NORTHEAST UTILITIES SYSTEM - 10-Q Quarterly Report

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

FORM 10-Q

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

For the quarterly period ended March 31, 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 April 30, 2003
- ------------------------ -----------------------------
Northeast Utilities
Common shares, $5.00 par value 126,638,593 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:

COMPANIES

Citigroup.................. Citigroup, Inc.
CL&P....................... The Connecticut Light and Power Company
CRC........................ CL&P Receivables Corporation
CVEC....................... Connecticut Valley Electric Company
HWP........................ Holyoke Water Power Company
NAEC....................... North Atlantic Energy Corporation
NEON....................... NEON Communications, Inc.
NGC........................ Northeast Generation Company
NGS........................ Northeast Generation Services Company
NRG........................ NRG Energy, Inc.
NRG-PM..................... NRG Power Marketing, Inc.
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, NAEC 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

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
ARO........................ Asset Retirement Obligation
CSC........................ Connecticut Siting Council
CTA........................ Competitive Transition Assessment
EAC........................ Energy Adjustment Clause
EITF....................... Emerging Issues Task Force
EPS........................ Earnings per Share
FASB....................... Financial Accounting Standards Board
FIN........................ FASB Interpretation
GSC........................ Generation Services Charge
IPPs....................... Independent Power Producers
ISO-NE..................... New England Independent System Operator
kWh........................ Kilowatt-hour
LMP........................ Locational Marginal Pricing
MW......................... Megawatts
NU 2002 Form 10-K.......... The Northeast Utilities and Subsidiaries combined
2002 Form 10-K as filed with the SEC
NYMEX...................... New York Mercantile Exchange
O&M........................ Operation and Maintenance
Restructuring
Settlement............... Agreement to Settle PSNH Restructuring
RMR........................ Reliability Must Run
SMD........................ Standard Market Design
TS......................... Transition Service

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

TABLE OF CONTENTS
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Page
----
Part I. Financial Information

Item 1. Consolidated Financial Statements (Unaudited)

and

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

For the following companies:

Northeast Utilities and Subsidiaries

Consolidated Balance Sheets -
March 31, 2003 and December 31, 2002................... 2

Consolidated Statements of Income -
Three Months Ended March 31, 2003 and 2002............. 4

Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002............. 5

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

Independent Accountants' Report............................. 25

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

The Connecticut Light and Power Company
and Subsidiaries

Consolidated Balance Sheets -
March 31, 2003 and December 31, 2002................... 46

Consolidated Statements of Income -
Three Months Ended March 31, 2003 and 2002............. 48

Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002............. 49

Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 50

Public Service Company of New Hampshire
and Subsidiaries

Consolidated Balance Sheets -
March 31, 2003 and December 31, 2002................... 54

Consolidated Statements of Income -
Three Months Ended March 31, 2003 and 2002............. 56

Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002............. 57

Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 58

Western Massachusetts Electric Company
and Subsidiary

Consolidated Balance Sheets -
March 31, 2003 and December 31, 2002................... 62

Consolidated Statements of Income -
Three Months Ended March 31, 2003 and 2002............. 64

Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002............. 65

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

Item 3. Quantitative and Qualitative
Disclosures About Market Risk.......................... 68

Item 4. Controls and Procedures................................ 68

Part II. Other Information

Item 1. Legal Proceedings...................................... 69

Item 6. Exhibits and Reports on Form 8-K....................... 69

Signatures and Certifications Pursuant to Section 302
of the Sarbanes-Oxley Act of 2002..................................... 71

NORTHEAST UTILITIES AND SUBSIDIARIES

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 NU 2002 Form 10-K, and the
current report on Form 8-K dated January 28, 2003.

FINANCIAL CONDITION

Overview
- --------

Consolidated: Northeast Utilities (NU or the company) earned $60.2 million,
or $0.47 per share, in the first quarter of 2003, compared with earnings of
$18.6 million, or $0.14 per share, in the first quarter of 2002. Results for
the first quarter of 2002 included after-tax write-downs totaling $10
million, or $0.08 per share, related primarily to NU's investments in NEON
Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics). First
quarter 2003 results did not include any similar write-downs. Excluding
those write-downs, NU earned $28.6 million in the first quarter of 2002. All
per share amounts are reported on a fully diluted basis.

Higher 2003 first quarter earnings for NU were a result of improved results
at NU Enterprises. NU's earnings per share also benefited from its ongoing
share repurchase program. NU repurchased approximately 1.6 million shares at
an average price of $14.14 in the first quarter of 2003 and had approximately
126.6 million shares outstanding at March 31, 2003. NU can repurchase an
additional 5.5 million shares through June 30, 2003, under a resolution
adopted by the NU Board of Trustees.

NU's revenues in the first quarter of 2003 increased to $1.7 billion from
revenues of $1.3 billion in the same period of 2002 also contributing to the
improvement in earnings. The increase in revenues is due to increases in
electric and firm natural gas sales in 2003 as compared to 2002 as well as
higher NU Enterprises' revenues.

Utility Group: Overall, NU's Utility Group's performance in the first quarter
of 2003 was comparable to the same period of 2002. The Connecticut Light and
Power Company (CL&P) and Yankee Energy System, Inc. (Yankee) improved results
from 2002 while Public Service Company of New Hampshire (PSNH) and Western
Massachusetts Electric Company (WMECO) earned less in the first quarter of
2003. Much colder weather in 2003 benefited the Utility Group and resulted
in an 8.9 percent increase in regulated retail electric sales and an 18.3
percent increase in total regulated firm natural gas sales in the first three
months of 2003, compared with the same period of 2002. The pre-tax earnings
benefit related to these higher sales of approximately $21.5 million was
offset by a reduction in pre-tax pension income and the absence of earnings
related to the company's investment in the Seabrook nuclear power plant in
the first quarter of 2003 compared with the same period of 2002.

CL&P benefited from the colder weather resulting in a 9.1 percent increase in
retail sales in the first quarter of 2003, compared with the same period of
2002. Also during the first quarter of 2003, CL&P recorded the final impacts
of the Connecticut Department of Public Utility Control's (DPUC) final
decision on the use of the proceeds from the Millstone sale which was issued
on February 27, 2003. This decision resulted in an increase in CL&P's first
quarter 2003 net income of $2.6 million. CL&P's earnings before the payment
of preferred dividends totaled $26.7 million in the first quarter of 2003,
compared with $21.7 million in the same period of 2002.

Due to the colder weather which resulted in an 18.3 percent increase in firm
natural gas sales in the first quarter of 2003 from the same period of 2002,
Yankee earned $15.1 million in the first quarter of 2003, compared with $12.6
million in the same period of 2002.

Other portions of the Utility Group recorded somewhat lower earnings, despite
significant sales increases. PSNH earned $10.8 million in the first quarter
of 2003, compared with $11.7 million in the same period of 2002, despite an
8.1 percent increase in retail sales. PSNH's 2003 earnings were negatively
affected by a lower level of regulatory assets on which it earned a return,
primarily due to the sale of the Seabrook nuclear units which was consummated
on November 1, 2002. Net regulatory assets were reduced in November 2002 as a
result of the sale of North Atlantic Energy Corporation's (NAEC) 35.98
percent ownership interest in Seabrook. The reduction in net regulatory
assets will continue to negatively affect PSNH's 2003 to 2002 earnings
comparisons.

WMECO earned $6.1 million in the first quarter of 2003, compared with $6.9
million in the same period of 2002, despite a 9.2 percent increase in retail
sales. The lower earnings in 2003 were due to lower pension income, which
more than offset the impact of increased sales.

NU Enterprises: NU Enterprises, which includes Select Energy, Inc. (Select
Energy), NU's competitive wholesale and retail energy marketing subsidiary,
earned $5.2 million in the first quarter of 2003, compared with a loss of
$20.1 million in the first quarter of 2002. Select Energy's wholesale
business includes 1,438 megawatts (MW) of generation and an energy trading
function. The trading function has been significantly reduced in size over
the past year. The wholesale business earned $6.8 million in the first
quarter of 2003, compared with a loss of approximately $5.9 million in the
same period of 2002. The first quarter 2002 results included approximately
$10 million of after-tax energy trading losses. The 2003 results improved
due to better management of the wholesale marketing portfolio, including
better and more complete sourcing and the absence of net trading losses in
the first quarter of 2003.

Other areas of NU Enterprises, which include selling of electricity and
natural gas to retail end-users and energy services businesses, lost
approximately $1.6 million in the first quarter of 2003, compared with losses
of $14.2 million in the first quarter of 2002. The 2003 improved retail
results are primarily due to improved management of gas retail contracts
along with improved margins on retail electric sales.

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

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

Utility Group: The earnings range of between $1.10 per share and $1.30 per
share includes earnings of between $1.05 per share and $1.15 per share at the
Utility Group.

NU Enterprises: NU continues to project earnings of between $0.15 per share
and $0.25 per share at NU Enterprises.

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. At March 31, 2003, NU
had $99 million of cash and cash equivalents on hand, a $44.3 million
increase over March 31, 2002. At March 31, 2003, NU parent had $209.9
million invested in the NU system Money Pool, all of which was loaned to both
the Utility Group and NU Enterprises.

NU's net cash flows from operating activities decreased to $144.9 million in
the first quarter of 2003 from $221 million in the first quarter of 2002.
The primary reason for the decrease is the payment of $125.2 million of taxes
primarily on the gain on the sale of Seabrook, offset by a $41.6 million
increase in income before preferred dividends of subsidiaries.

NU's capital expenditures totaled $98 million in the first quarter of 2003
compared to $97.4 million in the first quarter of 2002. NU also paid $14.3
million of debt maturities and $42.9 million of rate reduction bond
maturities.

In the first quarter of 2003, NU's long-term debt was impacted by two events.
Select Energy Services, Inc. (SESI) issued $44.3 million of long-term debt
that was used to refinance $6.5 million of short-term debt, with the
remainder being used to finance ongoing projects. Also, NU executed an
interest rate swap related to its $263 million fixed-rate senior notes, which
resulted in a fair value adjustment to long-term debt of $5.1 million.

The level of common dividends totaled $17.5 million in the first quarter of
2003, compared with $16.2 million in the first quarter of 2002. The increase
resulted from NU paying a $0.1375 per share quarterly common dividend in the
first quarter of 2003 and a $0.125 per share quarterly dividend in the first
quarter of 2002.

Management expects to continue to increase the dividend level periodically,
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 2001 and 2002,
NU's Board of Trustees approved dividend increases at the time of the
company's annual meeting, effective in the third quarter of those years.
NU's next annual meeting will be held May 13, 2003, and management expects
the Board of Trustees to consider a quarterly dividend increase at that time,
effective in the third quarter of 2003. On April 8, 2003, the NU Board of
Trustees approved a dividend of $0.1375 per share, payable June 30, 2003, to
shareholders of record at June 1, 2003.

Utility Group: At March 31, 2003, NU's Utility Group had $35 million borrowed
on their $300 million revolving credit agreement. This credit line matures
in November 2003.

In addition to its revolving credit arrangement, CL&P can access up to $100
million by selling certain of its accounts receivable. At March 31, 2003,
CL&P had $60 million of accounts receivable sold under this arrangement. At
December 31, 2002, $40 million of accounts receivable were sold. These
amounts are not reflected as obligations on the accompanying consolidated
balance sheets.

CL&P has withdrawn its application before the DPUC to fund approximately $200
million of spent nuclear fuel obligations. WMECO has an application pending
with the Massachusetts Department of Telecommunications and Energy (DTE) to
issue $100 million of unsecured long-term debt to fund its spent nuclear fuel
obligations and to reduce short-term borrowings.

NU Enterprises: NU parent and NU Enterprises had $60 million of borrowings
and $28.2 million of letters of credit drawn on their $350 million revolving
credit agreement. This credit line matures in November 2003.

NU expects to issue $100 million to $150 million of unsecured, five-year
fixed-rate senior notes in the second quarter of 2003 to refinance short-term
debt.

Implementation of Standard Market Design
- ----------------------------------------

On March 1, 2003, the New England Independent System Operator (ISO-NE)
implemented a new standard market design (SMD). As part of SMD, locational
marginal pricing (LMP) is 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. Prior to March 1, 2003, those costs were spread across
virtually all New England electric customers. 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 other New England states. The three
components of the LMP for each zone are an energy cost, congestion costs and
line loss costs. LMP is expected to increase costs in zones that have
inadequate or less cost-efficient generation and/or transmission constraints,
such as Connecticut, and decrease costs in zones that have significant excess
generation, such as Maine. The implementation of SMD may impact 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.
Due to high loads, transmission constraints and inadequate generation,
Connecticut could experience significant additional congestion costs under
SMD. ISO-NE estimates that the costs of transmission congestion for 2003 in
New England under SMD will range between $50 million and $300 million. ISO-
NE estimates that the majority of this congestion and its costs will be in
Connecticut, where approximately 80 percent is expected to be paid by CL&P
beginning on March 1, 2003.

In addition to the congestion cost component of LMP, the determination of the
energy delivery points associated with the standard offer service contracts
will also produce significant line loss charges for CL&P. For March 2003,
incremental LMP costs totaled $15.5 million. The majority of these
incremental costs were associated with line losses, and management expects
comparable monthly line loss charges for the remainder of 2003.

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. Management
believes that under the terms of its standard offer service contracts with
its standard offer suppliers the incremental costs associated with 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 $15.5 million of incremental costs incurred in March 2003 were recorded
as recoverable energy costs at March 31, 2003, which are included in
regulatory assets, for future recovery from 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. Accordingly, management
believes that these costs should be recovered from its customers and will not
impact 2003 earnings.

On April 1, 2003, an informational hearing on SMD was held before the DPUC.
On April 22, 2003, CL&P filed an application with the DPUC to recover their
2003 incremental LMP costs starting in May 2003. On May 1, 2003, the DPUC
issued a final decision in response to CL&P's April 22, 2003 filing. In its
decision, the DPUC directed CL&P to pursue legal remedies against its
standard offer suppliers in an effort to assign liability for incremental LMP
costs to 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. Recovery
of incremental LMP costs will be allowed through the Energy Adjustment Clause
(EAC) but will be subject to refund and posting of a surety bond. Recovery
is approved for sixty days, before the end of which period CL&P will be
required to report the status of the steps it has taken in its legal actions
against its standard offer suppliers. CL&P began recovery of the incremental
March 2003 LMP costs of $15.5 million in its May 1, 2003 bills to customers.
The incremental April 2003 LMP costs of $15.6 million will be collected in
June 2003 bills.

On May 5, 2003, CL&P filed a response to the decision with the DPUC. CL&P
intends to request a declaratory judgment from the Federal Energy Regulatory
Commission (FERC) to determine whether CL&P's standard offer service
suppliers are responsible for incremental LMP costs. Additionally, CL&P
intends to withhold payment of incremental LMP costs to its standard offer
service suppliers pending resolution of this matter.

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 Utility Group was responsible for approximately 25 percent of
these costs. Effective with the March 1, 2003 implementation of SMD, RMR
costs will be allocated to the load zone in which the RMR unit is located.
At present, the only load zone that will experience an RMR cost increase in
which the Utility Group operates is Connecticut. Reliability costs have been
previously approved for recovery by the DPUC in CL&P's 2001 Competitive
Transition Assessment (CTA) reconciliation filing. All RMR costs, which began
in 2002 and are considered reliability costs, 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. 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. Management cannot
determine the impact on the components of LMP in the market related to these
arrangements at this time.

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 first quarter of
2003 would be reduced by $7.8 million. Also, NU Enterprises' and NU's
earnings estimates do not include incremental LMP costs, which could be
substantial for the remainder of 2003.

Other impacts of SMD on its wholesale marketing business could be
significant. As more information regarding the various impacts of SMD
becomes available, there could be additional adverse effects that management
cannot determine at this time.

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

Subsidiaries: NU Enterprises, Inc. is the parent company of Select Energy,
Northeast Generation Company (NGC), SESI, Northeast Generation Services
Company (NGS), and their respective subsidiaries, which is referred to as "NU
Enterprises," collectively. Holyoke Water Power Company (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 owns 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: NU Enterprises improved financial performance in the first quarter
of 2003 compared to the first quarter of 2002. Management continues to
believe that NU Enterprises will earn $0.15 to $0.25 per share for 2003.

The wholesale marketing business obtained a significant level of new
contracts in the first quarter of 2003. On March 1, 2003, Select Energy
began serving Central Maine Power and Bangor-Hydro Electric Company under a
new six-month agreement that is expected to generate $30 million in revenue.
Select Energy was also successful in obtaining 1,200 MW of sales contracts in
the latest New Jersey basic generation service auction. Select Energy
estimates it will sell 700 MW for a 10-month period beginning August 1, 2003,
and 500 MW for a 34-month period also beginning August 1, 2003. These
contracts are expected to generate approximately $400 million in revenue.
Select Energy also entered into a new six-month contract with National Grid
for default service for certain of its subsidiaries that started in late
April 2003. This contract is expected to generate $75 million of additional
revenue through October 2003. In addition to new business, more normal
precipitation would positively impact NGC's hydroelectric generating plants.
Output has already increased in the first quarter of 2003 by about 40 percent
compared to the first quarter of 2002 resulting in $1.6 million of additional
earnings in 2003 as compared to 2002. Management currently believes that the
wholesale marketing business will generate the gross margins required to meet
their 2003 earnings estimate. Approximately 85 percent of the total margin
needed to meet the wholesale marketing business' 2003 earnings estimate has
been contracted in the first quarter of 2003. To meet the earnings estimate,
the wholesale marketing business will need to successfully manage its
portfolio of contracts to retain the estimated origination margins.

The retail marketing business incurred losses of approximately $2 million in
the first quarter of 2003, compared with losses of approximately $14 million
in the first quarter of 2002. Management is hopeful that the retail group,
as previously projected, will achieve break-even financial performance for
2003. However, through the first quarter of 2003, approximately 40 percent
of the margin needed to cover projected costs and break-even has been
contracted. Retail gas customers have been 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. The
retail marketing business will also need to manage its portfolio to realize
the estimated margin for the contracts it has already entered into but has
not yet served.

Intercompany Transactions: CL&P's standard offer service purchases from
Select Energy represented approximately $141 million of total NU Enterprises'
revenues for the first quarter of 2003. Other transactions between CL&P and
Select Energy amounted to approximately $36 million in revenues for Select
Energy in the first quarter of 2003. Select Energy continues to provide
standard offer service for its affiliate WMECO through December 31, 2003.
WMECO's purchases from Select Energy represented approximately $39 million of
total NU Enterprises' revenues in the first quarter 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 NU Enterprises, including Select Energy, is organized
by management to address the market, credit and operational exposures arising
from the company's primary business segments: 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
overall 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 March 31, 2003, the wholesale marketing portfolio, which includes the CL&P
standard offer service contract 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 is significant
volatility in the energy commodities markets that will 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 in 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
earnings.

At March 31, 2003, Select Energy had trading derivative assets of $162.8
million and trading derivative liabilities of $117 million on a counterparty-
by-counterparty basis, for a net positive position of $45.8 million on 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 trading 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
March 31, 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 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. 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 which is marked to model. This contract expires in 2006 and had a
fair value of $4.7 million at March 31, 2003. Broker quotes for electricity
are available through the year 2005, and models are generally used for the
years 2006 and thereafter.

Select Energy has sourced contracts with maturities in excess of four years.
Accordingly, the value of these contracts and the related power supply
contracts do not need to be determined with a model. Broker quotes for
natural gas are available through 2013.

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

As of and for the three months ended March 31, 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 March 31, 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 $(3.5) $ 0.1 $ - $(3.4)
Prices provided by
external sources 8.8 18.6 17.1 44.5
Prices based on
models or other
valuation methods - 4.7 - 4.7
- -------------------------------------------------------------------------------
Totals $ 5.3 $23.4 $17.1 $45.8
- -------------------------------------------------------------------------------

The fair value of energy trading contracts increased $4.8 million from $41
million at December 31, 2002 to $45.8 million at March 31, 2003. This
increase is primarily due to a positive change in fair value of existing
contracts and to contracts realized or otherwise settled during the period.
There were no changes in valuation techniques or assumptions in the first
quarter of 2003.

- -------------------------------------------------------------------------------
(Millions of Dollars) Total Fair Value
- -------------------------------------------------------------------------------
Three Months Ended
March 31, 2003
- -------------------------------------------------------------------------------
Fair value of trading contracts outstanding
at the beginning of the period $41.0
Contracts realized or otherwise settled
during the period (2.8)
Fair value of new contracts when entered
into during the period -
Changes in fair values attributable to
changes in valuation techniques and
assumptions -
Changes in fair value of contracts 7.6
- -------------------------------------------------------------------------------
Fair value of trading contracts
outstanding at the end
of the period $45.8
- -------------------------------------------------------------------------------

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
determine the estimated fair value of its long-term wholesale marketing
energy contracts.

Changes are occurring in the administration of transmission systems 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 in advance, letters of credit, and parent guarantees), and
the use of standardized agreements, which allow for the netting of positive
and negative exposures associated with a single counterparty. This
evaluation results in establishing credit limits prior to Select Energy
entering into trading activities. The appropriateness of these limits is
subject to continuing review. Concentrations among these counterparties may
impact Select Energy's overall exposure to credit risk, either positively or
negatively, in that the counterparties may be similarly affected by changes
to economic, regulatory or other conditions. At March 31, 2003,
approximately 75 percent of Select Energy's counterparty credit exposure to
wholesale marketing and trading counterparties was cash collateralized or
rated BBB- or better. Approximately five percent of the counterparty credit
exposure was to unrated municipalities.

At March 31, 2003, positions with three counterparties collectively
represented approximately $66 million or 41 percent of the $162.8 million
trading derivative assets. One of these counterparties has an investment
grade credit rating. Another counterparty's position is secured with letters
of credit and cash collateral. The third counterparty representing
approximately $17.3 million is an unrated generation entity. None of the
other counterparties represented more than 10 percent of the trading derivative
assets. Select Energy manages the credit risk of its trading portfolio in
accordance with established credit risk management policies and procedures.

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 $206 million of collateral or letters of credit to various
unaffiliated counterparties and approximately $63 million to several
independent system operators and unaffiliated local distribution companies,
which management believes NU would be able to provide. NU's ratings are
currently stable, and management does not believe that at this time there is
a significant risk of a ratings downgrade to sub-investment grade levels.

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

Utility Group: In October 2001, CL&P filed an application with the
Connecticut Siting Council (CSC) to construct a new 345,000 volt overhead
transmission line from Norwalk, Connecticut to Bethel, Connecticut. The line
would help address the difficulties in serving the load in southwest
Connecticut that create high LMP costs in Connecticut. In March 2003, CL&P
revised its proposal following a settlement with the towns through which the
transmission line is proposed. The proposal would place approximately half
of the line underground and would increase the cost to $185 million from $135
million. The CSC is expected to vote on the proposal in June 2003, and CL&P
hopes to begin construction by the end of 2003 and place the line into
service in mid-2005. At March 31, 2003, CL&P had capitalized approximately
$9.1 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 with CL&P owning 80 percent or approximately $400 million of the
project. At March 31, 2003, CL&P had capitalized approximately $3.2 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 and the uncertainty created by the recent damage to the existing
transmission line, the expected in-service date is currently under
evaluation. At March 31, 2003, CL&P had capitalized approximately $5.3
million related to this project.

Yankee Gas Services Company (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 with a final decision expected in the second quarter of 2003. If
approved, construction of the facility, which is expected to cost
approximately $60 million, could begin in the fourth quarter of 2003. At
March 31, 2003, Yankee Gas had capitalized approximately $0.8 million related
to this project.

In late May 2003, the Governor of New Hampshire is expected to sign into law
a bill that will permit PSNH to acquire 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 the New Hampshire
Public Utilities Commission (NHPUC) and is expected to close in December
2003.

Merchant Energy Company Counterparty Exposures
- ----------------------------------------------

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

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

Connecticut - CL&P: Since retail competition began in Connecticut in 2000,
only a small number of customers have opted to choose an alternate supplier
as virtually all of CL&P's customers have continued to procure their
electricity through CL&P's standard offer service. In 2003, Select Energy
will continue to supply 50 percent of CL&P's standard offer supply service
with NRG-PM, a subsidiary of NRG, contracted to supply 45 percent and a
subsidiary of Duke Energy, Inc. contracted to supply the remaining 5 percent
of service.

CL&P continues to evaluate NRG-PM's ability to meet its obligations under the
standard offer service contract, including the possibility that NRG-PM and
the other standard offer service suppliers could ultimately be responsible
for incremental LMP costs. 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, should they be incurred,
would be permitted under the provisions of Connecticut's electric utility
restructuring legislation and with the DPUC's prior decisions. On February 21,
2003, Fitch Ratings lowered its rating outlook on CL&P to negative as a
result of its concern over timely recovery of purchased-power costs if NRG-PM
were to default on its CL&P standard offer obligations and CL&P needs to
acquire replacement supply service at significantly higher prices.

On September 27, 2001, CL&P filed its application with the DPUC for approval
of the disposition of the proceeds in the amount of approximately $1.2
billion from the sale of the Millstone units. The DPUC's final decision
regarding this application was issued on February 27, 2003, and decreased the
amount of net proceeds used to reduce stranded costs to $26.9 million from
the $40.1 million reduction of stranded costs in its draft decision. The
earnings impact in the first quarter of 2003 of the final decision resulted
in an increase in net income of $2.6 million.

CL&P continues to be subject to the earnings sharing mechanism implemented by
the DPUC, under which CL&P's earnings in excess of a 10.3 percent return on
equity will be shared equally by shareholders and ratepayers. The next
earnings sharing calculation will be based on CL&P's earnings for the twelve
months ended June 30, 2003.

On April 3, 2003, CL&P filed its annual CTA and Systems Benefit Charge (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. CL&P has
proposed that a portion of the CTA/GSC overrecovery be utilized to reduce
nuclear stranded costs and the remaining amount be carried forward to 2003.
For the same period, SBC revenues exceeded the SBC revenue requirement by
approximately $21.4 million. After allocating a portion of the SBC
overrecovery as ordered by the DPUC in a prior decision, CL&P has proposed
that the remaining overrecovery of $18.6 million be applied to the CTA.
Management expects a decision from the DPUC in this docket by the end of
2003.

CL&P expects to file a distribution rate case with the DPUC in mid-2003 that
would be effective January 1, 2004. Also in the second half of 2003, CL&P
will need to secure bids for power supply contracts for 2004 to meet the
needs of its customers. Management has not yet identified what level of
rates it will request for 2004, but believes that several factors could
combine to result in a significant increase in supply costs in 2004. The
first is the expiration of current standard offer supply contracts. Another
factor is the impact of LMP. CL&P's reliability improvements and transmission
construction program will also impact the level of rates CL&P will request in
2004.

The Connecticut state legislature is considering revisions to its 1998
electric utility industry restructuring statutes. Senate Bill 733 passed the
Energy and Public Utilities and Environment committees in early 2003. Among
other actions, the bill would 1) extend the offering of standard offer
service rates for an additional three years to January 1, 2007; 2) allow base
rates to return to 1996 levels, which are above existing levels; and 3) allow
electric distribution companies, such as CL&P, to earn a transaction
management fee for buying standard offer service for retail customers. The
legislation, if passed and signed by the Connecticut Governor, would likely
impact the aforementioned CL&P distribution rate case.

Various Connecticut state budget proposals would direct approximately $100
million of electric utility revenues to the state's general fund, rather than
toward energy conservation programs. In 2002, CL&P earned approximately $3.3
million in incentive payments on its energy conservation programs, and future
earnings from conservation programs would be reduced if one of these budget
proposals passes unchanged.

Connecticut - Yankee Gas: In December 2002, the DPUC opened a new docket
concerning Yankee Gas overearnings. Yankee Gas received a draft decision
related to this docket on May 2, 2003. In the draft decision, the DPUC
indicated that Yankee Gas' rates do not need to be adjusted. A final
decision is expected on May 14, 2003.

On May 7, 2003, the DPUC issued a draft decision in the Infrastructure
Expansion Rate Mechanism (IERM) docket. The draft decision concludes that
the basic concept of IERM is valid, appropriate and beneficial. In the draft
decision, the DPUC estimated 2003 IERM overrecoveries of $3.6 million and
proposed refund of overrecoveries to customers from December 2003 through
February 2004. The final decision is scheduled for May 21, 2003. If the
final decision is consisent with the draft decision, management does not
expect that the decision will have a material impact on results of operations.

New Hampshire: On February 1, 2003, in accordance with the "Agreement to
Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH
raised the transition service (TS) rate for residential and small commercial
customers to $0.0460 per kilowatt-hour (kWh) from $0.0440 per kWh. On the
same date, PSNH also raised its TS rate for large commercial and industrial
customers to $0.0467 per kWh from $0.0440 per kWh. Given recent changes in
the energy markets, PSNH is unable to determine if these rates will be
adequate to currently recover its generation and purchased-power costs,
including the recovery of carrying costs on PSNH's generation investment. If
actual costs exceed those recoveries, PSNH will defer those costs for future
recovery from customers through its Stranded Cost Recovery Charge (SCRC). If
recoveries exceed PSNH's costs, those overrecoveries will be credited against
PSNH's Part 3 stranded cost balance.

PSNH's delivery rates are fixed by the Restructuring Settlement until
February 1, 2004. Under the Restructuring Settlement, PSNH must file a rate
case by December 31, 2003, for the purpose of commencing a review of PSNH's
delivery rates.

In April 2003, the New Hampshire state legislature approved legislation that
would require PSNH to retain ownership of its fossil and hydroelectric
generation assets until April 30, 2006. Subsequent to that time, PSNH may
sell the assets if the NHPUC finds such sale to be in the best economic
interest of customers. On April 23, 2003, the Governor of New Hampshire
signed the bill into law. This legislation effectively extends the time
period in which PSNH is required to supply TS and default service to its
retail customers until the sale of its fossil and hydroelectric generation
assets. The NHPUC will continue its regulatory oversight of TS and default
service rates.

On May 1, 2003, PSNH made a SCRC reconciliation filing with the NHPUC for the
period January 1, 2002, through December 31, 2002. This filing reconciles
stranded cost revenues against actual stranded costs with any difference
being credited against Part 3 stranded costs or deferred for future recovery.
Included in this stranded cost reconciliation filing are 1) a calculation of
the generation costs for the filing period, 2) the Seabrook sale net proceeds
calculation and 3) a request to recover, as a non-securitized stranded cost,
certain deferred costs associated with PSNH's initial efforts to sell its
fossil and hydroelectric generation assets as was previously required by the
Restructuring Settlement. Management does not expect that the outcome of
this docket will have a material adverse impact on PSNH's earnings or its
financial position.

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. In May 2003, the NHPUC is expected to issue 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. Under the terms of this
settlement, PSNH will make a lump sum payment totaling $20.4 million to the
fourteen IPPs on May 31, 2003, in exchange for the termination of the
existing power purchase obligations between PSNH and these IPPs. The buy out
costs will be deferred as a regulatory asset, and recovered, including a
return, over the remaining term of the initial contractual arrangements as a
Part 2 stranded cost.

Massachusetts: In December 2002, the DTE approved an overall increase of
approximately 1.8 percent in WMECO's non-contract retail delivery rates,
primarily reflecting slightly increased standard offer costs as well as other
inflationary factors. WMECO's standard offer service is supplied by Select
Energy at a rate for 2003 of approximately $0.0500 per kWh. An unaffiliated
company won the bid to serve WMECO's default service for the period of
January 1, 2003, through June 30, 2003, at an average price of $0.0510 per
kWh.

On March 31, 2003, WMECO filed its 2002 annual transition cost reconciliation
with the DTE. This filing reconciled the recovery of stranded generation
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.

On April 24, 2003, the DTE issued an order addressing three issues dealing
with the future procurement of default service: 1) the cost components to be
included in the calculation of default service rates, 2) default service
pricing options and procurement strategies and 3) the appropriate role of
distribution companies in moving their customers toward competitive supply.
While making changes in the way WMECO procures default service supply for its
customers, the order will not have an impact on WMECO's earnings.

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

Funded Status of Pension Plan: 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 April 30, 2003, the estimated fair value of Plan assets
exceeded the December 31, 2002 ABO by approximately $101 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 liability.

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

Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 4, "Commitments and Contingencies,"
to the consolidated financial statements.

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

RESULTS OF OPERATIONS

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

Income Statement Variances
(Millions of Dollars)
2003 over/(under) 2002
----------------------
Amount Percent
------ -------

Operating Revenues $404 31%

Operating Expenses:
Fuel, purchased and
net interchange power 343 47
Other operation (9) (4)
Maintenance (6) (12)
Depreciation (3) (5)
Amortization 37 (a)
Amortization of rate reduction bonds (7) (15)
Taxes other than income taxes (1) (1)
---- ----
Total operating expenses 354 30
---- ----

Operating income 50 44
---- ----

Interest expense, net (3) (5)
Other income/(loss), net 15 (a)
---- ----
Income before income tax expense 68 (a)
Income tax expense 26 (a)
---- ----
Income before preferred
dividends of subsidiaries 42 (a)
---- ----
Preferred dividends of subsidiaries - -
---- ----
Net income $ 42 (a)%
==== ====

(a) Percent greater than 100.

Comparison of the First Quarter of 2003 to the First Quarter of 2002

Operating Revenues
Total revenues increased by $404 million or 31 percent in the first quarter
of 2003, compared with the same period in 2002, due to higher revenues from
NU Enterprises ($231 million after intercompany eliminations) and higher
Utility Group revenues ($173 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. The Utility Group revenue increase is primarily due to higher
retail revenue ($119 million) and higher wholesale revenue ($54 million).
The regulated retail revenue increase is primarily due to higher retail
electric sales ($73 million) and higher Yankee revenue resulting from higher
purchased gas adjustment clause revenue ($27 million) and higher sales
volumes ($21 million). Regulated retail electric kWh sales increased by 8.9
percent and firm natural gas sales increased by 18.3 percent in the first
quarter of 2003. The regulated wholesale revenue increase is primarily due
to higher prices in 2003.

Fuel, Purchased and Net Interchange Power
Fuel, purchased and net interchange power expense increased by $343 million
or 47 percent in the first quarter of 2003, primarily due to higher wholesale
activity at NU Enterprises ($257 million after intercompany eliminations) and
higher purchased-power costs for the Utility Group primarily as a result of
power purchased to serve higher retail sales ($90 million after intercompany
eliminations).

Other Operation and Maintenance
Other operation and maintenance (O&M) expenses decreased $15 million in the
first quarter of 2003, primarily due to lower nuclear expenses as a result of
the sale of Seabrook in the last quarter of 2002 ($18 million), partially
offset by higher distribution costs ($3 million).

Depreciation
Depreciation decreased in 2003 due to lower decommissioning expenses
resulting from the sale of Seabrook in the last quarter of 2002 ($2 million),
lower NU Enterprises' depreciation resulting from the study to lengthen the
useful lives of certain generation assets ($3 million), partially offset by
higher Utility Group depreciation resulting from higher plant balances.

Amortization
Amortization increased 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 ($37 million),
partially offset by the decrease in amortization of rate reduction bonds ($7
million).

Interest Expense, Net
Interest expense, net decreased in the first quarter of 2003, primarily due
to lower rate reduction bond interest ($2 million) and the retirement of
NAEC's debt in November of 2002 ($1 million).

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

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

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 March 31, 2003,
and the related condensed consolidated statements of income and cash flows
for the three-month periods ended March 31, 2003 and 2002. 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.

We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet and
consolidated statement of capitalization of Northeast Utilities and
subsidiaries as of December 31, 2002, 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 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
May 9, 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 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 2002 Form 10-K, and the current report
on Form 8-K dated January 28, 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 March 31, 2003, the results of operations and
statements of cash flows for the three-month periods ended
March 31, 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 three-month periods ended
March 31, 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.

B. Regulatory Accounting and Assets

The accounting policies of NU's Utility Group conforms 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:

---------------------------------------------------------------------
March 31, December 31,
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Recoverable nuclear costs $ 138.5 $ 85.4
Securitized regulatory assets 1,848.0 1,891.8
Income taxes, net 294.8 331.9
Unrecovered contractual obligations 237.1 239.3
Recoverable energy costs, net 293.3 299.6
Other 21.5 61.9
---------------------------------------------------------------------
Totals $2,833.2 $2,909.9
---------------------------------------------------------------------

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 in SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended. 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 adopted net reporting effective July 1, 2002,
before this consensus was reached by the EITF.

The three months ended March 31, 2002, reflect net reporting. The
effects of this reporting for the three months ended March 31,
2002, which have been previously reported, are as follows:

---------------------------------------------------------------------
Operating Fuel, Purchased and
Revenues Net Interchange Power
---------------------------------------------------------------------
(Millions of Dollars)
---------------------------------------------------------------------
Operating Revenues:
As previously
reported $1,910.7 $1,352.8
Impact of
reclassification (626.2) (626.2)
---------------------------------------------------------------------
As currently
reported $1,284.5 $ 726.6
---------------------------------------------------------------------

The EITF continues to consider guidance on accounting for energy
trading activities. The EITF has proposed Issue No. 02-L,
"Reporting Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133, and Not Held for Trading
Purposes." EITF Issue No. 02-L is expected to address whether or
not gains or losses on non-trading derivatives should be presented
gross as revenues and expenses or on a net basis in revenues.

Management will determine the impact, if any, that EITF Issue No.
02-L will have on the classification of revenues and expenses if
and when the EITF reaches a consensus.

Derivative Accounting: Effective January 1, 2001, NU adopted SFAS
No. 133, 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 FASB Derivative
Implementation Group guidance, clarifies certain conditions, and
amends other existing pronouncements. Management is evaluating the
impact of SFAS No. 149 on the consolidated financial statements,
but does not believe that there will be a significant impact as a
result of the issuance of this new statement.

Asset Retirement Obligations: In June 2001, the 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 and when a reasonable
estimate of the fair value of the liability can be made. NU
adopted SFAS No. 143 on January 1, 2003. For the adoption of SFAS
No. 143, management completed a review for potential asset
retirement obligations (AROs), and did not identify any material
AROs that have been incurred. However, management has identified
certain removal obligations which arise in the ordinary course of
business that either have a low probability of occurring or are not
material in nature. These types of obligations would be recorded
as they are incurred and relate to transmission and distribution
lines and poles, telecommunication towers, transmission cables and
certain Federal Energy Regulatory Commission or state regulatory
agency re-licensing issues.

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." FIN 45 requires that disclosures be made 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. FIN 45 does not
apply to certain guarantee contracts, such as residual value
guarantees provided by lessees in capital leases, guarantees that
are accounted for as derivatives, guarantees that represent
contingent consideration in a business combination, guarantees
issued between either parents and their subsidiaries or
corporations under common control, a parent's guarantee of a
subsidiary's debt to a third party, and a subsidiary's guarantee of
the debt owed to a third party by either its parent or another
subsidiary of that parent. The initial recognition and initial
measurement provisions of FIN 45 are applicable to NU on a
prospective basis to guarantees issued or modified after January 1,
2003. The adoption of the initial recognition and initial
measurement provisions of FIN 45 had no impact on NU's consolidated
financial statements.

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 under these obligations by NU Enterprises. NU
currently has authorization from the Securities and Exchange
Commission to provide up to $500 million of guarantees through
September 30, 2003, and has applied for authority to increase this
amount to $750 million. At March 31, 2003, payments guaranteed by
NU, primarily on behalf of NU Enterprises, totaled $236.8 million.
Additionally, NU had $28.2 million of letters of credit outstanding
at March 31, 2003, and in conjunction with its investment in R.M.
Services, Inc., NU guarantees a $3 million line of credit through
2005. Also, in conjunction with its wholly owned subsidiary Select
Energy Services, Inc. (SESI), NU provides guarantees of
approximately $2 million in connection with SESI's issuance of debt
under arrangements with a third party financing of long-term
receivables.

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 table illustrates
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.

---------------------------------------------------------------------
For the Three Months Ended
---------------------------------------------------------------------
(Millions of Dollars, March 31, March 31,
except per share amounts) 2003 2002
---------------------------------------------------------------------
Net income, as reported $60.2 $18.6
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 $59.6 $17.5
---------------------------------------------------------------------
Earnings per share:
Basic and fully
diluted - as reported $ 0.47 $ 0.14
Basic and fully
diluted - pro forma $ 0.47 $ 0.14
---------------------------------------------------------------------

During the first quarter of 2003, NU granted approximately 375,000
shares of restricted stock under the Incentive Plan. For the three
months ended March 31, 2003, approximately $0.1 million was
expensed related to the restricted stock. 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 Three Months Ended
---------------------------------------------------------------------
March 31, March 31,
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Investment write-downs $ - $(17.1)
Investment income 3.9 5.0
Other, net (3.3) (1.9)
---------------------------------------------------------------------
Totals $ 0.6 $(14.0)
---------------------------------------------------------------------

F. Sale of Customer Receivables

CL&P has an arrangement with a subsidiary of Citigroup, Inc.
(Citigroup) under which CL&P can sell up to $100 million of
accounts receivable. At March 31, 2003, CL&P had sold accounts
receivable of $60 million to Citigroup with limited recourse
through CL&P Receivables Corporation (CRC), a wholly owned
subsidiary of CL&P. Additionally, at March 31, 2003, $6.1 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 March 31, 2003, amounts sold to CRC from CL&P but not sold to
the Citigroup subsidiary totaling $155.8 million are included in
investments in securitizable assets on the consolidated balance
sheets. At March 31, 2003 and December 31, 2002, $60 million and
$40 million of accounts receivable were sold, respectively.

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 earnings. 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 earnings. 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 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 earnings. 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 quarter of 2003, a negative $5.1 million, net of
tax, was reclassified from other comprehensive income in connection
with the consummation of the underlying hedged transactions and
recognized in earnings. A negative $0.2 million, net of tax, was
recognized in earnings for those derivatives that were determined
to be ineffective and for the ineffective portion of cash flow
hedges. Also during the first quarter of 2003, new cash flow hedge
transactions were entered into which 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 $3.7
million, net of tax. Accumulated other comprehensive income at
March 31, 2003, was a positive $11.8 million, net of tax (increase
to equity), relating to hedged transactions, and it is estimated
that $7.2 million of this balance, net of tax, will be reclassified
as an increase to earnings 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
March 31, 2003 and December 31, 2002. These amounts do not include
premiums paid, which are recorded as prepayments and amounted to
$20.2 million and $26.7 million at March 31, 2003 and December 31,
2002, respectively. These amounts also do not include premiums
received, which are recorded as other current liabilities and
amounted to $24.1 million and $33.9 million at March 31, 2003 and
December 31, 2002, respectively. The premium amounts relate
primarily to energy trading activities.

---------------------------------------------------------------------
At March 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
Select Energy:
Trading $162.8 $(117.0) $45.8
Nontrading 3.0 (0.8) 2.2
Hedging 24.7 (7.8) 16.9
---------------------------------------------------------------------
Yankee Gas:
Hedging 2.8 - 2.8
---------------------------------------------------------------------
NU Parent:
Hedging 5.1 - 5.1
---------------------------------------------------------------------
Total $198.4 $(125.6) $72.8
---------------------------------------------------------------------

---------------------------------------------------------------------
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 March 31, 2003 and at December 31, 2002
were assets of $45.8 million and $41.0 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 quotes; and bilateral contracts for the purchase or sale of
electricity or natural gas, the fair value of which is modeled
using available information from external sources based on recent
transactions and validated with a gas forward curve and an
estimated heat rate conversion. Select Energy's trading portfolio
also includes transmission congestion contracts. The fair value of
certain transmission congestion contracts is based on market
inputs. 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
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 by SFAS No. 133. 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 March 31, 2003 and at December 31, 2002
were assets of $2.2 million and $2.9 million, respectively.

Select Energy Hedging: Select Energy utilizes derivative financial
and commodity instruments, including futures and forward contracts,
to reduce market risk associated with fluctuations in the price of
electricity and natural gas purchased to meet firm sales
commitments to certain customers. Select Energy also utilizes
derivatives, including price swap agreements, call and put option
contracts, and futures and forward contracts, to manage the market
risk associated with a portion of its anticipated retail supply
requirements. These derivatives have been designated as cash flow
hedging instruments and are used to reduce the market risk
associated with fluctuations in the price of electricity, natural
gas, or oil. A derivative that hedges exposure to the variable
cash flows of a forecasted transaction (a cash flow hedge) is
initially recorded at fair value with changes in fair value
recorded in other comprehensive income. Hedges impact earnings
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
2004. Select Energy has hedged its gas supply risk under these
agreements through NYMEX futures contracts. Under these contracts