Risk Management
Instruments," and Note 5, "Comprehensive Income," to the consolidated
financial statements.

Business Development and Capital Expenditures

NU's capital expenditures totaled $212.5 million in the first six
months of 2002, compared with $215.3 million in the first six months
of 2001. NU currently projects year end 2002 capital expenditures to
approximate $492 million, approximately $100 million lower than the
company had projected at the beginning of 2002. The primary reasons
for the lower 2002 capital expenditure projection are delays in
commencing work on high voltage electric transmission projects and
lower projected capital spending at Yankee Gas. Those changes have
been partially offset by increased capital expenditures for CL&P's
electric distribution system.

In 2001, CL&P announced plans for three high voltage transmission
projects in Southwest Connecticut. For the first project, Connecticut
Siting Council (CSC) hearings on the replacement of an existing
138,000 volt line between Norwalk, Connecticut and Northport - Long
Island, New York were completed in June 2002, and a final decision is
expected in late 2002. CL&P currently expects to complete the
manufacture and installation of the cable in 2003 and early 2004,
respectively. CL&P would share the $80 million cost of this project
with the Long Island Power Authority (LIPA), which jointly owns the
cable.

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

For the third project, CL&P announced plans for a separate $400
million 345,000 volt transmission line between Norwalk, Connecticut
and Middletown, Connecticut. CL&P expects to apply to the CSC for
approval of the project in 2003.

Restructuring and Rate Matters

Connecticut - CL&P: On November 18, 2001, at the request of NRG Power
Marketing, Inc. (NRG-PM) which serves 40 percent of the standard offer
requirement in 2002, and will serve 45 percent of such load in 2003,
CL&P filed a request with the Connecticut Department of Public Utility
Control (DPUC) to raise the standard offer service rate from an
average of $0.0495 per kilowatt-hour (kWh) to $0.0595 per kWh to help
promote competition in advance of the January 1, 2004, termination of
the standard offer service period and to provide financial relief to
NRG-PM and the other standard offer suppliers including Select Energy.
In December 2001, the DPUC rejected CL&P's request, but opened two new
dockets to examine the absence of effective retail electric
competition in Connecticut and the viability of its standard offer
service supply contracts. The first docket culminated in a joint
study report issued in a decision by the DPUC on February 15, 2002,
which provided the DPUC's and the Office of Consumer Counsel's
findings on how to best structure default service and other issues
related to electric industry restructuring. The second of the two
dockets focused on the viability of the standard offer service
contracts. On June 17, 2002, the DPUC concluded "that there does not
exist either a legal or factual basis upon which to find probable
cause to commence further proceedings regarding the standard offer
generation service charge."

On July 18, 2002, CL&P, concerned with the financial viability of a
major unaffiliated standard offer service supplier, NRG-PM, filed a
new proposal with the DPUC to maintain current total rates, but to
shift $0.007 per kWh from being used to amortize stranded costs
to instead provide additional payments to CL&P's two principal
standard offer service suppliers to ensure that there are adequate,
available generating units to maintain electric reliability in the
near term in Southwest Connecticut. CL&P also proposed to rebid 95
percent of its 2003 standard offer supply requirements to confirm the
reasonableness of pricing and to test the market for replacement
suppliers. On July 26, 2002, the DPUC denied the requests in CL&P's
proposal, indicating that it expects CL&P to enforce the current
standard offer contracts. The DPUC also left this docket open to
further consider CL&P's requests.

CL&P is evaluating NRG-PM's ability to meet its obligations under the
standard offer contract based upon two recent developments. NRG
Energy, Inc. (NRG), the corporate parent and guarantor of NRG-PM's
standard offer contract with CL&P has been downgraded to below the
contractually required minimum investment grade level by all three
major rating agencies. In addition, NRG's Connecticut generating
affiliates, due to various disputes with the State of Connecticut and
ISO New England, have threatened to deactivate generating facilities
critical to the reliability of supply in the State of Connecticut as
early as August 9, 2002. If CL&P is required to seek an alternate
source of supply, CL&P would pursue recovery of any additional costs
associated with obtaining such supply from NRG-PM pursuant to the
contract and may be required to seek DPUC approval to flow through any
such costs to customers. Management believes that recovery of these
costs is consistent with the provisions of Connecticut's electric
utility restructuring legislation. In view of the deterioration of
NRG's financial condition, CL&P exercised its contractual right to
withhold past due congestion costs from the July standard offer
payment to NRG-PM pending the outcome of litigation between the
parties concerning contractual liability for congestion costs ongoing
in the U.S. District Court for the District of Connecticut. See NU's
Form 10-K for 2001, Item 3, "Legal Proceedings", for further
information on this litigation.

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

On November 23, 2001, CL&P petitioned the DPUC to adjust its stranded
costs to account for the announced sale of the Vermont Yankee nuclear
unit to an unaffiliated company. On June 12, 2002, the DPUC issued a
final decision that found CL&P's request was beneficial to ratepayers
and allowed for stranded cost recovery through the Competitive
Transition Assessment.

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

Connecticut - Yankee Gas: On May 15, 2002, the DPUC issued a final
decision which granted Yankee Gas' motion to terminate the
overearnings docket.

On August 1, 2002, Yankee Gas filed its first Infrastructure Expansion
Rate Mechanism (IERM) filing with the DPUC as directed in the January 30,
2002, rate case decision. Yankee Gas' filing requests approval of a 2003
IERM charge to be reflected on customers' bills effective January 1, 2003.
As specified in the rate case decision, Yankee Gas' filing reflects those 2001
through 2003 system expansion projects that Yankee Gas has undertaken or
plans to undertake by June 30, 2003, and that meet certain financial criteria
outlined by the DPUC. No schedule has yet been assigned to this filing,
but a decision is expected on or before January 1, 2003.

New Hampshire: The hearings on a docket opened by the New Hampshire
Public Utilities Commission (NHPUC) to review PSNH's fuel and purchased-power
adjustment clause (FPPAC) concluded in June 2002. At June 30, 2002, PSNH has
approximately $179.8 million of recoverable energy costs deferred under the
FPPAC, excluding previous deferrals of purchases from independent power
producers. Management believes the recovery of these costs is probable and
expects the NHPUC will issue its order in the third quarter of 2002.

On April 15, 2002, CL&P, NAEC and certain other unaffiliated joint
owners reached an agreement to sell approximately 88.2 percent of the
Seabrook nuclear unit to a subsidiary of FPL for $836.6 million,
including $61.9 million for nuclear fuel. FPL has agreed to assume
responsibility for decommissioning the unit and will receive all funds
in the Seabrook decommissioning trust. NU and the other unaffiliated
joint owners are obligated to top-off their shares of the decommissioning
trust if the trust's value does not equal a previously agreed upon level.
Approval of the transaction is required from various federal and state
regulatory agencies, and the parties are now in the process of obtaining
these approvals. Management expects the sale of CL&P's and NAEC's 40.04
percent share of Seabrook to close before the end of 2002.

Massachusetts: During the first quarter of 2000, WMECO filed its first
annual stranded cost reconciliation filing covering the period March 1,
1998 through December 31, 1999. The Massachusetts Department of
Telecommunications and Energy (DTE) issued its decision on this filing on
June 7, 2002. The decision included, among other things, a conclusion
that investment tax credits associated with generation assets that have
been divested did not need to be returned to ratepayers. As a result,
WMECO recognized approximately $13 million in tax credits in the second
quarter of 2002.

On March 30, 2001, WMECO also filed its second annual stranded cost
reconciliation with the DTE for calendar year 2000. On March 29,
2002, WMECO filed its 2001 annual transition cost reconciliation with
the DTE. This filing reconciles the recovery of stranded generation
costs for calendar year 2001. Also included in this filing are the
sales proceeds from WMECO's portion of Millstone, the impact of
securitization and approximately a $13 million benefit to ratepayers
from WMECO's nuclear performance-based ratemaking process. If
approved by the DTE, the inclusion of these items as part of the
reconciliation filing will allow WMECO to accelerate the recovery of
stranded costs.

On July 8, 2002, WMECO made a filing in compliance with the DTE's June 7,
2002, decision. This filing included updates to the 2000 and 2001 annual
transition cost reconciliation filings. Management anticipates a decision
regarding these filings in the second half of 2002. The cumulative deferral
of unrecovered stranded costs, as filed through calendar year 2001, is
approximately $8.5 million. Management believes these costs are fully
recoverable.

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

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

Nuclear Plant Performance and Other Matters

Seabrook: Seabrook operated at a capacity factor of 83 percent through
the first six months of 2002. Seabrook returned to service on June 1,
2002, after the completion of a 28-day scheduled refueling outage that
began on May 4, 2002. Excluding the scheduled refueling outage,
Seabrook operated at a capacity factor of 99 percent through the first
six months of 2002. Seabrook is expected to be sold before the end of
2002.

Yankee Companies: On July 31, 2002, Vermont Yankee Nuclear Power
Corporation (VYNPC) consummated the sale of its nuclear generating
unit to an unaffiliated company for approximately $180 million. After
the repayment of debt and taxes associated with the sale, VYNPC
expects to distribute cash proceeds of between $35 million and $40
million to its equity owners. NU subsidiaries CL&P, PSNH and WMECO
combined own approximately 17 percent of VYNPC and expect to receive
approximately $6 million in proceeds from the sale through a
combination of dividends and stock repurchases. Under the terms of the
sale, CL&P, PSNH and WMECO will continue to buy approximately 16
percent of the plant's output through March 2012 at a range of fixed prices.

Other Matters

Critical Accounting Policies: The preparation of financial statements
in conformity with accounting principles generally accepted in the
United States requires management to make estimates, assumptions and
at times difficult, subjective or complex judgments. On January 1,
2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets,"
which required significant estimates, assumptions and judgments in
determining reporting units and estimating the fair value of reporting
units. For further information regarding the adoption of SFAS No.
142, see Note 3, "Goodwill and Other Intangible Assets," to the
consolidated financial statements.

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

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

RESULTS OF OPERATIONS

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

Income Statement Variances
(Millions of Dollars)

2002 over/(under) 2001
-------------------------------------
Second Six
Quarter Percent Months Percent
------- ------- ------ -------
Operating Revenues $ 90 6% $ 200 6%

Operating Expenses:
Fuel, purchased and
net interchange power 148 15 370 17
Other operation 10 5 (11) (3)
Maintenance 13 23 (23) (15)
Depreciation 1 2 (12) (11)
Amortization (43) (50) (692) (86)
Taxes other than income taxes - - (1) (1)
Gain on sale of utility plant - - 654 100
---- --- ---- ---
Total operating expenses 129 9 285 9
---- --- ---- ---

Operating income (39) (30) (85) (29)
---- --- ---- ---
Other income/(loss), net (14) (89) (185) (a)
Interest expense, net (2) (4) (3) (2)
---- --- ---- ---
Income before income tax expense (51) (66) (267) (82)
Income tax expense (32) (a) (131) (93)
Preferred dividends of subsidiaries (1) (43) (3) (46)
---- --- ---- ---
Income before cumulative effect of
accounting change (18) (38) (133) (74)
Cumulative effect of accounting
change, net of tax benefit - - 22 100
---- --- ---- ---
Net income $(18) (38)% $(111) (70)%
==== === ===== ===
(a) Percent greater than 100.

Comparison of the Second Quarter of 2002 to the Second Quarter of 2001

Operating Revenues
Total revenues increased by $90 million or 6 percent in the second
quarter of 2002, compared with the same period in 2001, primarily due
to higher revenues from the competitive energy companies ($192
million, which reflects eliminations of sales to other NU affiliates),
partially offset by lower wholesale revenues for the regulated
subsidiaries ($57 million), and lower regulated retail revenues ($30
million).

The competitive energy companies' revenue increase is primarily due to
higher revenues from Select Energy, primarily as a result of increased
trading volumes and the acquisition of SENY. The regulated wholesale
revenue decrease is due to lower PSNH wholesale sales and lower
wholesale prices ($28 million) and lower sales associated with other
purchased-power contracts ($28 million). The regulated retail revenue
decrease is due to rate decreases for PSNH and WMECO ($16 million),
lower purchased gas adjustment clause revenue for Yankee ($14 million)
and lower retail electric sales ($10 million), partially offset by an
increase for CL&P resulting from the collection of deferred fuel costs
($10 million). Regulated retail electric kWh sales decreased by 0.9
percent, and firm natural gas volume sales increased by 10.6 percent
in the second quarter of 2002. Effective for the third quarter of
2002, management will apply EITF Issue No. 02-3, which requires net
reporting of energy trading revenues and expenses.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 2002,
primarily due to higher purchased energy and capacity costs as a
result of higher sales for Select Energy ($201 million, which reflects
eliminations of purchases from other NU affiliates), partially offset
by lower purchased-power costs for the regulated subsidiaries ($48
million). Effective for the third quarter of 2002, management will
apply EITF Issue No. 02-3, which requires net reporting of energy
trading revenues and expenses.

Other Operation and Maintenance
Other O&M expense increased $23 million in the second quarter of 2002,
primarily due to higher nuclear expenses as a result of a scheduled outage
at the Seabrook unit ($16 million), higher transmission expense ($12
million) and distribution expense ($6 million), partially offset by lower
administration and general expense ($5 million) and lower fossil and
hydroelectric expense ($4 million).

Amortization
Amortization decreased in 2002, primarily due to higher amortization
in 2001 related to recovery of the Millstone investment ($20 million),
the NAEC discontinuance of amortizing Seabrook deferred return in 2001
as a result of PSNH's restructuring ($16 million) and lower
amortization in 2002 related to restructuring ($7 million).

Other (Loss)/Income, Net
Other (loss)/income, net decreased primarily due to NU's 2001
recognition of a noncash gain in connection with the marking to market
of NU common shares acquired through forward share repurchase
arrangements ($10 million) and the gain on the disposition of property
for PSNH in 2001 ($4 million).

Income Tax Expense
Income tax expense decreased due to WMECO investment tax credits
recorded in 2002 ($13 million) and lower taxable income.

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

Operating Revenues
Total revenues increased by $200 million or 6 percent in the first six
months of 2002, compared with the same period in 2001, primarily due
to higher revenues from the competitive energy companies ($614
million, which reflects eliminations of sales to other NU affiliates),
partially offset by lower wholesale revenues for the regulated
subsidiaries ($216 million), and lower regulated retail revenues ($170
million).

The competitive energy companies' revenue increase is primarily due to
higher revenues from Select Energy, primarily as a result of increased
trading volumes and the acquisition of SENY. The wholesale revenue
decrease is due to lower PSNH wholesale sales and lower wholesale
prices ($92 million), the 2001 revenue associated with the sale of
Millstone output ($42 million) and lower sales associated with other
purchased-power contracts ($82 million). The regulated retail revenue
decrease is due to rate decreases for PSNH and WMECO ($60 million),
lower purchased gas adjustment clause revenue for Yankee ($57 million)
and lower retail sales ($74 million), partially offset by an increase
for CL&P resulting from the collection of deferred fuel costs ($21
million). Regulated retail electric kWh sales decreased by 2.5
percent, and firm natural gas volume sales decreased by 9.9 percent in
2002. Effective for the third quarter of 2002, management will apply
EITF Issue No. 02-3, which requires net reporting of energy trading
revenues and expenses.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased in 2002,
primarily due to higher purchased energy and capacity costs as a
result of higher sales for Select Energy ($653 million, which reflects
eliminations of purchases from other NU affiliates), partially offset
by lower purchased-power costs for the regulated subsidiaries ($275
million). Effective for the third quarter of 2002, management will
apply EITF Issue No. 02-3, which requires net reporting of energy
trading revenues and expenses.

Other Operation and Maintenance
Other O&M expense decreased $34 million in 2002, primarily due to
lower nuclear expenses as a result of the sale of the Millstone units
at the end of the first quarter in 2001 ($53 million), lower fossil
and hydroelectric expense ($8 million) and lower administration and
general expense ($2 million), partially offset by higher transmission
expense ($20 million) and distribution costs ($11 million).

Depreciation
Depreciation decreased in 2002 primarily due to the sale of the
Millstone units ($8 million) and PSNH restructuring ($4 million),
which began on May 1, 2001.

Amortization
Amortization decreased in 2002, primarily due to the amortization of
the gain in 2001 related to the sale of the Millstone units ($654
million), higher amortization in 2001 related to recovery of the
Millstone investment ($50 million) and the NAEC discontinuance of
amortizing Seabrook deferred return in 2001 as a result of PSNH's
restructuring ($16 million), partially offset by higher amortization
related to restructuring ($31 million).

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

Other (Loss)/Income, Net
Other (loss)/income, net decreased primarily due to NU's 2001
recognition of a gain in connection with the sale of Millstone units
to DNCI ($202 million pre-tax), a 2002 charge reflecting a write-down
in NU's investment in NEON ($15 million pre-tax) and the gain on the
disposition of property for PSNH in 2001 ($4 million), partially
offset by a 2001 noncash charge related to the forward purchase of NU
common shares ($35 million).

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

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

INDEPENDENT ACCOUNTANTS' REPORT

To the Board of Trustees
Northeast Utilities
Berlin, Connecticut

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

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

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

/s/ Deloitte & Touche LLP
Deloitte & Touche LLP

Hartford, Connecticut
August 7, 2002

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Northeast Utilities:

We have reviewed the accompanying consolidated balance sheet of
Northeast Utilities (a Massachusetts trust) and subsidiaries as of
June 30, 2001, and the related consolidated statements of income for
the three and six-month periods ended June 30, 2001 and 2000 and the
consolidated statements of cash flows for the six-month periods ended
June 30, 2001 and 2000. These financial statements are the
responsibility of the Company's management.

We conducted our review in accordance with standards established by
the American Institute of Certified Public Accountants. A review of
interim financial information consists principally of applying
analytical procedures to financial data and 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, the
objective of which is the expression of an opinion regarding the
financial statements taken as a whole. Accordingly, we do not express
such an opinion.

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

We have previously audited, in accordance with auditing standards
generally accepted in the United States, the consolidated balance sheet
and consolidated statement of capitalization as of December 31, 2000 and
the related consolidated statements of income, comprehensive income,
shareholders' equity, cash flows, and income taxes for the year then
ended (not presented herein), and, in our report dated January 23, 2001
(except with respect to the matters discussed in Note 15, as to which the
date is March 13, 2001), we expressed an unqualified opinion on those
financial statements. In our opinion, the information set forth in
the accompanying consolidated balance sheet as of December 31, 2000,
is fairly stated, in all material respects, in relation to the
consolidated balance sheet from which it has been derived.

/s/ Arthur Andersen LLP
Arthur Andersen LLP
Hartford, Connecticut
August 9, 2001

Readers of these consolidated financial statements should be aware
that this report is a copy of a previously issued Arthur Andersen LLP
report and that this report has not been reissued by Arthur Andersen
LLP. Furthermore, this report has not been updated since August 9,
2001, and Arthur Andersen LLP completed its last post-audit review of
December 31, 2001, consolidated financial information on May 13, 2002.

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

NOTES TO FINANCIAL STATEMENTS (Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

A. Presentation

The accompanying unaudited financial statements should be read in
conjunction with the management's discussion and analysis of financial
condition and results of operations in this Form 10-Q, the First
Quarter 2002 Form 10-Q and the Annual Reports of Northeast Utilities
(NU or the company), The Connecticut Light and Power Company (CL&P),
Public Service Company of New Hampshire (PSNH), and Western
Massachusetts Electric Company (WMECO), which were filed as part of
the NU 2001 Form 10-K, and the current reports on Form 8-K dated April
23, 2002, June 17, 2002, July 23, 2002, and August 2, 2002. The
accompanying financial statements contain, in the opinion of
management, all adjustments necessary to present fairly NU's and each
NU system company's financial position as of June 30, 2002, the
results of operations for the three-month and six-month periods ended
June 30, 2002 and 2001, and cash flows for the six-month periods ended
June 30, 2002 and 2001. All adjustments are of a normal, recurring
nature except those described in Notes 1C and 2. Due primarily to the
seasonality of NU's business, the results of operations for the three-
month and six-month periods ended June 30, 2002 and 2001, and
statements of cash flows for the six-month periods ended June 30, 2002
and 2001, are not indicative of the results expected for a full year.

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

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

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

B. Regulatory Accounting and Assets

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

-----------------------------------------------------------------------
June 30, December 31,
(Millions of Dollars) 2002 2001
-----------------------------------------------------------------------
Recoverable nuclear costs $ 209.4 $ 231.6
Securitized regulatory assets 1,966.2 2,004.1
Income taxes, net 311.3 312.8
Unrecovered contractual obligations 72.7 78.3
Recoverable energy costs, net 314.2 334.5
Other 286.5 326.2
-----------------------------------------------------------------------
Totals $3,160.3 $3,287.5
-----------------------------------------------------------------------

C. New Accounting Standards

Goodwill and Other Intangible Assets: Effective January 1, 2002, NU
adopted SFAS No. 142, "Goodwill and Other Intangible Assets." For
further information regarding the adoption of this standard, see Note 3,
"Goodwill and Other Intangible Assets," to the consolidated
financial statements.

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

Energy Trading and Risk Management Activities: In June 2002, the
Emerging Issues Task Force (EITF) of the FASB reached a consensus on
EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," requiring energy trading
companies to classify revenues and expenses associated with certain
energy trading contracts on a net basis within revenues, rather than
recording the gross revenues and expenses. The application of this
consensus will be retroactive to all periods presented but will have
no effect on net income. NU will adopt EITF Issue No. 02-3 in the
third quarter of 2002. As a result, NU now estimates that its
competitive energy revenues and expenses for the first six months of
2002 will be reduced to $800 million from the $1.9 billion reflected
in the accompanying NU consolidated statements of income. The
reduction in competitive energy revenues and expenses relates to energy
trading contracts that physically settle, which are currently recorded
as revenues for sales and fuel, purchased and net interchange power for
the costs of the sales. A second consensus was reached on EITF Issue
No. 02-3 requiring certain additional disclosures the majority of
which are included in this Form 10-Q. Management is in the process of
determining the impact EITF Issue No. 02-3 will have on prior periods.

D. Other (Loss)/Income, Net

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

---------------------------------------------------------------------
For the Six Months Ended
---------------------------------------------------------------------
June 30, June 30,
(Millions of Dollars) 2002 2001
---------------------------------------------------------------------
Loss on investments $(17.1) $ -
Gain related to Millstone sale - 202.2
Loss on share repurchase contracts - (35.4)
Other, net 4.8 6.1
---------------------------------------------------------------------
Totals $(12.3) $172.9
---------------------------------------------------------------------

E. Change in Estimated Useful Lives

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

2. COMMITMENTS AND CONTINGENCIES

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

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

New Hampshire: In July 2001, the New Hampshire Public Utilities
Commission (NHPUC) opened a docket to review the fuel and purchased-
power adjustment clause (FPPAC) cost accruals between August 2, 1999,
and April 30, 2001. Hearings at the NHPUC took place in June 2002,
and PSNH filed its closing brief with the NHPUC in July 2002. Under
the "Agreement to Settle PSNH Restructuring," FPPAC deferrals are
recovered as a Part 3 regulatory asset through a stranded cost
recovery charge. At June 30, 2002, PSNH had approximately $179.8
million of recoverable energy costs deferred under the FPPAC,
excluding previous deferrals of purchases from independent power
producers. Management believes the recoverability of these costs
is probable and expects the NHPUC to issue its order in the third
quarter of 2002.

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

Massachusetts: During the first quarter of 2000, WMECO filed its
first annual stranded cost reconciliation filing covering the period
March 1, 1998 through December 31, 1999. The Massachusetts Department
of Telecommunications and Energy (DTE) issued its decision on this
filing on June 7, 2002. The decision included, among other things, a
conclusion that investment tax credits associated with generation
assets that have been divested did not need to be returned to
ratepayers. As a result, WMECO recognized approximately $13 million
in tax credits in the second quarter of 2002.

On March 30, 2001, WMECO also filed its second annual stranded cost
reconciliation with the DTE for calendar year 2000. On March 29,
2002, WMECO filed its 2001 annual transition cost reconciliation with
the DTE. This filing reconciles the recovery of stranded generation
costs for calendar year 2001. Also included in this filing are the
sales proceeds from WMECO's portion of Millstone, the impact of
securitization and approximately a $13 million benefit to ratepayers
from WMECO's nuclear performance-based ratemaking process. If
approved by the DTE, the inclusion of these items as part
of the reconciliation filing will allow WMECO to accelerate the
recovery of stranded costs.

On July 8, 2002, WMECO made a filing in compliance with the DTE's
June 7, 2002, decision. This filing included updates to the 2000
and 2001 annual transition cost reconciliation filings. Management
anticipates a decision regarding these filings in the second half of
2002. The cumulative deferral of unrecovered stranded costs, as
filed through calendar year 2001, is approximately $8.5 million.
Management believes these costs are fully recoverable.

B. Long-Term Contractual Arrangements (Select Energy)

Select Energy, Inc. (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
$5.3 billion at June 30, 2002. These contracts extend through 2006
as follows (millions of dollars):

--------------------------------------------------------------------
Year
--------------------------------------------------------------------
2002 $2,947.0
2003 1,763.0
2004 292.4
2005 206.7
2006 61.6
--------------------------------------------------------------------
Total $5,270.7
--------------------------------------------------------------------

3. GOODWILL AND OTHER INTANGIBLE ASSETS

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

As of June 30, 2002, NU maintains $313 million of goodwill that is no
longer being amortized and $19.3 million of identifiable intangible
assets which continue to be amortized up to the maximum useful life of
15 years. These amounts are included on the consolidated balance
sheets as goodwill and other purchased intangible assets, net. NU
does not maintain any indefinite-lived intangible assets.

NU's reporting units that maintain goodwill are generally consistent
with the operating segments underlying the reportable segments
identified in Note 7, "Segment Information," and are as follows:
Yankee Gas Services Company (Yankee Gas), Select Energy Services, Inc.
(SESI) and Northeast Generation Services Company (NGS). Yankee Gas
is included in the regulated utilities - gas reportable segment and
SESI and NGS are included in the competitive energy subsidiaries
segment.

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

A summary of NU's goodwill as of June 30, 2002, by reportable segment
and reporting unit is as follows:

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

Competitive Energy Subsidiaries:
SESI 18.0
NGS 7.0
YESCO 0.4
------------------------------------------------------
Total $313.0
------------------------------------------------------

There were no impairments or adjustments to these goodwill balances
since January 1, 2002.

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

------------------------------------------------------------------------
As of June 30, 2002
------------------------------------------------------------------------
(Millions of Gross Accumulated Net
Dollars) Balance Amortization Balance
------------------------------------------------------------------------
Intangible assets
subject to
amortization:
Exclusively
agreement $17.7 $ 3.7 $14.0
Customer list 6.6 1.3 5.3
------------------------------------------------------------------------
Total $24.3 $ 5.0 $19.3
------------------------------------------------------------------------

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

NU recorded amortization expense of $0.8 million during the first
six months of 2002 and 2001, related to these intangible assets.
Based on the current amount of intangible assets subject to
amortization, the estimated amortization expense for each of the
succeeding 5 years from 2002 through 2006 is approximately $1.6
million. These amounts may vary as acquisitions and dispositions
occur in the future.

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

------------------------------------------------------------------------
Fully
(Millions of Dollars, except Net Basic Diluted
share information) Income EPS EPS
------------------------------------------------------------------------
Three Months Ended June 30, 2001:
------------------------------------------------------------------------
Reported net income $46.7 $0.35 $0.35
Add back: goodwill amortization 2.3 0.02 0.02
----- ----- -----
Adjusted net income $49.0 $0.37 $0.37
------------------------------------------------------------------------
Three Months Ended June 30, 2002:
------------------------------------------------------------------------
Reported net income $28.9 $0.22 $0.22
------------------------------------------------------------------------

------------------------------------------------------------------------
Fully
(Millions of Dollars, except Net Basic Diluted
share information) Income EPS EPS
------------------------------------------------------------------------
Six Months Ended June 30, 2001:
------------------------------------------------------------------------
Reported net income $158.9 $1.14 $1.14
Add back: goodwill amortization 4.5 0.04 0.03
------ ----- -----
Adjusted net income $163.4 $1.18 $1.17
------------------------------------------------------------------------
Six Months Ended June 30, 2002:
------------------------------------------------------------------------
Reported net income $ 47.5 $0.37 $0.37
------------------------------------------------------------------------

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

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

There have been changes to interpretations of SFAS No. 133 and EITF
Issue No. 98-10, and the FASB continues to consider changes and
amendments which could affect the recording and disclosure of
derivative and hedging activities and trading contracts which are
marked-to-market.

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

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

Commodity Price Risk - Trading Activities: As a market participant in
the Northeast United States, Select Energy conducts commodity-trading
activities in electricity and its related products, natural gas and
oil, and therefore, experiences net open positions. Select Energy
manages these open positions with strict policies which limit its
exposure to market risk and require daily reporting to management of
potential financial exposure. Under EITF Issue No. 98-10, these
instruments are adjusted to market value, and the unrealized gains and
losses are recognized in income in the current period in the
consolidated statements of income as fuel, purchased and net
interchange power and in the consolidated balance sheets as unrealized
net gains on mark-to-market transactions. The net mark-to-market
positions at June 30, 2002 and December 31, 2001, were assets of $75.5
million and $56.4 million, respectively.

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

As of June 30, 2002, Select Energy has calculated the market price
resulting from a 10 percent unfavorable change in forward market
prices. That 10 percent change would result in approximately a $2.4
million decline in the fair value of the Select Energy trading
portfolio. In the normal course of business, Select Energy also faces
risks that are either nonfinancial or nonquantifiable. Such risks
principally include credit risk, which is not reflected in
the aforementioned sensitivity analysis.

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

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

Select Energy has determined a hypothetical change in the fair value
for its nontrading derivatives and electricity, natural gas and oil
contracts, assuming a 10 percent unfavorable change in forward market
prices. As of June 30, 2002, an unfavorable 10 percent change in
market price would have resulted in a decline in fair value of
approximately $18 million.

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

Select Energy also maintains natural gas service agreements with
certain customers to supply gas at fixed prices for terms extending
through 2004. Select Energy has hedged its gas supply risk under
these agreements through New York Mercantile Exchange (NYMEX)
contracts. Under these contracts, the purchase price of a specified
quantity of gas is effectively fixed over the term of the gas service
agreements, which also extend through 2004. As of June 30, 2002, the
NYMEX contracts had a notional value of $58.2 million and a mark-to-
market asset value of $1.4 million.

Regulated Entities:

Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a
master swap agreement with a financial counterparty to purchase gas at
fixed prices. Under this master swap agreement, the purchase price of
a specified quantity of gas for two customers is effectively fixed
over the term of the gas service agreements with those customers for a
period of time not extending beyond 2005. As of June 30, 2002, the
commodity swap agreement had a notional value of $13.8 million and a
mark-to-market asset value of $0.6 million, which is included in the
$1.4 million reported for accumulated other comprehensive income
related to hedging activities.

Interest Rate Risk - Nontrading Activities: Previously, Yankee Energy
System, Inc. (Yankee) entered into an interest rate sensitive
derivative. During the