FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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)
1000 Elm 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
33-43508 NORTH ATLANTIC ENERGY CORPORATION 06-1339460
(a New Hampshire corporation)
1000 Elm Street
Manchester, New Hampshire 03105-0330
Telephone: (603) 669-400
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
- ---------- ------------------- ---------------------
Northeast Utilities Common Shares, New York Stock Exchange, Inc.
$5.00 par value
The Connecticut 9.3% Cumulative New York Stock Exchange, Inc.
Light and Power Monthly Income
Company Preferred Securities
Series A (1)
(1) Issued by CL&P Capital LP (CL&P LP), a wholly owned subsidiary of The
Connecticut Light and Power Company (CL&P), and guaranteed by CL&P.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class
---------- -------------------
The Connecticut Light Preferred Stock, par value $50.00 per share,
and Power Company issuable in series, of which the following
series are outstanding:
$1.90 Series of 1947 4.96% Series of 1958
$2.00 Series of 1947 4.50% Series of 1963
$2.04 Series of 1949 5.28% Series of 1967
$2.20 Series of 1949 $3.24 Series G of 1968
3.90% Series of 1949 6.56% Series of 1968
$2.06 Series E of 1954
$2.09 Series F of 1955
4.50% Series of 1956
Public Service Company Preferred Stock, par value $25.00 per share,
of New Hampshire issuable in series, of which the following series
is outstanding:
10.60% Series A of 1991
Western Massachusetts Preferred Stock, par value $100.00 per share,
Electric Company issuable in series, of which the following series
is outstanding:
7.72% Series B of 1971
Class A Preferred Stock, par value $25.00 per
share, issuable in series, of which the following
series is outstanding:
7.60% Series of 1987
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 if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par
Value, held by nonaffiliates, was $3,035,128,320 based on a closing sales
price of $20.40 per share for the 148,780,800 common shares outstanding on
February 28, 2001. Northeast Utilities holds all of the 7,584,884 shares,
1,000 shares, 590,093 shares, and 1,000 shares of the outstanding common
stock of The Connecticut Light and Power Company, Public Service Company
of New Hampshire, Western Massachusetts Electric Company, and North Atlantic
Energy Corporation, respectively.
Documents Incorporated by Reference:
Part of Form 10-K
into Which Document
Description is Incorporated
----------- -------------------
Portions of Annual Reports of the following
companies for the year ended December 31, 2000:
The Connecticut Light and Power Company Part II
Public Service Company of New Hampshire Part II
Western Massachusetts Electric Company Part II
North Atlantic Energy Corporation Part II
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
Con Edison......................... Consolidated Edison, Inc.
CYAPC.............................. Connecticut Yankee Atomic Power Company
Dominion........................... Dominion Resources, Inc.
HEC................................ HEC Inc.
HWP................................ Holyoke Water Power Company
Mode 1............................. Mode 1 Communications, Inc.
MYAPC.............................. Maine Yankee Atomic Power Company
NAEC............................... North Atlantic Energy Corporation
NAESCO............................. North Atlantic Energy Service Corporation
NEON............................... NEON Communications, Inc.
NGC................................ Northeast Generation Company
NGS................................ Northeast Generation Services Company
NNECO.............................. Northeast Nuclear Energy Company
NU or the Company.................. Northeast Utilities
NUEI............................... NU Enterprises, Inc.
NUSCO or the Service Company....... Northeast Utilities Service Company
PSNH............................... Public Service Company of New Hampshire
RRR................................ The Rocky River Realty Company
Select Energy...................... Select Energy, Inc.
SEPPI.............................. Select Energy Portland Pipeline, Inc.
The NU system...................... The Northeast Utilities System
The Yankee Companies............... CYAPC, MYAPC, VYNPC, and YAEC
VYNPC.............................. Vermont Yankee Nuclear Power Corporation
WMECO.............................. Western Massachusetts Electric Company
YAEC............................... Yankee Atomic Electric Company
Yankee............................. Yankee Energy System, Inc.
Yankee Gas......................... Yankee Gas Services Company
GENERATING UNITS
Millstone 1........................ Millstone Unit No. 1, a 660 MW nuclear
unit completed in 1970; Millstone 1 is
currently in decommissioning status.
Millstone 2........................ Millstone Unit No. 2, an 870 MW nuclear
electric generating unit completed in 1975
Millstone 3........................ Millstone Unit No. 3, a 1,154 MW nuclear
electric generating unit completed in 1986
Seabrook or Seabrook 1............. Seabrook Unit No. 1, a 1,148 MW nuclear
electric generating unit completed in 1986.
Seabrook 1 went into service in 1990.
REGULATORS
CDEP............................... Connecticut Department of
Environmental Protection
DOE................................ United States Department of Energy
DPUC............................... Connecticut Department of
Public Utility Control
DTE................................ Massachusetts Department of
Telecommunications and Energy
EPA................................ United States Environmental
Protection Agency
FERC............................... Federal Energy Regulatory Commission
NHDES.............................. New Hampshire Department of
Environmental Services
NHPUC.............................. New Hampshire Public Utilities Commission
NRC................................ Nuclear Regulatory Commission
SEC................................ Securities and Exchange Commission
OTHER
1935 Act........................... Public Utility Holding Company Act of 1935
CAAA............................... Clean Air Act Amendments of 1990
kWh................................ Kilowatt-hour
MW................................. Megawatt
NEPOOL............................. New England Power Pool
NUG&T.............................. Northeast Utilities Generation and
Transmission Agreement
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NORTH ATLANTIC ENERGY CORPORATION
2000 Form 10-K Annual Report
Table of Contents
PART I
Page
----
Item 1. Business................................................... 1
The Northeast Utilities System................................... 1
Safe Harbor Statement............................................ 2
Mergers and Acquisitions......................................... 3
Consolidated Edison, Inc. Merger........................... 3
Yankee Energy System, Inc. Merger.......................... 4
Rates and Electric Industry Restructuring........................ 4
General.................................................... 4
Connecticut Rates and Restructuring........................ 6
Massachusetts Rates and Restructuring...................... 8
New Hampshire Rates and Restructuring...................... 9
Competitive System Businesses.................................... 10
Energy-Related Products and Services and Gas Investments... 10
Energy Generation and Services............................. 12
Energy Management Services................................. 13
Gas Investments............................................ 13
Telecommunications......................................... 13
Financing Program................................................ 14
2000 Financings............................................ 14
2001 Financing Requirements................................ 16
2001 Financing Plans....................................... 16
Financing Limitations...................................... 17
Construction Program............................................. 22
Regulated Electric Operations.................................... 22
Distribution and Sales..................................... 22
Regional and System Coordination........................... 23
Transmission Access and FERC Regulatory Changes............ 25
Regulated Gas Operations......................................... 26
Regulation................................................. 26
Nuclear Generation............................................... 27
General.................................................... 27
Nuclear Plant Performance.................................. 28
Nuclear Insurance.......................................... 29
Nuclear Fuel............................................... 29
Decommissioning............................................ 31
Other Regulatory and Environmental Matters....................... 34
Environmental Regulation................................... 34
Electric and Magnetic Fields............................... 37
FERC Hydroelectric Project Licensing....................... 37
Employees........................................................ 38
Item 2. Properties................................................. 39
Item 3. Legal Proceedings.......................................... 44
Item 4. Submission of Matters to a Vote of Security Holders........ 49
PART II
Item 5. Market for Registrants' Common Equity and Related
Shareholder Matters....................................... 49
Item 6. Selected Financial Data................................... 50
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 50
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk............................................... 50
Item 8. Financial Statements and Supplementary Data............... 51
Item 9. Changes in Disagreements with Accountants on
Accounting and Financial Disclosure....................... 51
PART III
Item 10. Directors and Executive Officers of the Registrants....... 52
Item 11. Executive Compensation.................................... 61
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 71
Item 13. Certain Relationships and Related Transactions............ 76
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 77
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NORTH ATLANTIC ENERGY CORPORATION
PART I
ITEM 1. BUSINESS
THE NORTHEAST UTILITIES SYSTEM
Northeast Utilities (NU or the Company) is the parent company of the
Northeast Utilities system (NU system). The NU system furnishes franchised
retail electric service in Connecticut, New Hampshire and western Massachusetts
through three of NU's wholly owned subsidiaries (CL&P, Public Service Company
of New Hampshire [PSNH] and Western Massachusetts Electric Company [WMECO])
and to a limited number of customers through another wholly owned subsidiary,
Holyoke Water Power Company (HWP). The NU system serves approximately 30
percent of New England's electric needs and is one of the 25 largest electric
utility systems in the country as measured by revenues.
The NU system also furnishes retail natural gas service in most of
Connecticut through its Yankee Gas Services Company (Yankee Gas) subsidiary,
the largest natural gas distribution company in Connecticut. Yankee Gas serves
approximately 187,000 residential, commercial and industrial customers in 69
cities and towns in Connecticut.
NU, through its wholly owned subsidiary, NU Enterprises, Inc. (NUEI), owns
a number of competitive energy and telecommunications related businesses,
including Northeast Generation Company (NGC), Northeast Generation Services
Company (NGS), Select Energy, Inc. (Select Energy), HEC Inc. (HEC), Mode 1
Communications, Inc. (Mode 1), and Select Energy Portland Pipeline, Inc.
(SEPPI). For information regarding the activities of these subsidiaries, see
"Competitive System Businesses."
North Atlantic Energy Corporation (NAEC) is a wholly owned special-purpose
operating subsidiary of NU that owns a 35.98 percent interest in the Seabrook
Station nuclear unit (Seabrook) in Seabrook, New Hampshire, and sells its share
of the capacity and output from Seabrook to PSNH under two life-of-unit,
full-cost recovery contracts (Seabrook Power Contracts).
Several wholly owned subsidiaries of NU provide support services for the
NU system companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company (NUSCO) provides centralized accounting,
administrative, information technology, engineering, financial, legal,
operational, planning, purchasing, and other services to the NU system
companies. North Atlantic Energy Service Corporation (NAESCO) has operational
responsibility for Seabrook. Northeast Nuclear Energy Company (NNECO) acts as
agent for the NU system companies in operating the Millstone nuclear generating
units (Millstone) in Waterford, Connecticut. Three other subsidiaries
construct, acquire or lease some of the property and facilities used by the NU
system companies.
The NU system is regulated in virtually all aspects of its business by
various federal and state agencies, including the Securities and Exchange
Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Nuclear
Regulatory Commission (NRC) and various state and/or local regulatory
authorities with jurisdiction over the industry and the service areas in which
each company operates, including the Connecticut Department of Public Utility
Control (DPUC), the New Hampshire Public Utilities Commission (NHPUC) and the
Massachusetts Department of Telecommunications and Energy (DTE). In recent
years, there has been significant legislative and regulatory activity changing
the nature of regulation of the industry. For more information regarding these
restructuring initiatives, see "Rates and Electric Industry Restructuring" and
"Regulated Electric Operations."
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995
In connection with the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 (Reform Act), NU and its reporting subsidiaries
are hereby filing cautionary statements identifying important factors that
could cause NU or its subsidiaries' actual results to differ materially from
those projected in forward looking statements (as such term is defined in the
Reform Act) made by or on behalf of NU or its subsidiaries in this combined
Form 10-K, in any subsequent filings with the SEC, in presentations, in
response to questions, or otherwise. Any statements that express or involve
discussions as to expectations, beliefs, plans, objectives, assumptions or
future events, or performance (often, but not always, through the use of words
or phrases such as will likely result, are expected to, will continue, is
anticipated, estimated, projection, outlook) are not statements of historical
facts and may be forward looking. Forward looking statements involve
estimates, assumptions and uncertainties that could cause actual results to
differ materially from those expressed in the forward looking statements.
Accordingly, any such statements are qualified in their entirety by reference
to, and are accompanied by, the following important factors that could cause NU
or its subsidiaries' actual results to differ materially from those contained
in forward looking statements of NU or its subsidiaries made by or on behalf
of NU or its subsidiaries.
Any forward looking statement speaks only as of the date on which such
statement is made, and NU and its subsidiaries undertake no obligation to
update any forward looking statement or statements to reflect events or
circumstances after the date on which such statement is made or to reflect the
occurrence of unanticipated events. New factors emerge from time to time and
it is not possible for management to predict all of such factors, nor can it
assess the impact of each such factor on the business or the extent to which
any factor, or combination of factors may cause actual results to differ
materially from those contained in any forward looking statements.
Some important factors that could cause actual results or outcomes to
differ materially from those discussed in the forward looking statements
include prevailing governmental policies and regulatory actions, including
those of the SEC, the NRC, the FERC, and state regulatory agencies, with
respect to allowed rates of return, industry and rate structure, operation of
nuclear power facilities, acquisition and disposal of assets and facilities,
operation and construction of plant facilities, recovery of purchased-power
costs, stranded costs, decommissioning costs, and present or prospective
wholesale and retail competition (including but not limited to retail
wheeling and transmission costs).
The business and profitability of NU and its subsidiaries are also
influenced by economic and geographic factors including political and economic
risks, changes in environmental and safety laws and policies, weather
conditions (including natural disasters), population growth rates and
demographic patterns, competition for retail and wholesale customers, pricing
and transportation of commodities, market demand for energy from plants or
facilities, changes in tax rates or policies or in rates of inflation, changes
in project costs, unanticipated changes in certain expenses and capital
expenditures, capital market conditions, competition for new energy development
opportunities, and legal and administrative proceedings (whether civil or
criminal) and settlements.
All such factors are difficult to predict, contain uncertainties which
may materially affect actual results and are beyond the control of NU or its
subsidiaries.
MERGERS AND ACQUISITIONS
CONSOLIDATED EDISON, INC. MERGER
In October 1999, NU and Consolidated Edison, Inc. (Con Edison) agreed to a
merger to combine the two companies. During 2000, NU and Con Edison received
most of the approvals needed to complete the merger. Shareholders from both
companies approved the merger in April 2000 and all required state regulatory
approvals were granted by the end of the year. Additionally, the FERC approved
the merger in May 2000, which approval was reaffirmed on January 24, 2001, when
FERC denied The United Illuminating Company's request for rehearing of the
approval. The NRC and the U.S. Department of Justice approved the transaction
in August 2000 and February 2001, respectively. The final required approval,
that of the SEC, was expected in mid-March 2001.
On February 28, 2001, NU announced that it had requested that Con Edison
provide assurance in writing of its intent to close the merger on the agreed
upon terms by March 2, 2001, which date was later extended to March 5, 2001.
On March 5, 2001, NU announced that Con Edison had advised NU that Con Edison
was not willing to close the merger on the previously agreed upon terms. NU
said that it had notified Con Edison that it was treating its refusal to
proceed on the terms set forth in the merger agreement as a repudiation and
breach of the merger agreement, and that it would file a lawsuit to obtain
the benefits of the transaction as negotiated for NU's shareholders. On
March 6, 2001, Con Edison announced that Con Edison had filed suit in the
U.S. District Court for the Southern District of New York (Southern District)
seeking a declaratory judgment that NU failed to satisfy conditions precedent
under the merger agreement and that Con Edison had no further obligations
under the merger agreement. On March 12, 2001, NU filed suit in the Southern
District seeking substantial monetary damages against Con Edison arising out
of Con Edison's breach of the merger agreement. NU cannot predict the
outcome of these matters nor their effect upon NU. For further information
on litigation relating to the proposed merger, see "Item 3. Legal Proceedings."
Under the terms of the proposed transaction, NU shares would have been
acquired by Con Edison for a base price of $25.00 per share, comprised of 50
percent cash and 50 percent Con Edison shares. NU shareholders would have
received an additional $1 per share in proceeds because of the progress made in
selling the Millstone nuclear station. NU shareholders would have received
another $0.0034 per share for each day it took to complete the merger after
August 5, 2000. Under the agreement, the overall value of the stock and the
overall value of the cash that Con Edison would have provided to NU
shareholders would have been the same if Con Edison's shares averaged between
$36 and $46 per share during the pricing period. Should Con Edison shares have
averaged below $36 per share, the value of the stock proceeds received by NU
shareholders would have fallen, but should Con Edison shares have averaged
above $46 per share, the value of the stock proceeds would have risen.
Con Edison's share price had no bearing on the value of the cash portion of
the proceeds. Assuming that Con Edison's stock price averaged between $36
and $46 per share during the applicable pricing period, NU shareholders would
have received approximately $26.84 per share had the merger closed on
April 10, 2001.
Ultimately the value of the transaction to NU shareholders would have
depended on the timing of the closing, the average price of Con Edison shares
during the pricing period and the effect of proration among all shareholders.
YANKEE ENERGY SYSTEM, INC. (YANKEE) MERGER
On March 1, 2000, NU acquired Yankee, and Yankee became a wholly owned
subsidiary of NU. Yankee is the parent of Yankee Gas, the largest natural gas
distribution company in Connecticut. NU paid $45 per share, aggregating $478
million, in cash and stock for all Yankee shares. In addition, NU assumed
$164 million of Yankee's outstanding long-term debt and all of its short-term
debt, which totaled $70 million at closing. Yankee shareholders received 45
percent of the $478 million in NU common shares and 55 percent in cash.
NU borrowed the cash portion of the acquisition through a short-term loan of
$263 million, and met the stock component by issuing 11.1 million new NU
shares. NU expects to redeem approximately the same number of shares in the
second quarter of this year by closing out a forward share purchase program
with proceeds from restructuring of its electric utility businesses. The
forward share purchase program was conducted late in 1999 and early in 2000
through two financial institutions. With certain limited exceptions, NU's
merger agreement with Con Edison prohibited NU from purchasing additional
shares, but the forward shares may be retired at any time.
Yankee continues to act as the holding company of Yankee Gas and its three
nonutility subsidiaries, NorConn Properties, Inc., which holds the property and
facilities of the Yankee companies; Yankee Energy Financial Services Company,
which provides customers with financing for energy equipment installations,
and; R.M. Services, Inc., which provides debt collection service to utilities
and other businesses nationwide. For further information on the Yankee
companies, see "Regulated Gas Operations."
RATES AND ELECTRIC INDUSTRY RESTRUCTURING
GENERAL
NU's electric utility subsidiaries, CL&P, WMECO and PSNH, are undergoing
fundamental changes in their business operations as a result of the
restructuring of the electric industry in their respective jurisdictions. Most
notably, the companies have been divesting, and are continuing to divest,
their generation assets and will act solely as transmission and distribution
companies in the future. In general, their customers will be able to choose
their energy suppliers, with the electric utility companies furnishing
"standard offer" service just to those customers who do not choose a
competitive supplier. Critical to this restructuring is the companies' ability
to recover their stranded costs. Stranded costs are expenditures incurred, or
commitments for future expenditures made, on behalf of customers with the
expectation such expenditures would continue to be recoverable in the future
through rates. However, under certain circumstances these costs might not be
recoverable from customers in a fully competitive electric utility industry
(i.e., the costs may result in above-market energy prices).
As discussed more fully below, Connecticut and Massachusetts have enacted
restructuring legislation that permits CL&P and WMECO to recover substantially
all of their prudently incurred stranded costs. NU, PSNH and the state of New
Hampshire have reached a settlement (Settlement Agreement), which affects
restructuring as to PSNH and will permit PSNH to recover a substantial portion
of its stranded costs.
Electric utility restructuring in Connecticut, New Hampshire and
Massachusetts provides for a transition period of several years following the
opening of each state's electric market to customer choice. During that
interim period, the energy delivery companies, including CL&P, WMECO and PSNH,
are responsible for arranging for the supply of power to customers who do not
select alternative energy suppliers. Management recognizes that in other
states electric companies have been negatively affected by the inability to
recover supply costs on a timely basis. However, the Company believes that
current statutes and regulatory policy in the three states in which NU
subsidiaries operate electric delivery businesses will permit timely recovery.
CL&P has signed fixed-price contracts with three suppliers who together
will serve all of CL&P's standard offer requirements through 2003. One of
these suppliers is the Company's competitive marketing affiliate, Select
Energy. CL&P is fully recovering all of the payments it is making to those
suppliers and has financial guarantees from each supplier to shield CL&P from
risk in the event any of the suppliers encounters financial difficulties.
See "Connecticut Rates and Restructuring."
WMECO signed new one-year supply contracts with three unaffiliated
suppliers in December 2000 that will continue through the end of 2001. In
January 2001, the DTE approved a 17.4 percent increase in overall bills to
allow WMECO to fully recover its supply costs on a current basis. See
"Massachusetts Rates and Restructuring."
As of the beginning of 2001, PSNH remained a vertically integrated utility
with cost-of-service ratemaking and a fuel adjustment clause. For the first
nine months following the commencement of retail competition, customers who do
not choose alternative suppliers will be served by PSNH with energy from PSNH's
existing generating plants and power purchase contracts. When they are fully
operable, PSNH's current supply sources are generally well in excess of
customer demand. Nine months after the commencement of retail competition,
PSNH is required to bid out the supply of its transition service customers
(those who do not take service from competitive suppliers). PSNH is currently
limited to charging residential and small commercial customers 4.4 cents per
kilowatt-hour for the first 12 months after the bids take effect and 4.6 cents
per kilowatt-hour for the second 12 months. Those prices are now well below
the wholesale market price for firm requirements power in New England. Under
the New Hampshire restructuring statute, PSNH will be required to expense the
first $7 million of costs that cannot be collected under the rate cap and then
will be able to defer the balance for future recovery. See "New Hampshire
Rates and Restructuring."
CONNECTICUT RATES AND RESTRUCTURING
In a series of decisions issued during 1999 and 2000, the DPUC approved
CL&P's restructuring consistent with Connecticut's 1998 restructuring law.
Choice of electric supplier was available to CL&P customers living in
distressed cities (35 percent of CL&P total load) on January 1, 2000, and to
all CL&P customers effective July 1, 2000. CL&P rates were unbundled effective
January 1, 2000, with total rates 10 percent below rates in effect in December
1996, or 5 percent lower than rates in effect on December 31, 1999.
Effective January 1, 2000, CL&P's primary responsibility is to serve as
transmission and distribution provider to all customers within its service
territory and to provide standard offer service to those customers who have not
chosen a competitive supplier. CL&P's standard offer supply was obtained via a
request for proposal process, conducted by J.P. Morgan Securities, Inc.
(J.P. Morgan) on behalf of the DPUC. As approved by the DPUC, 50 percent of
the standard offer supply is met by a CL&P affiliate and 50 percent by two
unaffiliated suppliers. The contracts with all three suppliers terminate
December 31, 2003. CL&P is recovering all of its supply costs in rates.
The Connecticut restructuring legislation authorized the collection of
mitigated generation-related stranded costs and the securitization of
nonnuclear generation-related stranded costs. Securitization is the
monetization of stranded costs through the sale of nonrecourse debt securities
(rate reduction bonds) by a special purpose entity, which are collateralized
by a company's interests in stranded cost recoveries. Securitization proceeds
are applied in general to retire higher cost debt of the utility. The
legislation also required the divestiture of all generating assets and the
mitigation of purchased power contracts. Proceeds from asset divestiture are
required to be used to offset stranded costs.
The DPUC approved the divestiture plans, engaged J.P. Morgan to conduct
the auctions and approved the ultimate transactions regarding the divestiture
of all of CL&P's fossil and hydroelectric plants and the Millstone nuclear
station. In December 1999, CL&P sold 2,235 megawatts (MW) of fossil-fueled
generation assets to an unaffiliated company for $460 million. In March 2000,
CL&P transferred 1,057 MW of hydroelectric generation assets in Connecticut
and Massachusetts to NGC, an affiliated company, for $681 million. All
proceeds have been used to offset stranded costs.
In the fall of 1999, CL&P and WMECO sold the capacity and energy
associated with their unit entitlements in Millstone 2 and 3 and Seabrook to
Select Energy and five unaffiliated companies for the period beginning
January 1, 2000, through December 31, 2001. The revenues that result from
these contracts over the two year period (or until the units are sold, if
earlier) are expected to recover CL&P's and WMECO's share of the nuclear
operating costs, including a return on and the remaining nuclear plant
balances.
On August 7, 2000, the DPUC announced that an agreement had been reached
with Dominion Resources, Inc. (Dominion) for the sale of Millstone 1, Millstone
2 and approximately 94 percent of Millstone 3, including nuclear fuel and
inventory, for approximately $1.3 billion. All necessary state approvals for
CL&P, WMECO, PSNH, and the other selling joint owners have been obtained.
On February 20, 2001, the Connecticut Coalition Against Millstone (CCAM)
appealed the DPUC's approval of the agreement to the Connecticut Superior
Court and asked the court to issue a stay of the transaction pending resolution
of the appeal. The parties are pursuing the necessary federal regulatory
approvals to close the transaction as early as the end of March 2001. The
DPUC has approved recovery of Millstone-related stranded costs not offset by
asset divestiture proceeds. Pursuant to the DPUC order, CL&P will seek
recovery of Millstone post-1997 capital additions in the nuclear proceeds
calculation which will be filed after closing on the Millstone transaction.
CL&P must prove that the costs are not related to the extended outage that
began in 1996 and that the costs are reasonable relative to the benefits.
Among other rulings in the DPUC's restructuring decisions, the Connecticut
Office of Consumer Counsel (OCC) has appealed CL&P's ability to recover these
costs. Oral argument on these issues is scheduled in Connecticut Superior
Court for March 29, 2001. For further information on litigation relating to
the sale of Millstone, see "Item 3. Legal Proceedings."
CL&P intends to auction its interest in Seabrook when NAEC auctions its
Seabrook interests. Divestiture plans were filed simultaneously with the DPUC
and the NHPUC in December 2000. DPUC hearings are scheduled to commence in
March 2001.
The DPUC has approved CL&P negotiated buy-downs and buy-outs of 15
contracts with independent power producers (IPPs) and one wholesale power
contract. The DPUC has approved securitization of $1.026 billion in buy down
and buy out payments. Payments to the IPP projects will be made after receipt
of funds from the issuance of rate reduction bonds.
CL&P was unable to negotiate buy-downs or buy-outs with 15 IPPs that
produce approximately 345 MW. The DPUC authorized J.P. Morgan to auction the
long-term purchased power contracts and ultimately Constellation Power Source,
Inc. (Constellation) was selected as the winning bidder. Constellation and
CL&P entered an agreement, subject to DPUC approval, whereby Constellation
would obtain the power from the power purchase agreements and assume CL&P's
obligations thereunder, in exchange for monthly support payments from CL&P.
The DPUC rejected the agreement between Constellation and CL&P, finding that
it did not fully mitigate stranded costs. CL&P is selling the output from
the projects into the market and will continue to collect the difference
between the contract prices and the market revenues as stranded costs.
These stranded costs cannot be securitized.
The DPUC also approved recovery of and securitization of approximately
$439 million of generation-related regulatory assets. The OCC appealed to
the Connecticut Superior Court the methodology used by CL&P and endorsed by
the DPUC to calculate the regulatory assets. The parties have reached a
settlement of this appeal pursuant to which the OCC appeal will be withdrawn
and securitization, including the full amount of generation-related
regulatory assets, will go forward. DPUC approval of the settlement was
received on March 12, 2001. On March 16, 2001, the OCC withdrew its appeal.
On December 1, 2000, the Connecticut Attorney General (AG) and the OCC
each filed a petition requesting that the DPUC initiate a proceeding to
consider whether an interim decrease in the rates charged by CL&P is required.
The applicable statute requires the DPUC to commence a special public hearing
on the need for an interim rate decrease when, among other reasons, a public
service company has for six consecutive months earned a return on equity (ROE)
that exceeds the return authorized by the DPUC by at least one percentage
point. The AG and the OCC petitions were filed after CL&P reported ROEs of
13.12 percent for the second quarter of 2000 and 14.17 percent for the third
quarter of 2000. The DPUC conducted public hearings in this matter in February
and March 2001, and a decision from the DPUC is expected in April 2001.
MASSACHUSETTS RATES AND RESTRUCTURING
Massachusetts enacted comprehensive electric utility industry
restructuring in November 1997. That legislation required each electric
company to submit a restructuring plan and to reduce its rates by 15 percent
adjusted for inflation by September 1999. The 15 percent rate reduction is a
rate cap for standard offer service customers that extends until February
2005, the end of the restructuring transition period. WMECO filed, and in
1999, the DTE approved, WMECO's restructuring plan. The plan allows WMECO's
customers to choose their energy suppliers and allows WMECO to recover
generation-related stranded costs. Two parties have appealed the DTE's
decision on WMECO's restructuring plan to the Massachusetts Supreme Judicial
Court. There has been no significant action in these appeals since they were
filed in December 1999.
In addition, the DTE-approved plan requires WMECO to procure competitively
priced standard offer service and default service. These services provide
power to customers that decline to purchase energy from a competitive supplier.
WMECO competitively procured standard offer service and default service for
2000. For 2001, standard offer service has been procured as a composite rate
of 7.383 cents per kilowatt-hour (kWh), including congestion costs. Default
service has been procured through June 30, 2001, at a somewhat higher rate.
In December 2000, WMECO requested that the DTE approve a standard offer
service fuel adjustment for calendar year 2001. This fuel adjustment
recognizes significant increases in fuel prices. On December 29, 2000, the
DTE approved a fuel adjustment for standard offer customers of approximately
1.8 cents/kWh. The standard offer fuel adjustment and certain other rate
factors offset, to some extent, by a slowing of the amortization of WMECO's
stranded costs resulted in an average 17.4 percent rate increase for standard
offer service customers as of January 1, 2001. A slightly higher increase
was approved for default service customers as of February 1, 2001.
Pursuant to the Massachusetts restructuring act, electric companies were
required to divest their nonnuclear generation facilities. In July 1999,
WMECO sold 290 MW of fossil and hydroelectric generation assets for $47 million
to Consolidated Edison Energy Massachusetts, Inc. In March 2000, WMECO sold
272 MW of hydroelectric generation to NGC for approximately $184 million.
In addition, in August 2000, WMECO agreed to sell its Millstone nuclear assets
to Dominion.
WMECO filed an application with the DTE in April 2000, requesting
authorization to securitize a portion of its stranded costs. On February 7,
2001, the DTE approved the securitization of $155 million of stranded costs
and issued the required financing order and in March 2001, WMECO received the
approvals of the two Massachusetts state agencies directed by statute to
oversee the bond issuance. The stranded costs to be securitized include the
unrecovered plant balances of Millstone 2 and 3 and the buydown payment of
one IPP contract. Final approval for the issuance of the rate reduction
bonds must be obtained from the SEC.
NEW HAMPSHIRE RATES AND RESTRUCTURING
The state of New Hampshire's attempts to restructure the electric utility
industry in that state have resulted in extensive litigation in various federal
and state courts. In 1996, New Hampshire enacted legislation requiring a
competitive electric industry beginning in 1997. In February 1997, the NHPUC
issued restructuring orders that would have forced PSNH and NAEC to write off
all of their regulatory assets and possibly seek protection under Chapter 11 of
the bankruptcy laws. Following the issuance of these orders, PSNH obtained
injunctive relief on various grounds from federal district court that prevents
implementation of the NHPUC's restructuring orders.
In September 2000, the NHPUC approved a Settlement Agreement intended to
settle most of these proceedings. As required under the agreement, PSNH has
written off in excess of $200 million after-tax of its stranded costs and
will be allowed to recover the remaining amount. PSNH's obligations under
the Settlement Agreement are contingent upon the issuance of $725 million in
rate reduction bonds. In July 2000, the New Hampshire legislature endorsed
the Settlement Agreement as approved by the NHPUC with several amendments.
Other approvals are also required from the FERC and various financial lenders.
Under the terms of the Settlement Agreement, as amended by the
Legislature, customers' bills were reduced by 5 percent on October 1, 2000, and
on the effective date, PSNH's rates will be further reduced from current levels
by an average of 10.3 percent. The 5 percent rate reduction can be rescinded
on April 1, 2001, if PSNH has not closed on the sale of rate reduction bonds by
that time.
The Settlement Agreement also requires PSNH to divest its generation
assets and offer retail choice to its more than 420,000 electric customers
following the sale of the rate reduction bonds. The net proceeds from all
generation divestitures will be used to reduce PSNH's stranded costs. The
sales are to be accomplished through a sale process administered by the NHPUC.
Following the divestiture, the transmission and distribution portion of PSNH's
business will continue to be cost-of-service regulated.
On September 8, 2000, the NHPUC issued an order addressing various motions
for clarification and the rehearing of its April 19, 2000, order. In its
order, the NHPUC rejected motions for rehearing by various parties, granted the
relief requested by PSNH related to certain regulatory obligations and reduced
the amount PSNH could securitize from $725 million to up to $670 million, less
$6 million for each month beginning October 2000, until competition begins, and
found PSNH's compliance filing to be in conformance with New Hampshire law.
The NHPUC also issued an order addressing specific issues related to
securitization permitted under the Settlement Agreement.
In October 2000, the securitization process and the implementation of the
Settlement Agreement were delayed by two appeals of the NHPUC's order to the
New Hampshire Supreme Court. The New Hampshire Supreme Court issued an order
on January 16, 2001, rejecting both appeals, and on February 2, 2001,
reaffirmed its decision. One of the appellants indicated publicly it would
request a review of the New Hampshire decision by the United States Supreme
Court. Such a request must be filed by May 1, 2001. Management believes that
such an appeal would have a low probability of success, but cannot determine
what effect it might have on the timing of the sale of rate reduction bonds
and the implementation of customer choice. PSNH anticipates closing on its
rate reduction bonds early in the second quarter of 2001, with competition to
begin on the first day of the calendar month after such closing.
In November 1999, the NHPUC also approved continuation of the fuel and
purchased-power adjustment clause charge for PSNH at its current level until
the beginning of electric supply choice in New Hampshire.
In December 2000, PSNH filed divestiture plans with the NHPUC seeking
approval to begin the process of selling its fossil and hydroelectric
generation assets and NAEC's ownership share of Seabrook.
COMPETITIVE SYSTEM BUSINESSES
NU is engaged in a variety of competitive businesses. They are grouped
essentially into two separate and distinct business activities: the
competitive energy business and the telecommunications business. Select Energy
is the lead competitive energy business within NU. Select Energy is an
integrated energy business that buys, sells and markets electricity, gas and
oil and energy-related products and services. Under the umbrella of the Select
Energy brand, Select Energy, collectively with its affiliated competitive
energy businesses, provides a wide range of energy products and energy
services. These affiliated competitive energy companies include HEC, NGC, HWP,
NGS, and SEPPI. With the exception of HEC, the competitive businesses operate
primarily in the Northeast region of the United States.
ENERGY-RELATED PRODUCTS AND SERVICES AND GAS INVESTMENTS
Select Energy sells multiple energy products including electricity,
natural gas and oil to wholesale and retail customers in the northeastern
United States. Select Energy procures and delivers energy and capacity
required to serve its electric, gas and oil customers. Select Energy is the
largest wholesale and retail electric energy marketer in New England as
measured by MW load. In order to support and complement its growing wholesale
and retail business, Select Energy contracted in December of 1999 with NGC,
its unregulated generation company affiliate, to purchase and market all of
NGC's 1,289 MW for a 6-year period. These resources were acquired at auction
from CL&P and WMECO. In addition, Select Energy is purchasing approximately
200 MW of coal and hydroelectric generating resources from HWP and more than
1,500 MW of electrical supply from various New England generating facilities
on a long-term basis. Select Energy also utilizes generation failure
insurance, options and energy futures to hedge its supply requirements.
Moreover, Select Energy markets natural gas and develops and markets energy-
related products and services. It offers energy management consulting and
construction services through its affiliate, HEC, discussed more fully below.
Select Energy and its integrated competitive energy business affiliates had
aggregate revenues of approximately $1.9 billion in 2000, as compared to
approximately $648.9 million in 1999, and contributed $13.6 million to
consolidated earnings before extraordinary items in 2000, as compared to an
aggregate loss of approximately $37 million in 1999.
Select Energy is licensed to provide retail electric supply in
Connecticut, Delaware, Maryland, New Jersey, Maine, Pennsylvania, New York,
Massachusetts, Rhode Island, and New Hampshire. Within these states, Select
Energy is currently registered with approximately 36 electric distribution
companies and 52 gas distribution companies to provide retail services. Select
Energy's goal is to be the regional leader in providing electric service to
those Northeast markets opened to retail competition. In 2000, Select Energy
provided more than 5,000 MW of standard offer load, making it the largest
provider of standard offer service in the Northeast. During 2000, Select
Energy provided several utilities with standard offer full requirements
service and default services, comprising in the aggregate approximately 43
percent of its 2000 revenues. This included providing about 3,000 MW to a
Massachusetts utility. A new contract for default service was signed with
the same utility for a 6-month period in 2001.
On January 1, 2000, Select Energy began serving one half of CL&P's
standard offer load for a 4-year period. This equates to approximately 2,000
MW annually for each of the four contract years. Approximately 26 percent of
2000 competitive energy revenues came from this contract. The servicing of
this load is a significant risk for Select Energy, as this contract is
through the end of 2003, at fixed prices. This risk is partially mitigated
by Select Energy entering into purchase contracts with other energy providers
to supply a portion of the standard offer requirement, including its contracts
with NGC, the purchase of 850 MW of output from the Millstone and Seabrook
nuclear units through 2001, and other resources in the energy marketplace.
Although there can be no assurance that it will be able to do so, management
believes that Select Energy will be able to source its remaining load
requirement at reasonable prices. If Select Energy is unable to source its
remaining load requirement at prices below the standard offer contract price
as a result of energy price increases, Select Energy's earnings would be
adversely impacted. Select Energy has also entered into contracts with various
retail customers to provide energy services at fixed rates. Under these retail
contracts, Select Energy has the option to have the host utility provide energy
services and is obligated to compensate the customer as defined in the
contracts (CFD Payments). For the 12 months ended December 31, 2000, these CFD
Payments totaled approximately $3.55 million. These CFD Payments may increase
in the future. Policies and procedures have been established to manage these
exposures, including the use of risk management instruments and the purchase of
insurance for the output from the Millstone nuclear entitlements. In addition,
beginning in January 2000, Select Energy assumed responsibility for serving
approximately 500 MW of market-based wholesale contracts throughout New England
with electric energy supply that was previously provided by CL&P and WMECO.
For the most part, the prices are fixed by contract and applicable to actual
volumes.
As of December 31, 2000, Select Energy had contracts with high volume
retail electric customers in states throughout the Northeast with primarily
one-year terms. These contracts represent approximately 300 MW of load at
about 10,000 service locations and include predominantly commercial,
institutional and industrial accounts. This retail load is supplied by the
Select Energy wholesale business line and establishes Select Energy among the
largest competitive retail suppliers in New England as measured by MW load.
However, recent significant increases in electric supply costs may cause the
number of retail electric customers to decrease in the first quarter of 2001
as a result of contract expirations or terminations. There is no single
retail customer that accounts for over 10 percent of Select Energy's expected
retail revenues.
The energy marketing business is intensely competitive. There are many
large energy companies bidding for business in the increasingly restructured
New England market. In 2000, the sharp increases in the cost of power supply
caused by the extreme increases in oil and gas fuel costs, among other
things, provided significant challenges and opportunities for Select Energy.
In 2000, Select Energy increased its revenue by more than 300 percent over
the 1999 revenue level, reporting $1.79 billion in 2000, as compared with
$555 million in 1999.
Disputes with respect to interpretation and implementation of the New
England Power Pool (NEPOOL) market rules have arisen with respect to various
competitive product markets. In certain cases, Select Energy and the NU
operating companies stand to gain as a result of resolution of such disputes.
In other cases, Select Energy and the NU operating companies could incur
additional costs as a result of resolution of the disputes. These disputes
are in various stages of resolution through alternative dispute resolution
and regulatory review. It is too early to ascertain the level of potential
gain or loss that may result upon resolution of these issues.
During 2000, Select Energy significantly increased its competitive
retail and wholesale natural gas business. Its revenue for this business
segment increased from approximately $21 million in 1999, to approximately
$221 million in 2000. As of December 31, 2000, Select Energy had contracts
with approximately 2,000 retail gas customers, primarily located in
Connecticut, Massachusetts and Pennsylvania. These contracts generally have
one-year terms and include only commercial, institutional and industrial
accounts. There is no single retail gas customer that accounts for over 5
percent of Select Energy's expected retail gas revenues. In 2000, Select
Energy's retail gas revenues were approximately $67 million representing a
550 percent increase, as compared to 1999. The competitive retail gas
business has contracted for approximately $100 million in gas sales which
will extend into 2001 and 2002.
ELECTRIC GENERATION AND SERVICES
Select Energy buys, manages and markets the entire generation output from
its unregulated generation affiliate, NGC, to retail and wholesale customers.
NGC is a competitive business affiliate formed in 1999 to acquire generation
facilities. In March 2000, NGC received 1,289 MW of hydroelectric and pumped
storage generating assets in Connecticut and Massachusetts from CL&P and WMECO.
These assets include seven hydroelectric facilities along the Housatonic River
System (123 MW), the three facilities comprising the Eastern Connecticut
System, including one gas turbine (27 MW), the Northfield Mountain pumped
storage station and the Cabot and Turners Falls No. 1 hydroelectric stations
located in Massachusetts previously owned by WMECO. NGC began selling the
capacity and output of the plants to Select Energy for a period of 6 years
in March 2000.
HWP is another NU subsidiary which is considered part of the competitive
energy businesses. Select Energy buys, markets and manages the entire
generation output from its HWP affiliate. This generation consists of about
190 MW. HWP is selling all of its capacity and output to Select Energy through
the end of December 2001, with annual or longer contract renewals available
thereafter. Select Energy markets the entire output of electricity to retail
and wholesale customers. HWP recognized as an extraordinary loss a decrease
of $19.7 million, net of taxes in 2000, as a reduction in the value of its
hydro assets.
NGS was formed in 1999 to provide energy-related operation and maintenance
services to owners of generation facilities and the industrial market in the
Northeast. NGS currently focuses on providing turnkey management and operation
services and also a full range of industrial and consulting services. Select
Energy has contracted with NGS to operate and maintain all of the generating
plants within the Select Energy affiliated businesses.
NGS's industrial services include maintenance, permitting, environmental,
and specialized electrical testing services to large and medium-sized
industrial businesses. NGS also provides consulting services to these
customers, including engineering and design, construction management, asset
development, due diligence reviews and environmental regulatory compliance,
and permitting services. During 2000, NGS's revenues were approximately $44
million and are expected to grow significantly in 2001. This anticipated
growth will be due to NGS's increased geographical scope as a result of its
recent acquisition of an electrical contracting business and a number of
pending contracts with both new and repeat customers.
ENERGY MANAGEMENT SERVICES
As part of the Select Energy portfolio of products and services, Select
Energy, in conjunction with its affiliate HEC, markets energy efficiency and
design solutions to customers. In general, HEC contracts to reduce its
customers' energy costs, improve their operating efficiency within their
facilities and conserve energy and other resources. HEC's engineering,
construction management and financing assistance services have been directed
primarily to governmental and institutional markets and utilities in the
eastern United States. HEC increased its vertical integration through its
subsidiary Select Energy Contracting, Inc., which also provides mechanical
and electrical contracting services in new construction and service
contracts, primarily directed to commercial markets.
In competitive procurements by the U.S. Departments of Defense and Energy
during 1998 and 1999, HEC was selected as an "Energy Saving Performance
Contractor" (ESPC) for all fifty states and overseas bases. Recent orders have
been received calling for design, construction, financing, and long-term
operation and maintenance of energy-efficient and environmentally clean systems
to replace older infrastructure. Select Energy and HEC have recently begun
construction of a central energy plant for a school in Middletown, Connecticut.
This plant will include the largest U.S. installation of fuel cells yet
achieved. In 2000, federal ESPC work constituted 27 percent of HEC's revenues,
which were approximately $82.5 million (an increase of 20 percent over 1999).
NU's aggregate equity investment in HEC was approximately $25 million as of
December 31, 2000.
GAS INVESTMENTS
SEPPI was formed in March 1999 to hold a five percent partnership interest
in the Portland Natural Gas Transmission System. SEPPI's investment in the
project was $5.4 million as of December 31, 2000. During 2000, SEPPI
recognized a $3.9 million reduction in the value of its investment.
TELECOMMUNICATIONS
Mode 1 was established in 1996 to participate in a wide range of
telecommunications activities both within and outside New England. NU's
cumulative, total investment in Mode 1 was approximately $10.1 million as of
December 31, 2000. Mode 1 is a licensed competitive local exchange carrier
authorized to provide local phone service within the state of Connecticut.
Mode 1 currently owns approximately 4.8 million common shares of NEON
Communications, Inc. (formerly NorthEast Optic Network, Inc.) (NEON), or 20.5
percent of its outstanding shares fully diluted (assuming the issuance of all
shares to Consolidated Edison Communications, Inc. (CECI) and Exelon Ventures
(Exelon), as discussed below). NEON is constructing a fiber optic
communications network through New England, New York, Philadelphia, and
Washington, D.C., utilizing a portion of the NU system companies'
transmission and distribution facilities. An officer and trustee of NU and
an officer of NUSCO are members of the Board of Directors of NEON. In
addition, NU is a party to an agreement with Central Maine Power Company
(CMP), an owner of approximately 19.2 percent of NEON's common shares, fully
diluted, wherein NU and CMP each agree that, as long as NU owns at least 10
percent of the outstanding common stock of NEON, fully diluted, and the
cumulative holdings of NU and CMP are at least 33 1/3 percent, fully diluted,
neither NU nor CMP will take any action which will allow NEON to merge,
consolidate, liquidate or sell, lease or transfer substantially all of its
assets, or commence or acquiesce to any action or proceeding under any
bankruptcy laws.
In September 2000, CECI, a subsidiary of Con Edison, and Exelon, another
unaffiliated company, acquired 10.75 and 9.25 percent, respectively, of NEON's
common shares in exchange for contributions to NEON by each company of
telecommunications assets in kind and cash. Mode 1 is party to two reciprocal
agreements which commit it to vote for CMP's, CECI's and Exelon's nominees for
director of NEON and such companies agree to support Mode 1's nominees. Under
these arrangements, Mode 1 can presently designate two directors, and CMP,
CECI and Exelon can designate two, one and one director(s), respectively.
FINANCING PROGRAM
2000 FINANCINGS
On March 1, 2000, NU completed its acquisition of Yankee. NU financed
this acquisition with a combination of 11.1 million in newly issued shares and
a $263 million term loan credit facility. On February 28, 2001, NU repaid this
facility with the proceeds of a $263 million floating rate senior note
issuance. The senior notes bore an effective interest cost of 6.9 percent at
February 28, 2001, and mature in February 2003. Also, in anticipation of the
Yankee acquisition, in late 1999 and early 2000, NU entered into forward share
purchase arrangements with two financial institutions for a total of $215
million. These forward arrangements, which originally were due to expire on
December 31, 2000, terminate on June 29, 2001.
On March 14, 2000, CL&P and WMECO transferred to NGC certain of their
hydroelectric generation assets. NGC financed this acquisition with a $435
million equity infusion from NU and a $430 million credit facility. In
November 2000, the credit facility was extended from its original December 29,
2000, maturity date to June 29, 2001, with the ability to further extend to
September 28, 2001, if certain conditions are met.
On April 4, 2000, PSNH entered into two letters of credit and
reimbursement agreements totaling $115.4 million, which support its Series D
and E pollution control revenue bonds (PCRBs). The new letters of credit,
which replaced similar letters of credit that were set to expire on April 12,
2000, allow the PCRBs to remain in a flexible, floating interest rate mode.
On August 4, 2000, $39.5 million in principal amount of Series D PCRBs were
redeemed and the related letter of credit and reimbursement agreement was
terminated. On September 7, 2000, $69.7 million in principal amount of
Series E PCRBs were redeemed and the related letter of credit and
reimbursement agreement was terminated.
On November 9, 2000, NAEC entered into an unsecured $200 million 364-day
term credit agreement with four banks. This new facility replaced a 5-year
$225 million term loan dated November 9, 1995, which had $200 million
outstanding and was set to expire on November 9, 2000. An interest rate
collar and swaps related to the $200 million 5-year term credit agreement
also expired on November 9, 2000, and were not replaced.
On November 17, 2000, NU entered into a new 364-day revolving credit
facility for $400 million, replacing the previous $350 million revolving credit
facility which was to expire on that date. The new credit facility is subject
to two overlapping sublimits. First, subject to the notional amount of any
letters of credit outstanding, amounts up to $300 million may be borrowed.
Second, subject to outstanding borrowings, NU subsidiaries may access up to
$200 million in letters of credit.
On November 17, 2000, CL&P and WMECO entered into a new 364-day revolving
credit facility for $350 million, replacing the previous $500 million facility,
which was to expire on November 17, 2000. Under this agreement, CL&P and WMECO
may borrow up to $200 million and $150 million, respectively. Once CL&P and
WMECO receive the proceeds of securitization, the borrowing limits will be
reduced to $250 million, with a $150 million limit for CL&P and a $100 million
limit for WMECO.
On November 17, 2000, Yankee Gas extended its $60 million revolving credit
facility for an additional 364-day period from November 17, 2000, to
November 16, 2001. Also on November 17, 2000, Yankee permanently retired $25
million of short-term bank debt.
The level of common dividends totaled $57.4 million in 2000, up
significantly from the $13.2 million paid in 1999. The increase was a result
of NU paying a $0.10 per share quarterly common dividend for all of 2000, as
compared to only paying a $0.10 per share dividend in the fourth quarter of
1999.
Total NU system debt, including short-term and capitalized lease
obligations, was $3.8 billion as of December 31, 2000, compared with $3.3
billion as of December 31, 1999. The increase was primarily due to the
acquisition of Yankee. For more information regarding NU system financing,
see "Notes to Consolidated Statements of Capitalization" in NU's financial
statements, other footnotes related to long-term debt, short-term debt, and
the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's,
PSNH's, WMECO's, and NAEC's financial statements and "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."
2001 FINANCING REQUIREMENTS
The NU system's aggregate capital requirements for 2001 are approximately
as follows:
CL&P PSNH WMECO NAEC Yankee Other NU system
(Millions)
Construction $231.3 $ 78.7 $26.6 $ 6.6 $39.2 $37.6 $420.0
Nuclear Fuel - - - 14.5 - - 14.5
Maturities 160.0 - 60.0 - - - 220.0
Cash Sinking Funds - 24.3 1.5 70.0 1.1 23.1 120.0
------ ------ ----- ----- ----- ----- ------
Total $391.3 $103.0 $88.1 $91.1 $40.3 $60.7 $774.5
====== ====== ===== ===== ===== ===== ======
For further information on the NU system's 2001 and 5-year financing
requirements, see "Notes to Consolidated Statements of Capitalization" in NU's
financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's, WMECO's,
and NAEC's financial statements and "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."
2001 FINANCING PLANS
In 2001, NU expects to reduce the capitalization of its regulated electric
subsidiaries significantly as a result of securitization of stranded costs and
continued asset sales. NU expects its subsidiaries to receive about $830
million after expenses, certain cash settlements and taxes as a result of the
sale of its interest in Millstone station to Dominion. The sale is projected
to close as early as the end of March 2001. CL&P and WMECO will receive the
vast majority of the $830 million (approximately $600 million for CL&P and more
than $140 million for WMECO) and they are expected to use the cash to reduce
their level of debt and capitalized lease obligations and to return equity
capital to the parent company.
In 2001, the Company hopes to complete the process of securitizing
stranded costs for each of its major electric operating companies. In November
2000, the DPUC approved the securitization of up to $1.55 billion of CL&P's
stranded costs, including the buyout and buydown of more than $1 billion in
purchased power obligations. CL&P currently plans to securitize approximately
$1.45 billion of these stranded costs in late March 2001. Of that sum, CL&P
plans to use about $400 million to reduce debt.
In September 2000, the NHPUC approved a comprehensive restructuring order
that allows PSNH to securitize up to $670 million of stranded costs. In
January 2001, the New Hampshire Supreme Court upheld the restructuring order
on appeal and PSNH currently expects to work with the State of New Hampshire
to issue securitization bonds early in the second quarter of 2001. Proceeds
would be combined with cash on hand and used primarily to buy down the power
contract between PSNH and NAEC, allowing a total reduction in debt at the two
companies of approximately $300 million, the retirement of approximately
$25 million of PSNH preferred stock and the return of equity capital to NU
from PSNH and NAEC of another $375 million. By the end of 2002, PSNH also
expects to complete the sale of approximately 1,200 megawatts of fossil and
hydroelectric generating plants and all 418 megawatts of NAEC's share of
Seabrook. PSNH's restructuring settlement was predicated upon PSNH and NAEC
receiving approximately $400 million of net proceeds from those sales.
In February 2001, the DTE approved the securitization of $155 million of
stranded costs by WMECO. A significant amount of those proceeds would be used
to buy out a purchased power contract with the remainder used to reduce WMECO's
debt. WMECO hopes to complete the issuance early in the second quarter of
2001.
Should NU's operating subsidiaries successfully complete all of the asset
sales and securitization noted above, the regulated companies would receive in
excess of $5 billion of cash between 1999 and 2002.
Management currently expects NU's operating subsidiaries to use the
proceeds in four primary ways. More than $2 billion would be used to repay
debt and preferred stock; more than $1 billion to buy out and buy down high-
cost nonutility generator arrangements; approximately $600 million to pay taxes
on gains from the sale of generation assets; and approximately $1.2 billion
would be returned to NU from these operating companies. Of that $1.2 billion,
CL&P and WMECO repurchased $390 million of their common stock from NU in March
2000, the proceeds of which were immediately invested in NGC. NU will use
another $215 million to settle the forward share purchase noted above.
On February 28, 2001, NU issued $263 million aggregate principal amount
floating rate notes due February 2003. The proceeds were used to pay off the
$263 million term loan credit facility used to finance NU's acquisition of
Yankee.
In the first half of 2001, NGC expects to issue up to $440 million of
long-term debt to replace the $430 million credit facility discussed above.
Due to the fourth quarter write-down of certain assets owned by HWP, HWP
did not meet its equity maintenance covenant under certain of its letter of
credit and reimbursement agreements. In February 2001, HWP received a waiver
to permit its common equity ratio to fall below 30 percent for the quarters
ended December 31, 2000, March 31, 2001, and June 30, 2001. Thereafter, NU
will provide a guarantee of HWP's obligations for the benefit of the banks.
NU expects to receive approval from the SEC to implement this guarantee during
the second quarter of 2001.
FINANCING LIMITATIONS
Many of the NU system companies' charters and borrowing facilities contain
financial limitations that must be satisfied before borrowings can be made and
for outstanding borrowings to remain outstanding.
Under their current revolving credit facility, CL&P and WMECO are required
to maintain a ratio of common equity to total capitalization (common equity
ratio) of at least 30 percent. At December 31, 2000, CL&P's and WMECO's
common equity ratios were 32.8 percent and 34.4 percent, respectively. This
agreement also requires CL&P to maintain a 12-month earnings before interest
and taxes to interest expense ratio (interest coverage ratio) of at least 2.5
to 1.0 for the quarters ending December 31, 2000, and March 31, 2001, and 3.0
to 1.0 thereafter. WMECO is required to maintain a quarterly interest coverage
ratio of at least 2.0 to 1.0 for the quarters ending December 31, 2000, and
March 31, 2001, and 2.2 to 1.0 thereafter. At December 31, 2000, CL&P's and
WMECO's interest coverage ratios were 3.5 to 1 and 3.0 to 1, respectively.
Under NU's revolving credit facility and its term loan credit agreement,
NU is required to maintain a consolidated common equity ratio of at least 30
percent. At December 31, 2000, NU's consolidated common equity ratio was 35.1
percent. In addition, NU is required to maintain a 12-month consolidated
interest coverage ratio of at least 2.0 to 1.0 for the quarters ending
December 31, 2000, and March 31, 2001, and 2.2 to 1.0 thereafter. At
December 31, 2000, NU's consolidated interest coverage ratio was 2.4 to 1.0.
In addition, NU is required to maintain as of the end of each quarter with
respect to the four quarters then ended a ratio of operating cash flow to fixed
charges (cash flow ratio) of at least 1.5 to 1.0. At December 31, 2000,
NU's cash flow ratio was 2.1 to 1.0.
These agreements also limit NU's ability, without creditor approval, to
incur additional debt and to make future investments, including acquisitions
in excess of $25 million and investments in Select Energy and other
subsidiaries in excess of $200 million and $100 million, respectively.
NAEC is party to a 364-day term credit agreement which provides that
outstanding advances can be terminated or accelerated if NAEC does not maintain
specified minimum ratios of common equity to capitalization (as defined in the
agreement). For NAEC, the minimum common equity ratio under its term credit
agreement is 25 percent; at December 31, 2000, NAEC's common equity ratio was
32.4 percent. The agreement also requires a 12-month adjusted net income to
interest expense ratio (interest coverage ratio) of not less than 1.5 to 1.0.
At December 31, 2000, the ratio for NAEC was 2.0 to 1.0. The term credit
agreement also provides for mandatory prepayment of 50 percent of the aggregate
principal amount of advances outstanding within two days of a buydown of NAEC's
interest in Seabrook (Seabrook Interest) to $100 million as contemplated by the
PSNH restructuring Settlement Agreement, and prepayment of 100 percent within
two business days of the sale of the Seabrook Interest or earlier termination
of the Unit Contract as contemplated by the PSNH restructuring Settlement
Agreement. The 364-day term credit agreement also limits NAEC's other
unsecured debt to $60 million.
Under Yankee Gas' 364-day revolving credit facility, Yankee Gas is
required to maintain a common equity to stockholder's equity (common equity
ratio) of at least 37.5 percent and to maintain stockholders' equity of at
least $90 million. At December 31, 2000, Yankee Gas' common equity ratio was
75.0 percent and its consolidated stockholder's equity was $467.2 million.
Yankee Gas is also required to maintain a 12-month interest coverage ratio of
at least 2.0 to 1.0 for each fiscal quarter. At December 31, 2000, Yankee
Gas's interest coverage ratio was 4.2 to 1.0.
The amount of short-term debt that may be incurred by NU, CL&P, WMECO,
PSNH, NNECO, HWP, and NAEC is also subject to periodic approval by the SEC
under the Public Utility Holding Company Act of 1935 (1935 Act). PSNH's and
NAEC's short-term debt in excess of 10 percent of net fixed plant is also
regulated by the NHPUC. The following table shows the amount of short-term
borrowings authorized by the SEC or the NHPUC for each company, as the case may
be, as of December 31, 2000, and the net amounts of outstanding short-term debt
and cash investments of those companies at the end of 2000 and as of March 1,
2001:
Short-Term Debt
Outstanding
(Cash Investments) (1)
Maximum Authorized ------------------
Short-Term Debt December 31, 2000 March 1, 2001
------------------ ----------------- -------------
(Millions)
NU Parent $400.0 $ 144.6 $ 182.5
CL&P 375.0 77.0 47.6
PSNH (2) 225.0 (110.0) (62.9)
WMECO 250.0 110.6 90.7
HWP 5.0 (16.2) (17.1)
NAEC(3) 260.0 172.2 132.8
NNECO 75.0 (9.3) 16.8
Yankee Parent 50.0 - (1.5)
Yankee Gas 100.0 49.6 48.1
Other N/A 71.2 134.7
------- -------
Total $ 489.7 $ 571.7
======= =======
(1) These columns include borrowings of or cash investments by various NU
system companies from NU and other NU system companies excluding borrowings
under the NU term loan credit agreement and NGC credit facility. Total NU
system short-term indebtedness to unaffiliated lenders excluding the NU term
loan facility and NGC credit facility was $644.6 million at December 31,
2000, and $598 million at March 1, 2001. The NU term loan facility was
separately approved by the SEC and is not considered short-term debt for
purposes of the SEC authorization noted above. NGC's short-term debt is not
subject to SEC approval. At December 31, 2000, NU had $263 million borrowed
under the NU term loan facility and NGC had $403 million borrowed under the
NGC credit facility. As of March 1, 2001, NU had paid off the $263 million
term loan facility with proceeds from a $263 million debt issuance and NGC
had $388 million borrowed under the NGC credit facility.
(2) Under applicable NHPUC provisions, PSNH can incur short-term debt up to 10
percent of net fixed plant. As of December 31, 2000, PSNH's net fixed plant
as measured by FERC was approximately $712.9 million; accordingly, PSNH could
borrow up to $71.3 million of short-term debt.
(3) Under applicable NHPUC regulations, NAEC can incur short-term debt up to
10 percent of net fixed plant. As of December 31, 2000, NAEC's net fixed
plant as measured by FERC was approximately $524.8 million; accordingly, NAEC
could borrow up to $52.5 million of short-term debt. In connection with the
issuance of NAEC's 364-day term credit agreement, NAEC obtained NHPUC approval
for a short-term debt limit of $260 million, representing $200 million of
borrowings under the 364-day term credit agreement and $60 million of other
short-term debt.
The supplemental indentures under which NU issued $175 million in
principal amount of 8.58 percent amortizing notes in December 1991, and $75
million in principal amount of 8.38 percent amortizing notes in March 1992,
contain restrictions on dispositions of certain NU system companies' stock,
limitations of liens on NU assets and restrictions on distributions on and
acquisitions of NU stock. Under these provisions, NU, CL&P, PSNH, and WMECO
may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or
another NU system company, except that CL&P may sell voting stock for cash to
third persons if so ordered by a regulatory agency so long as the amount sold
is not more than 19 percent of CL&P's voting stock after the sale. The
restrictions also generally prohibit NU from pledging voting stock of CL&P,
PSNH or WMECO or granting liens on its other assets in amounts greater than
5 percent of the total common equity of NU. Many of the NU system companies'
credit agreements have similar restrictions. As of December 31, 2000, no NU
debt was secured by liens on NU assets. Furthermore, NU may not declare or
make distributions on its capital stock, acquire its capital stock (or rights
thereto), or permit a NU system company to do the same, at times when there
is an event of default under the supplemental indentures under which the
amortizing notes were issued.
Pursuant to its revolving credit facility and the $263 million term loan
credit agreement, NU may not declare dividends or make distributions, except
for dividends not to exceed $60 million during any 12-month period and stock
repurchases of up to $215 million in connection with the Yankee merger.
Similar restrictions are found in NU's merger agreement with Con Edison.
The charters of CL&P and WMECO contain preferred stock provisions
restricting the amount of unsecured debt those companies may incur. As of
December 31, 2000, CL&P's and WMECO's charters permit CL&P and WMECO to incur
an additional $245 million and $94 million, respectively, of unsecured debt.
The indentures securing the outstanding first mortgage bonds of CL&P,
PSNH, WMECO, and NAEC provide that additional bonds may not be issued, except
for certain refunding purposes, unless earnings (as defined in each indenture
and before income taxes, and, in the case of PSNH, without deducting the
amortization of PSNH's regulatory asset), are at least twice the pro forma
annual interest charges on outstanding bonds, and certain prior lien
obligations and bonds to be issued. While CL&P's and WMECO's 2000 earnings
permit them to meet those earnings coverage tests, certain loan agreements
prohibit the issuance of additional first mortgage bonds.
The preferred stock provisions of CL&P's and WMECO's charters also
prohibit the issuance of additional preferred stock (except for refinancing
purposes) unless income before interest charges (as defined and after income
taxes and depreciation) is at least 1.5 times the pro forma annual interest
charges on indebtedness and the annual dividend requirements on preferred
stock that will be outstanding after the additional stock is issued. CL&P's
and WMECO's earnings currently permit them to meet those earnings tests.
However, the companies are not expected to issue preferred stock during 2001.
Certain consolidated subsidiaries have dividend restrictions imposed by
their long-term debt agreements. These restrictions also limit the amount of
retained earnings available for NU common dividends. At December 31, 2000,
retained earnings available for the payment of dividends totaled $180.1
million.
CL&P and WMECO's revolving credit agreement requires the companies to
maintain at all times a ratio of common equity to total capitalization of at
least 30 percent. At December 31, 2000, this requirement would allow CL&P
and WMECO to make additional distributions from common equity of $90 million
and $31 million, respectively.
Under NAEC's first mortgage bond indenture, all retained earnings are
available for payment or distribution, plus an allowance of $10 million,
subject however to restrictions under New Hampshire statutes and the Federal
Power Act, which limit the payment of dividends to book retained earnings. At
December 31, 2000, NAEC's retained earnings was approximately $0.4 million.
During much of 2000, PSNH was prohibited from paying dividends on its
common stock and from investing any funds in the NU system money pool without
NHPUC approval. Payment of a $50 million dividend at the time of the temporary
rate reduction contemplated by the Settlement Agreement was authorized pursuant
to New Hampshire law and was paid by PSNH to NU on October 1, 2000. In its
finance order regarding securitization, the NHPUC authorized investment of
PSNH funds in the NU system money pool upon the write-off required by the
Settlement Agreement, which write-off was taken in the fourth quarter of 2000.
PSNH is now participating in the money pool and can pay dividends on its common
stock without NHPUC approval.
New Hampshire statutes and the Federal Power Act limit the payment of
dividends by PSNH to retained earnings. At December 31, 2000, PSNH's retained
earnings was approximately $123 million.
Applicable merger accounting rules require that upon acquisition by NU,
Yankee's and its subsidiaries' retained earnings were reclassified as capital
surplus. Also, the merger premium NU paid to acquire Yankee was allocated
among Yankee and its subsidiaries and "pushed down" to their balance sheets
and under current accounting rules is being amortized to expense. Under
existing accounting conventions, the majority of the merger premium will be
amortized over 40 years. The Financial Accounting Standards Board is
currently evaluating merger accounting. The current proposal would no longer
require companies to amortize goodwill as an expense to the income statement.
Instead goodwill will be evaluated for impairment and any impairments to
goodwill would be charged to expense. It is expected the new accounting rule
will be effective January 1, 2002. If enacted, the effect will be an
approximately $8 million annual reduction in goodwill expense.
Under the 1935 Act, subsidiaries of registered holding companies are only
allowed to pay dividends out of retained earnings unless the SEC allows
otherwise. The effect of this rule would be to prevent Yankee from paying
dividends to NU from any source other than post-merger earnings, as reduced
by the merger premium amortization. NU has received permission from the SEC,
through June 2002, for Yankee and Yankee Gas to pay dividends (i) out of
additional paid-in capital up to the amount of their respective retained
earnings just prior to the merger with NU and (ii) out of earnings before the
amortization of the merger goodwill (gross earnings) in the case of Yankee
Gas and out of distributed earnings in the case of Yankee. To assure that
Yankee Gas has sufficient cash to fund operations, Yankee Gas will not pay
dividends in excess of 80 percent of gross earnings on a rolling 5-year
average basis. In no case would dividends be paid by Yankee or Yankee Gas if
their common equity to total capitalization ratios were below 35 percent.
NU has also received permission from the SEC, through June 2002, for
Yankee and Yankee Gas to repurchase their common stock such that their common
equity to total capitalization ratios do not fall below 35 percent.
NU is required under the 1935 Act to maintain its consolidated common
equity at a level equal to at least 30 percent of its consolidated
capitalization. Following the issuance of rate reduction bonds by its
subsidiaries, NU will temporarily be unable to meet this standard because such
bonds, although nonrecourse to the NU system company issuers, are considered to
be indebtedness of the companies under generally accepted accounting
principles. The SEC has authorized the consolidated common equity ratio of NU
to fall below 30 percent through December 31, 2001. The 30 percent test also
applies to NU's electric operating subsidiaries. The SEC has authorized the
common equity ratios of CL&P, WMECO and PSNH to fall below 30 percent through
December 31, 2001.
NU provides credit assurance in the form of guarantees, letters of credit,
performance guarantees, and other assurances for the financial performance
obligation of certain of its unregulated subsidiaries, particularly Select
Energy. NU currently has authorization from the SEC to provide up to $500
million of guarantees. In addition, NU is limited under its revolving credit
facility and its term loan credit agreement to $500 million of such
arrangements without creditor approval. As of December 31, 2000, and March 1,
2001, NU had provided approximately $284 million and $376 million,
respectively, of such credit assurances.
Certain NU system credit agreements also have covenants or trigger events
tied to credit ratings of certain NU system companies.
CONSTRUCTION PROGRAM
The NU system's construction program expenditures, including allowance for
funds used during construction, is estimated to be in the range of from $395
million to $420 million in 2001. Of such total amount, approximately $206
million to $231 million is expected to be expended by CL&P, $79 million by
PSNH, $27 million by WMECO, $7 million by NAEC, $11 million by NGC, $39 million
by Yankee, and up to $26 million by other system entities. This construction
program data includes all anticipated costs necessary for committed projects
and for reasonably expected to become committed projects in 2001, regardless of
whether the need for the project arises from environmental compliance,
reliability requirements, nuclear safety, or other causes. The data assumes
the sale of the Millstone units on March 30, 2001. The construction program's
main focus in maintaining and upgrading the existing transmission and
distribution system and nuclear and hydroelectric generation assets. The
system expects to evaluate its needs beyond 2001 in light of future
developments, such as restructuring, industry consolidation, performance, and
other events.
REGULATED ELECTRIC OPERATIONS
DISTRIBUTION AND SALES
CL&P, PSNH and WMECO furnish retail franchise service in 149, 198 and 59
cities and towns in Connecticut, New Hampshire and Massachusetts, respectively.
In December 2000, CL&P furnished retail franchise service to approximately 1.13
million customers in Connecticut, PSNH provided retail service to approximately
434,000 customers in New Hampshire and WMECO served approximately 199,000
retail franchise customers in Massachusetts. HWP serves 30 retail customers in
Holyoke, Massachusetts.
The following table shows the sources of 2000 electric franchise retail
revenues based on categories of customers:
CL&P PSNH WMECO Total NU System
Residential........ 46% 41% 40% 4%
Commercial......... 39% 35% 37% 38%
Industrial......... 14% 23% 22% 7%
Other.............. 1% 1% 1% 1%
--- --- --- ---
Total.............. 100% 100% 100% 100%
=== === === ===
The actual changes in retail kWh sales for the last two years and the
forecasted retail sales growth estimates for the 10-year period 2000 through
2010 for CL&P, PSNH and WMECO are set forth below:
2000 over 1999 over Forecast 2000-2010
1999 1998 Compound Rate of Growth
NU system.......... 0.9% 3.8% 1.3%
CL&P............... 0.4% 2.9% 1.2%
PSNH............... 2.6% 5.3% 2.0%
WMECO.............. -0.1% 3.6% 1.0%
Consolidated NU retail sales rose by 0.9 percent in 2000, compared with
1999, primarily due to higher heating requirements and the strong economy,
offset by lower cooling requirements. Residential electric sales were up 0.2
percent. Commercial sales were up by 1.3 percent for the year and industrial
sales increased by 1.1 percent. Retail sales for all of the NU system
electric operating companies increased in 2000 with CL&P, WMECO and PSNH
sales up 0.4 percent, down 0.1 percent and up 2.6 percent, respectively.
REGIONAL AND SYSTEM COORDINATION
The NU system companies and most other New England utilities are parties
to an agreement (NEPOOL Agreement), which provides for coordinated planning and
operation of the region's generation and transmission facilities. The NEPOOL
Agreement was restated and revised as of March 1997 to provide for (i) a pool-
wide open access transmission tariff; (ii) the creation of an Independent
System Operator (ISO), and; (iii) a broader governance structure for NEPOOL and
a more open, competitive market structure. Under these new arrangements the
ISO, a nonprofit corporation whose board of directors and staff are not
controlled by or affiliated with market participants, ensures the reliability
of the NEPOOL transmission system, administers the NEPOOL tariff and oversees
the efficient and competitive functioning of the regional power market.
The NEPOOL tariff provides for nondiscriminatory open access to the
regional transmission network at a single rate regardless of transmitting
distance for all transactions. The rate is a formula, structured to ensure
that each transmission provider under the NEPOOL tariff recovers its revenue
requirements.
In 1999, the NEPOOL Executive Committee filed a comprehensive settlement
of all issues set for hearing concerning the NEPOOL transmission tariff. The
settlement resolves disputes concerning the calculation of revenue requirements
for transmission over NEPOOL facilities and resolves disputes over alleged
"double charges" under grandfathered transmission contracts retained by
individual transmission providers, including NU. The settlement also includes
a ROE component which sets the ROE for each individual transmission provider
owning NEPOOL transmission facilities with respect to those facilities from
March 1, 1997, through at least June 1, 2000, provided no changes to individual
network transmission tariff rates are made after December 31, 1999. NU's ROE
has been set at 11.75 percent. NU has made no changes to its transmission
tariff rates since the settlement was reached; accordingly, its ROE has
remained unchanged.
As part of the settlement, the ISO is required to independently audit the
charges in effect for the period June 1997 through May 2000, or direct that
such an audit be conducted under its supervision. In June 2000, the ISO
engaged an independent auditing firm to conduct such an audit. The audit
remains ongoing and the results of the audit will be filed at the FERC as an
informational filing.
In December 2000, NU was notified by the FERC that it, along with several
other companies, would be the subject of a separate FERC industry-wide audit of
the accounting related to formula rate transmission tariffs. The FERC
commenced its audit of NU in February 2001.
Two agreements determine the manner in which costs and savings are
allocated among the NU system electric operating companies. Under an agreement
(NUG&T) among CL&P, WMECO and HWP, these companies pool their electric
production costs and the costs of their principal transmission facilities.
Pursuant to the merger agreement between NU and PSNH, these companies and PSNH
entered into a 10-year sharing agreement (Sharing Agreement), expiring in June
2002, that provides, among other things, for the allocation of the capability
responsibility savings and energy expense savings resulting from a single-
system dispatch through NEPOOL.
The NUG&T was revised in 1999 to eliminate the generation aspects of the
agreement. Revision to the NUG&T was initially contested by the Massachusetts
Attorney General, who claimed that such revision would result in stranded costs
being transferred unfairly to WMECO. In July 1999, the FERC approved the
proposed amendment subject to the outcome of a hearing which was held in
abeyance pending the outcome of state restructuring proceedings. The DTE
rejected the Massachusetts Attorney General's arguments in a December 1999
order. While the FERC hearing continues to be held in abeyance, NUSCO and
the Massachusetts Attorney General reached settlement on a number of issues
related to restructuring in Massachusetts. As part of that settlement, the
Massachusetts Attorney General withdrew its opposition to the revisions to
the NUG&T. The FERC approved such withdrawal in September 2000.
The Settlement Agreement between PSNH and the state of New Hampshire was
approved by the NHPUC on April 19, 2000. Accordingly, NU will file for FERC
approval to terminate the Sharing Agreement, as mandated by the Settlement
Agreement, effective December 31, 2000. Only minor revenue changes are
expected in the future as no energy or capacity transactions have taken place
under the Sharing Agreement since CL&P and WMECO relinquished their
responsibilities to meet customer loads on January 1, 2000. Transmission
revenues will be allocated going forward based upon the respective companies'
cost of service where these revenues had been split equally by PSNH and CL&P
under the Sharing Agreement.
On March 6, 2001, the FERC issued an order on rehearing related to the
price for installed capacity (ICAP) in New England. The FERC reinstituted
the previously approved $8.75 per kilowatt-month charge for installed
capacity, but made the price effective April 1, 2001. In an earlier decision
in December 2000, the FERC had made the charge effective as of August 1,
2000, but in its revised decision, the FERC substituted a $0.17 per kilowatt-
month charge for the period of August 2000 through March 2001. Because NU
was a major seller of installed generating capacity during the last five months
of 2000, the FERC's revised decision with respect to the August through March
time period reduced NU's fourth quarter revenues by $24.6 million and lowered
earnings by $14.8 million, or $0.10 per share. On March 16, 2001, NU filed
with the FERC for rehearing of its order. On the same day, several utilities,
the Massachusetts Attorney General and the Maine Public Utilities Commission
appealed that portion of the FERC's order reinstituting the $8.75 charge on
a going-forward basis to the First Circuit U.S. Appeals Court.
TRANSMISSION ACCESS AND FERC REGULATORY CHANGES
Pursuant to FERC Order 888 (issued in April 1996), NU system companies
operate their transmission system under an open access, nondiscrimatory
transmission tariff.
In December 1999, the FERC issued an order calling on all transmission
owners to voluntarily join regional transmission organizations (RTOs) in order
to boost competition in electric markets (Order 2000). In general, each such
organization would be an independent operator over all transmission facilities,
and would perform, among other functions, tariff administration, construction
planning and reliability management for the particular regional transmission
system. NU's active voting interest in such an organization would be limited
to 5 percent under the proposal.
NU system companies and other parties have appealed this order. Of
primary concern to NU is the ratemaking authority granted to RTOs and its
impact on the ability of transmission owners to earn appropriate returns on
their transmission investment under the organizational structure and the
minimum functions proposed in the order. The NU system companies are
required to participate in a collaborative process established by the FERC
beginning in March of 2000.
On January 16, 2001, NU along with the ISO and five other New England
transmission owning utilities (National Grid, USA, The United Illuminating
Company, Bangor Hydro-Electric Company, CMP and Vermont Electric Company) filed
a proposal to establish a New England Regional Transmission Organization
(NERTO) in compliance with FERC's order. As proposed, NERTO would consist of
the ISO and a newly formed for-profit independent transmission company
(Northeast ITC). Pursuant to an RTO agreement, both entities would share the
minimum required functions of an RTO set forth in the FERC order. The ISO
would be primarily responsible for short-term reliability functions and
Northeast ITC would operate (but not initially own) the transmission assets of
the participating transmission owners, develop and administer a transmission
tariff, and engage in transmission planning and expansion activities. NU
would be a shareholder in Northeast ITC and would appoint a member of the
board of directors. NU's voting interest would remain capped at five percent,
consistent with the requirement of the FERC order, until a change in law or
regulation that would permit NU to have an increased voting interest.
The NERTO proposal will require changes to the existing NEPOOL
arrangements. Proposals for such changes continue to be discussed in regional
meetings. The NERTO proposal will also require changes to the NEPOOL tariff
and NU's other transmission tariffs and agreements. Provided the NERTO
proposal is approved, NU expects to file tariff changes later this year.
Since NEPOOL established competitive wholesale markets in 1999, congestion
costs (the cost of higher energy prices within the New England market due to
transmission constraints) have grown steadily surpassing $150 million in total
by year end 2000. The ISO New England made a filing at the FERC in March 2000
to implement a congestion management system (CMS) similar to those in use in
the New York ISO and Pennsylvania - New Jersey - Maryland Interconnection.
CMS uses locational based pricing to assign costs to regional load zones,
within New England. Individual load zones will experience higher or lower
congestion costs as the CMS will replace the current practice of distributing
and averaging congestion costs across all New England loads. The FERC's
response to the ISO New England's CMS filing encouraged early implementation
(less than a year); the ISO New England has indicated implementation will take
18 to 24 months. The current estimate for implementation of the CMS is during
the first quarter of 2002.
REGULATED GAS OPERATIONS
REGULATION
Yankee Gas operates the largest natural gas distribution system in
Connecticut as measured by number of customers and size of service territory.
Total throughput (sales and transportation) for 2000 was 52.6 billion cubic
feet. In 2000, total gas operating revenue of $345 million were comprised of
the following: 48 percent residential; 28 percent commercial; 20 percent
industrial, and; the remaining 4 percent other. Yankee Gas provides firm gas
sales service to customers who require a continuous gas supply throughout the
year, such as residential customers who rely on gas for their heating, hot
water and cooking needs. Yankee Gas also provides interruptible gas sales
service to certain commercial and industrial customers that have the
capability to switch from natural gas to an alternative fuel on short notice.
Yankee Gas can interrupt service to these customers during peak demand
periods. Yankee Gas offers firm and interruptible transportation services to
customers who purchase gas from sources other than Yankee Gas. In addition,
Yankee Gas performs gas exchanges and capacity releases to marketers to
reduce its overall gas expense.
Although Yankee Gas is not subject to FERC jurisdiction, the FERC does
regulate the interstate pipelines serving Yankee Gas' service territory.
Yankee Gas, therefore, is directly and substantially affected by the FERC's
policies and actions. Accordingly, Yankee Gas closely follows and, when
appropriate, participates in proceedings before the FERC.
Yankee Gas is subject to regulation by the DPUC, which, among other
things, has jurisdiction over rates, accounting procedures, certain
dispositions of property and plant, mergers and consolidations, issuances of
securities, standards of service, management efficiency, and construction and
operation of distribution, production and storage facilities.
The DPUC may, after a special public hearing, order an interim rate
decrease if it finds that Yankee Gas' ROE exceeds a reasonable rate of return
and rates are more than just, reasonable and adequate as determined by the
DPUC. The DPUC also is empowered to grant an interim rate increase under
compelling circumstances.
On August 9, 2000, Yankee Gas was ordered by the DPUC to file a rate
application. This review of Yankee Gas' rates is required under Connecticut
law because 4 years have passed since its last rate review. In accordance with
the most recent schedule approved by the DPUC, Yankee Gas filed a cost of
service study on February 14, 2001, which reflected a historical test year
ending September 30, 2000. Yankee Gas has asked the DPUC to approve a schedule
that would call for Yankee Gas to file a letter of intent in May 2001, and its
full filing in July 2001.
NUCLEAR GENERATION
GENERAL
Certain NU system companies have ownership interests in four nuclear
units, Millstone 1, 2 and 3 and Seabrook, and equity interests in four regional
nuclear companies (the Yankee Companies) that separately own the Connecticut
Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), the Vermont
Yankee nuclear unit (VY), and the Yankee Rowe nuclear unit (Yankee Rowe).
NU system companies operate Millstone 2 and 3 and Seabrook. Yankee Rowe,
CY, MY, and Millstone 1 have been permanently removed from service.
CL&P and WMECO own 100 percent of Millstone 1 and 2 as tenants in common.
Their respective ownership interests in each unit are 81 percent and 19
percent.
CL&P, PSNH and WMECO have agreements with other New England utilities
covering their joint ownership as tenants in common of Millstone 3. CL&P's,
PSNH's and WMECO's ownership interests in the unit are 52.93, 2.85 and 12.24
percent, respectively. NAEC and CL&P have 35.98 percent and 4.06 percent
ownership interests, respectively, in Seabrook.
In 1996, one of the joint owners of Millstone 3, the Vermont Electric
Generation and Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy.
The subsequent liquidation resulted in the offering of VEG&T's 0.35 percent
share of Millstone 3 for sale to the joint owners of Millstone 3. None of
the non-NU joint owners accepted the offer. The VEG&T ownership interest in
Millstone 3 is included in the sale of the unit to Dominion.
The Millstone 3 and Seabrook joint ownership agreements provide for pro-
rata sharing by the owners of each unit of the construction and operating
costs, the electrical output and the associated transmission costs. CL&P and
WMECO, through NNECO as agent, operate Millstone 3 at cost, and without
profit, under a sharing agreement that obligates them to utilize good utility
operating practice and requires the joint owners to share the risk of employee
negligence and other risks pro-rata in accordance with their ownership shares.
The sharing agreement provides that CL&P and WMECO would only be liable for
damages to the minority owners for a deliberate breach of the agreement
pursuant to authorized corporate action.
CL&P, PSNH, WMECO, and other New England electric utilities are the
stockholders of the Yankee Companies. Each Yankee Company owns a single
nuclear generating unit. The stockholder-sponsors of each Yankee Company are
responsible for proportional shares of the operating and decommissioning costs
of the respective Yankee Company and are entitled to proportional shares of the
electrical output in the case of VY, which is the only operating unit of the
four Yankee Companies set forth below. The relative rights and obligations
with respect to the Yankee Companies are approximately proportional to the
stockholders' percentage stock holdings, but vary slightly to reflect
arrangements under which nonstockholder electric utilities have contractual
rights to some of the output of particular units. CL&P's, PSNH's and WMECO's
stock ownership percentages in the Yankee Companies are set forth below:
CL&P PSNH WMECO NU system
Connecticut Yankee Atomic
Power Company (CYAPC) ...... 34.5% 5.0% 9.5% 49.0%
Maine Yankee Atomic Power
Company (MYAPC) ............ 12.0% 5.0% 3.0% 20.0%
Vermont Yankee Nuclear
Power Corporation (VYNPC)... 9.5% 4.0% 2.5% 16.0%
Yankee Atomic Electric
Company (YAEC) ............ 24.5% 7.0% 7.0% 38.5%
In 1999, VYNPC agreed to sell its nuclear generating unit for $22 million
to an unaffiliated company. Among other commitments, the acquiring company
would have agreed to assume the obligation to decommission the unit after it
is taken out of service, and the owners of VYNPC (including CL&P, WMECO and
PSNH) agreed to fund their shares of the decommissioning costs up to a
negotiated amount. Subsequent to the time that agreement was executed, the
original proposed acquiring company has increased the price it agreed to pay
and three other unaffiliated companies have indicated their interest in buying
VYNPC's generating unit on terms that have not been disclosed. Participants in
the Vermont regulatory proceeding, including VYNPC, have argued that it is most
appropriate for the unit to be sold in an open auction proceeding. On
February 14, 2001, the Vermont Public Service Commission rejected the agreement
to sell VY to the proposed purchaser. VYNPC is reviewing its options relating
to VY, including the possibility of an auction. At present, CL&P, WMECO and
PSNH expect that the unit will be sold, but the identity of the owner and the
terms of sale, including price, future decommissioning obligations and future
power purchase obligations, are not known.
The operators of Millstone 2 and 3, VY and Seabrook hold full term
operating licenses from the NRC and are subject to the jurisdiction of the NRC.
The NRC has broad jurisdiction over the design, construction and operation of
nuclear generating stations, including matters of public health and safety,
financial qualifications, antitrust considerations, and environmental impact.
The NRC issues 40-year initial operating licenses to nuclear units and NRC
regulations permit renewal of licenses for an additional 20-year period.
The NRC also has jurisdiction over the decommissioning activities at Yankee
Rowe, CY, MY, and Millstone 1.
The NRC also regularly conducts generic reviews of technical and other
issues, a number of which may affect the nuclear plants in which NU system
companies have interests. The cost of complying with any new requirements that
may result from these reviews cannot be estimated at this time, but such costs
could be substantial.
NUCLEAR PLANT PERFORMANCE
MILLSTONE 3
Millstone 3 has a license expiration date of November 25, 2025. In 2000,
Millstone 3 operated at a capacity factor of virtually 100 percent. On
February 3, 2001, Millstone 3 began a scheduled refueling outage and is
expected to return to service during March 2001.
MILLSTONE 2
Millstone 2 has a license expiration date of July 31, 2015. Millstone 2
returned to service on June 1, 2000, following a 41 day outage, which began in
April 2000, and achieved a 97.4 percent capacity factor from that date to
December 31, 2000. For the full year 2000, Millstone 2 operated at a capacity
factor of 82 percent.
SEABROOK
Seabrook has a license expiration date of October 17, 2026. In 2000,
Seabrook operated at a capacity factor of 78 percent. After an extended 101-
day refueling and maintenance outage due to repairs to an emergency diesel
generator, Seabrook returned to service on January 29, 2001.
VERMONT YANKEE
VY has a license expiration date of March 21, 2012. In 2000, VY operated
at a capacity factor of 99.2 percent.
NUCLEAR INSURANCE
For information regarding nuclear insurance, see "Commitments and
Contingencies - Nuclear Insurance Contingencies" in the notes to NU's, CL&P's,
PSNH's, WMECO's, and NAEC's financial statements.
NUCLEAR FUEL
GENERAL
The supply of nuclear fuel for the NU system's existing units requires the
procurement of uranium concentrates, followed by the conversion, enrichment and
fabrication of the uranium into fuel assemblies suitable for use in the NU
system's units. Fuel may also be purchased at a point after any of the above
processes are completed. The NU system expects that uranium concentrates and
related services for the units operated by the NU system and for the other
units in which the NU system companies are participating that are not covered
by existing contracts, will be available for the foreseeable future on
reasonable terms and prices.
As a result of the Energy Policy Act, the United States commercial nuclear
power industry is required to pay the United States Department of Energy (DOE),
through a special assessment, for the costs of the decontamination and
decommissioning of uranium enrichment plants owned by the United States
government, no more than $150 million per annum for 15 years beginning in 1993.
Each domestic nuclear utility's payment is based on its pro-rata share of all
enrichment services received by the United States commercial nuclear power
industry from the United States government through October 1992. Each year,
the DOE adjusts the annual assessment using the Consumer Price Index. The
Energy Policy Act provides that the assessments are to be treated as reasonable
and necessary current costs of fuel, which costs shall be fully recoverable in
rates in all jurisdictions. The NU system's remaining share to be recovered,
assuming no escalation, is approximately $28.9 million as of December 31, 2000.
Management believes that the DOE assessments against CL&P, WMECO, PSNH, and
NAEC will be recoverable in future rates. Accordingly, each of these companies
has recognized these costs as a regulatory asset, with a corresponding
obligation on its balance sheet.
In 1998, an action was initiated by the owners of Millstone in the U.S.
Court of Federal Claims against the DOE regarding the special annual assessment
that the DOE imposes on purchasers of enriched uranium to meet the future costs
of decontaminating and decommissioning (D&D) government owned uranium
enrichment facilities. Similar actions for Seabrook and CY were also filed.
The lawsuits challenge the imposition of the D&D assessment on federal
constitutional grounds, and are similar to actions filed by a number of other
utilities against DOE. Proceedings in the Millstone, Seabrook and CY cases
are stayed pending the final resolution of a similar claim brought against the
DOE by MYAPC. In July 1999, the claims court dismissed MYAPC's complaint.
MYAPC's appeal of this decision is pending before the court. As of
December 31, 2000, the NU system companies had paid approximately $41.7 million
into the fund.
Nuclear fuel costs associated with nuclear plant operations include
amounts for disposal of spent nuclear fuel. The NU system companies include
in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC,
NHPUC and DTE in rate case or fuel adjustment decisions. Spent fuel disposal
costs also are reflected in the FERC-approved wholesale charges.
HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal
government is responsible for the permanent disposal of spent nuclear reactor
fuel (SNF) and high-level waste. As required by the NWPA, electric utilities
generating SNF and high-level waste are obligated to pay fees into a fund which
would be used to cover the cost of siting, constructing, developing, and
operating a permanent disposal facility for this waste. The NU system
companies have been paying for such services for fuel burned on or after
April 7, 1983, on a quarterly basis since July 1983. The DPUC, NHPUC and DTE
permit the fee to be recovered through rates. For nuclear fuel used to
generate electricity prior to April 7, 1983, payment must be made prior to the
first delivery of spent fuel to the DOE. The DOE's current estimate for an
available site is 2010.
In return for payment of the fees prescribed by the NWPA, the federal
government is to take title to and dispose of the utilities' high-level wastes
and SNF. There have been numerous litigation proceedings involving the DOE's
statutory and contractual obligation to accept high-level waste and SNF. While
the courts have declined to order the DOE to begin accepting spent fuel for
disposal on January 31, 1998, the courts left open the utilities' ability to
bring damage claims against the DOE.
In 1998, YAEC, CYAPC and MYAPC filed separate complaints against the DOE
in the U.S. Court of Federal Claims seeking monetary damages resulting from
DOE's failure to accept spent nuclear fuel for disposal. In decisions later
that year, the court found liability on the part of DOE to the companies for
breach of the standard contract, based upon the DOE's failure to begin
disposal of spent nuclear fuel. Further proceedings to determine damages
owed to YAEC, CYAPC and MYAPC remain stayed by the court as a result of DOE's
appeal of the liability decisions and related litigation involving other
utilities.
Until the federal government begins accepting nuclear waste for disposal,
nuclear generating plants will need to retain high-level waste and spent fuel
onsite or make some other provisions for their storage. With the addition of
new storage racks, storage facilities for Millstone 3 are expected to be
adequate for the current licensed life of the unit. With the implementation
of currently planned modifications, the storage facilities for Millstone 2
are expected to be adequate (maintaining the capacity to accommodate a full-
core discharge from the reactor) until 2005 Seabrook is expected to have
spent fuel storage capacity until at least 2010.
The VY spent fuel pool is expected to be able to accommodate full-core
removal through 2004 as a result of the installation and licensing of new
racks in January 2001. In 2003, VYNPC expects to install an additional rack
which would provide for full core off-load capability through 2008.
Adequate storage capacity exists to accommodate all of the SNF at
Millstone 1, CY, MY, and Yankee Rowe until that fuel is removed by the DOE.
LOW-LEVEL RADIOACTIVE WASTE
The NU system currently has contracts to dispose of its low-level
radioactive waste (LLRW) at two privately operated facilities in Clive, Utah,
and in Barnwell, South Carolina. In July 2000, the Northeast Interstate Low
Level Radioactive Waste Management Compact, consisting of Connecticut and New
Jersey, accepted South Carolina as a new member and is now known as the
Atlantic Compact. This arrangement entitles Millstone and CY access to
Barnwell through their decommissioning. This arrangement may eventually
exclude other nuclear plants from accessing Barnwell. As a contingency, the
NU system has plans that will allow for onsite storage of LLRW for at least
5 years.
DECOMMISSIONING
Based upon the NU system's most recent comprehensive site-specific updates
of the decommissioning costs for each of the three Millstone units and for
Seabrook, the recommended decommissioning method continues to be immediate and
complete dismantlement of those units as soon as practical after their
retirement. The table below sets forth the estimated Millstone and Seabrook
decommissioning costs for the NU system companies. The estimates are based
on the latest site studies, stated in December 31, 2000, dollars.
CL&P PSNH WMECO NAEC NU system
(Millions)
Millstone 1* $ 580.3 $ - $136.1 $ - $ 716.4
Millstone 2 348.8 - 81.8 - 430.6
Millstone 3 343.1 18.4 79.3 - 440.8
Seabrook 23.8 - - 210.8 234.6
-------- ----- ------ ------ --------
Total $1,296.0 $18.4 $297.2 $210.8 $1,822.4
======== ===== ====== ====== ========
*The costs shown include all of the billings associated with the funding
of decommissioning, recovery of remaining assets and other closure costs
associated with the early retirement of Millstone 1 as of December 31, 2000,
which have been recorded as an obligation on the books of the NU system
companies of which $74.4 million has been spent and reimbursed as of
December 31, 2000.
In 1986, the DPUC approved the establishment of separate external trusts
for the currently tax-deductible portions of decommissioning expense accruals
for Millstone 1 and 2 and for all expense accruals for Millstone 3. WMECO
has established independent trusts to hold all decommissioning expense
collections from customers. The DTE has authorized WMECO to collect its
current decommissioning estimate for the three Millstone units.
New Hampshire enacted a law in 1981 requiring the creation of a state-
managed fund to finance decommissioning of any units in that state. NAEC's
costs for decommissioning Seabrook are billed by it to PSNH and recovered by
PSNH under the Rate Agreement. During April 1999, the Nuclear Decommissioning
Finance Committee (NDFC) issued an order that adjusted the decommissioning
collection period and funding levels. The NDFC's order concluded that
Seabrook's anticipated energy producing life was 25 years from the date it
went into commercial operation, and accordingly Seabrook will end its energy
producing life in October 2015. This is 11 years earlier than the service life
established by Seabrook's NRC operating license. The order also updated
Seabrook's decommissioning estimate to $513 million (in 1998 dollars). In
December 2000, the NDFC approved an updated decommissioning estimate of $585.9
million (in 2000 dollars). The cost of funding the decommissioning of Seabrook
continues to be accrued over the expected remaining service life of the plant,
as determined by the NDFC, and is included in depreciation expense. After
commencement of competition, PSNH will recover decommissioning expenses as a
stranded cost.
As of December 31, 2000, the NU system recorded balances (at market) in
its external decommissioning trust funds are as follows:
CL&P PSNH WMECO NAEC NU system
(Millions)
Millstone 1 $226.8 $ - $ 62.5 $ - $289.3
Millstone 2 179.6 - 49.5 - 229.1
Millstone 3 124.7 7.4 32.9 - 165.0
Seabrook 5.8 - - 50.8 56.6
------ ---- ------ ----- ------
Total $536.9 $7.4 $144.9 $50.8 $740.0
====== ==== ====== ===== ======
Pursuant to NU's purchase and sale agreement (PSA) with Dominion for the
sale of the Millstone units, upon the closing of the sale, which is expected to
occur on or about April 2, 2001, the sellers are obligated to deliver to
Dominion decommissioning funds in the amounts of $268.3 million for Unit 1,
$253 million for Unit 2 and $244 million for Unit 3. With respect to Unit 3,
the NU system companies are responsible for $178 million of the total amount
to be turned over to Dominion. At that point, Dominion will assume full
responsibility for decommissioning the three Millstone units, and NU
shareholders, the NU system companies and their ratepayers will have no
further obligation related to decommissioning. If the closing is delayed,
the amount of decommissioning funds to be transferred to Dominion will be
increased by 0.5 percent per month for each month of delay. Finally, the PSA
requires that Unit 1 be turned over to Dominion in "cold and dark" condition.
If it is not, the NU system companies have agreed to add to the decommissioning
trust fund the necessary additional amount to place the unit in "cold and dark"
condition. That amount, if any, is currently unknown, as it is expected that
the unit will be turned over in a "cold and dark" condition.
Pursuant to the PSNH Settlement Agreement, upon a successful sale of
NAEC's share of Seabrook, the existing Seabrook Power Contracts between PSNH
and NAEC will be terminated. However, subsequent to such sale, PSNH shall
continue to be responsible for funding NAEC's former ownership share of its
decommissioning liability, calculated on the basis of full funding by
December 31, 2015, using an estimated decommissioning date of 2015, or as
otherwise determined by the NDFC. PSNH may enter into a new contract to
provide for the payment of Seabrook nuclear decommissioning costs, with full
recovery of the costs of that contract to be recoverable from PSNH's
customers. Under no circumstances will PSNH's customers have any
responsibility for increases in decommissioning funding above the amount
calculated based upon the payment schedule as of the sale date.
In June 1999, NNECO filed with the NRC the Post-Shutdown Decommissioning
Activities Report for Millstone 1. The total estimated decommissioning costs,
which have been updated to reflect the early shutdown of the unit, are
approximately $692 million as of December 31, 2000 ($560.5 million for CL&P
and $131.5 million for WMECO).
CYAPC, VYNPC and MYAPC are all collecting revenues for decommissioning
from their power purchasers. The table below sets forth the NU system
companies' estimated share of remaining decommissioning costs (and closure
costs where applicable) of the Yankee units as of December 31, 2000. The
estimates are based on the latest site studies. For information on the
equity ownership of the NU system companies in each of the Yankee units and
the proposed sale of VY, see "Nuclear Generation - General."
CL&P PSNH WMECO NU system
(Millions)
VY $ 42.9 $18.1 $11.3 $ 72.3
CY* 93.5 13.5 25.8 132.8
MY* 67.1 27.9 16.8 111.8
------ ----- ----- ------
Total $203.5 $59.5 $53.9 $316.9
====== ===== ===== ======
*The costs shown include all of the expected future billings associated
with the funding of decommissioning, recovery of remaining assets and other
closure costs associated with the early retirement of Yankee Rowe, CY and MY
as of December 31, 2000, which have been recorded as an obligation on the
books of the NU system companies.
As of December 31, 2000, the NU system's share of the external
decommissioning trust fund balances (at market), which have been recorded on
the books of the Yankee nuclear companies, is as follows:
CL&P PSNH WMECO NU system
(Millions)
VY $ 26.8 $11.3 $ 7.0 $ 45.1
Yankee Rowe 36.8 10.5 10.5 57.8
CY 58.8 8.5 16.2 83.5
MY 18.7 7.8 4.7 31.2
------ ----- ----- ------
Total $141.1 $38.1 $38.4 $217.6
====== ===== ===== ======
On July 26, 2000, the FERC issued a letter approving an April 7, 2000,
settlement between CYAPC, the DPUC and the OCC on CY decommissioning.
Significant terms of the settlement include (1) decommissioning collections
of $16.7 million per year, fully funding decommissioning and spent fuel
storage costs through 2023; (2) consolidation of the pre-1983 spent fuel
trust into the decommissioning trust and lowering total decommissioning
collections by $56 million over the next seven years; (3) a ROE rate of 6
percent with no refunds of prior decommissioning or ROE collections, and;
(4) an incentive/penalty mechanism for decommissioning. The effect of this
settlement on CYAPC earnings is approximately $9.0 million, of which NU's
share would be approximately $4.4 million.
The settlement enabled the OCC to continue to argue that CYAPC was
entitled to recover only costs directly related to decommission the plant, and
may not recover remaining unamortized investment or any ROE, a position that
had been denied by the FERC's administrative law judge. On September 28, 2000,
the FERC issued an order confirming the ALJ's rejection of the OCC's argument,
from which no further action has been taken.
Effective January 1996, YAEC began billing its sponsors, including CL&P,
WMECO and PSNH, amounts based on a revised decommissioning cost estimate
approved by the FERC. Under the terms of its rate settlement agreement with
the FERC, YAEC filed a revised decommissioning cost estimate, which was approved
as of March 1, 2000. The YAEC filing assumes NRC license termination and
completion of decommissioning activities by 2004. Billings to YAEC sponsor
companies were completed in June 2000.
In January 2001, NNECO filed a written notification with the NRC reporting
that during a reconciliation and verification of Millstone spent nuclear fuel
records, personnel concluded that the location of two full-length irradiated
fuel rods could not be determined, and was not properly tracked in the records.
The records reconciliation and verification effort is part of ongoing
decommissioning activities at Millstone 1. NNECO reported that the two fuel
rods are from the same fuel assembly, which was disassembled in 1972 for
inspection, and were displaced from the fuel assembly in 1974. NNECO further
reported that records indicate that in 1979 and 1980 the displaced rods were
physically verified to be stored in a canister in the Millstone 1 spent fuel
pool, and that the rods and canister are no longer in the spent fuel pool
location documented in 1979 and 1980. NNECO's report indicated that records
retrieved to date do not document the relocation or disposition of the two
fuel rods.
Due to the radiation levels associated with the fuel rods, NU believes
that the two rods remain stored in the Millstone 1 spent fuel pool, or were
shipped in a shielded cask to a facility licensed to accept radioactive
material. NU's investigation into the location of the two fuel rods is
ongoing.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
ENVIRONMENTAL REGULATION
GENERAL
The NU system and its subsidiaries are subject to federal, state and
local regulations with respect to water quality, air quality, toxic substances,
hazardous waste, and other environmental matters. Additionally, the NU
system's major generation and transmission facilities may not be constructed
or significantly modified without a review by the applicable state agency of
the environmental impact of the proposed construction or modification.
Compliance with environmental laws and regulations, particularly air and
water pollution control requirements, may limit operations or require
substantial investments in new equipment at existing facilities.
SURFACE WATER QUALITY REQUIREMENTS
The federal Clean Water Act requires every "point source" discharger of
pollutants into navigable waters to obtain a National Pollutant Discharge
Elimination System (NPDES) permit from the United States Environmental
Protection Agency (EPA) or state environmental agency specifying the allowable
quantity and characteristics of its effluent. NU system facilities are in the
process of obtaining or renewing all required NPDES permits in effect.
Compliance with NPDES and state water discharge permits has necessitated
substantial expenditures, which are difficult to estimate, and may require
further expenditures because of additional requirements that could be imposed
in the future. For information regarding civil lawsuits related to alleged
violations of certain facilities' NPDES permits, see "Item 3. Legal
Proceedings."
The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements
for facility response plans and periodic inspections of spill response
equipment at facilities that can cause substantial harm to the environment by
discharging oil or hazardous substances into the navigable waters of the United
States and onto adjoining shorelines. The NU system companies are currently in
compliance with the requirements of OPA 90. OPA 90 includes limits on the
liability that may be imposed on persons deemed responsible for release of oil.
The limits do not apply to oil spills caused by negligence or violation of laws
or regulations. OPA 90 also does not preempt state laws regarding liability
for oil spills. In general, the laws of the states in which the NU system owns
facilities and through which the NU system transports oil could be interpreted
to impose strict liability for the cost of remediating releases of oil and for
damages caused by releases. The NU system currently carries general liability
insurance in the total amount of $100 million annual coverage, which includes
liability coverage for oil spills.
AIR QUALITY REQUIREMENTS
The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in
Connecticut, Massachusetts and New Hampshire, impose stringent requirements on
emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of
controlling acid rain and ground level ozone. In addition, the CAAA address
the control of toxic air pollutants. Installation of continuous emissions
monitors and expanded permitting provisions also are included. Compliance with
CAAA requirements has cumulatively cost the NU system approximately $48 million
as of December 31, 2000: $11 million for CL&P, $33 million for PSNH, $1 million
for WMECO, and $3 million for HWP. In addition, PSNH expects to spend
approximately $2 million a year for SO2 allowances.
Further requirements for NOX reductions became effective in 1999. PSNH
spent approximately $20 million for improvements at its Merrimack and Schiller
Stations to meet these requirements. These costs were offset by the sale of
$16 million of emission credits. Massachusetts and New Hampshire have proposed
significant emission reduction requirements for power plants in those states.
It is difficult to estimate the ultimate costs, since the proposals are not yet
firm, but the total could be approximately $10 to 15 million over the next
several years at Mt. Tom Station in Massachusetts. PSNH expects to divest the
New Hampshire plants before the new requirements become effective. Following
divestiture of the NU system's fossil units, these federal and state air
quality regulations are not expected to have a material impact on the NU system
companies.
HAZARDOUS WASTE REGULATIONS
As many other industrial companies have done in the past, the NU system
companies disposed of residues from operations by depositing or burying such
materials on-site or disposing of them at off-site landfills or facilities.
Typical materials disposed of include coal gasification waste, fuel oils,
gasoline, and other hazardous materials that might contain polychlorinated
biphenyls. It has since been determined that deposited or buried wastes, under
certain circumstances, could cause groundwater contamination or create other
environmental risks. The NU system has recorded a liability for what it
believes is, based upon currently available information, its estimated
environmental remediation costs for waste disposal sites for which the NU
system companies expect to bear legal liability, and continues to evaluate
the environmental impact of its former disposal practices. Under federal and
state law, government agencies and private parties can attempt to impose
liability on NU system companies for such past disposal. At December 31,
2000, the liability recorded by the NU system for its estimated environmental
remediation costs for known sites needing remediation, including those sites
described below, exclusive of recoveries from insurance or from third parties,
was approximately $82.3 million, representing 42 sites. This total includes
liabilities recorded by Yankee Gas of $35 million. All cost estimates were
made in accordance with generally accepted accounting principles where
remediation costs are probable and reasonably estimable. These costs could
be significantly higher if alternative remedies become necessary.
Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended, commonly known as Superfund, the EPA has
the authority to clean up or order the clean up of hazardous waste sites and
to impose the clean up costs on parties deemed responsible for the hazardous
waste activities on the sites. Responsible parties include the current owner
of a site, past owners of a site at the time of waste disposal, waste
transporters, and waste generators. The NU system currently is involved in
three Superfund sites: one in New York, one in New Hampshire, and one in
Kentucky, which could have a material impact on the NU system. The NU system
has committed in the aggregate approximately $1.4 million to its share of the
clean up of these sites.
The greatest liabilities currently relate to former manufactured gas
plant (MGP) facilities which represent the largest share of future clean up
costs. These facilities were owned and operated by predecessor companies to
the NU system from the mid-1800's to mid-1900's. Byproducts from the
manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar,
metals and other waste products that may pose risks to human health and the
environment. The NU system currently has partial or full ownership
responsibilities at 27 former MGP sites. Of the total NU system liabilities,
$67.9 million has been established to address future remediation costs at MGP
sites.
Other sites undergoing comprehensive investigations or remedial actions
under state programs located in Connecticut, Massachusetts, New Hampshire or
New Jersey include four former fuel oil releases, three landfills, three
asbestos hazard abatement projects and five miscellaneous projects. To date,
approximately $12.9 million has been established to address future
remediation costs at these sites.
In the past, the NU system has received other claims from government
agencies and third parties for the cost of remediating sites not currently
owned by the NU system but affected by past NU system disposal activities and
may receive more such claims in the future. The NU system expects that the
costs of resolving claims for remediating sites about which it has been
notified will not be material, but cannot estimate the costs with respect to
sites about which it has not been notified.
ELECTRIC AND MAGNETIC FIELDS
Published reports have discussed the possibility of adverse health effects
from electric and magnetic fields (EMF) associated with electric transmission
and distribution facilities and appliances and wiring in buildings and homes.
Most researchers, as well as numerous scientific review panels considering all
significant EMF epidemiological and laboratory studies to date, agree that
current information remains inconclusive, inconsistent and insufficient for
characterizing EMF as a health risk.
Based on this information, management does not believe that a causal
relationship between EMF exposure and adverse health effects has been
established or that significant capital expenditures are appropriate to
minimize unsubstantiated risks. The NU system companies have closely
monitored research and government policy developments for many years and will
continue to do so.
If further investigation were to demonstrate that the present electricity
delivery system is contributing to increased risk of cancer or other health
problems, the industry could be faced with the difficult problem of delivering
reliable electric service in a cost-effective manner while managing EMF
exposures. To date, no courts have concluded that individuals have been harmed
by EMF from electric utility facilities, but if utilities were to be found
liable for damages, the potential monetary exposure for all utilities,
including the NU system companies, could be enormous. Without definitive
scientific evidence of a causal relationship between EMF and health effects,
and without reliable information about the kinds of changes in utilities'
transmission and distribution systems that might be needed to address the
problem, if one is found, no estimates of the cost impacts of remedial actions
and liability awards are available.
FERC HYDROELECTRIC PROJECT LICENSING
Federal Power Act licenses may be issued for hydroelectric projects for
terms of 30 to 50 years as determined by the FERC. Upon the expiration of a
license, any hydroelectric project so licensed is subject to reissuance by
the FERC to the existing licensee or to others upon payment to the licensee
of the lesser of fair value or the net investment in the project plus
severance damages less certain amounts earned by the licensee in excess of a
reasonable rate of return.
The NU system companies currently hold FERC licenses for 12 hydroelectric
projects aggregating approximately 1,411 MW of capacity, located in
Connecticut, Massachusetts and New Hampshire. CL&P's and WMECO's 5 licenses
with approximately 1,302 MW of capacity were transferred to NGC in March 2000.
As part of the Settlement Agreement, PSNH has proposed to auction its 6
hydroelectric projects (totaling nine plants) with approximately 65 MW of
capacity upon approval of the agreement.
The original license for HWP's Holyoke Project expired in late 1999. In
August 1999, the FERC issued a new 40-year license to HWP. HWP was the
successful applicant in a contested license application proceeding for the
project, winning over co-applicants, the City of Holyoke Gas & Electric
Department, the Massachusetts Municipal Wholesale Electric Company and the
Ashburnham Municipal Light Plant. HWP filed a motion for stay and motion for
rehearing of the FERC's order, requesting that the FERC reconsider various
aspects of the license, including mandatory Section 18 fishway prescriptions,
bypass reach minimum flows and compliance schedules. Motions for rehearing
of the FERC's order were also filed by various other parties. The FERC issued
an order granting rehearing. HWP is awaiting further action by the FERC. In
a separate but related proceeding, HWP filed an appeal of the state water
quality certificate conditions and requested an adjudicatory hearing with the
Massachusetts Department of Environmental Protection. A settlement agreement
and revised water quality certificate were filed with the administrative law
judge on February 9, 2001.
NGC's FERC licenses for operation of the Falls Village and Housatonic
hydroelectric projects expire in 2001. A license application, which proposed
to combine both projects under one license, was submitted to the FERC in
August 1999. A settlement has been reached with the Connecticut Department
of Environmental Protection (DEP) on the Section 401 water certifications
necessary for relicensing. The FERC has begun the process that delineates
the items that it expects to review as part of its environmental assessment
of the projects and the application for license. Public meetings and tours
at the developments have been held and comments were filed by the public,
agencies and applicant by the January 8, 2001, FERC deadline. No additional
information requests have been received.
PSNH's FERC license for the three dam Amoskeag project expires on
December 31, 2005. PSNH filed a notice of intent to file for a new license
on December 29, 2001.
The FERC has issued a notice indicating that it has authority to order
project licensees to decommission projects that are no longer economic to
operate. The potential costs of decommissioning a project, however, could be
substantial. The FERC has recently ordered its first project decommissioning
under this authority. It is likely that this FERC decision will be appealed.
EMPLOYEES
As of December 31, 2000, the NU system companies had 9,260 employees on
their payrolls, of which 2,057 were employed by CL&P, 1,227 by PSNH, 406 by
WMECO, 410 by Yankee Gas, 110 by R. M. Services, 2 by HWP, 1,696 by NNECO,
2,044 by NUSCO, 782 by NAESCO, 104 by Select Energy, and 422 by HEC. NU,
NAEC, Mode 1, NUEI, NGC, NGS, and SEPPI have no employees.
On December 15, 2000, 498 employees of CL&P, PSNH, WMECO, HWP, NUSCO,
and Yankee Gas were offered a voluntary separation program (VSP). There
were 361 employees who accepted the VSP and are expected to retire between
March 1, 2001, and March 2002. Costs relating to the VSP will be reflected
in the first quarter of 2001 results.
Approximately 2,450 employees of CL&P, PSNH, WMECO, NAESCO, HWP, and
Yankee Gas are covered by 15 union agreements, which expire between June 1,
2001, and October 1, 2003.
ITEM 2. PROPERTIES
The physical properties of the NU system are owned or leased by
subsidiaries of NU. CL&P's principal plants and other properties are located
either on land which is owned in fee or on land, as to which CL&P owns
perpetual occupancy rights adequate to exclude all parties except possibly
state and federal governments, which has been reclaimed and filled pursuant
to permits issued by the United States Army Corps of Engineers. The principal
properties of PSNH are held by it in fee. In addition, PSNH leases space in
an office building under a 30-year lease expiring in 2002. WMECO's principal
plants and a major portion of its other properties are owned in fee, although
one hydroelectric plant is leased. NAEC owns a 35.98 percent interest in
Seabrook and approximately 560 acres of exclusion area land located around
the unit. In addition, CL&P, PSNH and WMECO have certain substation equipment,
data processing equipment, nuclear fuel, nuclear control room simulators,
vehicles, and office space that are leased. With few exceptions, the NU system
companies' lines are located on or under streets or highways, or on properties
either owned or leased, or in which the Company has appropriate rights,
easements or permits from the owners.
CL&P's and PSNH's properties are subject to the lien of each company's
respective first mortgage indenture. WMECO's properties are subject to the
lien of its first mortgage indenture. NAEC's first mortgage bonds are secured
by a lien on the Seabrook Interest described above, and all rights of NAEC
under the Seabrook Power Contracts. In addition, CL&P's and WMECO's interests
in Millstone 1 are subject to second liens for the benefit of lenders under
agreements related to PCRBs. Also, CL&P and WMECO granted, as collateral,
their second mortgage ownership interests in Millstone 2 and 3 that secure
their borrowings under the new credit agreement. Various of these properties
are also subject to minor encumbrances which do not substantially impair the
usefulness of the properties to the owning company.
The NU system companies' properties are well maintained and are in good
operating condition.
TRANSMISSION AND DISTRIBUTION SYSTEM
At December 31, 2000, the NU system companies owned 103 transmission and
370 distribution substations that had an aggregate transformer capacity of
19,751,356 kilovoltamperes (kVa) and 8,957,289 kVa, respectively; 3,075 circuit
miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV,
and 196 cable miles of underground transmission lines ranging from 69 kV to
138 kV; 33,216 pole miles of overhead and 2,191 conduit bank miles of
underground distribution lines; and 423,055 line transformers in service with
an aggregate capacity of 18,268,000 kVa.
ELECTRIC GENERATING PLANTS
As of December 31, 2000, the electric generating plants of the NU system
companies and the NU system companies' entitlement in the generating plant of
the VYNPC were as follows (See "Item 1. Business - Nuclear Generation" for
information on ownership and operating results for the year):
Claimed
Year Capability*
Owner Plant Name (Location) Type Installed (kilowatts)
- ----- -------------------- ---- --------- -----------
CL&P Millstone (Waterford, CT)
Unit 2 Nuclear 1975 706,543
Unit 3 Nuclear 1986 603,436
Seabrook (Seabrook, NH) Nuclear 1990 47,135
VT Yankee (Vernon, VT) Nuclear 1972 45,189
---------
Total Nuclear-Steam Plants ( 4 units) 1,402,303
Total Internal Combustion ( 4 units) 1970 195,600
---------
Total CL&P Generating Plant ( 8 units) 1,597,903
=========
PSNH Millstone (Waterford, CT)
Unit 3 Nuclear 1986 32,461
VT Yankee (Vernon, VT) Nuclear 1972 18,999
---------
Total Nuclear-Steam Plants ( 2 units) 51,460
Total Fossil-Steam Plants ( 7 units) 1952-78 639,568
Total Hydro-Conventional (20 units) 1917-83 67,930
Total Internal Combustion ( 5 units) 1968-70 103,594
---------
Total PSNH Generating Plant (34 units) 862,552
=========
WMECO Millstone (Waterford, CT)
Unit 2 Nuclear 1975 165,732
Unit 3 Nuclear 1986 139,519
VT Yankee (Vernon, VT) Nuclear 1972 11,904
---------
Total Nuclear-Steam Plants ( 3 units) 317,155
Total Hydro-Conventional ( 3 units) 1930 33,960**
---------
Total WMECO Generating Plant ( 6 units) 351,115
=========
NAEC Seabrook (Seabrook, NH) Nuclear 1990 417,751
=========
HWP Mt. Tom (Holyoke, MA) Fossil-Steam 1960 147,000
Total Hydro-Conventional (15 units) 1905-83 43,560
---------
Total HWP Generating Plant (16 units) 190,560
=========
NGC Total Hydro-Conventional (36 units) 1903-55 158,220
Total Hydro-Pumped Storage ( 7 units) 1928-73 1,151,350
Tunnel (Preston, CT) ( 1 unit) 1969 20,800
---------
Total NGC Generating Plant (44 units) 1,330,370
=========
NU system Millstone (Waterford, CT)
Unit 2 Nuclear 1975 872,275
Unit 3 Nuclear 1986 775,416
Seabrook (Seabrook, NH) Nuclear 1990 464,886
VT Yankee (Vernon, VT) Nuclear 1972 76,092
---------
Total Nuclear-Steam Plants ( 4 units) 2,188,669
Total Fossil-Steam Plants ( 8 units) 1952-78 786,568
Total Hydro-Conventional (74 units) 1903-83 303,670
Total Hydro-Pumped Storage ( 7 units) 1928-73 1,151,350
Total Internal Combustion (10 units) 1968-70 319,994
---------
Total NU system Generating Plant
Including Vermont Yankee (103 units) 4,750,251
=========
Excluding Vermont Yankee (102 units) 4,674,159
=========
* Claimed capability represents winter ratings as of December 31, 2000.
** Total Hydro-Conventional capability includes the Cobble Mtn. plant's
33,960 kilowatts which is leased from the City of Springfield, MA.
FRANCHISES
CL&P. Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits and
consents of public authority and others prescribed by statute, CL&P has,
subject to certain exceptions not deemed material, valid franchises free from
burdensome restrictions to provide electric transmission and distribution
services, and, until January 2000, to sell electricity, in the respective
areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution
services as set forth above, the franchises of CL&P include, among others,
limited rights and powers, as set forth in Title 16 of the Connecticut General
Statutes and the special act of the General Assembly constituting its charter,
to manufacture, generate, purchase and sell electricity at retail, including to
provide standard offer, backup, and default service, to sell electricity at
wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on public highways and grounds, all subject to such
consents and approvals of public authority and others as may be required by
law. The franchises of CL&P include the power of eminent domain.
PSNH. The NHPUC, pursuant to statutory requirement, has issued orders
granting PSNH exclusive franchises free from burdensome restrictions to sell
electricity in the respective areas in which it is now supplying such
service.
In addition to the right to sell electricity as set forth above, the
franchises of PSNH include, among others, rights and powers to manufacture,
generate, purchase, transmit, and distribute electricity, to sell electricity
at wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on certain public highways and grounds, all
subject to such consents and approvals of public authority and others as may
be required by law. The franchises of PSNH include the power of eminent
domain.
NNECO. Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits and
consents of public authority and others prescribed by statute, NNECO has a
valid franchise free from burdensome restrictions to sell electricity to
utility companies doing an electric business in Connecticut and other states.
In addition to the right to sell electricity as set forth above, the
franchise of NNECO includes, among others, rights and powers to manufacture,
generate and transmit electricity, and to erect and maintain facilities on
certain public highways and grounds, all subject to such consents and approvals
of public authority and others as may be required by law.
WMECO. WMECO is authorized by its charter to conduct its electric
business in the territories served by it, and has locations in the public
highways for transmission and distribution lines. Such locations are granted
pursuant to the laws of Massachusetts by the Department of Public Works of
Massachusetts or local municipal authorities and are of unlimited duration, but
the rights thereby granted are not vested. Such locations are for specific
lines only, and, for extensions of lines in public highways, further similar
locations must be obtained from the Department of Public Works of Massachusetts
or the local municipal authorities. In addition, WMECO has been granted
easements for its lines in the Massachusetts Turnpike by the Massachusetts
Turnpike Authority.
Pursuant to the Massachusetts restructuring legislation, the DTE is
required to define service territories for each distribution company,
including WMECO, based on the service territories actually served on July 1,
1997, and following to the extent possible municipal boundaries. The DTE has
not yet defined service territories. After established by the DTE, until
terminated by effect of law or otherwise, the distribution company shall have
the exclusive obligation to provide distribution service to all retail
customers within its service territory, and no other person shall provide
distribution service within such service territory without the written
consent of such distribution company.
HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly
owned subsidiary HP&E, are authorized by their charters to conduct their
businesses in the territories served by them. HWP's electric business is
subject to the restriction that sales be made by written contract in amounts
of not less than 100 horsepower to purchasers who use the electricity in
their own business in the counties of Hampden or Hampshire, Massachusetts and
cities and towns in these counties, and customers who occupy property in
which HWP has a financial interest, by ownership or purchase money mortgage.
HWP also has certain dam and canal and related rights, all subject to such
consents and approvals of public authorities and others as may be required by
law. The two companies have locations in the public highways for their
transmission and distribution lines. Such locations are granted pursuant to
the laws of Massachusetts by the Department of Public Works of Massachusetts
or local municipal authorities and are of unlimited duration, but the rights
thereby granted are not vested. Such locations are for specific lines only
and, for extensions of lines in public highways, further similar locations
must be obtained from the Department of Public Works of Massachusetts or the
local municipal authorities. HP&E has no retail service territory area and
sells electric power exclusively at wholesale.
ITEM 3. LEGAL PROCEEDINGS
1. Connecticut Superior Court - Connecticut Attorney General Civil Lawsuit
and Appeal
In 1997, the AG initiated a civil lawsuit, on behalf of the CDEP, in
Connecticut Superior Court against NNECO and NUSCO for violations of the
Millstone water discharge permit and Connecticut water discharge regulations.
In 1998, the Superior Court approved a settlement between NNECO and the AG.
The settlement required NNECO to pay a $700,000 civil penalty and expend
$500,000 to fund three supplemental environmental projects. Additionally,
the settlement requires NNECO to perform two environmental audits of its
water compliance program, have a third-party review of the first NNECO audit
and inform the CDEP of major changes to its environmental management system.
The first audit and the third-party review have been completed. The second
required water compliance audit by NNECO has been completed and the audit
report was submitted to the CDEP for review on January 5, 2001.
An intervenor in the Superior Court proceeding appealed the settlement order.
On July 27, 2000, the Connecticut Supreme Court ruled in favor of NNECO and
NUSCO and affirmed the lower court's decision.
2. Shareholder Securities Class Actions - Nuclear Matters
Consolidated Federal Court Actions: Pursuant to a court order dated
October 1, 1997, the six class actions separately filed against NU in 1996
were consolidated for pre-trial and trial purposes. The actions are based on
various federal securities law and common law theories alleging
misrepresentations and omissions in public disclosures related to the NU
system's nuclear problems, which resulted in extended outages at Millstone
and impacted the financial condition of NU and certain of its subsidiaries.
These complaints represent classes of plaintiffs who purchased or otherwise
acquired NU common stock from March 1994 to April 1996.
The parties executed a settlement agreement and, on March 27, 2000, filed the
agreement with the Federal court. On that date, the court also approved the
form of the settlement notice to be sent to shareholder class members and set
down a schedule for the mailing of the notice (May 10, 2000), the formal
hearing to approve the settlement (July 24, 2000), and the date to file proof
of claim forms (September 29, 2000). Any class member who wished to object
to or opt-out of the settlement was required to do so in writing by July 5,
2000. On July 24, 2000, the court entered an Order approving the settlement
which provides for the dismissal of Stepak v. NU et al, a related state court
action. The time to take an appeal has expired and the judgment is final.
3. Merger-Related Shareholder Lawsuits
On October 13, 1999, and October 19, 1999, virtually identical complaints
were filed in the Supreme Court of New York against NU and its Board of
Trustees. Both complaints purport to be "class action complaints" and allege
that the trustees have breached their fiduciary duties to the plaintiffs and
other members of the class by not (i) obtaining the best price for NU's
assets and businesses and (ii) entrenching themselves and their corporate
offices. The plaintiffs seek equitable relief, including an order that the
trustees maximize shareholder value and award attorneys fees. The cases are
now pending in state court in New York and have been inactive during the
pendency of the Federal action referred to below.
An additional action was brought in Federal court in New York by the plaintiffs
in the shareholder state court actions, alleging that NU, Con Edison and NU's
Trustees have, in addition to violating fiduciary duties, violated Section
14(a) of the Exchange Act by filing a joint proxy statement that fails to
disclose material information about the Indian Point nuclear generating plant.
To avoid a preliminary injunction proceeding and the possibility of the
cancellation of the April 14, 2000, shareholders' vote to approve the merger,
Con Edison and NU agreed to send a supplement to the proxy to the Companies'
shareholders addressing recent developments concerning Indian Point.
At a status conference on November 3, 2000, in the Federal case, a tentative
settlement agreement was reached by which a class would be certified, counsel
fees would be paid by Con Edison and the Section 14(a) claim would be
dismissed with prejudice. The parties executed the settlement agreement
which was submitted to the Court, for approval, at the status conference on
March 16, 2001. At the conference, the Court, as a result of the termination
of the merger agreement, dismissed the fiduciary duty claims without prejudice,
and scheduled a hearing for approval of the settlement for July 13, 2001.
Notice of the hearing will be sent to shareholders on or about May 17, 2001.
After dismissal of the Federal action, the trustees will move to dismiss the
state court actions, without prejudice, because the issues raised therein are
moot.
4. Con Edison/NU Merger Appeals and Related Litigation
On October 19, 2000, the DPUC issued a decision (the October Decision) in
Docket No. 00-01-11, Joint Application of Con Edison and NU for Approval of
Change of Control, approving with conditions the merger of Con Edison and NU.
Subsequent to the October Decision, the AG, the OCC and Con Edison and NU
(collectively, the Applicants) filed separate petitions for reconsideration.
In a decision dated November 22, 2000 (the November Decision), the DPUC
rejected the petitions for reconsideration of the AG and the OCC. The DPUC
granted in part and rejected in part the Applicants' petition for
reconsideration, and ordered a portion of the modifications that the
Applicants had requested.
On December 4, 2000, the AG appealed the November Decision to the Connecticut
Superior Court. On December 6, 2000, the OCC appealed the October Decision
to the Superior Court. The appeals are pending. On February 13, 2001, the
AG and the OCC filed motions to stay the DPUC's approval, intended to prevent
the merger from being consummated prior to the court's determination of the
appeal. On February 14, 2001, NU, Con Edison and the DPUC filed motions to
dismiss the appeals. A status conference was held on February 23, 2001, at
which the court established a briefing and argument schedule for the motions
for stay and motions to dismiss. On March 8, 2001, as a result of the events
leading to the lawsuits described below, NU filed a motion with the court to
suspend the briefing and argument schedule in the appeals. That motion was
granted by the court on March 9, 2001.
On March 6, 2001, Con Edison filed suit in the U.S. District Court for the
Southern District seeking a declaratory judgment that NU had failed to
satisfy conditions precedent under the merger agreement and that Con Edison
had no further obligations under the merger agreement. On March 12, 2001, NU
filed suit in the U.S. District Court for the Southern District seeking
substantial monetary damages against Con Edison arising out of Con Edison's
material breach of the merger agreement.
For further information on the events leading to these lawsuits, see "Part I,
Item 1. Business - Mergers and Acquisitions."
5. Connecticut Superior Court - Fish Unlimited Lawsuits
In March 1999, certain parties brought a civil suit in Connecticut Superior
Court against NNECO and NUSCO seeking a temporary and a permanent injunction
to prevent the restart of Millstone 2 until a fish return system and cooling
tower are installed. In April 1999, the Superior Court issued a temporary
restraining order (TRO) to prevent NNECO from starting up Millstone 2 until
it ruled on the temporary injunction issue. In May 1999, the court dissolved
the TRO and denied the applications for both temporary and permanent
injunctions. The plaintiffs appealed this decision. In July 2000, the
Connecticut Supreme Court ruled in favor of NNECO and NUSCO, holding that it
did not have jurisdiction to consider the plaintiffs' claims for injunctive
relief. The Supreme Court vacated the prior judgment and remanded the case
to the trial court with direction to dismiss the action. Fish Unlimited's
motion seeking reconsideration has been denied by the Supreme Court.
In July 1999, the Connecticut Superior Court granted NNECO's and NUSCO's
motion to dismiss an additional lawsuit that was filed by certain plaintiffs
in June 1999, challenging the validity of Millstone's water discharge permit.
Millstone's NPDES permit is currently under review for renewal, but both
NNECO and CDEP contend that the existing NPDES permit is valid. The plaintiffs
appealed the court's decision, and on July 24, 2000, the Connecticut Supreme
Court ruled in favor of NNECO and NUSCO and affirmed the trial court's
decision.
6. Millstone 3 - Damage to Fish Population Lawsuits
On April 20, 2000, two lawsuits were filed in Connecticut Superior Court
against NNECO and NUSCO seeking to enjoin operations at Millstone due to
alleged damage caused to the winter flounder population in the Niantic River
and Long Island Sound. The first action, brought by certain citizens groups,
sought a temporary injunction to suspend Millstone 3 operations through the
second week of June 2000. On August 30, 2000, NNECO filed a motion to dismiss
on the grounds that the plaintiffs failed to exhaust their administrative
remedies before resorting to the court. The motion also contended that the
action should be dismissed as moot since plaintiffs only sought to enjoin the
operation of Millstone 3 through June 2000. On October 16, 2000, NNECO's
motion to dismiss this action was granted.
The second action, brought by two fishermen, alleges two counts: common law
nuisance and tortuous interference with a business expectancy. The suit
alleges that Millstone has engaged in various actions, including entrainment
of winter flounder, that have caused the two fishermen to suffer damages.
The suit seeks, among other claims of relief, temporary and permanent
injunctions to suspend Millstone operations during the winter flounder
spawning season, conversion of Millstone to a close-cooling system or, in the
alternative, permanent shutdown and compensatory and punitive damages. A
motion to strike both counts of the plaintiffs' complaint was filed on
July 31, 2000. On December 22, 2000, NNECO's motion to strike was denied.
NNECO is now proceeding with discovery.
On April 26, 2000, another lawsuit was filed in Hartford Superior Court against
NUSCO, NNECO and the Commissioner of the CDEP challenging the validity of
previously issued CDEP emergency and temporary authorizations allowing
Millstone to discharge wastewater not expressly authorized by the facility's
NPDES permit. The suit sought a temporary and permanent injunction against
operations at Millstone 1, 2 and 3. On August 30, 2000, NNECO filed a motion
to dismiss, and on October 16, 2000, NNECO's motion was granted. Plaintiffs
have since filed an appeal, which remains pending, with the Connecticut
Appellate Court.
7. Sale of Millstone to Dominion Nuclear Connecticut, Inc.
On February 20, 2001, the CCAM filed in Connecticut Superior Court an appeal of
the DPUC's decision approving the sale of Millstone to Dominion. CCAM alleges
that the final decision violates the Connecticut general statues on multiple
grounds and requests that the decision be reversed and vacated. On March 2,
2001, CCAM filed a motion to stay, which was heard by the court on March 12,
2001. The parties are awaiting a decision from the court on the motion.
On March 8, 2001, CCAM and other parties also filed a lawsuit in Connecticut
Superior Court against the CDEP, NNECO and Dominion challenging (1) the
validity of Millstone's NPDES permit (Permit) and a previously issued CDEP
emergency authorization allowing Millstone to discharge wastewater not
expressly authorized by the facility's Permit, and (2) CDEP's authority to
transfer both Millstone's Permit and emergency authorization to Dominion.
The lawsuit seeks to declare both the Permit declaratory and emergency
authorization invalid and to enjoin continued power operation at Millstone
and the transfer of NNECO's Permit and emergency authorization to Dominion.
The plaintiffs have applied for a TRO which seeks to enjoin CDEP from
transferring both the permit and emergency authorization to Dominion prior to
a full hearing. NNECO has filed a Motion to Dismiss and a memorandum in
opposition to CCAM's request for a TRO. On March 21, 2001, this matter was
transferred to the Superior Court's complex litigation docket.
On March 12, 2001, the Millstone Station Employees Association filed in
Connecticut Superior Court a request for a stay of the DPUC's approval of the
sale of Millstone pending resolution of certain employee pension issues. The
DPUC and CL&P have moved to dismiss the stay request on various grounds. No
hearing date has been established.
For further information on the sale of the Millstone units, see "Item 1.
Business - Rates and Electric Industry Restructuring" and "Nuclear
Generation."
8. Other Legal Proceedings
The following sections of "Item 1. Business" discuss additional legal
proceedings: See "Rates and Electric Industry Restructuring" for information
about various state restructuring proceedings and civil lawsuits related
thereto; "Regulated Electric Operations" and "Regulated Gas Operations" for
information about proceedings relating to power, transmission and pricing
issues; "Nuclear Generation" and "Nuclear Plant Performance" for information
related to nuclear plant performance, nuclear fuel enrichment pricing, high-
level and LLRW disposal, decommissioning matters, and NRC regulation, and;
"Other Regulatory and Environmental Matters" for information about proceedings
involving surface water and air quality, toxic substances and hazardous waste,
electric and magnetic fields, licensing of hydroelectric projects, and other
matters.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No event that would be described in response to this item occurred with
respect to NU, CL&P, PSNH, WMECO, or NAEC.
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
NU. The common shares of NU are listed on the New York Stock Exchange.
The ticker symbol is "NU," although it is frequently presented as "Noeast
Util" and/or "NE Util" in various financial publications. The high and low
sales prices for the past two years, by quarters, are shown below.
Year Quarter High Low
---- ------- ---- ---
2000 First $21.5000 $18.0000
Second 23.1250 20.8125
Third 23.9600 21.5000
Fourth 24.5600 18.2500
1999 First $16.4375 $13.7500
Second 18.3125 13.5625
Third 19.0000 17.3750
Fourth 22.0000 17.7500
As of January 31, 2001, there were 79,709 common shareholders of record
of NU. As of the same date, there were a total of 148,772,670 common shares
issued, including 4,913,146 unallocated ESOP shares held in the ESOP trust.
On January 11, 2000, the NU Board of Trustees approved the payment of a
10 cent per share dividend, payable on March 31, 2000, to shareholders of
record as of March 1, 2000. The record date for this dividend was changed on
January 31, 2000 to March 6, 2000, to provide Yankee shareholders who
received NU common shares the opportunity to receive the dividend following
the Yankee merger.
On April 12, 2000, the NU Board of Trustees approved the payment of a 10
cent per share dividend, payable on June 30, 2000, to shareholders of record
as of June 1, 2000.
On July 11, 2000, the NU Board of Trustees approved the payment of a 10
cent per share dividend, payable on September 29, 2000, to shareholders of
record as of September 1, 2000.
On October 10, 2000, the NU Board of Trustees approved the payment of a
10 cent per share dividend, payable on December 29, 2000, to shareholders of
record as of December 1, 2000.
On September 14, 1999, the NU Board of Trustees approved the payment of
NU's first common share dividend since March 1997. NU paid a 10 cent per
share dividend on December 30, 1999, to shareholders of record as of
December 1, 1999.
Information with respect to dividend restrictions for NU and its
subsidiaries is contained in Item 1. Business under the caption "Financing
Program - Financing Limitations" and in Note (b) to the "Consolidated
Statements of Shareholders' Equity" on page F-26 of this document.
CL&P, PSNH, WMECO, and NAEC. The information required by this item is
not applicable because the common stock of CL&P, PSNH, WMECO, and NAEC is
held solely by NU.
ITEM 6. SELECTED FINANCIAL DATA
NU. Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page F-67 of this document.
CL&P. Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page 41 of CL&P's 2000 Annual
Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected
Financial Data" contained on page 38 of PSNH's 2000 Annual Report, which
information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on page 37 of WMECO's 2000 Annual
Report, which information is incorporated herein by reference.
NAEC. Reference is made to information under the heading "Selected
Financial Data" contained on page 27 of NAEC's 2000 Annual Report, which
information is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS; AND
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NU. Reference is made to information under the heading "Management's
Discussion and Analysis and Results of Operations" contained on pages F-1
through F-18 of this document.
CL&P. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 11 in CL&P's 2000 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 9 in PSNH's 2000 Annual Report, which
information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 9 in WMECO's 2000 Annual Report, which
information is incorporated herein by reference.
NAEC. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 1 through 7 in NAEC's 2000 Annual Report, which
information is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
NU. Reference is made to information under the headings "Company Report,"
"Report of Independent Public Accountants," "Consolidated Statements of
Income," "Consolidated Statements of Comprehensive Income," "Consolidated
Balance Sheets," "Consolidated Statements of Shareholders' Equity,"
"Consolidated Statements of Cash Flows," "Consolidated Statements of
Capitalization," "Consolidated Statements of Income Taxes," "Notes to
Consolidated Financial Statements," and "Consolidated Statements of Quarterly
Financial Data" contained on pages F-19 through F-65 of this document.
CL&P. Reference is made to information under the headings "Report of
Independent Public Accountants," "Consolidated Statements of Income,"
"Consolidated Statements of Comprehensive Income," "Consolidated Balance
Sheets," "Consolidated Statements of Common Stockholder's Equity,"
"Consolidated Statements of Cash Flows," "Notes to Consolidated Financial
Statements," and "Consolidated Quarterly Financial Data" contained on pages
12 through 41 in CL&P's 2000 Annual Report, which information is incorporated
herein by reference.
PSNH. Reference is made to information under the headings "Report of
Independent Public Accountants," "Statements of Income," "Statements of
Comprehensive Income," "Balance Sheets," "Statements of Common Stockholder's
Equity," "Statements of Cash Flows," "Notes to Financial Statements," and
"Quarterly Financial Data" contained on pages 10 through 38 in PSNH's 2000
Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Report of
Independent Public Accountants," "Consolidated Statements of Income,"
"Consolidated Statements of Comprehensive Income," "Consolidated Balance
Sheets," "Consolidated Statements of Common Stockholder's Equity,"
"Consolidated Statements of Cash Flows," "Notes to Consolidated Financial
Statements," and "Consolidated Quarterly Financial Data" contained on pages
10 through 37 in WMECO's 2000 Annual Report, which information is
incorporated herein by reference.
NAEC. Reference is made to information under the headings "Report of
Independent Public Accountants," "Statements of Income," "Balance Sheets,"
"Statements of Common Stockholder's Equity," "Statements of Cash Flows,"
"Notes to Financial Statements," and "Quarterly Financial Data" contained on
pages 8 through 27 in NAEC's 2000 Annual Report, which information is
incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
No event that would be described in response to this item has occurred
with respect to NU, CL&P, PSNH, WMECO, or NAEC.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
NU.
First First
Positions Elected Elected
Name Held an Officer a Trustee
- ----------------------- --------- ---------- ---------
Cotton M. Cleveland T n/a 06/23/92
Sanford Cloud, Jr. T n/a 05/09/00
William F. Conway T n/a 06/17/97
E. Gail de Planque T n/a 10/01/95
John H. Forsgren EVP, CFO 02/01/96 05/09/00
Raymond L. Golden T n/a 05/11/99
Cheryl W. Grise SVP, SEC, GC 06/01/91 n/a
Elizabeth T. Kennan T n/a 01/22/80
Bruce D. Kenyon P 09/03/96 n/a
Hugh C. MacKenzie (1) P 07/01/88 n/a
Michael G. Morris CHB, P, CEO, T 08/19/97 08/19/97
Emery G. Olcott T n/a 05/09/00
William J. Pape II T n/a 04/23/74
Robert E. Patricelli T n/a 05/25/93
Gary D. Simon OTH 04/15/98 n/a
John F. Swope T n/a 06/23/92
Lisa J. Thibdaue OTH 01/01/98 n/a
John F. Turner T n/a 05/23/95
CL&P.
First First
Positions Elected Elected
Name Held an Officer a Director
- ----------------------- --------- ---------- ----------
David H. Boguslawski VP, D 09/09/96 06/30/99
John H. Forsgren (2) OTH 02/10/96 n/a
Cheryl W. Grise (2) OTH 06/01/91 n/a
Bruce D. Kenyon (2) OTH 09/03/96 n/a
Hugh C. MacKenzie (1) P, D 07/01/88 06/06/90
Michael G. Morris (2) OTH 08/19/97 n/a
Rodney O. Powell VP, D 10/18/98 06/30/99
Lisa J. Thibdaue (2) OTH 01/01/98 n/a
PSNH.
First First
Positions Elected Elected
Name Held an Officer a Director
- ----------------------- --------- ---------- ----------
David H. Boguslawski VP, D 06/05/92 06/30/99
John C. Collins D n/a 10/19/92
John H. Forsgren (2) OTH, D 02/01/96 08/05/96
Cheryl W. Grise (2) OTH 07/31/98 n/a
Bruce D. Kenyon (2) OTH 09/03/96 n/a
Gerald Letendre D n/a 10/19/92
Gary A. Long P, COO, D 01/01/94 07/01/00
Hugh C. MacKenzie (1)(2) OTH, D 02/01/96 02/01/94
Michael G. Morris CH, D 08/19/97 08/19/97
Jane E. Newman D n/a 10/19/92
Lisa J. Thibdaue (2) OTH 01/01/98 n/a
WMECO.
First First
Positions Elected Elected
Name Held an Officer a Director
- ----------------------- --------- ---------- ----------
David H. Boguslawski VP, D 09/09/96 06/30/99
James E. Byrne D n/a 09/17/99
John H. Forsgren (2) OTH, D 02/01/96 06/10/96
Cheryl W. Grise (2) OTH 06/01/91 n/a
Bruce D. Kenyon (2) OTH 09/03/96 n/a
Kerry J. Kuhlman P, COO, D 10/18/98 04/01/99
Hugh C. MacKenzie (1)(2) OTH, D 07/01/88 06/06/90
Paul J. McDonald D n/a 09/17/99
Michael G. Morris CH, CEO, D 08/19/97 08/19/97
Melinda M. Phelps D n/a 09/17/99
Lisa J. Thibdaue (2) OTH 01/01/98 n/a
NAEC.
First First
Positions Elected Elected
Name Held an Officer a Director
- ----------------------- --------- ---------- ----------
William A. DiProfio (3) D n/a 06/30/99
Ted C. Feigenbaum EVP, CNO, D 10/21/91 06/30/99
John H. Forsgren (2) OTH 02/01/96 n/a
George R. Gram II D n/a 02/02/01
Cheryl W. Grise (2) OTH 10/21/91 n/a
Bruce D. Kenyon P, CEO, D 09/03/96 09/03/96
Michael G. Morris (2) OTH 08/19/97 n/a
1. Mr. MacKenzie retired effective January 1, 2001.
2. Executive Officers of Registrant because of policy-making functions for
NU system.
3. Mr. DiProfio retired effective February 1, 2001.
Key:
CEO - Chief Executive Officer OTH - Executive Officer of
CFO - Chief Financial Officer Registrant because of policy-
CH - Chairman making functions for NU system
CHB - Chairman of the Board P - President
CNO - Chief Nuclear Officer SEC - Secretary
COO - Chief Operating Officer SVP - Senior Vice President
D - Director T - Trustee
EVP - Executive Vice President VP - Vice President
GC - General Counsel
Name Age Business Experience During Past 5 Years
- ------------------------- --- ---------------------------------------
David H. Boguslawski 46 Vice President-Energy Delivery of CL&P, PSNH
and WMECO, since 1996; previously Vice
President-Customer Operations of PSNH from
1994 to 1996 and Vice President-Marketing of
PSNH from 1992 to 1994.
James E. Byrne 46 Partner, Finneran, Byrne & Dreshsler, L.L.P.,
since 1982.
Cotton M. Cleveland (1) 48 President of Mather Associates, New London,
New Hampshire (a firm specializing in
leadership and organizational development for
corporate and non-profit organizations).
From 1991 until 1998, founding Executive
Director of Leadership New Hampshire.
Sanford Cloud, Jr. (2) 56 President and Chief Executive Officer of The
National Conference for Community and
Justice, New York, New York. From 1993 to
1994, he was a partner in the law firm of
Robinson and Cole, Hartford, Connecticut.
Previously Vice President of Aetna Life and
Casualty Company and served for two terms as
a state senator of Connecticut.
John C. Collins (3) 55 Chief Executive Officer, Dartmouth-Hitchcock
Clinic, Dartmouth-Hitchcock Medical Center
since 1977.
William F. Conway (4) 70 President of William F. Conway & Associates,
Inc., Scottsdale, Arizona (a management
consulting firm to the nuclear power
industry). From 1989 to 1994 (retired July
1994), he was Executive Vice President-
Nuclear of Arizona Public Service Company,
Phoenix, Arizona. Previously, he was Senior
Vice President of Nuclear Operations at
Florida Power & Light Company, Juno Beach,
Florida.
E. Gail de Planque (5) 56 President, Strategy Matters, Inc., and
Director Energy Strategies Consultancy, Ltd.
From 1991 to 1995, Dr. de Planque was a
Commissioner with the United States NRC. In
1967, Dr. de Planque joined the Health and
Safety Laboratory of the United States Atomic
Energy Commission. She served at the
Laboratory, now known as the Environmental
Measurements Laboratory, until December 1991,
as Deputy Director beginning in 1982 and as
Director in 1987.
William A. DiProfio 58 Retired February 1, 2001. Seabrook Station
Director, NAESCO from 1992 to 2000.
Ted C. Feigenbaum (6) 50 Executive Vice President and Chief Nuclear
Officer of NAEC since February, 1996;
previously Senior Vice President of NAEC
since 1991; Senior Vice President and Chief
Nuclear Officer of PSNH from June 1992 to
August 1992; President and Chief Executive
Officer-New Hampshire Yankee Division of PSNH
from 1990 to 1992 and Chief Nuclear
Production Officer of PSNH from 1990 to 1992.
John H. Forsgren (7) 54 Executive Vice President and Chief Financial
Officer of NU since February 1996;
previously Executive Vice President and Chief
Financial Officer of CL&P, PSNH, WMECO and
NAEC from February 1996 to June 1999;
Managing Director of the Chase Manhattan Bank
from 1995 to 1996 and Senior Vice President
of The Walt Disney Company from 1990 to 1994.
Raymond L. Golden (8) 63 Independent Consultant. Previously served as
Chairman Emeritus of BT Wolfensohn, New York,
New York, a business unit of BT Alex Brown
Incorporated. From August 1996 to December
1997, he was Chairman of BT Wolfensohn.
Prior to that, he served as President of
Wolfensohn & Company.
George W. Gram II 52 Director - Support Services, Seabrook
Station, NAESCO since December 1999;
Previously Director - Site Support from March
1999 to December 1999; and Executive Director
of Support Services from 1991 to 1999.
Cheryl W. Grise 48 Senior Vice President, Secretary and General
Counsel of NU since July 1998; previously
Senior Vice President, Secretary and General
Counsel of CL&P, PSNH and NAEC and Senior
Vice President, Secretary, Assistant Clerk
and General Counsel of WMECO from July 1998
to June 1999; Senior Vice President and Chief
Administrative Officer of CL&P, PSNH and
NAEC, and Senior Vice President of WMECO from
1995 to 1998; Senior Vice President-Human
Resources and Administrative Services of
CL&P, WMECO and NAEC from 1994 to 1995 and
Vice President-Human Resources of CL&P, WMECO
and NAEC from 1992 to 1994.
Elizabeth T. Kennan (9) 62 President Emeritus of Mount Holyoke College,
South Hadley, Massachusetts. Previously
President of Mount Holyoke College.
Bruce D. Kenyon (10) 58 President and Chief Executive Officer of NAEC
since September 1996 and President-Generation
Group of NU since March 1999; previously
President-Generation Group of CL&P, PSNH and
WMECO from March 1999 to June 1999;
President-Nuclear Group of NU, CL&P, PSNH and
WMECO from September 1996 to March 1999;
President and Chief Operating Officer of
South Carolina Electric and Gas Company from
1990 to 1996.
Kerry J. Kuhlman 50 President and Chief Operating Officer of
WMECO since April 1999; previously Vice
President-Customer Operations of WMECO from
October 1998 to April 1999; Vice President-
Central Region of CL&P from August 1997 to
October 1998; and Vice President-Eastern
Region of CL&P from July 1994 to August 1997.
Gerald Letendre (11) 59 President, Diamond Casting & Machine Co.,
Inc. since 1972.
Gary A. Long 49 President and Chief Operating Officer of
PSNH since July 1, 2000; previously Senior
Vice President-PSNH from February 2000
through June 2000 and Vice President-
Customer Service and Economic Development of
PSNH from January 1994 to February 2000.
Hugh C. MacKenzie 58 Retired January 1, 2001; Previously President
- Retail Business Group of NU from February
1996 and President of CL&P from January 1994
through December 2000; previously President
of WMECO from January 1994 to April 1999;
Senior Vice President-Customer Service
Operations of CL&P and WMECO from 1990 to
1994.
Paul J. McDonald (12) 57 Advisor to the Board of Directors, Friendly
Ice Cream Corporation since January 2000;
previously Senior Executive Vice President
and Chief Financial Officer, Friendly Ice
Cream Corporation, from 1986 to 1999.
Michael G. Morris (13) 54 Chairman of the Board, President and Chief
Executive Officer of NU, Chairman and Chief
Executive Officer of PSNH since July 1,
2000, and Chairman of WMECO since August
1997; previously Chairman and Chief Executive
Officer of PSNH from August 1997 to March
2000, previously Chairman of CL&P and NAEC
from August 1997 to June 1999; President and
Chief Executive Officer of Consumers Power
Company from 1994 to 1997 and Executive Vice
President and Chief Operating Officer of
Consumers Power Company from 1992 to 1994.
Jane E. Newman (14) 55 Executive Dean, Harvard University's John F.
Kennedy School of Government since July
2000; Previously Managing Director, The
Commerce Group, LLC, a strategic
communications company, from January 1999 to
July 2000; Dean, Whittemore School of
Business and Economics of the University of
New Hampshire from January 1998 to January
1999; Executive Vice President and Director,
Exeter Trust Company from 1995 to 1997 and
President, Coastal Broadcasting Corporation
from 1992 to 1995.
Emery G. Olcott (15) 62 Chairman, President and Chief Executive
Officer of Packard BioScience Company
(f/k/a Canberra Industries Incorporated),
provider of systems and reagents for the
life science and genomics industries and
radiation detection instrumentation for
environmental monitoring and clean up.
William J. Pape II (16) 69 Publisher, Waterbury Republican-American,
Waterbury, Connecticut (newspaper) and
President of American-Republican, Inc.
Robert J. Patricelli (17) 61 Chairman, President and Chief Executive
Officer of Women's Health USA, Inc. (provides
women's health care services), and of
Evolution Health, LLC (provides employee
benefit services), both of Avon, Connecticut.
He is also Chairman of AviaHealth, Inc.
(provides internet applications to doctors
and patients), of Farmington, Connecticut.
From 1987 to 1997, he was Chairman, President
and Chief Executive Officer of Value Health,
Inc., Avon Connecticut. Previously Executive
Vice President of CIGNA Corporation and
President of CIGNA's Affiliated Businesses
Group. He has held various positions in the
federal government, including White House
Fellow in 1965; counsel to a United States
Senate Subcommittee; Deputy Undersecretary of
the Department of Health, Education and
Welfare; and Administrator of the United
States Urban Mass Transportation
Administration.
Melinda M. Phelps 57 Partner, Buckley, Richardson & Gelinas, LLP
since January 1, 2001 and Police
Commissioner, City of Springfield,
Massachusetts since 1998. Previously Of
Counsel to Buckley, Richardson & Gelinas,
LLP, from May 2000 through December 2000;
and Partner, Keyes and Donnellan, P.C.,
from 1992 to 2000.
Rodney O. Powell 48 Vice President-Central Region of CL&P since
October 1998; previously General Manager-
Simsbury of CL&P from October 1997 to October
1998; Manager-Regulatory Relations of NUSCO
from December 1995 to October 1997 and Senior
Customer Engineering and Marketing Services
Consultant of NUSCO from January 1994 to
December 1995.
Gary D. Simon (18) 52 Senior Vice President-Strategy and
Development of NUSCO since April 1998.
John F. Swope (19) 62 Previously President and Chief Executive
Officer, Public Broadcasting Service,
Alexandria, Virginia from 1999 to March 1,
2000. Retired in 1997 as of counsel to the
law firm of Sheehan Phinney Bass & Green,
Professional Association, Manchester, New
Hampshire. Previously President of Chubb
Life Insurance Company of America, Concord,
New Hampshire (retired December 1994).
Lisa J. Thibdaue 47 Vice President-Rates, Regulatory Affairs and
Compliance of NUSCO since January 1998;
previously Vice President-Rates, Regulatory
Affairs and Compliance of CL&P, PSNH and
WMECO from January 1998 to June 1999;
Executive Director, Rates and Regulatory
Affairs, Consumers Power Company from 1996
to 1998 and Director of Regulatory Affairs,
Consumers Power Company from 1991 to 1996.
John F. Turner (20) 58 President and Chief Executive Officer of The
Conservation Fund, Arlington, Virginia (a
national nonprofit organization dedicated to
land and water conservation and economic
development). From 1989 to 1993, he was
Director of the United States Fish &
Wildlife Service in the United States
Department of the Interior. He has also
served as President of the Wyoming State
Senate. A former Chairman of the Board of
Directors of the Bank of Jackson Hole,
Mr. Turner continues as a partner in the
family ranch business in Wyoming.
(1) Ms. Cleveland is a Director of The National Grange Mutual Insurance
Company and of the Ledyard National Bank and serves on the Board of the
New Hampshire Center for Public Policy. She is the moderator of the
Town of New London, New Hampshire. She has served on the University
System of New Hampshire Board of Trustees as Chair, Vice Chair and a
member and served on the Bank of Ireland First Holdings Board of
Directors from 1986 to 1996. She was formerly Co-Chair of the Governor's
Commission on New Hampshire in the 21st Century and an Incorporator for
the New Hampshire Charitable Foundation.
(2) Mr. Cloud is a Director of The Advest Group, Incorporated and Tenet
Healthcare Corporation and Chairman of the Board of Ironbridge Mezzanine
Fund, L.P.
(3) Mr. Collins is a Director of Blue Cross and Blue Shield of Vermont,
Hamden Assurance Company Limited and the Business and Industry
Association of New Hampshire.
(4) Mr. Conway is a member of the American Nuclear Society. He served on
the Board of Directors of the Nuclear Utilities Management and Resources
Council and its Issues Management Committee. He has also served on the
Research Advisory Committee of the Electric Power Research Institute and
served as Chairman of its Nuclear Power Division Advisory Committee. A
former Chairman of the ABB Combustion Engineering Owners Group Executive
Committee, Mr. Conway currently serves on its Advanced Light Water
Reactor Executive Advisory Committee. Having been a member of the
Institute of Nuclear Power Operations (INPO) Board of Directors, he
currently serves on INPO's Advisory Council and is a member of the
Accrediting Board of its National Academy for Nuclear Training. Mr.
Conway is a Director of First Energy Corporation and is Chairman of its
Nuclear Committee. He also serves on the Nuclear Safety Review Board at
several nuclear facilities.
(5) Dr. de Planque is a Fellow and past President of the American Nuclear
Society, a member of the National Academy of Engineering and the
National Council on Radiation Protection and Measurements, a Director of
British Nuclear Fuels, plc., a Director of British Nuclear Fuels, Inc.
and President of the International Nuclear Societies Council. She is a
member of the Texas Utilities Electric Operations Review Committee; the
Diablo Canyon Independent Safety Committee; the External Advisory
Committee; Amarillo National Resource Center for Plutonium; the visiting
Committee for the Department of Nuclear Engineering, Massachusetts
Institute of Technology; and a consultant to the United Nation's
International Atomic Energy Agency.
(6) Mr. Feigenbaum is a Director of CYAPC, MYAPC, and VYAPC, and YAEC.
(7) Mr. Forsgren is a Director of NEON and The Circle Trust Company and a
member of the Board of Regents of Georgetown University.
(8) Mr. Golden serves as a Trustee on the National Wildlife Federation
Endowment and the Board of the Jewish Federation of Palm Beach County,
Florida.
(9) Dr. Kennan is a Director of The Putnam Funds and Talbots. She is a
member of the Folger Shakespeare Library Committee and is Chairman of
Cambus Kenneth Bloodstock, Inc.
(10) Mr. Kenyon is a Trustee of Columbia College and Director of CYAPC.
(11) Mr. Letendre is a Director of the National Association of Manufacturers
(Washington, DC).
(12) Mr. McDonald is a Director of CIGNA Investments Inc. and Polytainer's,
LLC (Toronto, Canada).
(13) Mr. Morris is a Director of the Institute of Nuclear Power Operations,
the Nuclear Energy Institute, the Edison Electric Institute, the
Association of Edison Illuminating Companies, Nuclear Electric Insurance
Limited, Connecticut Business & Industry Association, and the Webster
Financial Corporation. Mr. Morris is also a Regent of Eastern Michigan
University.
(14) Ms. Newman is a Director of Citizens Advisors.
(15) Mr. Olcott is Vice Chairman and Trustee of the Loomis Chaffee School and
serves on the Dean's Advisory Council for the Sloan School of Management
at the Massachusetts Institute of Technology.
(16) Mr. Pape is a Director of Platt Bros. & Co. and Paper Delivery, Inc. He
is a Trustee of the Connecticut Policy and Economic Council, Inc. and
the Waterbury Y.M.C.A.
(17) Mr. Patricelli is a Director of Curagen Corporation, the Connecticut
Business & Industry Association, and The Bushnell, and a Trustee of
Wesleyan University.
(18) Mr. Simon is a Director of NEON.
(19) Mr. Swope is a Director of the Public Broadcasting Service and PBS
Enterprises and the New Hampshire Business Committee for the Arts. He
is President of The Currier Gallery of Art and a Trustee of Tabor
Academy.
(20) Mr. Turner is assisting schools of natural resources at the University
of Wyoming, University of Michigan and Yale University with wildlife and
land use projects. He is a member of the National Coal Council and a
Director of Land Trust Alliance and National Wildlife Refuge
Association.
There are no family relationships between any director or executive
officer and any other director or executive officer of NU, CL&P, PSNH, WMECO,
or NAEC.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires Trustees
and certain officers of NU and persons who beneficially own more than 10
percent of the outstanding common shares of NU to file reports of ownership
and changes in ownership with the SEC and the New York Stock Exchange. Based
on review of copies of such forms furnished to NU, or written representations
that no Form 5 was required, NU believes that for the year ended December 31,
2000, all such reporting requirements were complied with in a timely manner
except that Mr. Cloud failed to include on his Form 3 shares of NU acquired
in the Yankee merger, and Mr. Pape failed to report until 2001, 800 shares of
CL&P preferred stock acquired in 1994 by a privately-held corporation of
which he is a 7.9 percent owner.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following tables present the cash and non-cash compensation received by the Chief Executive
Officer and the next four highest paid executive officers of NU, CL&P, PSNH, WMECO, and NAEC, in
accordance with rules of the SEC:
Annual Compensation Long Term Compensation
-------------------------------------------- ----------------------
Awards Payouts
Securities
Other Restrict- Underlying Long Term All
Annual ed Stock Options/ Incentive Other
Compensa- Award(s) Stock Program Compen-
Name and Salary tion ($) ($) Appreciation Payouts sation ($)
Principal Position Year ($) Bonus ($) (Note 1) (Note 2) Rights (#) ($) (Note 3)
- ------------------ ---- ------ --------- --------- -------- ------------ --------- ----------
Michael G. Morris 2000 830,770 1,200,000 - - 140,000 - 27,326
Chairman of the
Board, President 1999 783,173 1,253,300 92,243 348,611 118,352 - 23,210
and Chief Executive
Officer 1998 757,692 891,000 134,376 255,261 64,574 - 22,731
Bruce D. Kenyon 2000 504,616 475,000 - - 20,000 - 16,274
President -
Generation Group 1999 500,000 - - 77,690 20,804 462,500 15,000
1998 500,000 300,000 - - 21,236 - 14,800
John H. Forsgren 2000 444,615 450,000 - - 36,000 - 5,100
Executive Vice
President and 1999 429,904 400,000 - 122,682 32,852 87,003 12,888
Chief Financial
Officer 1998 373,077 - - - 73,183 - 104,800
Hugh C. MacKenzie 2000 270,000 250,000 - - 15,000 - 5,100
President - Retail
Business Group 1999 270,000 250,000 - 73,612 19,712 - 108,100
1998 270,000 - - - 15,496 42,972 7,500
Cheryl W. Grise 2000 279,616 290,000 - - 23,000 - 8,795
Senior Vice
President, 1999 244,712 250,000 - 73,612 19,712 - 82,247
Secretary and
General Counsel 1998 209,231 - - - 12,916 20,720 6,123
(in NU, CL&P, PSNH and
WMECO tables only)
Ted C. Feigenbaum 2000 261,539 145,000 - - 12,000 216,200 8,198
Executive Vice
President and 1999 260,000 130,000 - 28,620 7,664 24,827 5,849
Chief Nuclear Officer
of NAEC 1998 260,000 48,750 - 40,961 10,044 20,723 7,800
(in NAEC table only)
OPTION/SAR GRANTS IN LAST FISCAL YEAR
Individual Grants Grant Date Value
Number of % of Total
Securities Options/SARs
Underlying Granted to Exercise or Grant Date
Options/SARs Employees Base Price Expiration Present
Name Granted (#) in Fiscal Year ($/sh) Date Value ($)
(Note 4)
- ---- ------------ -------------- ----------- ---------- -----------
Michael G. Morris 140,000 22.1 18.4375 2/20/2010 1,027,600
Bruce D. Kenyon 20,000 3.2 18.4375 2/20/2010 146,800
John H. Forsgren 36,000 5.7 18.4375 2/20/2010 264,240
Hugh C. MacKenzie 15,000 2.4 18.4375 2/20/2010 110,100
Cheryl W. Grise 23,000 3.6 18.4375 2/20/2010 168,820
Ted C. Feigenbaum 12,000 1.9 18.4375 2/20/2010 88,080
AGGREGATED OPTIONS/SAR EXERCISES IN LAST
FISCAL YEAR AND FY-END OPTION/SAR VALUES
Shares With
Respect to Number of Securities Value of Unexercised
Which Underlying Unexercised In-the-Money
SARs Were Value Options/SARs Options/SARs
Exercised Realized at Fiscal Year End (#) at Fiscal Year End ($)
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
Michael G. Morris - - 495,692 327,234 6,543,905 3,221,429
Bruce D. Kenyon - - 66,424 33,869 658,708 245,405
John H. Forsgren - - 134,605 57,901 1,244,361 413,203
Hugh C. MacKenzie 39,020 380,445 61,087 28,141 (Note 5) 618,289 209,563
Cheryl W. Grise - - 43,977 36,141 436,164 256,063
Ted C. Feigenbaum - - 12,599 36,733 103,518 231,392
Notes to Summary Compensation and Option/SAR Grants Tables:
1. Other annual compensation for Mr. Morris consists of 1998 and 1999
relocation expense reimbursements.
2. At December 31, 2000, the aggregate restricted stock holdings by the five
individuals named in the table for NU, CL&P, WMECO, and PSNH were 31,070
shares with a value of $753,448 and for NAEC were 29,062 shares with a
value of $704,754. Awards shown for 1998 have vested. Awards shown for
1999 vest one-third on February 23, 2000, one-third on February 23, 2001,
and one-third on February 23, 2002. No restricted stock was awarded in
2000. Dividends paid on restricted stock are either paid out or reinvested
into additional shares.
3. "All Other Compensation" for 2000 consists of employer matching
contributions under the Northeast Utilities Service Company 401(k) Plan,
generally available to all eligible employees ($5,100 for each named
officer), and matching contributions under the Deferred Compensation Plan
for Executives (Mr. Morris - $22,226, Mr. Kenyon - $11,174, Mrs. Grise -
$3,695, and Mr. Feigenbaum - $3,098).
4. These options were granted on February 22, 2000, under the Northeast
Utilities Incentive Plan. All options granted vest one-third on
February 22, 2001, one-third on February 22, 2002, and one-third on
February 22, 2003. Valued using the Black-Scholes option pricing model,
with the following assumptions: Volatility: 26.06 percent (36 months of
monthly data); Risk-free rate: 6.55 percent; Dividend yield: 1.82 percent;
Exercise date: February 22, 2010.
5. Mr. MacKenzie's unvested stock options vested and became exercisable upon
his retirement on January 1, 2001.
COMPENSATION COMMITTEE
REPORT ON EXECUTIVE COMPENSATION
Overview and Strategy
The Compensation Committee of the Board of Trustees (the Committee) is
the administrator of executive compensation for the executives of the NU
system (the Company) with authority to establish and interpret the terms of
the Company's executive salary and incentive programs. The goal of the
Committee's executive compensation program for 2000 was to provide a
competitive compensation package to enable the Company to attract and retain
key executives with an eye towards the future in a more competitive
environment. To help achieve this, the Committee drew upon information from
a variety of sources, including compensation consultants, utility and general
industry surveys, and other publicly available information, including proxy
statements. The Committee further sought to align executive interests with
those of NU's shareholders and with Company performance by continuing with the
use of share-based incentives as a significant part of executives'
compensation.
Base Salary
The Committee sets the annual base salary for each executive officer
except for the Chief Executive Officer (CEO), whose base salary is set by the
Board of Trustees following a recommendation by the Committee pursuant to an
evaluation process developed by the Committee in conjunction with the
Corporate Governance Committee of the Board of Trustees. The Committee
periodically adjusts officers' base salaries to reflect considerations such
as changes in responsibility, market sensitivity, individual performance and
internal equity. In 2000 the Committee reviewed the average salary growth of
officers, as reported by several national surveys, with the goal of maintaining
the current competitive salary positions. The CEO's base salary was increased
by 12.5 percent in 2000 based on the market review and the Committee's judgment
as to his past and expected future performance.
Annual Incentive Awards
The Committee again implemented an Annual Incentive Program during 2000.
The incentive payout target was 80 percent of base salary for the CEO, and
varied from 25 to 50 percent of base salary for the other officers. The
Annual Incentive Program was designed to calculate actual aggregate payouts
based on the Company's performance against a net income goal and pre-
established individual goals. Individual awards were made in cash in January
2001. The CEO received an award under this program of $1,200,000, or 180
percent of target, determined on the fulfillment of the net income goal and
the successful achievement during 2000 of critical strategic, restructuring,
operational, and merger related goals.
Long-Term Incentive Grants
Long-term stock-based incentive grants were made in February 2000 to
each executive officer and other officers and certain key employees of the
Company. The Committee targeted these awards, which were made entirely in
the form of stock options, such that long-term incentive awards for the officer
group would be at the 50th percentile of general industry. The CEO's grant
was targeted at 158 percent of base salary based upon the Committee's dual
goals of market competitiveness and alignment with shareholder interests.
Internal Revenue Service Limitation on Deductibility of Executive
Compensation
The Committee believes that its compensation program adequately responds
to issues raised by the deductibility cap placed on executive salaries by
Section 162(m) of the Internal Revenue Code because of the use of stock options
and qualified performance-based compensation in Company incentive programs.
Respectfully submitted,
/s/ Robert E. Patricelli, Chairman
/s/ William J. Pape II, Vice Chairman
/s/ Cotton Mather Cleveland
/s/ E. Gail de Planque
/s/ Elizabeth T. Kennan
/s/ John F. Swope
Dated: February 27, 2001
PENSION BENEFITS
The following table shows the estimated annual retirement benefits payable
to an executive officer of NU upon retirement, assuming that retirement occurs
at age 65 and that the officer is at that time not only eligible for a pension
benefit under the Northeast Utilities Service Company Retirement Plan (the
Retirement Plan) but also eligible for the make-whole benefit and the target
benefit under the Supplemental Executive Retirement Plan for Officers of NU
system companies (the Supplemental Plan). The Supplemental Plan is a non-
qualified pension plan providing supplemental retirement income to system
officers. The make-whole benefit under the Supplemental Plan, available to
all officers, makes up for benefits lost through application of certain tax
code limitations on the benefits that may be provided under the Retirement
Plan, and includes as "compensation" awards under the executive incentive plans
and deferred compensation (as earned). The target benefit further supplements
these benefits and is available to officers at the Senior Vice President level
and higher who are selected by the Board of Trustees to participate in the
target benefit and who remain in the employ of NU companies until at least age
60 (unless the Board of Trustees sets an earlier age).
The benefits presented below are based on a straight life annuity
beginning at age 65 and do not take into account any reduction for joint and
survivorship annuity payments. Final average compensation for purposes of
calculating the target benefit is the highest average annual compensation of
the participant during any 36 consecutive months compensation was earned.
Compensation taken into account under the target benefit described above
includes salary, bonus, restricted stock awards, and long-term incentive
payouts shown in the Summary Compensation Table, but does not include
employer matching contributions under the 401k Plan. In the event that an
officer's employment terminates because of disability, the retirement
benefits shown above would be offset by the amount of any disability benefits
payable to the recipient that are attributable to contributions made by NU
and its subsidiaries under long term disability plans and policies.
ANNUAL BENEFIT
Final Average Years of Credited Service
Compensation
15 20 25 30 35
$ 200,000 $ 72,000 $ 96,000 $120,000 $120,000 $120,000
250,000 90,000 120,000 150,000 150,000 150,000
300,000 108,000 144,000 180,000 180,000 180,000
350,000 126,000 168,000 210,000 210,000 210,000
400,000 144,000 192,000 240,000 240,000 240,000
450,000 162,000 216,000 270,000 270,000 270,000
500,000 180,000 240,000 300,000 300,000 300,000
600,000 216,000 288,000 360,000 360,000 360,000
700,000 252,000 336,000 420,000 420,000 420,000
800,000 288,000 384,000 480,000 480,000 480,000
900,000 324,000 432,000 540,000 540,000 540,000
1,000,000 360,000 480,000 600,000 600,000 600,000
1,100,000 396,000 528,000 660,000 660,000 660,000
1,200,000 432,000 576,000 720,000 720,000 720,000
Each of the executive officers of NU named in the Summary Compensation
Table is currently eligible for a target benefit, except Messrs. Morris and
Kenyon, whose Employment Agreements provide specially calculated retirement
benefits, based on their previous arrangements with CMS Energy/Consumers
Energy Company (CMS Energy) and South Carolina Electric and Gas, respectively.
Mr. Morris's agreement provides that upon retirement after reaching the fifth
anniversary of his employment date (or upon disability or termination without
cause or following a change in control, as defined) he will be entitled to
receive a special retirement benefit calculated by applying the benefit formula
of the CMS Energy Supplemental Executive Retirement Plan to all compensation
earned from the NU system and to all service rendered to the Company and CMS
Energy. If Mr. Kenyon retires with at least three years of service with the
Company, he will be deemed to have 2 extra years of service for purpose of
his special retirement benefit. If after achieving three years of service he
voluntarily terminates employment following a "substantial change in
responsibilities resulting from a material change in the business of Northeast
Utilities", he will be deemed to have an additional year of service for purpose
of his special retirement benefit, and if he retires with at least 3 years of
service with the Company, he will receive a lump sum payment of $500,000.
In addition, Mr. Forsgren's Employment Agreement provides for supplemental
pension benefits based on crediting up to 10 years additional service and
providing payments equal to 25 percent of salary for up to 15 years following
retirement, reduced by four percentage points for each year that his age is
less than 65 years at retirement.
As of December 31, 2000, the executive officers named in the Summary
Compensation Table had the following years of credited service for purposes
of calculating target benefits under the Supplemental Plan (or in the case of
Messrs. Morris and Kenyon, for purposes of calculating the special retirement
benefits under their respective Employment Agreements): Mr. Morris - 22, Mr.
Kenyon - 6, Mr. Forsgren - 4, Mr. MacKenzie - 35, Mrs. Grise - 20, and Mr.
Feigenbaum - 15. In addition, Mr. Forsgren had 9 years of service for purposes
of his supplemental pension benefit and would have 25 years of service for such
purpose if he were to retire at age 65. Assuming that retirement were to occur
at age 65 for these officers, retirement would occur with 33, 13, 15, 47, 36
and 29 years of credited service, respectively.
COMPENSATION OF DIRECTORS
During 2000, each Trustee who was not an employee of NU or its
subsidiaries was compensated at an annual rate of $20,000 cash plus 500 common
shares of NU, and received $1,000 for each meeting attended of the Board or its
Committees. A non-employee Trustee who participates in a meeting of the Board
or any of its Committees by conference telephone receives $675 per meeting.
Also, a non-employee Trustee who is asked by either the Board of Trustees or
the Chairman of the Board to perform extra services in the interest of the NU
system may receive additional compensation of $1,000 per day plus necessary
expenses. The Chairs of the Audit, the Compensation, the Corporate Affairs,
the Corporate Governance and the Nuclear Committees were compensated at an
additional annual rate of $3,500. In addition to the above compensation,
Dr. Kennan is paid at the annual rate of $30,000 for the extra services
performed as Lead Trustee. The Chair of the Nuclear Committee receives an
additional retainer at the rate of $25,000 per year.
Under the terms of the Incentive Plan adopted by shareholders at the 1998
Annual Meeting, each non-employee Trustee is eligible for stock-based grants.
During 2000 each such Trustee was granted nonqualified options to purchase
2,500 common shares of NU. Receipt of shares acquired on exercise of these
options may be deferred pursuant to the terms of the Northeast Utilities
Deferred Compensation Plan for Executives.
In February 2000, each non-employee Trustee was granted nonqualified
options to purchase 2,500 common shares.
Prior to the beginning of each calendar year, each non-employee Trustee
may irrevocably elect to have all or any portion of the annual retainer fee
paid in the form of common shares of NU. Pursuant to the Northeast Utilities
Deferred Compensation Plan for Trustees, each Trustee may also irrevocably
elect to defer receipt of some or all cash and/or share compensation.
During 2000 each non-employee Director of PSNH and WMECO was compensated
at an annual rate of $10,000 cash, and received $500 for each meeting attended
of the Board of Directors or, in the case of PSNH, its committees. A non-
employee Director who participates in a meeting of the Board of Directors or
any of its committees by conference telephone receives $300 per meeting.
Also, committee chairs were compensated at an additional annual rate of $1,500.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS
NUSCO has entered into employment agreements (the Officer Agreements)
with each of the named executive officers. The Officer Agreements are also
binding on NU and on each majority-owned subsidiary of NU.
Each Officer Agreement obligates the officer to perform such duties as
may be directed by the NUSCO Board of Directors or the NU Board of Trustees,
protect the Company's confidential information, and refrain, while employed
by the Company and for a period of time thereafter, from competing with the
Company in a specified geographic area. Each Officer Agreement provides that
the officer's base salary will not be reduced below certain levels without
the consent of the officer, and that the officer will participate in
specified benefits under the Supplemental Executive Retirement Plan or other
supplemental retirement programs (see Pension Benefits, above) and/or in
certain executive incentive programs at specified incentive opportunity
levels.
Each Officer Agreement provides for a specified employment term and for
automatic one-year extensions of the employment term unless at least six
months' notice of non-renewal is given by either party. The employment term
may also be ended by the Company for "cause", as defined, at any time (in
which case no supplemental retirement benefit, if any, shall be due), or by
the officer on thirty days' prior written notice for any reason. Absent
"cause", the Company may remove the officer from his or her position on 60
days' prior written notice, but in the event the officer is so removed and
signs a release of all claims against the Company, the officer will receive
one or two years' base salary and annual incentive payments, specified
employee welfare and pension benefits, and vesting of stock appreciation
rights, options and restricted stock.
Under the terms of an Officer Agreement, upon any termination of
employment following a change of control, as defined, between (a) the earlier
of the date shareholders approve a change of control transaction or a change
of control transaction occurs and (b) the earlier of the date, if any, on
which the Board of Trustees abandons the transaction or the date 2 years
following the change of control, if the officer signs a release of all claims
against the Company, the officer will be entitled to certain payments
including a multiple (not to exceed four) of annual base salary, annual
incentive payments, specified employee welfare and pension benefits, and
vesting of stock appreciation rights, options and restricted stock. Certain
of the change in control provisions may be modified by the Board of Trustees
prior to a change in control, on at least two years' notice to the affected
officer(s).
Besides the terms described above, the Officer Agreements of Messrs.
Morris, Kenyon and Forsgren provide for a specified salary, cash, restricted
stock and/or stock options upon employment, special incentive programs and/or
special retirement benefits. See Pension Benefits, above, for further
description of these provisions.
The descriptions of the various agreements set forth above are for
purpose of disclosure in accordance with the proxy and other disclosure rules
of the SEC and shall not be controlling on any party; the actual terms of the
agreements themselves determine the rights and obligations of the parties.
SHARE PERFORMANCE CHART
The following chart compares the cumulative total return on an investment
in NU common shares with the cumulative total return of the S&P 500 Stock
Index and the S&P Electric Companies Index over the last five fiscal years,
in accordance with the rules of the SEC:
(Assumes $100 invested on January 1, 1996, in NU common shares, S&P 500 Index
and S&P Electric Companies Index with all dividends reinvested.)
Year Ended December 31, 2000
NU Common* S&P Electric Companies S&P 500
---------- ---------------------- -------
1996 59.00 100.00 123.00
1997 55.00 126.00 164.00
1998 75.00 146.00 211.00
1999 97.00 117.00 255.00
2000 116.00 203.00 232.00
*Total return of NU common shares assumes reinvestment of all dividends
on payment date.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
NU.
The following table provides, as of December 31, 2000, information with
respect to persons who are known to NU to beneficially own more than five
percent of the common shares of NU. NU has no other class of voting
securities.
Name and Address Amount and Nature of Percent of
of Beneficial Owner Beneficial Ownership Class
- ------------------- -------------------- ----------
Barrow, Hanley, Mewhinney 11,274,868 (1) 7.58%
& Strauss, Inc.
One McKinney Plaza
3232 McKinney Avenue, 15th Floor
Dallas, TX
Capital Research and 7,525,000 (2) 5.06%
Management Company
333 South Hope Street
Los Angeles, California 90071
- -----------------------
(1) According to a Statement on Schedule 13G dated February 12, 2001, Barrow,
Hanley, Mewhinney & Strauss, Inc. holds 11,274,868 common shares of NU.
According to the Schedule 13G, Barrow, Hanley, Mewhinney & Strauss, Inc.
has sole voting power for 7,238,468 shares, shared voting power for
4,036,400 shares and sole dispositive power for 11,274,868 shares.
(2) According to an Amendment to Schedule 13G dated February 9, 2001, Capital
Research and Management Company holds 10,938,200 common shares of NU.
According to the Amendment, Capital Research and Management Company has
sole voting power for zero shares, shared voting power for zero shares,
sole dispositive power for 10,938,200 shares and shared dispositive power
for zero shares. The Schedule 13G states that beneficial ownership is
disclaimed pursuant to Rule 13d-4.
The following table provides information as of February 28, 2001, as to
the beneficial ownership of the common shares of NU by each Trustee and nominee
for Trustee, each of the 5 highest paid executive officers of NU and its
subsidiaries, and all Trustees, nominees for Trustee and executive officers as
a group. Unless otherwise noted, each Trustee, nominee and executive officer
has sole voting and investment power with respect to the listed shares.
Amount and Nature of Percent
Name Beneficial Ownership of Class (1)
---- -------------------- ------------
Cotton M. Cleveland 15,169 (2)
Sanford Cloud, Jr. 10,913 (3)
William F. Conway 14,280 (2)(4)
E. Gail de Planque 12,256 (2)
John H. Forsgren 115,014 (5)
Raymond L. Golden 13,210 (6)
Cheryl W. Grise 51,396 (7)
Elizabeth T. Kennan 13,600 (2)
Bruce D. Kenyon 109,458 (8)
Hugh C. MacKenzie 18,360 (9)
Michael G. Morris 621,767 (10)
Emery G. Olcott 17,751 (3)
William J. Pape II 9,203 (2)(11)
Robert E. Patricelli 17,877 (2)
John F. Swope 15,814 (2)
John F. Turner 9,705 (2)(12)
All Trustees and Executive Officers
as a Group (18 persons) 1,147,925 (13)
- ----------------------
(1) As of February 28, 2001, the Trustees and executive officers of NU, as a
group, beneficially owned less than one percent of the NU common shares
outstanding.
(2) Includes 8,750 shares that could be acquired by the beneficial owner
pursuant to currently exercisable options.
(3) Includes 3,750 shares that could be acquired by the beneficial owner
pursuant to currently exercisable options.
(4) Includes 5,530 shares held jointly by Mr. Conway and his wife, who share
voting and investment power.
(5) Includes 2,738 restricted shares, as to which Mr. Forsgren has sole
voting power but no dispositive power. Includes 107,087 shares that
could be acquired by Mr. Forsgren pursuant to currently exercisable
options.
(6) Includes 6,250 shares that could be acquired by Mr. Golden pursuant to
currently exercisable options.
(7) Includes 1,643 restricted shares, as to which Mrs. Grise has sole voting
power, but no dispositive power. Includes 33,724 shares that could be
acquired by Mrs. Grise pursuant to currently exercisable options.
Includes 265 shares held by Mrs. Grise's husband as custodian for her
children, with whom she shares voting and dispositive power.
(8) Includes 1,734 restricted shares, as to which Mr. Kenyon has sole voting
power but no dispositive power. Includes 41,772 shares that could be
acquired by Mr. Kenyon pursuant to currently exercisable options.
(9) Mr. MacKenzie retired effective January 1, 2001. Beneficial ownership
is given as of December 31, 2000, and includes 3,285 restricted shares,
as to which Mr. MacKenzie had sole voting power but no dispositive
power, and 22,067 shares that could be acquired by Mr. MacKenzie
pursuant to then exercisable options. Mr. MacKenzie's restricted stock
and 28,141 unvested options vested upon his retirement.
(10) Includes 7,779 restricted shares, as to which Mr. Morris has sole voting
power but no dispositive power. Includes 573,476 shares that could be
acquired by Mr. Morris pursuant to currently exercisable options.
Includes 13,499 shares held jointly by Mr. Morris and his wife, who
share voting and investment power.
(11) Includes 5,176 shares as to which Mr. Pape shares voting and dispositive
power. Includes 1,250 shares that could be acquired by Mr. Pape pursuant
to currently exercisable options. In addition, Mr. Pape shares beneficial
ownership of 800 shares of CL&P 4.50% Preferred Series 1956.
(12) Includes 955 shares held jointly by Mr. Turner and his wife, who share
voting and investment power.
(13) Includes 2,053 restricted shares held by executive officers other than
those named in the table above as to which they have sole voting power
but no dispositive power. Includes 70,623 shares that could be acquired
by them pursuant to currently exercisable options.
CL&P, PSNH, WMECO, and NAEC.
NU owns 100% of the outstanding common stock of registrants CL&P, PSNH,
WMECO, and NAEC. As of February 28, 2001, the Directors and Executive Officers
of CL&P, PSNH, WMECO, and NAEC beneficially owned the number of shares of each
class of equity securities of NU listed below. No equity securities of CL&P,
PSNH, WMECO, or NAEC are owned by the Directors and Executive Officers of CL&P,
PSNH, WMECO, and NAEC. Unless otherwise noted, each Director and Executive
Officer of CL&P, PSNH, WMECO, and NAEC has sole voting and investment power
with respect to the listed shares.
Title of Amount and Nature of Percent of
Class Name Beneficial Ownership Class (1)
NU Common David H. Boguslawski 23,246 (2)
NU Common James E. Byrne None
NU Common John C. Collins None
NU Common William A. DiProfio 5,326 (3)
NU Common Ted C. Feigenbaum 38,459 (4)
NU Common John H. Forsgren 115,014 (5)
NU Common George R. Gram II 6,634 (6)
NU Common Cheryl W. Grise 51,396 (7)
NU Common Bruce D. Kenyon 109,458 (8)
NU Common Kerry J. Kuhlman 14,509 (9)
NU Common Gerald Letendre None
NU Common Gary A. Long 13,078 (10)
NU Common Hugh C. MacKenzie 18,360 (11)
NU Common Paul J. McDonald 500
NU Common Michael G. Morris 621,767 (12)
NU Common Jane E. Newman None
NU Common Melinda M. Phelps None
NU Common Rodney O. Powell 8,288 (13)
Amount beneficially owned by Directors and Executive Officers as a group:
Amount and Nature of
Company Number of Persons Beneficial Ownership
CL&P 8 969,352 (14)
PSNH 11 974,142 (14)
WMECO 22 976,073 (14)
NAEC 7 948,054
(1) As of February 28, 2001, there were 148,780,800 common shares of NU
outstanding. The percentage of such shares beneficially owned by any
Director or Executive Officer, and by all Directors and Executive
Officers of CL&P, PSNH, WMECO, and NAEC as a group, does not exceed one
percent.
(2) Includes 730 restricted shares, as to which Mr. Boguslawski has sole
voting power but no dispositive power. Includes 15,512 shares that
could be acquired by Mr. Boguslawski pursuant to currently exercisable
options.
(3) Mr. DiProfio retired effective February 1, 2001. Beneficial ownership
is given as of January 31, 2001, and includes 879 shares that could be
acquired by Mr. DiProfio pursuant to then exercisable options. 1,295
unvested options vested upon Mr. DiProfio's retirement.
(4) Includes 639 restricted shares, as to which Mr. Feigenbaum has sole
voting power but no dispositive power. Includes 19,153 shares that
could be acquired by Mr. Feigenbaum pursuant to currently exercisable
options.
(5) Includes 2,738 restricted shares, as to which Mr. Forsgren has sole
voting power but no dispositive power. Includes 107,087 shares that
could be acquired by Mr. Forsgren pursuant to currently exercisable
options.
(6) Includes 5,283 shares that could be acquired by Mr. Gram pursuant to
currently exercisable options.
(7) Includes 1,643 restricted shares, as to which Mrs. Grise has sole voting
power, but no dispositive power. Includes 33,724 shares that could be
acquired by Mrs. Grise pursuant to currently exercisable options.
Includes 265 shares held by Mrs. Grise's husband as custodian for her
children, with whom she shares voting and dispositive power.
(8) Includes 1,734 restricted shares, as to which Mr. Kenyon has sole voting
power but no dispositive power. Includes 41,772 shares that could be
acquired by Mr. Kenyon pursuant to currently exercisable options.
(9) Includes 342 restricted shares, as to which Ms. Kuhlman has sole voting
power but no dispositive power. Includes 8,395 shares that could be
acquired by Ms. Kuhlman pursuant to currently exercisable options.
(10) Includes 319 restricted shares, as to which Mr. Long has sole voting
power but no dispositive power. Includes 7,590 shares that could be
acquired by Mr. Long pursuant to currently exercisable options.
(11) Mr. MacKenzie retired effective January 1, 2001. Beneficial ownership
is given as of December 31, 2000, and includes 3,285 restricted shares,
as to which Mr. MacKenzie had sole voting power but no dispositive power,
and 22,067 shares that could be acquired by Mr. MacKenzie pursuant to then
exercisable options. Mr. MacKenzie's restricted stock and 28,141 unvested
options vested upon his retirement.
(12) Includes 7,779 restricted shares, as to which Mr. Morris has sole voting
power but no dispositive power. Includes 573,476 shares that could be
acquired by Mr. Morris pursuant to currently exercisable options.
Includes 13,499 shares held jointly by Mr. Morris and his wife, who
share voting and investment power.
(13) Includes 249 restricted shares, as to which Mr. Powell has sole voting
power but no dispositive power. Includes 6,750 shares that could be
acquired by Mr. Powell pursuant to currently exercisable options.
(14) Includes 684 restricted shares held by an executive officer other than
those named in the table above as to which such officer has sole voting
power but no dispositive power. Includes 16,174 shares that could be
acquired by such officer pursuant to currently exercisable options.
CHANGES IN CONTROL
See Item 1 - Business - Mergers and Acquisitions - Consolidated Edison, Inc.
Merger on pages 3-4.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The law firm of Sulloway and Hollis provided legal services to NU, PSNH
and NAEC during 2000. John B. Garvey, who is the husband of Cotton M.
Cleveland, a Trustee of NU, is a member of the firm.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements:
The Report of Independent Public Accountants and financial statements
of CL&P, PSNH, WMECO, and NAEC are hereby incorporated by reference
and made a part of this report (see "Item 8. Financial Statements and
Supplementary Data").
Report of Independent Public Accountants
on Schedules S-1
Consent of Independent Public Accountants S-2
2. Schedules:
Financial Statement Schedules for NU (Parent),
NU and Subsidiaries, CL&P and Subsidiaries,
PSNH, and WMECO and Subsidiary are listed in
the Index to Financial Statements Schedules S-3
3. Exhibits Index E-1
(b) Reports on Form 8-K:
NU filed a current report on Form 8-K dated February 29, 2000, disclosing:
o The 1999 financial statements for NU consolidated and notes thereto
and management's discussion and analysis of financial condition and
results of operations relating to the 1999 financial statements.
NU filed a current report on Form 8-K dated March 1, 2000, disclosing:
o The completion of the merger with Yankee.
NU, CL&P and WMECO filed current reports on Form 8-K dated March 14,
2000, disclosing:
o The transfer of approximately 1,289 MW of hydroelectric and pumped
storage generation assets in Connecticut and Massachusetts to NGC.
NU filed a current report on Form 8-K dated March 29, 2000, disclosing:
o The supplement to the joint proxy statement/prospectus for the
special meeting of shareholders related to the Con Edison merger.
NU filed a current report on Form 8-K dated September 27, 2000,
disclosing:
o The Utility Operations Management Analysis Unit of the DPUC recommended
that the DPUC approve the results of the recently completed auction of
the Millstone nuclear units.
NU filed a current report on Form 8-K dated October 24, 2000, disclosing:
o Con Edison issued a press release on October 23, 2000, regarding the
DPUC's decision on October 19, 2000, which approved the proposed merger
between NU and Con Edison, subject to a number of conditions.
NU filed a current report on Form 8-K dated October 24, 2000, disclosing:
o NU's earnings press release for the third quarter of 2000.
NU filed a current report on Form 8-K dated October 31, 2000, disclosing:
o NU's and Con Edison's presentation dated October 31, 2000, entitled
"The Northeast's Energy Company."
NU filed a current report on Form 8-K dated January 23, 2001, disclosing:
o NU's earnings press release for the fourth quarter and full year 2000.
NU filed a current report on Form 8-K dated February 28, 2001, disclosing:
o NU's news release formally seeking Con Edison's assurance of intent
to close merger.
NU filed a current report on Form 8-K dated March 5, 2001, disclosing:
o NU declares Con Edison in breach of merger agreement. NU to sue Con
Edison to recover value of merger for NU shareholders.
NU filed a current report on Form 8-K dated March 12, 2001, disclosing:
o NU filed suit in the U.S. District Court for the Southern District
seeking for itself and its shareholders in excess of $1 billion in
damages arising from Con Edison's breach of the merger agreement.
NU filed a current report on Form 8-K dated March 22, 2001, disclosing:
o NU's news release announcing revised 2000 earnings and confirming
2001 projected earnings.
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
NORTHEAST UTILITIES
-------------------
(Registrant)
Date: March 16, 2001 By /s/ Michael G. Morris
----------------------------
Michael G. Morris
Chairman of the Board,
President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
- ---- ----- ---------
March 16, 2001 Chairman of the Board, /s/ Michael G. Morris
President and --------------------------
Chief Executive Officer Michael G. Morris
and a Trustee
March 16, 2001 Executive Vice /s/ John H. Forsgren
President and Chief --------------------------
Financial Officer John H. Forsgren
and a Trustee
March 16, 2001 Vice President and /s/ John J. Roman
Controller --------------------------
John J. Roman
March 16, 2001 Trustee /s/ Cotton M. Cleveland
--------------------------
Cotton M. Cleveland
March 16, 2001 Trustee /s/ Sanford Cloud, Jr.
--------------------------
Sanford Cloud, Jr.
March 16, 2001 Trustee /s/ William F. Conway
--------------------------
William F. Conway
March 16, 2001 Trustee /s/ E. Gail de Planque
--------------------------
E. Gail de Planque
March 16, 2001 Trustee /s/ Raymond L. Golden
--------------------------
Raymond L. Golden
March 16, 2001 Trustee /s/ Elizabeth T. Kennan
--------------------------
Elizabeth T. Kennan
March 16, 2001 Trustee /s/ Emery G. Olcott
--------------------------
Emery G. Olcott
March 16, 2001 Trustee /s/ William J. Pape II
--------------------------
William J. Pape II
March 16, 2001 Trustee /s/ Robert E. Patricelli
--------------------------
Robert E. Patricelli
March 16, 2001 Trustee /s/ John F. Swope
--------------------------
John F. Swope
March 16, 2001 Trustee /s/ John F. Turner
--------------------------
John F. Turner
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY
---------------------------------------
(Registrant)
Date: March 16, 2001 By /s/ Michael G. Morris
------------------------------------
Michael G. Morris
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
- ---- ----- ---------
March 16, 2001 Treasurer /s/ Randy A. Shoop
-----------------------------
Randy A. Shoop
March 16, 2001 Controller /s/ John P. Stack
-----------------------------
John P. Stack
March 16, 2001 Director /s/ David H. Boguslawski
-----------------------------
David H. Boguslawski
March 16, 2001 Director /s/ Rodney O. Powell
-----------------------------
Rodney O. Powell
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
---------------------------------------
(Registrant)
Date: March 16, 2001 By /s/ Michael G. Morris
------------------------------------
Michael G. Morris
Chairman and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
- ---- ----- ---------
March 16, 2001 Chairman and Chief /s/ Michael G. Morris
Executive Officer -----------------------------
and a Director Michael G. Morris
March 16, 2001 President and Chief /s/ Gary A. Long
Operating Officer and -----------------------------
a Director Gary A. Long
March 16, 2001 Vice President and /s/ David R. McHale
Treasurer -----------------------------
David R. McHale
March 16, 2001 Vice President /s/ John J. Roman
and Controller -----------------------------
John J. Roman
March 16, 2001 Director /s/ David H. Boguslawski
-----------------------------
David H. Boguslawski
March 16, 2001 Director /s/ John C. Collins
-----------------------------
John C. Collins
March 16, 2001 Director /s/ John H. Forsgren
-----------------------------
John H. Forsgren
March 16, 2001 Director /s/ Gerald Letendre
-----------------------------
Gerald Letendre
March 16, 2001 Director /s/ Jane E. Newman
-----------------------------
Jane E. Newman
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
--------------------------------------
(Registrant)
Date: March 16, 2001 By /s/ Michael G. Morris
----------------------------------
Michael G. Morris
Chairman and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
- ---- ----- ---------
March 16, 2001 Chairman and Chief /s/ Michael G. Morris
Executive Officer -----------------------------
and a Director Michael G. Morris
March 16, 2001 President and /s/ Kerry J. Kuhlman
Chief Operating -----------------------------
Officer and a Director Kerry J. Kuhlman
March 16, 2001 Vice President /s/ David R. McHale
and Treasurer -----------------------------
David R. McHale
March 16, 2001 Vice President /s/ John J. Roman
and Controller -----------------------------
John J. Roman
March 16, 2001 Director /s/ David H. Boguslawski
-----------------------------
David H. Boguslawski
March 16, 2001 Director /s/ James E. Byrne
-----------------------------
James E. Byrne
March 16, 2001 Director /s/ John H. Forsgren
-----------------------------
John H. Forsgren
March 16, 2001 Director /s/ Paul J. McDonald
-----------------------------
Paul J. McDonald
March 16, 2001 Director /s/ Melinda M. Phelps
-----------------------------
Melinda M. Phelps
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
NORTH ATLANTIC ENERGY CORPORATION
---------------------------------
(Registrant)
Date: March 16, 2001 By /s/ Bruce D. Kenyon
------------------------------------
Bruce D. Kenyon
President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Date Title Signature
- ---- ----- ---------
March 16, 2001 President and Chief /s/ Bruce D. Kenyon
Executive Officer ------------------------------
and a Director Bruce D. Kenyon
March 16, 2001 Vice President and /s/ David R. McHale
Treasurer of Northeast -----------------------------
Utilities Service David R. McHale
Company as Agent for
North Atlantic Energy
Corporation
March 16, 2001 Vice President and /s/ John J. Roman
and Controller of -----------------------------
Northeast Utilities John J. Roman
Service Company as
Agent for North Atlantic
Energy Corporation
March 16, 2001 Director /s/ Ted C. Feigenbaum
-----------------------------
Ted C. Feigenbaum
March 16, 2001 Director /s/ George R. Gram
----------------------------
George R. Gram
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
-----------------------------------------------------
We have audited in accordance with auditing standards generally accepted in
the United States, the financial statements included in Northeast Utilities'
annual report on Form 10-K and The Connecticut Light and Power Company's,
Western Massachusetts Electric Company's, Public Service Company of New
Hampshire's, and North Atlantic Energy Corporation's annual reports,
incorporated by reference in this Form 10-K, and have issued our reports
thereon dated January 23, 2001 (except with respect to the matters discussed
in Note 15, Note 15, Note 14, Note 14, and Note 11 for Northeast Utilities,
The Connecticut Light and Power Company, Western Massachusetts Electric
Company, Public Service Company of New Hampshire, and North Atlantic Energy
Corporation, respectively, as to which the date is March 13, 2001). Our
audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The schedules listed in the accompanying Index
to Financial Statements Schedules are the responsibility of the companies'
management and are presented for purposes of complying with the Securities
and Exchange Commission's rules and are not a part of the basic financial
statements. These schedules have been subjected to the auditing procedures
applied in the audit of the basic financial statements and, in our opinion,
fairly state in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Hartford, Connecticut
January 23, 2001
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
-----------------------------------------
As independent public accountants, we hereby consent to the incorporation of
our reports dated January 23, 2001 (except with respect to the matters
discussed in Note 15 for Northeast Utilities and The Connecticut Light and
Power Company, Note 14 for Western Massachusetts Electric Company and Public
Service Company of New Hampshire, and Note 11 for North Atlantic Energy
Corporation, as to which the date is March 13, 2001), included (or
incorporated by reference) in this Form 10-K into the Company's previously
filed Registration Statements No. 33-55279 of The Connecticut Light and Power
Company, No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814, No.
33-63023, No. 33-40156, No. 333-52413, No. 333-52415, and No. 333-85613 of
Northeast Utilities. It should be noted that we have not audited any
financial statements of the Company subsequent to December 31, 2000 or
performed any audit procedures subsequent to the date of our report.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Hartford, Connecticut
March 27, 2001
INDEX TO FINANCIAL STATEMENTS SCHEDULES
Schedule
I. Financial Information of Registrant:
Northeast Utilities (Parent) Balance
Sheets 2000 and 1999 S-4
Northeast Utilities (Parent) Statements
of Income 2000, 1999, and 1998 S-5
Northeast Utilities (Parent) Statements
of Cash Flows 2000, 1999, and 1998 S-6
II. Valuation and Qualifying Accounts and Reserves
2000, 1999, and 1998:
Northeast Utilities and Subsidiaries S-7 - S-9
The Connecticut Light and Power Company
and Subsidiaries S-10 - S-12
Public Service Company of New Hampshire S-13 - S-15
Western Massachusetts Electric Company
and Subsidiary S-16 - S-18
All other schedules of the companies' for which provision is made in the
applicable regulations of the SEC are not required under the related
instructions or are not applicable, and therefore have been omitted.
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 2000 AND 1999
(Thousands of Dollars)
2000 1999
---------- ----------
ASSETS
- ------
Other Property and Investments:
Investments in subsidiary companies, at equity............ $2,687,804 $2,252,175
Investments in transmission companies, at equity.......... 15,011 16,460
Other, at cost............................................ 14 54
----------- -----------
2,702,829 2,268,689
----------- -----------
Current Assets:
Cash...................................................... 1,058 -
Notes receivable from affiliated companies................ 94,400 45,300
Notes and accounts receivable............................. 868 625
Receivables from affiliated companies..................... 3,908 8,351
Taxes receivable.......................................... - 418
Prepayments............................................... 3,744 1,192
----------- -----------
103,978 55,886
----------- -----------
Deferred Charges:
Unamortized debt expense.................................. 13 6
Other..................................................... 321 122
Deferred Yankee Energy System, Inc. acquisition expenses.. - 3,427
----------- -----------
334 3,555
----------- -----------
Total Assets......................................... $2,807,141 $2,328,130
=========== ===========
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 148,781,861 shares issued and
143,820,405 shares outstanding in 2000 and
137,393,829 shares issued and
131,870,284 outstanding in 1999......................... $ 693,345 $ 636,405
Capital surplus, paid in.................................. 927,059 776,290
Temporary equity from stock forward....................... 215,000 215,000
Deferred contribution plan - employee stock ownership plan (114,463) (127,725)
Retained earnings......................................... 495,873 581,817
Accumulated other comprehensive income.................... 1,769 1,524
----------- -----------
Total common shareholders' equity....................... 2,218,583 2,083,311
Long-term debt............................................ 117,000 138,000
----------- -----------
Total capitalization.................................... 2,335,583 2,221,311
----------- -----------
Current Liabilities:
Long-term debt - current portion.......................... 21,000 20,000
Notes payable to banks.................................... 436,000 65,000
Accounts payable.......................................... 966 7,258
Accounts payable to affiliated companies.................. 18 1,201
Accrued taxes............................................. 1,135 -
Accrued interest.......................................... 6,961 1,705
Accrued Con Edison/Northeast Utilities merger fees........ 20 6,143
----------- -----------
466,100 101,307
----------- -----------
Accumulated deferred income taxes........................... 5,026 5,302
Other deferred credits...................................... 432 210
----------- -----------
5,458 5,512
----------- -----------
Total Capitalization and Liabilities $2,807,141 $2,328,130
=========== ===========
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998
(Thousands of Dollars Except Share Information)
2000 1999 1998
------------- ------------- -------------
Operating Revenues................ $ - $ - $ -
------------- ------------- -------------
Operating Expenses:
Other........................... 15,335 19,126 7,674
Federal income taxes............ 2,708 (4,849) 1,569
------------- ------------- -------------
Total operating expenses....... 18,043 14,277 9,243
------------- ------------- -------------
Operating Loss.................... (18,043) (14,277) (9,243)
------------- ------------- -------------
Other Income/(Loss):
Equity in earnings/(loss)
of subsidiaries................ 23,553 56,812 (145,874)
Equity in earnings of
transmission companies......... 2,553 2,608 2,903
Other, net...................... 9,134 2,628 21,995
Income taxes.................... 2,036 2,057 -
------------- ------------- -------------
Other income/(loss), net...... 37,276 64,105 (120,976)
------------- ------------- -------------
Income/(loss) before interest
charges...................... 19,233 49,828 (130,219)
------------- ------------- -------------
Interest Charges.................. 47,819 15,612 16,534
------------- ------------- -------------
(Loss)/Earnings for Common Shares. $ (28,586) $ 34,216 $ (146,753)
============= ============= =============
Basic and Fully Diluted (Loss)/
Earnings Per Common Share....... $ (0.20) $ 0.26 $ (1.12)
============= ============= =============
Basic Common Shares
Outstanding (average)............ 141,549,860 131,415,126 130,549,760
============= ============= =============
Fully Diluted Common Shares
Outstanding (average)............ 141,967,216 132,031,573 130,549,760
============= ============= =============
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(Thousands of Dollars)
2000 1999 1998
------------ -------------- --------------
Operating Activities:
Net (loss)/income........................................ $ (28,586) $ 34,216 $ (146,753)
Adjustments to reconcile to net cash
provided by operating activities:
Equity in earnings of subsidiary companies............. (23,553) (56,812) 145,874
Cash dividends received from subsidiary companies...... 183,016 66,000 47,000
Deferred income taxes.................................. (276) 74 777
Other sources of cash.................................. 3,276 16,655 20,926
Changes in working capital:
Receivables.......................................... 4,200 (7,220) (84)
Accounts payable..................................... (7,475) 5,863 523
Other working capital (excludes cash)................ (1,866) 12,191 (15,981)
------------ -------------- --------------
Net cash flows provided by operating activities............ 128,736 70,967 52,282
------------ -------------- --------------
Investing Activities:
NU system Money Pool..................................... (49,100) (10,900) (200)
Investment in subsidiaries............................... (117,631) (99,462) (40,029)
Other investment activities, net......................... 1,489 1,245 2,278
Payment for the purchase of Yankee Energy System, Inc.... (260,347) - -
------------ -------------- --------------
Net cash flows used in investing activities................ (425,589) (109,117) (37,951)
------------ -------------- --------------
Financing Activities:
Issuance of common shares................................ 4,269 5,318 2,659
Net increase in short-term debt.......................... 371,000 65,000 -
Reacquisitions and retirements of long-term debt......... (20,000) (19,000) (17,000)
Cash dividends on common shares.......................... (57,358) (13,168) -
------------ -------------- --------------
Net cash flows provided by/(used in) financing activities.. 297,911 38,150 (14,341)
------------ -------------- --------------
Net increase/(decrease) in cash for the period............. 1,058 - (10)
Cash - beginning of period................................. - - 10
------------ -------------- --------------
Cash - end of period....................................... $ 1,058 $ - $ -
============ ============== ==============
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized..................... $ 39,099 $ 15,724 $ 16,610
============ ============== ==============
Income taxes............................................. $ 1,430 $ 28,982 $ 16,929
============ ============== ==============
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 4,895 $26,740 $ 130 (c) $19,265 (a) $12,500
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $44,995 $22,573 $37,680 (c) $25,967 (b) $79,281
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
(c) Amounts represent activity related to the acquisition of Yankee on March 1, 2000.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1999
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,417 $ 8,026 $ - $ 5,548 (a) $ 4,895
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $40,438 $18,597 $ - $14,040 (b) $44,995
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,052 $ 3,042 $ - $ 2,677 (a) $ 2,417
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $34,437 $12,427 $ - $ 6,426 (b) $40,438
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 300 $ 9,270 $ - $ 9,270 (a) $ 300
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $16,069 $ 7,488 $ - $ 9,897 (b) $13,660
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1999
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 300 $ 290 $ - $ 290 (a) $ 300
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $16,656 $ 5,422 $ - $ 6,009 (b) $16,069
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 300 $ 183 $ - $ 183 (a) $ 300
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $14,962 $ 5,612 $ - $ 3,918 (b) $16,656
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,359 $ 2,220 $ - $ 1,710 (a) $ 1,869
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $11,405 $ 9,855 $ - $ 9,610 (b) $11,650
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1999
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,041 $ 1,590 $ - $ 2,272 (a) $ 1,359
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 9,906 $ 7,268 $ - $ 5,769 (b) $11,405
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,702 $ 2,726 $ - $ 2,387 (a) $ 2,041
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,788 $ 4,136 $ - $ 2,018 (b) $ 9,906
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,640 $ 2,416 $ - $ 2,170 (a) $ 1,886
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,188 $ 1,130 $ - $ 1,558 (b) $ 6,760
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1999
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 50 $ 4,564 $ - $ 2,974 (a) $ 1,640
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,960 $ 3,085 $ - $ 1,857 (b) $ 7,188
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1998
(Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
- -------------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 50 $ 106 $ - $ 106 (a) $ 50
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 5,503 $ 816 $ - $ 359 (b) $ 5,960
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
EXHIBIT INDEX
Each document described below is incorporated by reference to the files
of the SEC, unless the reference to the document is marked as follows:
* - Filed with the 2000 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
into the 2000 Annual Reports on Form 10-K for CL&P, PSNH, WMECO, and NAEC.
# - Filed with the 2000 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
into the 2000 Annual Report on Form 10-K for CL&P.
@ - Filed with the 2000 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
into the 2000 Annual Report on Form 10-K for PSNH.
** - Filed with the 2000 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 2000 NU Form 10-K, File No. 1-5324
into the 2000 Annual Report on Form 10-K for WMECO.
## - Filed with the 2000 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 2000 Form 10-K, File No. 1-5324 into
the 2000 Annual Report on Form 10-K for NAEC.
Exhibit
Number Description
2 Plan of acquisition, reorganization, arrangement, liquidation or
succession
2.1 Agreement and Plan of Merger (Exhibit 1 in NU's Current Report
on Form 8-K dated June 14, 1999, File No. 1-5324)
2.2 Agreement and Plan of Merger (Exhibit 1 to NU's Current Report
on Form 8-K dated October 13, 1999, File No. 1-5324)
3 Articles of Incorporation and By-Laws
3.1 Northeast Utilities
3.1.1 Declaration of Trust of NU, as amended through May 24,
1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324)
3.2 The Connecticut Light and Power Company
3.2.1 Certificate of Incorporation of CL&P, restated to
March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K,
File No. 1-5324)
3.2.2 Certificate of Amendment to Certificate of Incorporation
of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU
Form 10-K, File No. 1-5324)
3.2.3 Certificate of Amendment to Certificate of Incorporation
of CL&P, dated April 27, 1998. (Exhibit 3.2.3, 1998 NU
Form 10-K, File No. 1-5324)
3.2.4 By-laws of CL&P, as amended to January 1, 1997.
(Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)
3.3 Public Service Company of New Hampshire
3.3.1 Articles of Incorporation, as amended to May 16, 1991.
(Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.3.2 By-laws of PSNH, as amended to November 1, 1993.
(Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)
3.4 Western Massachusetts Electric Company
3.4.1 Articles of Organization of WMECO, restated to
February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K,
File No. 1-5324)
3.4.2 By-laws of WMECO, as amended to April 1, 1999.
(Exhibit 3.1, 1999 NU Form 10-Q for the Quarter Ended
June 30, 1999, File No. 1-5324)
3.4.3 By-laws of WMECO, as further amended to May 1, 2000.
(Exhibit 3.1, 2000 NU Form 10-Q for the Quarter Ended
June 30, 2000, File No. 1-5324)
3.5 North Atlantic Energy Corporation
3.5.1 Articles of Incorporation of NAEC dated September 20,
1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324)
3.5.2 Articles of Amendment dated October 16, 1991 and June 2,
1992, to Articles of Incorporation of NAEC. (Exhibit
3.5.2, 1993 NU Form 10-K, File No. 1-5324)
3.5.3 By-laws of NAEC, as amended to November 8, 1993. (Exhibit
3.5.3, 1993 NU Form 10-K, File No. 1-5324)
3.5.4 By-laws of NAEC, as amended to June 1, 2000. (Exhibit
3.1, 2000 NU Form 10-Q for the Quarter Ended September 30,
2000, File No. 1-5324)
4 Instruments defining the rights of security holders, including
indentures
4.1 Northeast Utilities
4.1.1 Indenture dated as of December 1, 1991, between Northeast
Utilities and IBJ Schroder Bank & Trust Company, with
respect to the issuance of Debt Securities. (Exhibit
4.1.1, 1991 NU Form 10-K, File No. 1-5324)
4.1.2 First Supplemental Indenture dated as of December 1,
1991, between Northeast Utilities and IBJ Schroder Bank &
Trust Company, with respect to the issuance of Series A
Notes. (Exhibit 4.1.2, 1991 NU Form 10-K, File No.
1-5324)
4.1.3 Second Supplemental Indenture dated as of March 1, 1992,
between Northeast Utilities and IBJ Schroder Bank & Trust
Company with respect to the issuance of 8.38% Amortizing
Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No.
1-5324)
4.1.4 Credit Agreement among NU, CL&P, WMECO and the Co-Agents
and Banks named therein, dated as of November 17, 2000,
(includes Open End Mortgages), (Exhibit No. 2 on 35-CERT
filed November 27, 2000, File No. 70-8875)
*4.1.5 Term Loan Agreement among NU and the Banks named therein,
dated as of March 1, 2000.
*4.1.5.1 First Amendment to Term Loan Agreement dated
as of December 15, 2000.
4.1.6 Indenture between NU and The Bank of New York, as Trustee,
dated as of February 28, 2001, relating to Senior Notes
(Exhibit A-1 to 35-CERT filed March 9, 2001, File No.
70-9535)
4.1.6.1 First Supplemental Indenture to the Indenture,
dated as of February 28, 2001, between NU and
The Bank of New York, as Trustee, relating to
Floating Rate Notes Due 2003 (Exhibit A-2 to
35-CERT filed March 9, 2001, File No. 70-9535)
4.2 The Connecticut Light and Power Company
4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, Trustee, dated as of May 1, 1921.
(Composite including all twenty-four amendments to May 1,
1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No.
1-5324)
Supplemental Indentures to the Composite May 1, 1921,
Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, dated as of:
4.2.2 December 1, 1969. (Exhibit 4.2.2, 1998 NU Form 10-K,
File No. 1-5324)
4.2.3 June 30, 1982. (Exhibit 4.33, File No. 2-79235)
4.2.4 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K,
File No. 1-5324)
4.2.5 July 1, 1992. (Exhibit 4.31, File No. 33-59430)
4.2.6 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.7 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.8 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K,
File No. 1-5324)
4.2.9 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K,
File No. 1-5324)
4.2.10 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K,
File No. 1-5324)
4.2.11 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K,
File No. 1-5324)
4.2.12 June 1, 1996. (Exhibit 4.2.16, 1996 NU Form 10-K,
File No. 1-5324)
4.2.13 January 1, 1997. (Exhibit 4.2.17, 1996 NU Form 10-K,
File No. 1-5324)
4.2.14 May 1, 1997. (Exhibit 4.19, File No. 333-30911)
4.2.15 June 1, 1997. (Exhibit 4.20, File No. 333-30911)
4.2.16 June 1, 1997. (Exhibit 4.2.17, 1997 NU Form 10-K, File
No. 1-5324)
4.2.17 May 1, 1998. (Exhibit 4.2.17, 1998 NU Form 10-K, File
No. 1-5324)
4.2.18 May 1, 1998. (Exhibit 4.2.18, 1998 NU Form 10-K, File
No. 1-5324)
4.2.19 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1986 Series) dated as of
December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S,
File No. 30-246)
4.2.20 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1988 Series) dated as of
October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S,
File No. 30-246)
4.2.21 Loan and Trust Agreement among Business Finance Authority
of the State of New Hampshire, CL&P and the Trustee
(Pollution Control Bonds, 1992 Series A) dated as of
December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S,
File No. 30-246)
4.2.22 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.21, 1993 NU Form 10-K, File No. 1-5324)
4.2.23 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series B, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.22, 1993 NU Form 10-K, File No. 1-5324)
4.2.24 Amended and Restated Loan Agreement between Connecticut
Development Authority and CL&P (Pollution Control Revenue
Bond - 1996A Series) dated as of May 1, 1996, and Amended
and Restated as of January 1, 1997. (Exhibit 4.2.24, 1996
NU Form 10-K, File No. 1-5324)
4.2.24.1 Amended and Restated Indenture of Trust between
Connecticut Development Authority and the
Trustee (CL&P Pollution Control Revenue Bond-
1996A Series), dated as of May 1, 1996, and
Amended and Restated as of January 1, 1997.
(Exhibit 4.2.24.1, 1996 NU Form 10-K, File
No. 1-5324)
#4.2.24.2 Standby Bond Purchase Agreement among CL&P,
Bank of New York as Purchasing Agent and the
Banks Named therein, dated October 24, 2000.
4.2.24.3 AMBAC Municipal Bond Insurance Policy issued
by the Connecticut Development Authority (CL&P
Pollution Control Revenue Bond-1996A Series),
effective January 23, 1997. (Exhibit 4.2.24.3,
1996 NU Form 10-K, File No. 1-5324)
4.2.25 Amended and Restated Limited Partnership Agreement (CL&P
LP) among CL&P, NUSCO, and the persons who became limited
partners of CL&P LP in accordance with the provisions
thereof dated as of January 23, 1995 (MIPS). (Exhibit
A.1 (Execution Copy), File No. 70-8451)
4.2.26 Indenture between CL&P and Bankers Trust Company, Trustee
(Series A Subordinated Debentures), dated as of January 1,
1995 (MIPS). (Exhibit B.1 (Execution Copy), File No.
70-8451)
4.2.27 Payment and Guaranty Agreement of CL&P dated as of
January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy),
File No. 70-8451)
4.3 Public Service Company of New Hampshire
4.3.1 First Mortgage Indenture dated as of August 15, 1978,
between PSNH and First Fidelity Bank, National
Association, New Jersey, now First Union National Bank,
Trustee, (Composite including all amendments to May 16,
1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File No.
1-5324)
4.3.1.1 Tenth Supplemental Indenture dated as of May 1,
1991, between PSNH and First Fidelity Bank,
National Association, now First Union National
Bank. (Exhibit 4.1, PSNH Current Report on
Form 8-K dated February 10, 1992, File No.
1-6392)
4.3.3 Series A (Tax Exempt New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH
Current Report on Form 8-K dated February 10, 1992,
File No. 1-6392)
4.3.4 Series B (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH
Current Report on Form 8-K dated February 10, 1992,
File No. 1-6392)
4.3.5 Series C (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH
Current Report on Form 8-K dated February 10, 1992,
File No. 1-6392)
4.3.6 Series D (Tax Exempt Refunding) Amended and Restated PCRB
Loan and Trust Agreement dated as of April 1, 1999.
(Exhibit 4.3.6, 1999 NU Form 10-K, File No. 1-5324)
4.3.7 Series E (Tax Exempt Refunding) Amended and Restated PCRB
Loan and Trust Agreement dated as of April 14, 1999.
(Exhibit 4.3.7, 1999 NU Form 10-K, File No. 1-5324)
4.4 Western Massachusetts Electric Company
4.4.1 First Mortgage Indenture and Deed of Trust between WMECO
and Old Colony Trust Company, Trustee, dated as of
August 1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K,
File No. 1-5324)
Supplemental Indentures thereto dated as of:
4.4.2 October 1, 1954. (Exhibit 4.4.2, 1998 NU Form 10-K,
File No. 1-5324)
4.4.3 March 1, 1967. (Exhibit 4.4.3, 1997 NU Form 10-K,
File No. 1-5324)
4.4.4 July 1, 1973. (Exhibit 2.10, File No. 2-68808)
4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772)
4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K,
File No. 1-5324)
4.4.7 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K,
File No. 1-5324)
4.4.8 May 1, 1997. (Exhibit 4.11, File No. 33-51185)
4.4.9 July 1, 1997. (Exhibit 4.4.10, 1997 NU Form 10-K,
File No. 1-5324)
4.4.10 May 1, 1998. (Exhibit 4.4.10, 1998 NU Form 10-K, File
No. 1-5324)
4.4.11 May 1, 1998. (Exhibit 4.4.11, 1998 NU Form 10-K, File
No. 1-5324)
4.4.12 Loan Agreement between Connecticut Development Authority
and WMECO, (Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.4.13, 1993 NU Form 10-K, File No. 1-5324)
4.5 North Atlantic Energy Corporation
4.5.1 First Mortgage Indenture and Deed of Trust between NAEC
and United States Trust Company of New York, Trustee,
dated as of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form
10-K, File No. 1-5324)
4.5.2 Term Credit Agreement dated as of November 9, 1995.
(Exhibit 4.5.2, 1995 NU Form 10-K, File No. 1-5324)
10 Material Contracts
10.1 Stockholder Agreement dated as of July 1, 1964, among the
stockholders of CYAPC. (Exhibit 10.1, 1994 NU Form 10-K, File
No. 1-5324)
10.2 Form of Power Contract dated as of July 1, 1964, between CYAPC
and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.2, 1994 NU
Form 10-K, File No. 1-5324)
10.2.1 Form of Additional Power Contract dated as of April 30,
1984, between CYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)
10.2.2 Form of 1987 Supplementary Power Contract dated as of
April 1, 1987, between CYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No.
1-5324)
10.3 Capital Funds Agreement dated as of September 1, 1964, between
CYAPC and CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.3, 1994 NU
Form 10-K, File No. 1-5324)
10.4 Stockholder Agreement dated December 10, 1958, between YAEC and
CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.4, 1993 NU Form 10-K,
File No. 1-5324)
10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power
Contract between YAEC and each of CL&P, PSNH and WMECO, including
a composite restatement of original Power Contract dated June 30,
1959, and Amendment No. 1 dated April 1, 1975, and Amendment No. 2
dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No.
1-5324.)
10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6,
1988, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.5.4 Form of Amendment No. 7 to Power Contract, dated
February 1, 1992, between YAEC and each of CL&P, PSNH
and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File
No. 1-5324)
10.6 Stockholder Agreement dated as of May 20, 1968, among stockholders
of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)
10.7 Form of Power Contract dated as of May 20, 1968, between MYAPC
and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.7, 1997
Form 10-K, File No. 1-5324)
10.7.1 Form of Amendment No. 1 to Power Contract dated as of
March 1, 1983, between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No.
1-5324)
10.7.2 Form of Amendment No. 2 to Power Contract dated as of
January 1, 1984, between MYAPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File
No. 1-5324)
10.7.3 Form of Amendment No. 3 to Power Contract dated as of
October 1, 1984, between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File
No. 1-5324)
10.7.4 Form of Additional Power Contract dated as of February 1,
1984, between MYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
10.8 Capital Funds Agreement dated as of May 20, 1968, between MYAPC
and CL&P, PSNH, HELCO, and WMECO. (Exhibit 10.8, 1997 NU Form
10-K, File No. 1-5324)
10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of
August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.
(Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)
10.9 Sponsor Agreement dated as of August 1, 1968, among the sponsors
of VYNPC. (Exhibit 10.9, 1997 NU Form 10-K, File No. 1-5324)
10.10 Form of Power Contract dated as of February 1, 1968, between VYNPC
and each of CL&P, HELCO, PSNH, and WMECO. (Exhibit 10.10, 1997 NU
Form 10-K, File No. 1-5324)
10.10.1 Form of Amendment to Power Contract dated as of June 1,
1972, between VYNPC and each of CL&P, HELCO, PSNH and
WMECO. (Exhibit 5.22, File No. 2-47038)
10.10.2 Form of Second Amendment to Power Contract dated as of
April 15, 1983, between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K,
File No. 1-5324)
10.10.3 Form of Third Amendment to Power Contract dated as of
April 24, 1985, between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File
No. 1-5324)
10.10.4 Form of Fourth Amendment to Power Contract dated as of
June 1, 1985, between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.10.4, 1996 NU Form 10-K, File
No. 1-5324)
10.10.5 Form of Fifth Amendment to Power Contract dated as of
May 6, 1988, between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.5, 1990 NU Form 10-K, File No.
1-5324)
10.10.6 Form of Sixth Amendment to Power Contract dated as of
May 6, 1988, between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No.
1-5324)
10.10.7 Form of Seventh Amendment to Power Contract dated as of
June 15, 1989, between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No.
1-5324)
10.10.8 Form of Eighth Amendment to Power Contract dated as of
December 1, 1989, between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File
No. 1-5324)
10.10.9 Form of Additional Power Contract dated as of
February 1, 1984, between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.9, 1993 NU Form 10-K, File
No. 1-5324)
10.11 Capital Funds Agreement dated as of February 1, 1968, between
VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11, 1997 NU
Form 10-K, File No. 1-5324)
10.11.1 Form of First Amendment to Capital Funds Agreement dated
as of March 12, 1968, between VYNPC and CL&P, HELCO,
PSNH, and WMECO. (Exhibit 10.11.1, 1997 NU Form 10-K,
File No. 1-5324)
10.11.2 Form of Second Amendment to Capital Funds Agreement
dated as of September 1, 1993, between VYNPC and CL&P,
HELCO, PSNH, and WMECO. (Exhibit 10.11.2, 1993 NU Form
10-K, File No. 1-5324)
10.12 PSA for the Millstone Power Station dated as of August 7, 2000,
by and among CL&P and WMECO as Sellers and Dominion as Buyer.
(Exhibit 10.1, 2000 NU Form 10-Q for the Quarter ended June 30,
2000, File No. 1-5324)
10.13 Amended and Restated Millstone Plant Agreement dated as of
December 1, 1984, by and among CL&P, WMECO and NNECO. (Exhibit
10.12, 1994 NU Form 10-K, File No. 1-5324)
10.14 Sharing Agreement dated as of September 1, 1973, with respect to
1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit
6.43, File No. 2-50142)
10.14.1 Amendment dated August 1, 1974, to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No.
2-52392)
10.14.2 Amendment dated December 15, 1975, to Sharing Agreement
- 1979 Connecticut Nuclear Unit. (Exhibit 7.47, File
No. 2-60806)
10.14.3 Amendment dated April 1, 1986, to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990
NU Form 10-K, File No. 1-5324)
10.15 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint
owners with respect to operation of Seabrook. (Exhibit 10.53, 1990
NU Form 10-K, File No. 1-5324)
10.16 Sharing Agreement between CL&P, WMECO, HP&E, HWP, and PSNH dated
as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No.
1-5324)
10.17 Rate Agreement by and between NUSCO, on behalf of NU, and the
Governor of the State of New Hampshire and the New Hampshire
Attorney General dated as of November 22, 1989. (Exhibit 10.44,
1989 NU Form 10-K, File No. 1-5324)
10.17.1 First Amendment to Rate Agreement dated as of
December 5, 1989. (Exhibit 10.16.1, 1995 NU Form 10-K,
File No. 1-5324)
10.17.2 Second Amendment to Rate Agreement dated as of
December 12, 1989. (Exhibit 10.16.2, 1995 NU Form 10-K,
File No. 1-5324)
10.17.3 Third Amendment to Rate Agreement dated as of
December 3, 1993. (Exhibit 10.16.3, 1995 NU Form 10-K,
File No. 1-5324)
10.17.4 Fourth Amendment to Rate Agreement dated as of
September 21, 1994. (Exhibit 10.16.4, 1995 NU Form 10-K,
File No. 1-5324)
10.17.5 Fifth Amendment to Rate Agreement dated as of
September 9, 1994. (Exhibit 10.16.5, 1995 NU Form 10-K,
File No. 1-5324)
10.18 Agreement to Settle PSNH Restructuring (Exhibit 10.2, 1999 NU Form
10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)
10.19 Merger Settlement Agreement between NU, Con Edison and NHPUC dated
as of December 6, 2000. (Exhibit O.1, to NU's U-1 Application,
File No. 70-9711)
10.20 Form of Seabrook Power Contract between PSNH and NAEC, as amended
and restated. (Exhibit 10.45, 1992 NU Form 10-K, File No. 1-5324)
10.21 Agreement (composite) for joint ownership, construction and
operation of New Hampshire nuclear unit, as amended through the
November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994
NU Form 10-K, File No. 1-5324)
10.21.1 Memorandum of Understanding dated November 7, 1988,
between PSNH and Massachusetts Municipal Wholesale
Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K,
File No. 1-6392)
10.21.2 Agreement of Settlement among Joint Owners dated as of
January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K,
File No. 1-5324)
10.21.2.1 Supplement to Settlement Agreement, dated as
of February 7, 1989, between PSNH and CMP.
(Exhibit 10.18.1, PSNH 1989 Form 10-K, File
No. 1-6392)
10.22 Amended and Restated Agreement for Seabrook Project Disbursing
Agent dated as of November 1, 1990. (Exhibit 10.4.7, File
No. 33-35312)
10.22.1 Form of First Amendment to Exhibit 10.22. (Exhibit
10.4.8, File No. 33-35312)
10.22.2 Form (Composite) of Second Amendment to Exhibit 10.22.
(Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324)
10.23 Agreement dated November 1, 1974, for Joint Ownership,
Construction and Operation of William F. Wyman Unit No. 4 among
PSNH, CMP and other utilities. (Exhibit 5.16, File No. 2-52900)
10.23.1 Amendment to Exhibit 10.23 dated June 30, 1975. (Exhibit
5.48, File No. 2-55458)
10.23.2 Amendment to Exhibit 10.23 dated as of August 16, 1976.
(Exhibit 5.19, File No. 2-58251)
10.23.3 Amendment to Exhibit 10.23 dated as of December 31,
1978. (Exhibit 5.10.3, File No. 2-64294)
10.24 Form of Service Contract dated as of July 1, 1966, between each
of NU, CL&P and WMECO and the Service Company. (Exhibit 10.20,
1993 NU Form 10-K, File No. 1-5324)
10.24.1 Service Contract dated as of June 5, 1992, between PSNH
and the Service Company. (Exhibit 10.12.4, 1992 NU Form
10-K, File No. 1-5324)
10.24.2 Service Contract dated as of June 5, 1992, between NAEC
and the Service Company. (Exhibit 10.12.5, 1992 NU Form
10-K, File No. 1-5324)
10.24.3 Form of Service Agreement dated as of June 29, 1992,
between PSNH and NAESCO, and the First Amendment
thereto. (Exhibits B.7 and B.7.1, File No. 70-7787)
10.24.4 Form of Annual Renewal of Service Contract. (Exhibit
10.20.3, 1993 NU Form 10-K, File No. 1-5324)
10.25 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP, and
WMECO dated as of June 1, 1970, with respect to pooling of
generation and transmission. (Exhibit 13.32, File No. 2-38177)
10.25.1 Amendment to Memorandum of Understanding between CL&P,
HELCO, HP&E, HWP, and WMECO dated as of February 2,
1982, with respect to pooling of generation and
transmission. (Exhibit 10.21.1, 1993 NU Form 10-K,
File No. 1-5324)
10.25.2 Amendment to Memorandum of Understanding between CL&P,
HELCO, HP&E, HWP, and WMECO dated as of January 1,
1984, with respect to pooling of generation and
transmission. (Exhibit 10.21.2, 1994 NU Form 10-K,
File No. 1-5324)
10.25.3 Second Amendment to Memorandum of Understanding between
CL&P, HELCO, HP&E, HWP, and WMECO dated as of June 8,
1999, with respect to pooling of generation and
transmission. (Exhibit 10.23.3, 1999 NU Form 10-K,
File No. 1-5324)
*10.26 Restated NEPOOL Power Pool Agreement (restated by the sixty-ninth
Agreement dated as of December 31, 2000, and includes the Restated
NEPOOL Open Access Transmission Tariff
10.26.1 Form of Interim ISO Agreement (Attachment to Thirty-
third Amendment to Exhibit 10.26 dated as of
December 31, 1996). (Exhibit 10.23.6, 1996 NU Form
10-K, File No. 1-5324)
10.27 Agreements among New England Utilities with respect to the Hydro-
Quebec interconnection projects. (See Exhibits 10(u) and 10(v);
10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K
of New England Electric System, File No. 1-3446.)
10.28 Trust Agreement dated February 11, 1992, between State Street Bank
and Trust Company of Connecticut, as Trustor, and Bankers Trust
Company, as Trustee, and CL&P and WMECO, with respect to Niantic
Bay Fuel Trust. (Exhibit 10.23, 1991 NU Form 10-K, File No.
1-5324)
10.28.1 Nuclear Fuel Lease Agreement dated as of February 11,
1992, between Bankers Trust Company, Trustee, as Lessor,
and CL&P and WMECO, as Lessees. (Exhibit 10.23.1, 1991
NU Form 10-K, File No. 1-5324)
10.28.2 Modification and Amendment to Nuclear Fuel Lease
Agreement dated as of May 17, 1999, between Bankers
Trust Company, Trustee, as Lessor, and CL&P and WMECO,
as Lessees. (Exhibit 10.26.2, 1999 NU Form 10-K,
File No. 1-5324)
10.29 Simulator Financing Lease Agreement, dated as of May 2, 1985, by
and between The Prudential Insurance Company of America and NNECO.
(Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324)
10.30 Lease dated as of April 14, 1992, between The Rocky River Realty
Company (RRR) and NUSCO with respect to the Berlin, Connecticut
headquarters (office lease). (Exhibit 10.29, 1992 NU Form 10-K,
File No. 1-5324)
10.30.1 Lease dated as of April 14, 1992, between RRR and NUSCO
with respect to the Berlin, Connecticut headquarters
(project lease). (Exhibit 10.29.1, 1992 NU Form 10-K,
File No. 1-5324)
10.31 Lease and Agreement, dated as of December 15, 1988, by and between
WMECO and Bank of New England, N.A., with BNE Realty Leasing
Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K,
File No. 1-5324.)
10.32 Note Agreement dated April 14, 1992, by and between RRR and
Purchasers named therein (Connecticut General Life Insurance
Company, Life Insurance Company of North America, INA Life
Insurance Company of New York, Life Insurance Company of Georgia),
with respect to RRR's sale of $15 million of guaranteed senior
secured notes due 2007 and $28 million of guaranteed senior
secured notes due 2017. (Exhibit 10.52, 1992 NU Form 10-K,
File No. 1-5324)
10.32.1 Amendment to Note Agreement, dated September 26, 1997.
(Exhibit 10.31.1, 1997 NU Form 10-K, File No. 1-5324)
10.32.2 Note Guaranty dated April 14, 1992, by Northeast
Utilities pursuant to Note Agreement dated April 14,
1992, between RRR and Note Purchasers, for the benefit
of The Connecticut National Bank as Trustee, the
Purchasers and the owners of the notes. (Exhibit
10.52.1, 1992 NU Form 10-K, File No. 1-5324)
10.32.2.1 Extension of Note Guaranty, dated
September 26, 1997. (Exhibit 10.31.2.1,
1997 NU Form 10-K, File No. 1-5324)
10.32.3 Assignment of Leases, Rents and Profits, Security
Agreement and Negative Pledge, dated as of April 14,
1992, among RRR, NUSCO and The Connecticut National Bank
as Trustee, securing notes sold by RRR pursuant to
April 14, 1992, Note Agreement. (Exhibit 10.52.2,
1997 NU Form 10-K, File No. 1-5324)
10.32.3.1 Modification of and Confirmation of
Assignment of Leases, Rents and
Profits, Security Agreement and Negative
Pledge, dated as of September 26, 1997.
(Exhibit 10.31.3.1, 1997 NU Form 10-K,
File No. 1-5324)
10.32.4 Purchase and Sale Agreement, dated July 28, 1997, by
and between RRR and the Sellers and Purchasers named
therein. (Exhibit 10.31.4, 1997 NU Form 10-K, File
No. 1-5324)
10.32.5 Purchase and Sale Agreement, dated September 26, 1997,
by and between RRR and the Purchaser named therein.
(Exhibit 10.31.5, 1992 NU Form 10-K, File No. 1-5324)
10.33 Master Trust Agreement dated as of September 2, 1986, between
CL&P and WMECO and Colonial Bank as Trustee, with respect to
reserve funds for Millstone 1 decommissioning costs. (Exhibit No.
10.32, 1996 NU Form 10-K, File No. 1-5324)
10.33.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.41.1, 1992 NU Form 10-K, File
No. 1-5324)
10.34 Master Trust Agreement dated as of September 2, 1986, between CL&P
and WMECO and Colonial Bank as Trustee, with respect to reserve
funds for Millstone 2 decommissioning costs. (Exhibit No. 10.33,
1996 NU Form 10-K, File No. 1-5324)
10.34.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.42.1, 1992 NU Form 10-K, File
No. 1-5324)
10.35 Master Trust Agreement dated as of April 23, 1986, between CL&P
and WMECO and Colonial Bank as Trustee, with respect to reserve
funds for Millstone 3 decommissioning costs. (Exhibit No. 10.34,
1996 NU Form 10-K, File No. 1-5324)
10.35.1 Notice of Appointment of Mellon Bank, N.A. as Successor
Trustee, dated November 20, 1990, and Acceptance of
Appointment. (Exhibit 10.43.1, 1992 NU Form 10-K,
File No. 1-5324)
10.36 Rights Agreement dated as of February 23, 1999, between Northeast
Utilities and NUSCO, as Rights Agent (Exhibit 1 to NU's
Registration Statement on Form 8-A, filed on 4/12/99, File No.
001-05324).
10.36.1 Amendment to Rights Agreement (Exhibit 3 to NU's Current
Report on Form 8-K dated October 13, 1999, File No.
1-5324).
10.37 NU Executive Incentive Plan, effective as of January 1, 1991.
(Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)
10.37.1 NU Incentive Plan, effective as of January 1, 1998.
(Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)
10.37.1.1 Amendment to Exhibit 10.37.1, effective as of
February 23, 1999. (Exhibit 10.35.1.1, 1998 NU
Form 10-K, File No. 1-5324)
10.38 Supplemental Executive Retirement Plan for Officers of NU system
companies, Amended and Restated effective as of January 1, 1992.
(Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30,
1992, File No. 1-5324)
10.38.1 Amendment 1 to Exhibit 10.38, effective as of August 1,
1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No.
1-5324)
10.38.2 Amendment 2 to Exhibit 10.38, effective as of January 1,
1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No.
1-5324)
10.38.3 Amendment 3 to Exhibit 10.38, effective as of January 1,
1996. (Exhibit 10.36.3, 1995 NU Form 10-K, File No.
1-5324)
10.39 Special Severance Program for Officers of NU system companies, as
adopted on July 15, 1998. (Exhibit 10.37, 1998 NU Form 10-K,
File No. 1-5324)
10.39.1 Amendment to Exhibit 10.39, effective as of February 23,
1999. (Exhibit 10.37.1, 1998 NU Form 10-K, File No.
1-5324)
10.39.2 Amendment to Exhibit 10.39, effective as of September 14,
1999. (Exhibit 10.3, 1999 NU Form 10-Q for the Quarter
Ended September 30, 1999, File No. 1-5324)
10.40 Loan Agreement dated as of December 2, 1991, by and between NU
and Mellon Bank, N.A., as Trustee, with respect to NU's loan of
$175 million to an ESOP Trust. (Exhibit 10.46, 1991 NU Form 10-K,
File No. 1-5324)
10.40.1 First Amendment to Exhibit 10.40 dated February 7, 1992.
(Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)
10.40.2 Loan Agreement dated as of March 19, 1992 by and between
NU and Mellon Bank, N.A., as Trustee, with respect to
NU's loan of $75 million to the ESOP Trust. (Exhibit
10.49.1, 1992 NU Form 10-K, File No. 1-5324)
10.40.3 Second Amendment to Exhibit 10.40 dated April 9, 1992.
(Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)
10.41 Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997
NU Form 10-K, File No. 1-5324)
10.40.1 Amendment to Exhibit 10.41, dated as of February 23,
1999. (Exhibit 10.39.1, 1998 NU Form 10-K, File No.
1-5324)
10.42 Transition and Retirement Agreement with Bernard M. Fox.
(Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324)
10.43 Employment Agreement with Bruce D. Kenyon. (Exhibit 10.40, 1996
NU Form 10-K, File No. 1-5324)
10.43.1 Amendment to Exhibit 10.43, dated as of January 13, 1998.
(Exhibit 10.41.1, 1998 NU Form 10-K, File No. 1-5324)
10.43.2 Amendment to Exhibit 10.43, dated as of February 23, 1999.
(Exhibit 10.41.2, 1998 NU Form 10-K, File No. 1-5324)
10.43.3 Amendment to Exhibit 10.43, dated as of March 21, 1999.
(Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended
March 31,1999, File No. 1-5324)
10.43.4 Amendment to Exhibit 10.43, dated as of May 14, 2000.
(Exhibit 10.3, 2000 NU Form 10-Q for the Quarter Ended
June 30, 2000, File No. 1-5324)
10.44 Employment Agreement with John H. Forsgren. (Exhibit 10.41, 1996
NU Form 10-K, File No. 1-5324)
10.44.1 Amendment to Exhibit 10.44, dated as of January 13, 1998.
(Exhibit 10.42.1, 1998 NU Form 10-K, File No. 1-5324)
10.44.2 Amendment to Exhibit 10.44, dated as of February 23,
1999. (Exhibit 10.42.2, 1998 NU Form 10-K, File No.
1-5324)
10.44.3 Amendment to Exhibit 10.44, dated as of May 10, 1999.
(Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended
March 31, 1999, File No. 1-5324)
10.44.4 Amendment to Exhibit 10.44, dated as of September 14,
1999. (Exhibit 10.4, 1999 NU Form 10-Q for the Quarter
Ended September 30, 1999, File No. 1-5324)
10.45 Employment Agreement with Hugh C. MacKenzie. (Exhibit 10.42,
1996 NU Form 10-K, File No. 1-5324)
10.45.1 Amendment to Exhibit 10.45, dated as of January 13,
1998. (Exhibit 10.43.1, 1998 NU Form 10-K, File
No. 1-5324)
10.45.2 Amendment to Exhibit 10.45, dated as of February 23,
1999. (Exhibit 10.43.2, 1998 NU Form 10-K, File No.
1-5324)
#@**10.45.3 Separation Agreement with Hugh C. MacKenzie, dated
as of December 20, 2000.
10.46 Employment Agreement with Cheryl W. Grise. (Exhibit 10.44,
1998 NU Form 10-K, File No. 1-5324)
10.46.1 Amendment to Exhibit 10.46, dated as of January 13, 1998.
(Exhibit 10.44.1, 1998 NU Form 10-K, File No. 1-5324)
10.46.2 Amendment to Exhibit 10.46, dated as of February 23,
1999. (Exhibit 10.44.2, 1998 NU Form 10-K, File No.
1-5324)
10.46.3 Amendment to Exhibit 10.46, dated as of September 14,
1999. (Exhibit 10.5, 1999 NU Form 10-Q for the Quarter
Ended September 30, 1999, File No. 1-5324)
10.47 Northeast Utilities Deferred Compensation Plan for Trustees,
Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU
Form 10-K, File No. 1-5324)
10.48 Deferred Compensation Plan for Officers of Northeast Utilities
System Companies adopted September 23, 1986. (Exhibit 10.40, 1995
NU Form 10-K, File No. 1-5324)
10.49 Northeast Utilities Deferred Compensation Plan for Executives,
adopted January 13, 1998. (Exhibit A.5, File No. 70-09185)
10.50 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC,
and NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form
10-K, File No. 1-5324)
10.51 Receivables Purchase and Sale Agreement (CL&P and CL&P Receivables
Corporation [CRC]), dated as of September 30, 1997. (Exhibit
10.49, 1997 NU Form 10-K, File No. 1-5324)
10.51.1 Amendment to Exhibit 10.51 dated September 29, 1998.
(Exhibit 10.49.1, 1998 NU Form 10-K, File No. 1-5324)
10.51.2 Amendment to Exhibit 10.51 dated September 28, 1999.
(Exhibit C.10.3, 1999 NU Form U5S, File No. 30-246)
#10.51.3 Amendment to Exhibit 10.51 dated September 27, 2000.
10.51.4 Purchase and Contribution Agreement (CL&P and CRC),
dated as of September 30, 1997. (Exhibit 10.49.1,
1997 NU Form 10-K, File No. 1-5324)
*10.52 Confirmation Agreement between Credit Suisse First Boston and
NU, dated as of January 2, 2001.
10.53 Confirmation Agreement between Bank One and NU, dated as of
December 9, 1999. (Exhibit 10.56, 1999 NU Form 10-K, File
No. 1-5324)
*10.53.1 First Amendment to Confirmation Agreement, dated as
of January 1, 2001.
*10.54 Credit Agreement dated as of March 9, 2000, among NGC as
Borrower and the Initial Lenders Named Therein as Initial Lenders
and Citibank, N.A. as Administrative and Collateral Agent and
Depository Bank.
*10.54.1 Amendment No. 1 to Exhibit 10.54, dated as of July 27,
2000.
*10.54.2 Amendment No. 2 to Exhibit 10.54, dated as of
November 22, 2000.
*10.55 Tranche B Mortgage dated as of March 9, 2000, among NGC and
Citibank, N.A.
10.56 Indenture of Mortgage and Deed of Trust dated July 1, 1989,
between Yankee and the Connecticut National Bank, as Trustee
(Exhibit 4.7, 1990 Yankee Form 10-K, File No. 0-10721)
10.57 Credit Agreement dated as of February 2, 1995, by and among
Yankee and the Bank of New York as Agent (Exhibit 10.18, 1995
Yankee Form 10-K, File No. 0-10721)
13 Annual Report to Security Holders (Each of the Annual Reports is filed
only with the Form 10-K of that respective registrant.)
13.1 Annual Report of CL&P.
13.2 Annual Report of WMECO.
13.3 Annual Report of PSNH.
13.4 Annual Report of NAEC.
*21 Subsidiaries of the Registrant.
MANAGEMENT'S DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
OVERVIEW
Northeast Utilities (NU or the company) reported year end 2000 earnings before
extraordinary items of $205.3 million, or $1.45 per share on a fully diluted
basis, compared with earnings of $34.2 million, or $0.26 per share, in 1999
and a loss of $146.8 million, or $1.12 per share in 1998. Because of
extraordinary charges totaling $233.9 million after-tax, NU reported a net loss
of $28.6 million, or $0.20 per share, on a fully diluted basis, for the year.
These extraordinary charges are associated with the impacts of industry
restructuring and the discontinuation of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." The most significant write-off occurred at Public Service Company
of New Hampshire (PSNH) during the fourth quarter as a result of the "Agreement
to Settle PSNH Restructuring" (Settlement Agreement) with the State of
New Hampshire.
Increases in competitive energy subsidiaries' sales pushed total NU revenues to
a record $5.9 billion in 2000, up 31 percent from $4.47 billion in 1999.
Revenues were $3.77 billion in 1998. The growth in competitive energy
subsidiaries' revenues more than offset a 5 percent retail rate decrease on
January 1, 2000, for customers of The Connecticut Light and Power Company
(CL&P) and a 5 percent rate reduction on October 1, 2000, for PSNH retail
customers. Regulated retail electric sales increased by 0.8 percent in 2000,
as compared to 1999, primarily due to economic growth in NU's service
territories. However, retail electric sales would have increased 1.9 percent
had it not been for mild summer temperatures.
Many areas of the Northeast Utilities system (NU system) contributed to the
better operating performance in 2000. The most significant improvement
occurred at CL&P, NU's largest operating subsidiary. CL&P's earnings totaled
$148.1 million in 2000, compared with a loss of $13.6 million in 1999 and
$195.7 million in 1998. The 2000 results represented CL&P's first annual
profit since 1995. CL&P benefited from the return to service of the Millstone
2 unit in May 1999 and the strong performance of the Millstone 2 and 3 units
in 2000. Millstone 2 operated at a capacity factor of 82 percent in 2000,
while Millstone 3 operated at a capacity factor of virtually 100 percent in
2000. However, management projects that CL&P's earnings will decline in 2001
as a result of the expected sale of CL&P's share of the Millstone units, other
rate adjustments and the pending resolution of the over-earnings docket.
Although CL&P's earnings are expected to decline, its return on equity is not
expected to be compromised.
NU's competitive energy subsidiaries achieved a significant improvement in
operating results in 2000 over 1999. The competitive energy subsidiaries
contributed $13.6 million before extraordinary charges in 2000 toward NU's
consolidated earnings, compared with a net loss of $37 million in 1999.
During 2000, the Holyoke Water Power Company (HWP) recorded an extraordinary
charge of $19.7 million after-tax, or $0.14 per share, as a result of the
discontinuation of SFAS No. 71 for certain hydroelectric generation assets.
Absent the extraordinary charge, PSNH earned $67.6 million in 2000, compared
with $84.2 million in 1999 and $91.7 million in 1998. North Atlantic Energy
Corporation (NAEC) earned $32.5 million in 2000, compared with $29.6 million
in 1999 and $29.5 million in 1998. Operating earnings at PSNH and NAEC are
expected to decline significantly after the first quarter of 2001, as a result
of the retail rate reductions and capital redeployment that will accompany the
introduction of industry restructuring in New Hampshire.
Similar to CL&P, Western Massachusetts Electric Company (WMECO) also
experienced a significant improvement in operating results in 2000, primarily
as a result of the return to service of Millstone 2 and the absence of
restructuring charges. In 2000, WMECO earned $35.3 million, compared with
$2.9 million in 1999 and a loss of $9.6 million in 1998.
NU projects earnings will be between $1.40 per share and $1.60 per share during
2001, not including significant nonrecurring gains and losses.
CONSOLIDATED EDISON, INC. MERGER
In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year. Additionally,
the Federal Energy Regulatory Commission (FERC) approved the merger in May
2000, the Nuclear Regulatory Commission approved the transaction in August
2000, and the United States Department of Justice approved the merger in
February 2001. Necessary approval from the Securities and Exchange Commission
(SEC) was expected to be received in mid-March 2001.
On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms of
the definitive merger agreement between the two companies. This included
assurances that Con Edison would consummate the pending merger at the price
set forth in the agreement promptly following the receipt of SEC approval.
The original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001. On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement. On March 12, 2001, NU
filed suit against Con Edison in the Southern District seeking damages in
excess of $1 billion arising from Con Edison's breach of the merger
agreement. NU cannot predict the outcome of this matter nor its effect on NU.
Under the terms of the proposed transaction, had it proceeded to closing, NU
shareholders would have received a base price of $25 per share, in a
combination of cash and Con Edison common stock, plus $0.0034 per share per
day, or approximately $0.10 per share per month, for each day that the merger
did not close after August 5, 2000. Additionally, NU shareholders would have
received another $1 per share as a result of a recommendation by the
Connecticut Department of Public Utility Control's (DPUC) Utility Operations
Management Analysis Unit that the DPUC accept the results of the Millstone
auction that were announced on August 7, 2000. The DPUC approved the sale in
January 2001. The $25 per share base price, the $0.0034 per share per day
compensation and the additional $1 per share resulting from the Millstone
auction would have been subject to the collar mechanism described in the
merger proxy statement dated February 29, 2000, to the extent NU shareholders
received Con Edison stock. Assuming that Con Edison's stock price had averaged
between $36 and $46 per share during the applicable pricing period, as defined,
NU shareholders would have received approximately $26.84 per share, were the
merger to have closed on April 10, 2001.
YANKEE ENERGY SYSTEM, INC. MERGER
On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc.
(Yankee), the parent company of Connecticut's largest natural gas distribution
company. Under the terms of the merger, NU issued approximately 11.1 million
NU common shares and paid $261.4 million of cash to Yankee's shareholders.
As expected, the transaction was dilutive for NU earnings per share in 2000,
in part because the merger was closed at the end of the winter heating season
and near the end of Yankee's strongest earnings period. Yankee lost $0.7
million during the 10 months of 2000 it has been part of the NU system.
Substantially better financial results are anticipated in 2001 during which
Yankee's operations will include the months of January and February.
Yankee anticipates filing a rate case in the second quarter of 2001.
On August 9, 2000, Yankee Gas Services Company (Yankee Gas) was ordered by the
DPUC to file a rate application. This review of Yankee Gas' rates is required
under Connecticut law because four years have passed since its last rate
review. In accordance with the most recent schedule approved by the DPUC,
Yankee Gas filed a cost of service study on February 14, 2001, which reflected
a historical test year ending September 30, 2000. Yankee Gas has asked the
DPUC to approve a schedule that would call for Yankee Gas to file a letter of
intent in May 2001, and its full filing in July 2001.
LIQUIDITY
NU's net cash flows provided by operating activities declined slightly to
$578.4 million in 2000 compared with $614.2 million in 1999 and $663.3
million in 1998. Industry restructuring in Connecticut which required
retail rate cuts reduced cash flows from operating activities. Industry
restructuring resulted in a reduction of depreciation and amortization
expense of $382.8 million for the year, as compared to 1999. Changes in
working capital, primarily a decrease in accrued taxes and an increase in
prepayments and other, also decreased cash flows from operating activities.
The increase in prepayments and other is primarily due to increases in
prepaid property taxes. In addition, an increase in prepaid pension, which
is a component of other sources and uses, contributed to the decrease in
cash flows from operating activities. Those factors were partially offset
by a $162.5 million increase in income after interest charges for the year
ended December 31, 2000, compared with the same period in 1999. Cash flows
from operations, however, was more than adequate to meet the payment of the
NU system's common and preferred dividends ($71.6 million) and investments
in electric and other utility plant, nuclear fuel and nuclear
decommissioning trusts ($453.6 million). The level of common dividends
totaled $57.4 million in 2000, as compared to $13.2 million paid in 1999
and no cash dividends in 1998. This increase was a result of NU paying a
$0.10 per share quarterly common dividend for all of 2000, as compared to
only the fourth quarter of 1999. The level of preferred dividends
decreased to $14.2 million in 2000, compared with $22.8 million in 1999 and
$26.4 million in 1998, reflecting NU's ongoing effort to reduce preferred
stock outstanding. The NU system companies currently forecast construction
expenditures ranging from $395 million to $420 million for the year 2001.
The transfer of 1,289 megawatts (MW) of hydroelectric generation assets to
Northeast Generation Company (NGC), an affiliated company, from CL&P and WMECO
in March 2000, produced a significant source of cash for CL&P and WMECO. NGC
financed the transfer with a short-term credit agreement collateralized by
the generation assets transferred and an equity infusion from NU. CL&P and
WMECO used this cash to retire long-term debt, preferred stock and to return
equity capital to the parent company. Consolidated financing activities for
2000 included $812.3 million for the retirement of long-term debt and
preferred stock, compared with $864 million for 1999.
Aside from the NGC borrowings, the largest new financing for the NU system in
2000 was the borrowing of $263 million to finance the cash portion of the
Yankee acquisition. NU refinanced that borrowing on February 28, 2001, when
it issued $263 million of two-year variable-rate notes. Based on the initial
rate of those notes, NU expects to save more than $1 million annually as a
result of the refinancing.
The NU system also renewed a series of other borrowing facilities over the
course of 2000. In November 2000, NU parent increased its revolving credit
agreement to $400 million from $350 million, primarily to meet Select Energy
Inc.'s (Select Energy) increased working capital needs to support a rapidly
growing level of business. NU parent provides credit assurance in the form
of guarantees, letters of credit, performance guarantees, and other assurances
for the financial performance obligations of certain of its competitive energy
subsidiaries, particularly Select Energy. Also in November 2000, CL&P and
WMECO reduced their revolving credit agreement to $350 million from $500
million to reflect lower borrowing needs post-restructuring, NAEC renewed its
$200 million term credit agreement for 364 days, and Yankee Gas renewed a
$60 million revolving credit agreement. All of those facilities were renewed
with more favorable terms as a result of the NU system's improving credit
profile. In April 2000, Moody's Investors Service (Moody's) upgraded its
credit ratings for NU, PSNH and NAEC, and in October 2000, Fitch IBCA (Fitch)
upgraded its credit ratings for PSNH and NAEC. In January 2001, Moody's and
Standard and Poor's upgraded their credit ratings for NU, CL&P, PSNH, WMECO,
and NAEC, primarily as a result of the New Hampshire Supreme Court's decision
to uphold that state's restructuring plan, the anticipated sale of the
Millstone units and NU's general financial recovery. In February 2001, Fitch
upgraded its credit ratings for NU, CL&P and WMECO. These upgrades return
NU's unsecured debt to investment grade ratings for the first time in five
years and will save the NU system in excess of $4.7 million annually in
financing costs.
For further information regarding the NU system's borrowing facilities, see
Note 2, "Short-Term Debt," to the consolidated financial statements.
PSNH terminated its $75 million revolving credit agreement in April 1999 and
continues to fund its operations and capital program with cash on hand and
operating cash flows. In August and September 2000, PSNH repaid $109.2 million
of variable-rate taxable pollution control bonds from cash on hand. PSNH also
paid a $50 million common dividend to NU on October 2, 2000, PSNH's first
common dividend to NU since February 1997. Despite those cash outflows,
PSNH maintained $115.1 million of cash on hand as of December 31, 2000.
On January 2, 2001, NU modified its forward share purchase arrangements for
approximately 10 million NU common shares. To initially effect these
arrangements, the financial institutions (counterparties) purchased
approximately 10 million NU common shares on the open market in December 1999
and January 2000, in a total aggregate amount of $215 million at an average
price of $21.26. The counterparties maintain ownership of the shares until
the transactions are settled. NU will continue to accrue charges on the total
aggregate amount at LIBOR plus an agreed upon percentage per annum until the
transactions are settled. These transactions can be settled in cash or NU
common shares at the company's discretion. NU expects to repurchase the shares
from the counterparties in the first half of 2001 with proceeds from
restructuring. However, if prior to the settlement date, NU's share price
falls below $18.06 per share, NU may be required to provide the counterparties
with additional collateral. This amount has been classified as temporary
equity from stock forward on NU's consolidated balance sheets at
December 31, 2000 and 1999.
For further information regarding the forward share purchase arrangements,
see Note 1C, "Summary of Significant Accounting Policies - New Accounting
Standards," to the consolidated financial statements.
In 2001, NU expects to reduce the capitalization of its regulated electric
operating companies significantly as a result of continued asset sales and
securitization of stranded costs. CL&P, PSNH and WMECO expect to receive
gross proceeds of $843.2 million, $26 million and $196.2 million,
respectively, as a result of the sale of their ownership interests in the
Millstone units to Dominion Resources, Inc. (Dominion). This sale is
expected to close as early as the end of March 2001. The cash proceeds are
expected to be used to repay subsidiary debt and capital lease obligations
and to return equity capital to the parent company.
By the end of 2002, PSNH expects to complete the auction of approximately
1,200 MW of fossil and hydroelectric generation assets, as well as CL&P's
and NAEC's share of the Seabrook Station nuclear unit (Seabrook). PSNH's
restructuring settlement was predicated upon receiving approximately $400
million of net proceeds from those sales. Cash proceeds will be used to
retire debt and to return equity capital to the parent company.
In November 2000, the DPUC approved CL&P's request to securitize an amount
not to exceed $1.55 billion of approved, eligible stranded costs, primarily
related to above-market purchased-power contracts and generation-related
regulatory assets. CL&P plans to use approximately $400 million of those
proceeds to reduce debt with the remaining proceeds to be used to buydown
and buyout above-market purchased-power contracts and to return equity
capital to the parent company. However, the Office of Consumer Counsel
(OCC) has appealed the securitization order to the Connecticut Superior
Court. On March 1, 2001, CL&P and the OCC entered into an agreement to
settle this issue. Under the agreement, pending DPUC approval, the OCC
agreed to withdraw its appeal of the securitization order and not take any
action that would affect the timing and amount of securitization financing
to be undertaken. The DPUC approved the agreement on March 12, 2001. The
OCC withdrew is appeal on March 16, 2001. Securitization for CL&P is
expected to take place by the end of the first quarter 2001.
In September 2000, the New Hampshire Public Utilities Commission (NHPUC)
approved a comprehensive restructuring settlement that allows PSNH to
securitize up to $670 million of stranded costs. In January 2001, the New
Hampshire Supreme Court upheld this restructuring order on appeal. However,
one of the appellants indicated publicly it would request a review of the
New Hampshire Supreme Court decision by the United States Supreme Court.
Such a request must be filed by May 1, 2001. Management believes that such
an appeal would have a low probability of success, but cannot determine what
effect it might have on the timing of the issuance of securitization bonds
and the implementation of customer choice in New Hampshire. PSNH currently
expects to work with the State of New Hampshire to issue securitization bonds
early in the second quarter of 2001. Cash proceeds would be combined with
cash on hand and used primarily to buydown the power contract between PSNH
and NAEC, retire debt at the two companies of approximately $300 million and
to return equity capital to the parent company from PSNH and NAEC of another
$375 million.
During February 2001, the Massachusetts Department of Telecommunications and
Energy (DTE) approved the securitization of $155 million of stranded costs
by WMECO. A significant portion of those proceeds will be used to buyout
a purchased-power contract with the remainder used to retire WMECO's debt
and to return equity capital to the parent company. Securitization for WMECO
is expected to take place early in the second quarter of 2001.
Should NU's regulated companies successfully complete the aforementioned asset
sales and securitization transactions, between 1999 and 2002, these regulated
companies would receive in excess of $5 billion of cash, including
approximately $1.4 billion previously received related to the sale and transfer
of CL&P's and WMECO's fossil and hydroelectric generation assets during 1999
and 2000. In total, management currently expects these operating subsidiaries
to use these proceeds in four primary ways. More than $2 billion would be used
to repay debt and preferred stock; more than $1 billion to buyout and buydown
high-cost purchased-power contracts; approximately $600 million to pay taxes
on gains from the sales of generation assets, and; approximately $1.2 billion
would be returned to NU from these operating companies. Of that $1.2 billion,
CL&P and WMECO repurchased $390 million of their common stock from NU in
March 2000, the proceeds of which were immediately invested in NGC. NU will
also use another $215 million of these proceeds to settle the aforementioned
forward share purchase arrangement.
RESTRUCTURING
As a result of industry restructuring, CL&P and WMECO stopped supplying power
directly to customers in 2000. Instead, CL&P and WMECO became energy delivery
companies, delivering electricity to customers that is produced by other
companies and sometimes bought by customers through intermediaries. In 2000,
customers in both states had the option of choosing alternative power suppliers
or relying on CL&P and WMECO to acquire the power for them through standard
offer service.
In 1999, under the oversight of the DPUC, CL&P secured four-year fixed-price
contracts with three suppliers to provide power to customers who choose
standard offer service. CL&P is fully recovering from retail customers the
cost of buying power from these three standard offer suppliers and expects to
continue recovery through the expiration of the contracts on December 31, 2003.
As of January 1, 2000, Select Energy, an affiliated company, became responsible
for 50 percent of CL&P's standard offer load for the entire standard offer
period, or approximately 2,000 MW annually at peak. Two other unaffiliated
suppliers became responsible for the balance of CL&P's standard offer load
also for the entire standard offer period.
CL&P and WMECO continue to generate power through either direct ownership of
generating plants, such as Millstone 2 and 3 and Seabrook, or through
purchased-power contracts. CL&P and WMECO sold the capacity associated with
Millstone 2 and 3 and Seabrook to Select Energy and five unaffiliated
companies. These contracts will expire on December 31, 2001. The revenues
generated from these contracts are expected to recover CL&P's and WMECO's share
of the nuclear operating costs through the divestiture of the Millstone units.
In 2000, WMECO supplied power to standard offer customers at a rate of slightly
more than $0.045 per kilowatt-hour. As a result of new one-year standard offer
supply contracts signed in December 2000, that rate will increase significantly
in 2001 to approximately $0.073 per kilowatt-hour. In January 2001, the DTE
approved an average overall rate increase of approximately 17.4 percent for
WMECO standard offer customers, allowing WMECO to fully recover these increased
power procurement costs. A higher rate was also approved for customers who
take default service from WMECO. Under the new standard offer contracts,
three unaffiliated companies provide up to 630 MW of power to WMECO's standard
offer customers and one unaffiliated company serves WMECO's default load of up
to 70 MW through December 31, 2001. WMECO renegotiates its standard offer
supply contracts on an annual basis.
Because of delays in implementing restructuring in New Hampshire, PSNH remained
a vertically integrated utility in 2000 with a fuel and purchased-power
adjustment charge. For the first nine months following restructuring, PSNH
will meet the load requirements of those customers who do not choose an
alternative supplier (Transition Service or standard offer service) through its
own generation assets and purchased-power obligations. Because PSNH's
generation assets are heavily weighted toward coal and nuclear generation, PSNH
is somewhat insulated from rising oil and natural gas prices. Following that
initial nine-month period, PSNH expects to sell its generation assets and
acquire power for up to two years from third-party suppliers for customers who
remain on transition service. Under the restructuring statute and the
conforming Settlement Agreement, PSNH will utilize its own generation
capability to provide Transition Service and Default Service for the Initial
Transition Service Period (ITSP, the first nine months after competition day).
At the conclusion of the ITSP, PSNH will be required to contract for Transition
Service for the remaining 24-month Transition Service period with third party
suppliers through a competitive bidding process administered by the NHPUC.
As part of its negotiation with state legislature, PSNH has agreed to expense
the first $7 million of costs for the first 12-month period following the ITSP,
if the cost of acquiring Transition Service exceeds the rate charged to
customers. PSNH will be permitted to defer and recover, as unsecuritized
stranded costs, all Transition Service costs in excess of the initial
$7 million.
Provisions for Transition Service are but one element of Settlement Agreement
which during 2000 was approved by the New Hampshire House and Senate, signed
into law by the Governor of New Hampshire and approved by the NHPUC. Other
provisions allow for issuing rate reduction bonds to securitize stranded costs;
implementing a rate decrease of approximately 15.5 percent, 5 percent of which
was implemented on a temporary basis on October 1, 2000; an after-tax write-off
of stranded costs in excess of $200 million, which was recorded in the fourth
quarter; selling NAEC's share of Seabrook no later than December 31, 2003, and;
fixing PSNH's delivery rates at $0.028 per kilowatt-hour for the first 33
months after the Settlement Agreement takes effect. PSNH and NAEC will also
terminate the Seabrook Power Contracts upon the sale of Seabrook.
Restructuring is expected to take effect the first day of the month after PSNH
issues rate reduction bonds, which is anticipated to be May 1, 2001.
For further information regarding commitments and contingencies related to
restructuring, see Note 6A, "Commitments and Contingencies - Restructuring," to
the consolidated financial statements.
REGIONAL TRANSMISSION ORGANIZATION
Pursuant to FERC Order 888 (issued in April 1996), the NU system companies
operate their transmission system under an open access, nondiscriminatory
transmission tariff.
In December 1999, the FERC issued an order calling on all transmission owners
to voluntarily join Regional Transmission Organizations (RTOs) in order to
boost competition in electric markets. In general, each of these organizations
would be an independent operator over all transmission facilities, and would
perform, among other functions, tariff administration, construction planning
and reliability management for the particular regional transmission system.
NU's active voting interest in such an organization would be limited to 5
percent under the proposal.
The NU system companies and other parties have appealed this order. Of primary
concern to NU is the ratemaking authority granted to RTOs and its impact on the
ability of transmission owners to earn appropriate returns on their
transmission investment under the organizational structure and the minimum
functions proposed in the order. The NU system companies were required to
participate in a collaborative process established by the FERC beginning in
March of 2000. On January 16, 2001, NU along with the Independent System
Operator and five other New England transmission owning utilities filed a
proposal to establish a New England RTO.
COMPETITIVE ENERGY SUBSIDIARIES
NU's competitive energy subsidiaries engage in a variety of energy-related
activities, primarily in the competitive energy retail and wholesale commodity,
marketing and services fields. In addition, these subsidiaries own and manage
1,521 MW of capacity, as well as provide services to the electric generation
market and large commercial and industrial customers in the Northeast.
NU's competitive energy subsidiaries contributed $13.6 million before
extraordinary items in 2000 towards NU's consolidated earnings, compared with a
net loss of $37 million in 1999. In July 1999, NGC was announced as one of the
winning bidders of certain CL&P and WMECO hydroelectric generation assets.
Management expected this transaction to close by January 1, 2000. The
transaction actually closed on March 14, 2000. This transaction has allowed
the competitive energy subsidiaries to better balance their energy purchase and
supply commitments, improving profitability. Since January 1, 2000, these
assets have been managed by the competitive energy subsidiaries and earnings of
$6.9 million have been included in the contributed earnings reported above of
$13.6 million. As a result of the delayed closing, however, the $6.9 million
was recorded by CL&P and WMECO for the period from January 1, 2000 to March 14,
2000. Unconsolidated revenues for the competitive energy subsidiaries were
$1.9 billion in 2000, compared with $648.9 million in 1999. CL&P's standard
offer purchases from Select Energy, represented $651.9 million of total
competitive energy subsidiaries' revenues in 2000, which is eliminated in
consolidation.
NUCLEAR PLANT PERFORMANCE AND DIVESTITURE
Millstone: The Millstone units completed one of their best years ever in 2000.
Millstone 2 operated at a capacity factor of 82 percent in 2000 and completed
a refueling outage in early June more than four days ahead of schedule. The
40-day, 21-hour outage set a world record for a refueling that included a full
generator rewind. Millstone 3 operated at virtually a 100 percent capacity
factor in 2000 and ran for 585 consecutive days before beginning a scheduled
refueling outage on February 3, 2001. Millstone 3 is expected to return to
service by the end of the first quarter of 2001. Along with the higher output,
NU benefited from lower costs. NU's share of the nonfuel operation and
maintenance (O&M) expenses associated with Millstone 2 and 3 totaled $193.6
million in 2000, compared with $269.4 million in 1999.
On August 7, 2000, CL&P, WMECO and certain other joint owners reached an
agreement to sell substantially all of the Millstone units, located in
Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including
approximately $105 million for nuclear fuel. Dominion has also agreed to
assume responsibility for decommissioning the three units and NU will transfer
to Dominion all funds in the Millstone decommissioning trust. Additionally,
NU is obligated to top-off the decommissioning trust if its value does not
equal an agreed upon amount at closing. That amount is pursuant to the
purchase and sale agreement (PSA) with Dominion, subject to adjustment for
delays in the closing of the sale and Millstone 1 not meeting the "cold and
dark" condition specified in the PSA.
If the transaction is consummated as proposed, CL&P and WMECO would receive
gross proceeds of approximately $843.2 million and $196.2 million on a pretax
basis for their respective ownership interests. The proceeds from the sale of
these interests will be used to reduce the companies' stranded costs under
restructuring and the cash proceeds will be used to repay subsidiary debt and
capital lease obligations and to return equity capital to the parent company.
PSNH will receive $26 million on a pretax basis, which will be reflected as a
gain in accordance with the Settlement Agreement.
In preparation for the divestiture of the Millstone units, it was discovered
that two full-length irradiated fuel rods are missing. The company believes
that the two rods remain stored in the Millstone 1 spent fuel pool or were
shipped in a shielded cask to a facility licensed to accept radioactive
material. The company's investigation into the location of the two rods is
ongoing. NU is responsible for any potential liabilities, which are not
determinable at this time, related to these missing fuel rods.
In connection with the prior settlement of Millstone 3 joint owner claims, if
the aforementioned transaction is consummated as proposed, the NU system will
record a pretax gain in excess of $150 million.
NU currently expects to close on the sale of Millstone as early as the end of
March 2001. In anticipation of the sale of Millstone, in December 2000, NU
announced a voluntary separation program designed to reduce generation-related
support staff in 2001. NU will reflect this program's cost in the first
quarter of 2001.
Seabrook: Seabrook operated at a capacity factor of 78 percent in 2000. The
unit began a scheduled refueling outage on October 21, 2000. The outage was
extended by approximately two months as a result of the need to repair
extensive problems with a back-up diesel generator. Seabrook returned to
service on January 29, 2001.
On December 15, 2000, NU filed its divestiture plan for Seabrook with the
NHPUC and the DPUC. NU hopes to complete the sale in 2002.
In October 2000, NU reached an agreement with an unaffiliated joint owner, who
owns approximately 15 percent of Seabrook, to auction its share of the plant
with NU's share. As part of the agreement, if the unaffiliated joint owner's
share of the proceeds from the sale of Seabrook is less than $87.2 million,
NU will provide up to $17.4 million to compensate for any shortfall. NU also
will share in the benefits if the proceeds from the sale of that share of
Seabrook exceeds $87.2 million. Additionally, under the agreement, NU will
top-off certain decommissioning obligations above a defined level.
Yankee Companies: In 1999, the Vermont Yankee Nuclear Power Corporation
(VYNPC) agreed to sell its nuclear generating unit for $22 million to an
unaffiliated company. Among other commitments, the acquiring company agreed
to assume the obligation to decommission the unit after it is taken out of
service, and the owners of VYNPC (including CL&P, WMECO and PSNH) agreed to
fund their shares of the decommissioning costs up to a negotiated amount.
Subsequent to the time that the agreement was executed, the original proposed
acquiring company increased its purchase price and three other unaffiliated
companies have indicated their interest in buying VYNPC's generating unit on
terms that have not been disclosed. On February 14, 2001, the Vermont Public
Service Board dismissed the acquiring company's petition for approval and
VYNPC agreed to work with the Vermont regulators to develop an auction process
for the sale of the unit. At present, CL&P, WMECO and PSNH expect that the
unit will be sold, but the identity of the owner and the terms of sale,
including price, future decommissioning obligations and future power purchase
obligations, are not known.
NUCLEAR DECOMMISSIONING
In connection with the aforementioned sale of the Millstone units, Dominion has
agreed to assume responsibility for decommissioning the Millstone units.
For further information regarding nuclear decommissioning, see Note 7, "Nuclear
Decommissioning and Plant Closure Costs," to the consolidated financial
statements.
SPENT NUCLEAR FUEL DISPOSAL COSTS
The United States Department of Energy (DOE) originally was scheduled to begin
accepting delivery of spent nuclear fuel in 1998. However, delays in
confirming the suitability of a permanent storage site continually have
postponed plans for the DOE's long-term storage and disposal site. Extended
delays or a default by the DOE could lead to consideration of costly
alternatives. NU has the primary responsibility for the interim storage of
its spent nuclear fuel prior to divestiture of its nuclear units.
For further information regarding spent nuclear fuel disposal costs, see
Note 6D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs,"
to the consolidated financial statements.
COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS
NU's competitive energy subsidiaries, as major providers of electricity and
natural gas, have certain market risks inherent in their business activities.
The competitive energy subsidiaries enter into contracts of varying length 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
companies' financial statements due to adverse changes in commodity market
prices. Through December 31, 2000, the competitive energy subsidiaries
increased their volume of electricity and gas marketing activities,
increasing these risks.
The competitive energy subsidiaries manage its portfolio of contracts and
assets to maximize value and minimize associated risks. The length of
contracts to buy and sell energy vary in duration from daily/hourly to several
years. At any point in time, the portfolio may be long (purchases exceeds
sales) or short (sales exceeds purchases). Portfolio and risk management
disciplines are used to manage exposures to market risks. Policies and
procedures have been established to manage these risks. At market spot prices
in effect at December 31, 2000, the portfolio had a negative mark to market.
There is significant volatility in the energy commodities market and for
certain of the energy products and contracts there has been limited liquidity.
Management does not believe the ultimate settlement through physical delivery
of its energy portfolio will result in realization of this negative mark to
market. The servicing of CL&P's standard offer load is a significant risk
for Select Energy, as this contract is for a 4-year period, ending December 31,
2003, at fixed prices. Approximately 26 percent of the 2000 competitive
energy revenues came from this contract. This risk is partially mitigated by
Select Energy entering into purchase contracts with other energy providers
to supply a portion of the standard offer requirement, including its contracts
with NGC, the purchase of 850 MW of output from the Millstone and Seabrook
units through 2001 and other resources in the energy marketplace. Although
there can be no assurance that it will be able to do so, management believes
that Select Energy will be able to source its remaining load requirement at
reasonable prices. If Select Energy is unable to source its remaining load
requirement at prices below the standard offer contract price as a result
of energy price increases, Select Energy's earnings would be adversely
impacted. For further information see Note 8, "Market Risk and Risk Management
Instruments," to the consolidated financial statements.
OTHER MATTERS
Derivative Instruments and Market Risk: Select Energy engages in the trading
of commodity derivatives which are accounted for using the mark-to-market
method under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities." All other nontrading transactions
are recognized where settled. For further information regarding these topics,
see Note 8, "Market Risk and Risk Management Instruments," to the consolidated
financial statements.
Environmental Matters: NU is subject to environmental laws and regulations
structured to mitigate or remove the effect of past operations and to improve
or maintain the quality of the environment. For further information regarding
environmental matters, see Note 6C, "Commitments and Contingencies -
Environmental Matters," to the consolidated financial statements.
Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 6, "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 historical weather patterns,
changes in laws, developments in legal or public policy doctrines,
technological developments, and other presently unknown or unforeseen factors.
RESULTS OF OPERATIONS
The components of significant income statement variances for the past two years
are provided in the table below.
Income Statement Variances
(Millions of Dollars)
2000 over/(under) 1999 1999 over/(under) 1998
-----------------------------------------------
Amount Percent Amount Percent
------ ------- ------ -------
Operating Revenues $1,405 31% $704 19%
Operating Expenses:
Fuel, purchased and net
interchange power 1,423 75 428 29
Other operation (6) (1) 53 7
Maintenance (85) (25) (58) (15)
Depreciation (62) (21) (31) (9)
Amortization of regulatory
assets, net (321) (54) 393 (a)
Federal and state income taxes 49 27 99 (a)
Taxes other than income taxes (22) (9) 9 4
Gain on sale of utility plant 309 100 (309) -
------ --- ---- ---
Total operating expenses 1,285 31 584 16
------ --- ---- ---
Operating income 120 35 120 53
------ --- ---- ---
Other Income:
Equity in earnings of regional
nuclear generating and
transmission companies 10 (a) (7) (59)
Nuclear related costs 53 75 72 50
Other, net 29 95 (19) (a)
Other income taxes (14) (17) 6 8
------ --- ---- ---
Net other income 78 (a) 52 69
Interest charges, net 36 14 (5) (2)
Preferred dividends of
subsidiaries (9) (38) (4) (14)
------ --- ---- ---
Income before extraordinary line 171 (a) 181 (a)
------ --- ---- ---
Extraordinary loss (234) (a) - -
------ --- ---- ---
Net (loss)/income $ (63) (a) $181 (a)
====== === ==== ===
(a) Percent greater than 100.
OPERATING REVENUES
Total revenues increased by $1,405 million or 31 percent in 2000, primarily due
to higher revenues from the competitive energy subsidiaries ($1,246 million of
which $669 million represents sales to other NU affiliates which are eliminated
in consolidation), the acquisition of Yankee ($262 million) and higher
regulated wholesale revenues ($727 million of which $281 million represents
sales to other NU affiliates which are eliminated in consolidation), partially
offset by lower regulated retail revenues ($26 million). The competitive
energy companies' increase is primarily due to higher revenues from Select
Energy as a result of new contracts for energy sales and services. The
regulated wholesale revenue increase is primarily due to higher PSNH energy
sales and higher CL&P and WMECO revenue from the sale of the output from
Millstone 2 and 3. The regulated retail decrease is primarily due to retail
rate reductions for CL&P and PSNH ($108 and $8 million, respectively),
partially offset by the impact of Millstone 2 being returned to CL&P's rate
base ($33 million), higher retail sales ($18 million), higher fuel revenues
for PSNH ($15 million) and higher retail revenue attributed to lower price
discounts in 2000 and changing customer mix ($24 million). Regulated retail
kilowatt-hour sales increased by 0.8 percent in 2000.
Total revenues increased by $704 million or 19 percent in 1999, primarily due
to higher revenues from the competitive energy subsidiaries ($552 million),
higher regulated wholesale revenue ($107 million) and higher regulated retail
revenue ($45 million). The competitive energy companies' increase is primarily
due to higher revenues from Select Energy as a result of new contracts for
energy sales. The regulated wholesale revenue increase is primarily due to
higher energy sales and related capacity and transmission revenues. The
regulated retail increase is primarily due to higher retail sales ($99 million)
and the impact of Millstone 2 and 3 being returned to CL&P's rate base
($13 million). These retail increases were partially offset by retail rate
reductions for CL&P and WMECO ($55 and $12 million, respectively). Regulated
retail kilowatt-hour sales increased by 3.8 percent.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased in 2000, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($1,053 million of which $660 million represents purchases
from NU other affiliates which are eliminated in consolidation), Yankee
expenses ($135 million) and higher purchased power for regulated subsidiaries
($235 million).
Fuel, purchased and net interchange power expense increased in 1999, primarily
due to higher purchased energy and capacity costs as a result of higher sales
for Select Energy ($521 million), regulated wholesale ($86 million) and
regulated retail ($36 million), partially offset by lower replacement power
costs due to the return to service of Millstone 2 and 3 ($215 million).
OTHER OPERATION AND MAINTENANCE
Other O&M expenses decreased $91 million in 2000, primarily due to lower
spending at the nuclear units due to better performance ($75 million), lower
expenses due to the sale of certain CL&P and WMECO fossil generation assets
($74 million), lower corporate support ($38 million), the decommissioning
status of Millstone 1 ($17 million), lower environmental-related costs ($12
million), and higher 1999 expenses associated with the Con Edison merger
($12 million), partially offset by the addition of Yankee ($60 million),
higher O&M expenses for the competitive energy businesses ($54 million),
primarily due to the business expansion, and higher distribution expenses
($29 million), including increased conservation program expenses.
Other O&M expenses decreased in 1999, primarily due to lower costs at the
Millstone units ($125 million), partially offset by the recognition of
environmental insurance proceeds in 1998 and additional environmental reserves
in 1999 ($30 million), higher transmission and power exchange expenses ($35
million), higher spending at Seabrook ($10 million) as a result of the
refueling outage, higher expenditures for HEC Inc. and the competitive energy
businesses ($32 million), and expenses associated with the Con Edison merger
($12 million) in 1999.
DEPRECIATION
Depreciation decreased in 2000, primarily due to the effect of discontinuing
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for
the portion of the generation business for CL&P and WMECO and the resulting
reclassification of depreciable nuclear plant balances to regulatory assets
($84 million) and the sale of certain CL&P and WMECO fossil and hydroelectric
generation assets, partially offset by the addition of Yankee ($23 million).
Depreciation decreased in 1999, primarily due to the retirement of Millstone 1.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased in 2000, primarily due to the
amortization in 1999 as a result of the gain on the sale of fossil and
hydroelectric generation assets for CL&P and WMECO ($309 million) and changes
in amortization levels as a result of industry restructuring ($95 million).
These decreases were partially offset by higher amortization associated with
the reclassified nuclear plant balances ($84 million).
Amortization of regulatory assets, net increased in 1999, primarily due to the
increased amortization associated with the gain on the sale of CL&P's and
WMECO's fossil and hydroelectric generation assets ($309 million), the
amortization of CL&P's and WMECO's Millstone 1 remaining investment ($56
million) and the amortization of stranded nuclear plant balances reclassified
as regulatory assets ($23 million).
FEDERAL AND STATE INCOME TAXES
The consolidated statement of income taxes provides a reconciliation of actual
and expected tax expense. The tax effect of temporary differences is accounted
for in accordance with the rate-making treatment of the applicable regulatory
commission. In past years, this rate-making treatment has required the company
to provide the customers with a portion of the tax benefits associated with
accelerated tax depreciation in the year it is generated (flow-through
depreciation). As these flow-through differences turn around, higher tax
expense is recorded.
Federal and state income tax expense increased approximately $63 million in
2000. Significant variances responsible for this increase include higher
pretax earnings ($90 million) and lower adjustments to the tax valuation
allowance ($21 million). Reduction in flow-through depreciation and
amortization ($51 million) partially offset the overall change.
Federal and state income tax expense increased approximately $93 million in
1999, primarily due to the significant increase in book pretax earnings.
Significant variances of other items include a $10 million increase in
flow-through depreciation turnaround and $4.6 million of nontax deductible
merger-related expenditures, offset by the elimination of a $23 million
deferred tax asset valuation reserve.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes decreased in 2000, primarily due to lower
Connecticut gross earnings taxes ($12 million) and lower payroll taxes
($7 million).
Other income taxes increased in 1999, primarily due to higher local property
taxes ($3 million) and higher gross earnings taxes ($2 million).
GAIN ON SALE OF UTILITY PLANT
CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric
generation assets in 1999. A corresponding amount of amortization expense was
recorded.
EQUITY IN EARNINGS OF REGIONAL NUCLEAR GENERATING AND TRANSMISSION COMPANIES
Equity in earnings of regional nuclear generating and transmission companies
increased in 2000, primarily due to higher earnings from the Connecticut Yankee
Atomic Power Company (CYAPC) as a result of a rate settlement.
Equity in earnings of regional nuclear generating and transmission companies
decreased in 1999, primarily due to lower earnings from CYAPC.
NUCLEAR RELATED COSTS
Nuclear related costs in 2000 are comprised of a CL&P/WMECO settlement of
Millstone 3 joint owner litigation, net of insurance proceeds ($11 million),
and CL&P/WMECO regulatory settlements ($6 million). In comparison, 1999 is
comprised of one-time charges related to the CL&P write-off of Connecticut
Municipal Electric Energy Cooperative (CMEEC) nuclear costs ($20 million),
the CL&P write-off of capital projects as a result of the Connecticut standard
offer decision ($11 million), the CL&P/WMECO settlement of Millstone 3 joint
owner litigation, net of insurance proceeds ($27 million), and WMECO return
disallowances on Millstone 1 plant ($13 million). Recoverable costs in 1998
are comprised of the write-off of the Millstone 1 entitlement formerly held by
CMEEC ($28 million) and the write-off of unrecoverable Millstone 1 costs as a
result of the February 1999 CL&P rate decision ($115 million).
OTHER, NET
Other, net increased in 2000, primarily due to a one-time gain related to
Mode 1 Communications, Inc.'s investment in NEON Communications, Inc. ($17
million) and the loss in 1999 on the CL&P assignment of market-based contracts
to Select Energy ($15 million).
Other income/(loss), net decreased in 1999, primarily due to the PSNH
settlement with the New Hampshire Electric Cooperative ($6 million) and the
loss on the CL&P assignment of market-based contracts to Select Energy
($15 million).
INTEREST CHARGES, NET
Interest charges, net increased in 2000, primarily due to higher short-term
borrowings associated with the NGC asset transfer and the Yankee merger,
partially offset by lower long-term debt as a result of reacquisitions and
retirements.
Interest charges, net decreased in 1999, primarily due to lower long-term
debt as a result of reacquisitions and retirements.
PREFERRED DIVIDENDS
Preferred dividends decreased in 1999 and 2000, primarily due to lower
preferred stock outstanding.
EXTRAORDINARY LOSS
The extraordinary loss is primarily due to an after-tax write-off by PSNH
of approximately $225 million of stranded costs under an industry
restructuring settlement with the state of New Hampshire, combined with
other positive effects on PSNH from the discontinuance of SFAS No. 71 ($11
million) and a loss associated with the pending sale of certain HWP assets
($20 million).
COMPANY REPORT
The accompanying consolidated financial statements of Northeast Utilities and
subsidiaries and other sections of this annual report were prepared by the
company. These financial statements, which were audited by Arthur Andersen
LLP, were prepared in accordance with accounting principles generally accepted
in the United States using estimates and judgments, where required, and giving
consideration to materiality.
The company has endeavored to establish a control environment that encourages
the maintenance of high standards of conduct in all of its business activities.
The company maintains a system of internal controls over financial reporting,
which is designed to provide reasonable assurance to the company's management
and Board of Trustees regarding the preparation of reliable, published
financial statements. The system is supported by an organization of trained
management personnel, policies and procedures, and a comprehensive program of
internal audits. Through established programs, the company regularly
communicates to its management employees their internal control
responsibilities and policies prohibiting conflicts of interest.
The Audit Committee of the Board of Trustees is composed entirely of
independent trustees. The Audit Committee meets periodically with management,
the internal auditors and the independent auditors to review the activities
of each and to discuss audit matters, financial reporting and the adequacy
of internal controls.
Because of inherent limitations in any system of internal controls, errors or
irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment provide
reasonable assurance that its assets are safeguarded from loss or unauthorized
use and that its financial records, which are the basis for the preparation
of all financial statements, are reliable.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To the Board of Trustees and
Shareholders of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust) and
subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, comprehensive income, shareholders' equity, cash flows,
and income taxes for each of the three years in the period ended December 31,
2000. These financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northeast Utilities and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 23, 2001 (except with
respect to the matters discussed
in Note 15, as to which the
date is March 13, 2001)
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
- ---------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information) 2000 1999 1998
- ---------------------------------------------------------------------------------------------
Operating Revenues................................. $ 5,876,620 $ 4,471,251 $ 3,767,714
------------- ------------- -------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power...... 3,321,226 1,898,314 1,470,200
Other.......................................... 850,192 855,917 803,419
Maintenance........................................ 255,884 340,419 399,165
Depreciation....................................... 239,798 302,305 332,807
Amortization of regulatory assets, net............. 276,139 596,437 203,132
Federal and state income taxes..................... 230,031 180,883 82,332
Taxes other than income taxes...................... 238,587 261,353 251,932
Gain on sale of utility plant...................... - (308,914) -
------------- ------------- -------------
Total operating expenses..................... 5,411,857 4,126,714 3,542,987
------------- ------------- -------------
Operating Income................................... 464,763 344,537 224,727
------------- ------------- -------------
Other Income/(Loss):
Equity in earnings of regional nuclear
generating and transmission companies......... 14,586 5,034 12,420
Nuclear related costs ............................. (17,907) (71,066) (143,239)
Other, net......................................... (1,689) (30,855) (12,225)
Minority interest in loss of subsidiary............ (9,300) (9,300) (9,300)
Income taxes....................................... 68,306 82,272 76,393
------------- ------------- -------------
Other income/(loss), net..................... 53,996 (23,915) (75,951)
------------- ------------- -------------
Income before interest charges............... 518,759 320,622 148,776
------------- ------------- -------------
Interest Charges:
Interest on long-term debt......................... 200,697 258,093 273,824
Other interest, net................................ 98,605 5,558 (4,735)
------------- ------------- -------------
Interest charges, net........................ 299,302 263,651 269,089
------------- ------------- -------------
Income/(loss) after interest charges......... 219,457 56,971 (120,313)
Preferred Dividends of Subsidiaries................ 14,162 22,755 26,440
------------- ------------- -------------
Income/(Loss) before extraordinary loss............ 205,295 34,216 (146,753)
Extraordinary loss, net of tax benefit
of $169,562..................................... (233,881) - -
------------- ------------- -------------
Net (Loss)/Income.................................. $ (28,586) $ 34,216 $ (146,753)
============= ============= =============
Basic and Fully Diluted (Loss)/Earnings Per
Common Share:
Income/(loss) before extraordinary loss......... $ 1.45 $ 0.26 $ (1.12)
Extraordinary loss, net of tax benefit.......... (1.65) - -
------------- ------------- -------------
Basic (Loss)/Earnings Per Common Share............. $ (0.20) $ 0.26 $ (1.12)
============= ============= =============
Basic Common Shares Outstanding (average).......... 141,549,860 131,415,126 130,549,760
============= ============= =============
Fully Diluted Common Shares Outstanding (average).. 141,967,216 132,031,573 130,549,760
============= ============= =============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
- ---------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999 1998
- ---------------------------------------------------------------------------------------------
Net (Loss)/Income.................................. $ (28,586) $ 34,216 $ (146,753)
------------- ------------- -------------
Other comprehensive income, net of tax:
Foreign currency translation adjustments........... - 1 -
Unrealized gains on securities..................... 245 118 2,019
Minimum pension liability adjustments.............. - - (613)
------------- ------------- -------------
Other comprehensive income, net of tax......... 245 119 1,406
------------- ------------- -------------
Comprehensive (Loss)/Income........................ $ (28,341) $ 34,335 $ (145,347)
============= ============= =============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999
- ----------------------------------------------------------------------------------------
ASSETS
- ------
Utility Plant, at cost:
Electric................................................ $ 9,370,176 $ 9,185,272
Gas and other........................................... 861,727 226,002
------------- -------------
10,231,903 9,411,274
Less: Accumulated provision for depreciation......... 7,041,279 6,088,310
------------- -------------
3,190,624 3,322,964
Unamortized PSNH acquisition costs...................... - 324,437
Construction work in progress........................... 228,330 177,504
Nuclear fuel, net....................................... 128,261 122,529
------------- -------------
Total net utility plant.............................. 3,547,215 3,947,434
------------- -------------
Other Property and Investments:
Nuclear decommissioning trusts, at market............... 740,058 711,910
Investments in regional nuclear generating
companies, at equity.................................. 62,477 81,503
Other, at cost.......................................... 137,291 94,768
------------- -------------
939,826 888,181
------------- -------------
Current Assets:
Cash and cash equivalents............................... 200,017 255,154
Investments in securitizable assets..................... 98,146 107,620
Receivables, less accumulated provision for
uncollectible accounts of $12,500 in 2000 and
$4,895 in 1999........................................ 472,863 310,190
Unbilled revenues....................................... 121,090 75,728
Fuel, materials and supplies, at average cost........... 163,711 172,973
Recoverable energy costs, net - current portion......... - 73,721
Prepayments and other................................... 94,528 75,225
------------- -------------
1,150,355 1,070,611
------------- -------------
Deferred Charges:
Regulatory assets....................................... 3,910,801 3,642,439
Unamortized debt expense................................ 33,475 39,192
Goodwill and other purchased intangible assets.......... 324,389 23,542
Prepaid pensions........................................ 139,546 669
Other .................................................. 171,542 75,984
------------- -------------
4,579,753 3,781,826
------------- -------------
Total Assets.............................................. $ 10,217,149 $ 9,688,052
============= =============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999
- ----------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common shares, $5 par value - authorized 225,000,000
shares; 148,781,861 shares issued and 143,820,405
shares outstanding in 2000 and 137,393,829 shares
issued and 131,870,284 shares outstanding in 1999..... $ 693,345 $ 636,405
Capital surplus, paid in................................ 927,059 776,290
Temporary equity from stock forward..................... 215,000 215,000
Deferred contribution plan - employee stock
ownership plan........................................ (114,463) (127,725)
Retained earnings....................................... 495,873 581,817
Accumulated other comprehensive income.................. 1,769 1,524
------------- -------------
Total common shareholders' equity.................... 2,218,583 2,083,311
Preferred stock not subject to mandatory redemption....... 136,200 136,200
Preferred stock subject to mandatory redemption........... 15,000 121,289
Long-term debt............................................ 2,029,593 2,372,341
------------- -------------
Total capitalization................................. 4,399,376 4,713,141
------------- -------------
Minority Interest in Consolidated Subsidiary.............. 100,000 100,000
------------- -------------
Obligations Under Capital Leases.......................... 47,234 62,824
------------- -------------
Current Liabilities:
Notes payable to banks.................................. 1,309,977 278,000
Long-term debt and preferred stock - current portion.... 340,041 503,315
Obligations under capital leases - current portion...... 112,645 118,469
Accounts payable........................................ 538,983 347,321
Accrued taxes........................................... 54,088 158,684
Accrued interest........................................ 41,131 37,904
Other................................................... 144,931 126,768
------------- -------------
2,541,796 1,570,461
------------- -------------
Deferred Credits and Other Long-term Liabilities:
Accumulated deferred income taxes....................... 1,585,494 1,688,114
Accumulated deferred investment tax credits............. 153,155 140,407
Decommissioning obligation - Millstone 1................ 692,560 702,351
Deferred contractual obligations........................ 244,608 358,387
Other................................................... 452,926 352,367
------------- -------------
3,128,743 3,241,626
------------- -------------
Commitments and Contingencies (Note 6)
Total Capitalization and Liabilities...................... $ 10,217,149 $ 9,688,052
============= =============
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
- ------------------------------------------------------------------------------------------
Accum-
Deferred ulated
Capital Contribu- Other
Common Surplus, tion Retained Compre-
Shares Paid In Plan- Earnings hensive
(Thousands of Dollars) (a) (a) ESOP (b) Income Total
- ------------------------------------------------------------------------------------------
Balance as of
January 1, 1998................$684,211 $ 932,494 $(154,141)$ 707,522 $ (1)$2,170,085
- ------------------------------------------------------------------------------------------
Net loss for 1998............. (146,753) (146,753)
Issuance of 189,094 common
shares, $5 par value........ 945 1,714 2,659
Allocation of benefits-ESOP... (4,769) 13,522 8,753
Unearned stock compensation... (537) (537)
Capital stock expenses, net... 3,560 3,560
Gain on equity investment..... 8,140 8,140
Gain on repurchase of
preferred stock............. 59 59
Other comprehensive income.... 1,406 1,406
- ------------------------------------------------------------------------------------------
Balance as of
December 31, 1998............. 685,156 940,661 (140,619) 560,769 1,405 2,047,372
- ------------------------------------------------------------------------------------------
Net income for 1999........... 34,216 34,216
Cash dividends on common
shares-$0.10 per share...... (13,168) (13,168)
Issuance of 362,565 common
shares, $5 par value........ 1,813 3,505 5,318
Allocation of benefits-ESOP... (3,053) 12,894 9,841
Unearned stock compensation... (1,194) (1,194)
Capital stock expenses, net... 807 807
Other comprehensive income.... 119 119
- ------------------------------------------------------------------------------------------
Balance as of
December 31, 1999............. 686,969 940,726 (127,725) 581,817 1,524 2,083,311
- ------------------------------------------------------------------------------------------
Net loss for 2000............. (28,586) (28,586)
Cash dividends on common
shares-$0.40 per share...... (57,358) (57,358)
Issuance of 11,388,032 common
shares, $5 par value........ 56,940 164,443 221,383
Common share repurchase
transaction fee............. (13,786) (13,786)
Allocation of benefits-ESOP... (1,617) 13,262 11,645
Redemption of
preferred stock............. (749) (749)
Capital stock expenses, net... 2,478 2,478
Other comprehensive income.... 245 245
- ------------------------------------------------------------------------------------------
Balance as of
December 31, 2000.............$743,909 $1,091,495 $(114,463)$ 495,873 $1,769 $2,218,583
- ------------------------------------------------------------------------------------------
(a) In conjunction with NU's forward share purchase arrangement, 10,112,879 shares or
$50.6 million and $164.4 million, respectively, have been reclassified from
Common Shares and Capital Surplus, Paid In, at December 31, 2000 and 1999, to
Temporary Equity from Stock Forward.
(b) Certain consolidated subsidiaries have dividend restrictions imposed by their
long-term debt agreements. These restrictions also limit the amount of retained
earnings available for NU common dividends. At December 31, 2000, retained earnings
available for payment of dividends totaled $180.1 million. Pursuant to certain
credit agreements, NU may not declare or make distributions in an amount not to
exceed $60 million for any twelve month period.
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999 1998
- ------------------------------------------------------------------------------------------------
Operating Activities:
Income/(loss) after interest charges......................... $ 219,457 $ 56,971 $(120,313)
Adjustments to reconcile to net cash
provided by operating activities:
Depreciation............................................... 239,798 302,305 332,807
Deferred income taxes and investment tax credits, net...... (16,117) (183,356) 23,502
Amortization of regulatory assets, net..................... 276,139 596,437 203,132
Net (deferral)/amortization of recoverable energy costs.... (30,603) 44,526 38,356
Nuclear related costs...................................... 17,907 71,066 143,239
Gain on sale of utility plant.............................. - (308,914) -
Net other sources/(uses) of cash........................... (88,549) (79,232) 53,346
Changes in working capital:
Receivables and unbilled revenues, net..................... (104,868) (106,566) (27,553)
Fuel, materials and supplies............................... 12,450 29,688 10,060
Accounts payable........................................... 171,148 8,709 (64,258)
Accrued taxes.............................................. (128,107) 107,929 4,739
Investments in securitizable assets........................ 9,474 74,498 48,787
Other working capital (excludes cash)...................... 254 157 17,424
---------- ---------- ----------
Net cash flows provided by operating activities................ 578,383 614,218 663,268
---------- ---------- ----------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant...................... (352,736) (287,081) (217,009)
Nuclear fuel............................................... (61,286) (42,471) (17,026)
---------- ---------- ----------
Net cash flows used for investments in plant................. (414,022) (329,552) (234,035)
Investments in nuclear decommissioning trusts................ (39,550) (74,231) (75,551)
Investment in competitive energy assets...................... - (23,542) -
Net proceeds from the sale of utility plant.................. - 565,436 -
Other investment activities, net............................. (28,478) 13,084 14,342
Payment for the purchase of Yankee, net of cash acquired..... (260,347) - -
---------- ---------- ----------
Net cash flows (used in)/provided by investing activities...... (742,397) 151,195 (295,244)
---------- ---------- ----------
Financing Activities:
Issuance of common shares.................................... 4,269 5,318 2,659
Issuance of long-term debt................................... 26,477 200 275
Net increase/(decrease) in short-term debt................... 961,977 248,000 (20,000)
Reacquisitions and retirements of long-term debt............. (685,555) (817,759) (269,555)
Reacquisitions and retirements of preferred stock............ (126,771) (46,250) (62,211)
Cash dividends on preferred stock............................ (14,162) (22,755) (26,440)
Cash dividends on common shares.............................. (57,358) (13,168) -
---------- ---------- ----------
Net cash flows provided by/(used in) financing activities...... 108,877 (646,414) (375,272)
---------- ---------- ----------
Net (decrease)/increase in cash and cash equivalents........... (55,137) 118,999 (7,248)
Cash and cash equivalents - beginning of period................ 255,154 136,155 143,403
---------- ---------- ----------
Cash and cash equivalents - end of period...................... $ 200,017 $ 255,154 $ 136,155
========== ========== ==========
Supplemental schedule of noncash investing and financing activities:
In conjuction with the Yankee acquisition on March 1, 2000, common stock was issued
and debt was assumed as follows:
Fair value of assets acquired, net of liabilites assumed $ 712,484
Cash paid (261,370)
NU common stock issued (217,114)
----------
$ 234,000
==========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized......................... $ 269,735 $ 266,823 $ 238,990
========== ========== ==========
Income taxes................................................. $ 253,383 $ 86,183 $ 19,454
========== ========== ==========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases.............. $ 8,067 $ 5,865 $ 12,583
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- ----------------------------------------------------------------------------------------------------------------
At December 31,
- ----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999
- ----------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity (a) $2,218,583 $2,083,311
Cumulative Preferred Stock of Subsidiaries:
$25 par value - authorized 36,600,000 shares at December 31, 2000 and 1999;
1,630,722 shares outstanding in 2000 and 2,720,000 shares outstanding in 1999
$50 par value - authorized 9,000,000 shares at December 31, 2000 and 1999;
2,324,000 shares outstanding in 2000 and 4,314,774 shares outstanding in 1999
$100 par value - authorized 1,000,000 shares at December 31, 2000 and 1999;
200,000 shares outstanding in 2000 and 1999
- ----------------------------------------------------------------------------------------------------------------
Current Current
Redemption Shares
Dividend Rates Prices (b) Outstanding
- ----------------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
$50 par value - $1.90 to $3.28 $50.50 to $54.00 2,234,000 116,200 116,200
$100 par value - $7.72 $103.51 200,000 20,000 20,000
--------- ---------
Total Preferred Stock Not Subject to Mandatory Redemption 136,200 136,200
--------- ---------
Subject to Mandatory Redemption: (c)
$25 par value - $1.90 to $2.65 $25.00 to $25.26 1,630,722 40,768 68,000
$50 par value - $2.65 to $3.615 - - - 99,539
--------- ---------
Total Preferred Stock Subject to Mandatory Redemption 40,768 167,539
Less: Preferred Stock to be Redeemed Within One Year 25,768 46,250
--------- ---------
Preferred Stock Subject to Mandatory Redemption, Net 15,000 121,289
--------- ---------
Long-Term Debt: (d)
First Mortgage Bonds -
Maturity Interest Rates
- ----------------------------------------------------------------------------------------------------------------
2000 5.75% to 6.875%................................... - 159,000
2001 7.375% to 7.875%.................................. 220,000 220,000
2002 7.75% to 9.05%.................................... 375,000 489,150
2005 6.75%............................................. 20,000 -
2009-2012 6.20% to 7.19%.................................... 80,000 -
2019-2024 7.375% to 10.07%.................................. 313,050 325,000
----------- ----------
Total First Mortgage Bonds......................................... 1,008,050 1,193,150
----------- ----------
Other Long-Term Debt -
Pollution Control Notes and Other Notes - (e)
2000 Adjustable Rate and 7.67%......................... - 206,011
2003-2006 6.24% to 8.58%.................................... 139,600 158,000
2013-2018 Adjustable Rate and 5.90%......................... 33,400 33,400
2020 Adjustable Rate................................... 15,300 15,300
2021-2022 Adjustable Rate and 5.85% to 7.65%................ 443,285 552,485
2028 5.85% to 5.95%.................................... 369,300 369,300
2031 Adjustable Rate................................... 62,000 62,000
---------- ----------
Total Pollution Control Notes and Other Notes...................... 1,062,885 1,396,496
Fees and interest due for spent nuclear fuel disposal costs............... 240,303 226,463
Other..................................................................... 38,978 15,346
---------- ----------
Total Other Long-Term Debt................................................ 1,342,166 1,638,305
---------- ----------
Unamortized premium and discount, net..................................... (6,350) (2,049)
---------- ----------
Total Long-Term Debt...................................................... 2,343,866 2,829,406
Less: Amounts due within one year........................................ 314,273 457,065
---------- ----------
Long-Term Debt, Net....................................................... 2,029,593 2,372,341
---------- ----------
Total Capitalization...................................................... $4,399,376 $4,713,141
========== ==========
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) On January 2, 2001, NU modified its forward share purchase arrangements
for approximately 10 million NU common shares. To initially effect these
arrangements, the financial institutions (counterparties) purchased
approximately 10 million NU common shares on the open market in December 1999
and January 2000, in a total aggregate amount of $215 million, at an average
price of $21.26. The counterparties maintain ownership of the shares until
the transactions are settled. NU will continue to accrue charges on the total
aggregate amount at LIBOR plus an agreed upon percentage per annum, until the
transactions are settled. These transactions can be settled in cash or NU
common shares at the company's discretion. NU expects to repurchase the shares
from the counterparties in the first half of 2001 with the proceeds from
restructuring. This amount has been classified as temporary equity from stock
forward on NU's consolidated balance sheets at December 31, 2000 and 1999.
(b) Each of these series is subject to certain refunding limitations for the
first five years after issuance. For preferred stock subject to mandatory
redemption, redemption prices reduce in future years.
(c) The minimum sinking fund requirements of the series subject each year
to mandatory redemption aggregate $25.8 million in 2001 and $1.5 million in
2002, 2003, 2004, and 2005. In case of default on sinking fund payments,
no payments may be made on any junior stock by way of dividends or
otherwise (other than in shares of junior stock) so long as the default
continues. If a subsidiary is in arrears in the payment of dividends on
any outstanding shares of preferred stock, the subsidiary is prohibited
from redeeming or purchasing less than all of the outstanding preferred
stock.
(d) Long-term debt maturities and cash sinking fund requirements, excluding
fees and interest due for spent nuclear fuel disposal costs, on debt
outstanding at December 31, 2000, for the years 2001 through 2005 are $314.3
million, $331.5 million, $26.6 million, $26.4 million, and $48.5 million,
respectively.
Essentially all utility plant of CL&P, PSNH, WMECO, and NAEC, is subject to the
liens of each company's respective first mortgage bond indenture. NAEC's first
mortgage bonds are also secured by payments made to NAEC by PSNH under the
terms of two life-of-unit, full cost recovery contracts.
CL&P and WMECO have secured $369.3 million of pollution control notes with
second mortgage liens on Millstone 1, junior to the liens of their respective
first mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with
bond insurance secured by the first mortgage bonds and a liquidity facility.
Concurrent with the issuance of PSNH's Series A and B first mortgage bonds,
PSNH entered into financing arrangements with the Business Finance Authority
(BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA
issued five series of PCRBs and loaned the proceeds to PSNH. At December 31,
2000 and 1999, $407.3 million and $516.5 million, respectively, of the PCRBs
were outstanding. PSNH's obligation to repay each series of PCRBs is secured
by the first mortgage bonds. Each such series of first mortgage bonds contains
similar terms and provisions as the applicable series of PCRBs. For financial
reporting purposes, these bonds would not be considered outstanding unless PSNH
failed to meet its obligations under the PCRBs.
(e) The average effective interest rates on the variable-rate pollution control
notes ranged from 3.2 percent to 6.8 percent for 2000 and 2.2 percent to 6.1
percent for 1999.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME TAXES
- ----------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
- ----------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------
The components of the federal and state income tax
provisions charged to operations are:
Current income taxes:
Federal...................................................... $ 154,790 $ 248,012 $ (13,660)
State........................................................ 23,052 33,955 (3,903)
--------- --------- ---------
Total current................................................... 177,842 281,967 (17,563)
--------- --------- ---------
Deferred income taxes, net:
Federal....................................................... 7,297 (134,773) 51,913
State......................................................... (5,529) (28,789) (12,948)
--------- --------- ---------
Total deferred.................................................. 1,768 (163,562) 38,965
--------- --------- ---------
Investment tax credits, net..................................... (17,885) (19,794) (15,463)
--------- --------- ---------
Total income tax expense........................................ $ 161,725 $ 98,611 $ 5,939
========= ========= =========
The components of total income tax expense are
classified as follows:
Income taxes charged to operating expenses.................. $ 230,031 $ 180,883 $ 82,332
Other income taxes.......................................... (68,306) (82,272) (76,393)
--------- --------- ---------
Total income tax expense........................................ $ 161,725 $ 98,611 $ 5,939
========= ========= =========
Deferred income taxes are comprised of the tax effects of
temporary differences as follows:
Deferred tax asset associated with net operating losses...... $ 1,563 $ 14,801 $ 69,212
Depreciation, leased nuclear fuel, settlement
credits and disposal costs.................................. 9,514 (4,580) 16,217
Regulatory deferral.......................................... (34,486) (27,297) (38,287)
Regulatory disallowance...................................... - (30,719) (18,080)
Sale of fossil and hydroelectric generation assets........... - (125,807) -
Pension...................................................... 25,751 8,936 10,950
Other........................................................ (574) 1,104 (1,047)
--------- --------- ---------
Deferred income taxes, net...................................... $ 1,768 $(163,562) $ 38,965
========= ========= =========
A reconciliation between income tax expense and the
expected tax expense at 35 percent of pretax income:
Expected federal income tax..................................... $ 133,413 $ 54,454 $ (40,031)
Tax effect of differences:
Depreciation................................................. 7,775 24,583 25,793
Amortization of regulatory assets............................ 11,942 45,825 30,740
Amortization of PSNH acquisition costs....................... 9,946 9,946 17,301
Investment tax credit amortization........................... (17,885) (19,794) (15,463)
State income taxes, net of federal benefit................... 11,390 3,358 (10,953)
Nondeductible penalties...................................... 38 17 3,589
Adjustment for prior years' taxes............................ - (2,796) (7,338)
Employee stock ownership plan................................ (999) 1,166 (1,670)
Dividends received deduction................................. (8,618) (1,314) (3,218)
Adjustment to tax asset valuation allowance.................. (2,136) (23,129) 7,000
Merger-related expenditures.................................. 5,829 4,597 -
Deferred intercompany gain................................... 5,038 786 630
Other, net................................................... 5,992 912 (441)
--------- --------- ---------
Total income tax expense $ 161,725 $ 98,611 $ 5,939
========= ========= =========
The accompanying notes are in integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ABOUT NORTHEAST UTILITIES
Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system (NU system). Through its regulated utilities and competitive
energy subsidiaries, the NU system serves in excess of 30 percent of New
England's electric needs and is one of the 25 largest electric utility systems
in the country as measured by revenues. The NU system's regulated utilities
furnish franchised retail electric service in Connecticut, New Hampshire and
western Massachusetts through three wholly owned subsidiaries: The Connecticut
Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH)
and Western Massachusetts Electric Company (WMECO). Another wholly owned
subsidiary, North Atlantic Energy Corporation (NAEC), sells all of its
entitlement to the capacity and output of the Seabrook Station nuclear unit
(Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery
contracts (Seabrook Power Contracts). A fifth wholly owned subsidiary, Holyoke
Water Power Company (HWP), also is engaged in the production and distribution
of electric power.
On March 1, 2000, NU completed its acquisition of Yankee Energy System, Inc.
(Yankee), the parent company of Yankee Gas Services Company (Yankee Gas),
Connecticut's largest natural gas distribution system.
NU is registered with the Securities and Exchange Commission (SEC) as a holding
company under the Public Utility Holding Company Act of 1935 (1935 Act), and
the NU system is subject to the provisions of the 1935 Act. Arrangements among
the NU system companies, outside agencies and other utilities covering inter-
connections, interchange of electric power and sales of utility property are
subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or
the SEC. The operating subsidiaries are subject to further regulation for
rates, accounting and other matters by the FERC and/or applicable state
regulatory commissions.
NU Enterprises, Inc. is a wholly owned subsidiary of NU and acts as the holding
company for certain of NU's competitive energy subsidiaries. Northeast
Generation Company (NGC) was formed to acquire and manage generation
facilities. Northeast Generation Services Company and its subsidiaries (NGS)
was formed to maintain and service any fossil or hydroelectric facility that is
acquired or contracted with for these services. HEC Inc. and its subsidiaries
(HEC), Mode 1 Communications, Inc. (Mode 1), Select Energy, Inc. (Select
Energy), and Select Energy Portland Pipeline, Inc. engage in a variety of
energy-related and telecommunications activities, as applicable, primarily in
the competitive energy retail and wholesale commodity, marketing and services
fields.
Several wholly owned subsidiaries of NU provide support services for the
NU system companies and, in some cases, for other New England utilities.
Northeast Utilities Service Company provides centralized accounting,
administrative, information resources, engineering, financial, legal,
operational, planning, purchasing, and other services to the NU system
companies. Northeast Nuclear Energy Company acts as agent for the NU system
companies and other New England utilities in operating the Millstone nuclear
units. North Atlantic Energy Service Corporation has operational
responsibility for Seabrook. Three other subsidiaries construct, acquire or
lease some of the property and facilities used by the NU system companies.
B. PRESENTATION
The consolidated financial statements of the NU system include the accounts of
all 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 years' data have been made to conform with
the current year's presentation.
C. NEW ACCOUNTING STANDARDS
Derivative Instruments: Effective January 1, 2001, NU adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. SFAS No. 133 requires that
derivative instruments be recorded as an asset or liability measured at its
fair value and that changes in the fair value of derivative instruments be
recognized currently in earnings unless specific hedge accounting criteria
are met.
In order to implement SFAS No. 133 by January 1, 2001, NU established a cross-
functional project team to identify all derivative instruments, measure the
fair value of those derivative instruments, designate and document various
hedge relationships, and evaluate the effectiveness of those hedge
relationships. NU has completed the process of identifying all derivative
instruments and has established appropriate fair value measurements of those
derivative instruments in place at January 1, 2001. In addition, for those
derivative instruments which are hedging an identified risk, NU has designated
and documented all hedging relationships anew.
NU believes that the majority of its nontrading energy and capacity contracts,
purchased-power agreements, power sale agreements, and gas and electric retail
contracts, qualify for the "normal purchases and sales" exception of the new
standard, and therefore are not required to be recognized at fair value.
However, NU believes that its electric, oil and gas swap contracts, interest
rate swap agreements, and gas and oil futures are derivatives and will be
recorded on its consolidated balance sheets at fair value on January 1, 2001.
NU believes that certain of these contracts meet specific hedge accounting
criteria; accordingly, changes in the fair value of these contracts will be
recorded in other comprehensive income on the consolidated balance sheets.
For those contracts that do not meet the hedging requirements, the changes in
fair value of those contracts will be recognized currently in earnings. As
explained within Note 8 commodity derivatives that are utilized for trading
purposes, are accounted for using the mark-to-market method, under Emerging
Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and
Risk Management Activities."
Management will record the effects of SFAS No. 133 in the first quarter of 2001
through a cumulative effect of a change in accounting principle and estimates
that the effect will be to reduce pretax earnings by approximately $37.4
million and increase shareholders' equity by $21.7 million. These estimates
do not include certain long-term energy and capacity contracts which management
believes represent "normal purchases and sales." The accounting for these
types of contracts is currently being evaluated by the Financial Accounting
Standards Board (FASB). Further guidance from the FASB may change management's
conclusions regarding these contracts and require them to be accounted for as
derivatives.
Transfers of Financial Assets: In September 2000, the FASB issued SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities - a Replacement of FASB Statement No. 125." SFAS No. 140
revises the criteria for accounting for securitizations, other financial asset
transfers and collateral and introduces new disclosures, but otherwise carries
forward most of the provisions of SFAS No. 125, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities," without
amendment. SFAS No. 140 is effective for transfers and servicing of financial
assets and extinguishments of liabilities occurring after March 31, 2001, and
is effective for recognition and reclassification of collateral and for
disclosures relating to securitization transactions and collateral for fiscal
years ending after December 15, 2000. The adoption of the disclosure
requirements under SFAS No. 140 did not have a material impact on NU's
consolidated financial statements.
Revenue Recognition: In December 1999, the SEC issued Staff Accounting
Bulletin (SAB) No. 101, "Revenue Recognition." The adoption of SAB No. 101,
as amended, did not have a material impact on NU's consolidated financial
statements.
Forward Share Purchase Arrangement: EITF Issue No. 00-19, "Accounting for
Derivative Financial Instruments Indexed to, and Potentially Settled in, a
Company's Own Stock," requires that all contracts be initially measured at fair
value and subsequently accounted for based on the current classification and
the assumed or required settlement method. As NU's forward share purchase
arrangements can be settled in cash or NU common shares at the company's
discretion, this amount was classified as temporary equity from stock forward
on the consolidated balance sheets at December 31, 2000 and 1999.
On January 2, 2001, these arrangements were modified. As a result of applying
the revised guidance under EITF Issue No. 00-19, the aforementioned forward
share purchase transactions no longer meet the temporary equity criteria and
will be classified as an asset or liability in the first quarter of 2001.
The difference between the fair value and contract value will be included in
earnings. NU expects to repurchase the shares from the counterparties in the
first half of 2001 with the proceeds from restructuring.
D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock
in four regional nuclear companies (Yankee Companies). The NU system's
ownership interests in the Yankee Companies at December 31, 2000 and 1999,
which are accounted for on the equity method due to the NU system companies'
ability to exercise significant influence over their operating and financial
policies are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC),
38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent of the
Maine Yankee Atomic Power Company (MYAPC), and 16 percent of the Vermont Yankee
Nuclear Power Corporation (VYNPC). The NU system's total equity investment in
the Yankee Companies at December 31, 2000 and 1999, is $62.5 million and $81.5
million, respectively. Each Yankee Company owns a single nuclear generating
unit. However, VYNPC is the only unit still in operation at December 31, 2000.
Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a
660 megawatt (MW) nuclear unit, which is currently in decommissioning status,
and Millstone 2, an 870 MW nuclear generating unit. CL&P, PSNH and WMECO
together have a 68.02 percent joint ownership interest in Millstone 3, a
1,154 MW nuclear generating unit. On August 7, 2000, CL&P, WMECO and certain
other joint owners reached an agreement to sell substantially all of the
Millstone units to Dominion Resources, Inc. (Dominion) for approximately $1.3
billion, including approximately $105 million for nuclear fuel. NU currently
expects to close on the sale of Millstone as early as the end of March 2001.
Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership interest
in Seabrook, a 1,148 MW nuclear generating unit. NAEC sells all of its share
of the power generated by Seabrook to PSNH under the Seabrook Power Contracts.
CL&P and NAEC expect to auction their joint ownership interests in Seabrook in
2001 with a closing on the sale expected in 2002.
Plant-in-service and the accumulated provision for depreciation for the NU
system's share of Millstone 2 and 3 and Seabrook are as follows:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
(Millions of Dollars) 2000 1999
- -------------------------------------------------------------------------------
Plant-in-service
Millstone 2 $ 962.0 $ 952.1
Millstone 3 2,427.2 2,414.9
Seabrook 909.3 901.9
Accumulated provision for depreciation
Millstone 2 $ 953.6 $ 910.0
Millstone 3 2,214.3 2,220.5
Seabrook 821.3 318.8
- -------------------------------------------------------------------------------
Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling $15
million and $16.5 million at December 31, 2000 and 1999, respectively, in two
companies that transmit electricity imported from the Hydro-Quebec system in
Canada.
E. DEPRECIATION
The provision for depreciation is calculated using the straight-line method
based on the estimated remaining useful lives of depreciable utility plant-
in-service, adjusted for salvage value and removal costs, as approved by the
appropriate regulatory agency where applicable. Except for major facilities,
depreciation rates are applied to the average plant-in-service during the
period. Major facilities are depreciated from the time they are placed in
service. When plant is retired from service, the original cost of the plant,
including costs of removal less salvage, is charged to the accumulated
provision for depreciation. The costs of closure and removal of nonnuclear
facilities are accrued over the life of the plant as a component of
depreciation. The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.1 percent in 2000
and 3.3 percent in 1999 and 1998.
As a result of discontinuing the application of SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation
businesses in 1999, including CL&P's ownership interest in Seabrook, NU
recorded a charge to accumulated depreciation for the nuclear plant in excess
of the estimated fair market value at the time in the amount of $2 billion and
a corresponding regulatory asset was created. Also, in 2000, HWP discontinued
SFAS No. 71 and recorded a charge to accumulated depreciation for the plant in
excess of fair value for certain hydroelectric generation assets, which was
recorded as an extraordinary loss.
F. REVENUES
Regulated utility revenues are based on authorized rates applied to each
customer's use of electricity. In general, rates can be changed only through
a formal proceeding before the appropriate regulatory commission. Regulatory
commissions also have authority over the terms and conditions of nontraditional
rate-making arrangements. At the end of each accounting period, CL&P, PSNH,
WMECO, Select Energy, and Yankee Gas accrue a revenue estimate for the amount
of energy delivered but unbilled.
Revenues for NU's competitive energy subsidiaries, primarily Select Energy, are
recognized when the energy is delivered.
G. PSNH ACQUISITION COSTS
PSNH acquisition costs represent the aggregate value placed by the 1989 rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in
excess of the net book value of PSNH's non-Seabrook assets, plus the
$700 million value assigned to Seabrook by the Rate Agreement as part of the
bankruptcy resolution on June 5, 1992. The Rate Agreement provided for the
recovery through rates, with a return, of the PSNH acquisition costs. In
connection with the "Agreement to Settle PSNH Restructuring" (Settlement
Agreement) approximately $219.4 million was written off and the balance of
$76.6 million has been reclassified as a regulatory asset.
H. REGULATORY ACCOUNTING AND ASSETS
The accounting policies of the NU system operating companies and the
accompanying consolidated financial statements conform to accounting
principles generally accepted in the United States applicable to rate-regulated
enterprises and historically reflect the effects of the rate-making process in
accordance with SFAS No. 71. As a result of final restructuring orders issued
in 1999, CL&P and WMECO discontinued the application of SFAS No. 71 for the
generation portion of their businesses. During the fourth quarter of 2000,
the Settlement Agreement became probable of implementation, therefore, PSNH
discontinued the application of SFAS No. 71 for the generation portion of its
business.
CL&P's, WMECO's and PSNH's transmission and distribution business will continue
to be cost-based and management believes the application of SFAS No. 71
continues to be appropriate. Management continues to believe it is probable
that the NU system operating companies will recover their investments in long-
lived assets, including regulatory assets through charges to their transmission
and distribution customers generally over periods of 7 to 26 years, subject to
certain adjustments. The majority for CL&P and WMECO will be recovered through
a transition charge over a 12-year period. PSNH will recover securitized
assets over a 12-year period. Nuclear decommissioning and IPP costs will be
recovered over the period PSNH is responsible for those costs. The third type
of PSNH stranded costs are nonsecuritized regulatory assets (type three
regulatory assets). Any type three regulatory assets not collected by the
recovery end date will be written off. Based on current projections, PSNH
expects to fully recovery all of its type three regulatory assets by the
recovery end date stipulated in the Settlement Agreement. In addition, all
material regulatory assets are earning a return. The components of the NU
system companies' regulatory assets are as follows:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
(Millions of Dollars) 2000 1999
- -------------------------------------------------------------------------------
Recoverable nuclear costs $2,565.8 $2,210.8
Income taxes, net 504.7 636.6
Unrecovered contractual obligations 255.8 349.2
Recoverable energy costs, net 332.5 228.2
Other 252.0 217.6
- -------------------------------------------------------------------------------
Totals $3,910.8 $3,642.4
- -------------------------------------------------------------------------------
As a result of discontinuing the application of SFAS No. 71 in 1999 for CL&P's
and WMECO's generation businesses, CL&P and WMECO reclassified nuclear plant
in excess of its estimated fair market value from plant to regulatory assets.
As of December 31, 2000 and 1999, both the CL&P unamortized balance ($1.35
billion and $1.38 billion, respectively) and the WMECO unamortized balance
($286.9 million and $316.1 million, respectively) are classified as recoverable
nuclear costs. Also included in that regulatory asset component for 2000 and
1999 are $449.2 million and $514.7 million, respectively, which includes
Millstone 1 recoverable nuclear costs relating to the recoverable portion of
the undepreciated plant and related assets ($90.8 million and $145.7 million,
respectively) and the decommissioning and closure obligation ($358.4 million
and $369 million, respectively).
As a result of discontinuing the application of SFAS No. 71 in 2000 for PSNH's
generation business, PSNH recorded an after-tax charge of $214.2 million in the
fourth quarter of 2000. In addition, a regulatory asset was created for the
Seabrook over market generation in the amount of $484.7 million, which is
classified as recoverable nuclear costs. It is anticipated this regulatory
asset will be securitized.
I. INCOME TAXES
The tax effect of temporary differences (differences between the periods in
which transactions affect income in the financial statements and the periods
in which they affect the determination of taxable income) is accounted for
in accordance with the rate-making treatment of the applicable regulatory
commissions.
The tax effect of temporary differences, including timing differences accrued
under previously approved accounting standards, that give rise to the
accumulated deferred tax obligation is as follows:
- -------------------------------------------------------------------------------
(Millions of Dollars) 2000 1999
- -------------------------------------------------------------------------------
Accelerated depreciation and other
plant-related differences $1,364.9 $1,388.0
Regulatory assets - income tax
gross-up 189.1 241.2
Other 31.5 58.9
- -------------------------------------------------------------------------------
Totals $1,585.5 $1,688.1
- -------------------------------------------------------------------------------
J. UNRECOVERED CONTRACTUAL OBLIGATIONS
Under the terms of contracts with the Yankee Companies, the shareholder-
sponsored companies are responsible for their proportionate share of the
remaining costs of the units, including decommissioning. As management
expects that the NU system companies will be allowed to recover these costs
from their customers, the NU system companies have recorded regulatory assets,
with corresponding obligations, on their respective balance sheets.
K. RECOVERABLE ENERGY COSTS
Energy Policy Act of 1992: Under the Energy Policy Act of 1992 (Energy Act),
CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of
the costs of decontaminating and decommissioning uranium enrichment plants
owned by the United States Department of Energy (DOE) (D&D Assessment). The
Energy Act requires that regulators treat D&D Assessments as a reasonable and
necessary current cost of fuel, to be fully recovered in rates like any other
fuel cost. CL&P, PSNH, WMECO, and NAEC are currently recovering these costs
through rates. As of December 31, 2000 and 1999, the NU system's total D&D
Assessment deferrals were $34.5 million and $38.4 million, respectively.
CL&P: Through December 31, 1999, CL&P had an energy adjustment clause under
which fuel prices above or below base-rate levels were charged to or credited
to customers. Coincident with the start of restructuring, the energy
adjustment clause was terminated. Energy costs deferred and not yet collected
under the energy adjustment clause amounted to $61.1 million and $62.6 million
at December 31, 2000 and 1999, respectively. This balance is recorded as a
generation-related stranded cost and will be recovered through a transition
charge mechanism pending final Connecticut Department of Public Utility Control
(DPUC) approval.
PSNH: The Rate Agreement includes a fuel and purchased-power adjustment clause
(FPPAC) permitting PSNH to pass through to retail customers, for a 10-year
period that began in May 1991, the retail portion of differences between the
fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual
costs, which include the costs related to the Seabrook Power Contracts and the
Clean Air Act Amendment. The cost components of the FPPAC are subject to a
prudence review by the New Hampshire Public Utilities Commission (NHPUC). At
December 31, 2000 and 1999, PSNH had $230.1 million and $120.5 million,
respectively, of recoverable energy costs deferred under the FPPAC. Under the
Settlement Agreement, the FPPAC will be recovered as a type three regulatory
asset through a transition charge.
L. CASH AND CASH EQUIVALENTS
Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.
2. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by NU and the
NU system operating companies is subject to periodic approval by either the SEC
under the 1935 Act or by the respective state regulators. Currently, SEC
authorization allows NU, CL&P, WMECO, and Yankee Gas to incur total short-term
borrowings up to a maximum of $400 million, $375 million, $250 million, and
$100 million, respectively. In addition, the charters of CL&P and WMECO
contain preferred stock provisions restricting the amount of unsecured debt
those companies may incur. As of December 31, 2000, CL&P's and WMECO's
charters permit CL&P and WMECO to incur $245 million and $94 million,
respectively, of additional unsecured debt. PSNH and NAEC are authorized by
the NHPUC to incur short-term borrowings up to a maximum of $71.3 million and
$260 million, respectively.
Credit Agreements:
NGC: In March 2000, CL&P and WMECO transferred 1,289 MW of hydroelectric
generation assets in Connecticut and Massachusetts to NGC, an affiliated
company, for approximately $865.5 million. To finance the transfer, on
March 9, 2000, NGC entered into a new short-term credit agreement with a total
commitment amount of $865.5 million, collateralized by the generation assets
transferred. Under the short-term credit agreement, $435.5 million of the
commitment matured on March 14, 2000, and was repaid. This credit agreement,
with an original maturity date of December 29, 2000, was extended for a
minimum of six months. NGC expects to replace the short-term credit agreement
with up to $440 million of permanent financing in the first half of 2001.
At December 31, 2000, there were $402.4 million in borrowings under the
credit agreement.
Yankee Merger: To finance the cash portion of the Yankee merger, on March 1,
2000, NU entered into an unsecured term loan agreement for $266 million.
The term loan agreement will expire on February 28, 2001. NU expects to
replace this financing with permanent, long-term financing prior to its
maturity date. At December 31, 2000, there were $263 million in borrowings
under the term loan agreement.
CL&P and WMECO: On November 17, 2000, CL&P and WMECO entered into a 364-day
revolving credit facility for $350 million, replacing the previous $500 million
facility which was to expire on November 17, 2000. CL&P and WMECO may draw up
to $200 million and $150 million, respectively, under the facility which, until
the nuclear divestiture, is secured by second mortgages on Millstone 2 and 3.
Once CL&P and WMECO receive the proceeds from securitization, the $350 million
revolving credit facility will be reduced to $250 million, with a $150 million
limit for CL&P and a $100 million limit for WMECO. Unless extended, the credit
facility will expire on November 16, 2001. At December 31, 2000 and 1999,
there were $225 million and $213 million, respectively, in borrowings under
these facilities.
NAEC: On November 9, 2000, NAEC entered into an unsecured 364-day term credit
agreement for $200 million, replacing a $225 million term loan which was to
expire on November 9, 2000. The proceeds from the term credit agreement were
used to repay the $200 million outstanding under the previous term loan.
Additionally, the interest rate swaps and collar related to the previous term
loan expired and were not replaced. The term credit agreement also contains
two mandatory prepayment provisions; the first is a 50 percent mandatory
principal repayment of amounts outstanding to $100 million within two days of
the buydown of the Seabrook Power Contracts and the second is 100 percent
prepayment within two days of the sale of Seabrook. Any amounts prepaid can
not be reborrowed. Unless extended, the term credit agreement will expire on
November 8, 2001. At December 31, 2000 and 1999, there were $200 million in
borrowings under the credit agreement and previous term loan.
NU Parent: To continue to support the working capital needs of NU and its
competitive energy subsidiaries, NU replaced its $350 million 364-day unsecured
revolving credit facility which was to expire on November 17, 2000, with a
364-day unsecured revolving credit facility on November 17, 2000. This
facility provides a total commitment of $400 million which is available subject
to two overlapping sub-limits. First, subject to the notional amount of any
letters of credit outstanding, amounts up to $300 million are available for
advances. Second, subject to the advances outstanding, letters of credit may
be issued in notional amounts up to $200 million. Unless extended, this credit
facility will expire on November 16, 2001. At December 31, 2000 and 1999,
there were $173 million and $65 million, respectively, in borrowings under the
new and previous facilities. With regard to credit support, NU had $40 million
and $29 million, respectively, in letters of credit issued under the new and
previous agreements at December 31, 2000 and 1999.
Yankee Gas: Yankee Gas has arranged a $60 million unsecured revolving credit
facility. On November 17, 2000, the expiration date of this facility was
extended to November 16, 2001. At December 31, 2000, there were $46.6 million
in borrowings under this credit facility.
NU provides credit assurance in the form of guarantees, letters of credit and
other assurances for the financial performance obligations of certain of its
competitive energy subsidiaries. NU currently has authorization from the SEC
to provide up to $500 million of such assurances. As of December 31, 2000 and
1999, NU had provided approximately $284 million and $190 million,
respectively, of such credit assurances.
Under the aforementioned credit agreements, the respective borrowers may borrow
at fixed or variable rates plus an applicable margin based upon certain debt
ratings, as rated by the lower of Standard and Poor's or Moody's Investors
Service. The weighted average interest rate on the NU system companies' notes
payable to banks outstanding on December 31, 2000 and 1999, was 8.85 percent
and 7.93 percent, respectively. Maturities of short-term debt obligations were
for periods of three months or less.
These credit agreements provide that the parties to these agreements must
comply with certain financial and nonfinancial covenants as are customarily
included in such agreements, including, but not limited to, common equity
ratios, interest coverage ratios, cash flow ratios, and dividend payment
restrictions. The parties to the credit agreements currently are and expect
to remain in compliance with these covenants.
3. LEASES
CL&P and WMECO finance their nuclear fuel for Millstone 2 and their respective
shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust
(NBFT) capital lease agreement. This capital lease agreement has an expiration
date of June 1, 2040. At December 31, 2000 and 1999, the present value of the
capital lease obligation to the NBFT was $139.2 million and $157 million,
respectively. In connection with the planned nuclear divestiture the NBFT
capital lease agreement will be terminated, the nuclear fuel will be
transferred to Dominion and the related $180 million Series G Intermediate Term
Note Agreement will be extinguished with the divestiture proceeds.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors based on a units-of-production method at rates which
reflect estimated kilowatt-hours of energy provided plus financing costs
associated with the fuel in the reactors. Upon permanent discharge from the
reactors, ownership of the nuclear fuel transfers to CL&P and WMECO.
The NU system companies also have entered into lease agreements, some of which
are capital leases, for the use of data processing and office equipment,
vehicles, nuclear control room simulators, and office space. The provisions
of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $50.1 million
in 2000, $20.8 million in 1999 and $31 million in 1998. Interest included in
capital lease rental payments was $11.6 million in 2000, $13.7 million in 1999
and $18.3 million in 1998. Operating lease rental payments charged to expense
were $10.1 million in 2000, $7.5 million in 1999 and $15.7 million in 1998.
Future minimum rental payments, excluding annual nuclear fuel lease payments
and executory costs, such as property taxes, state use taxes, insurance, and
maintenance, under long-term noncancelable leases, as of December 31, 2000
are as follows:
- ------------------------------------------------------------------------------
(Millions of Dollars)
- ------------------------------------------------------------------------------
Year Capital Leases Operating Leases
- ------------------------------------------------------------------------------
2001 $ 4.9 $ 25.0
2002 3.2 20.0
2003 3.2 15.0
2004 3.0 11.5
2005 2.8 9.4
After 2005 27.7 23.2
- ------------------------------------------------------------------------------
Future minimum lease payments 44.8
Less amount representing interest 24.1 104.1
- ------------------------------------------------------------------------------
Present value of future minimum
lease payments for other than
nuclear fuel 20.7
Present value of future nuclear
fuel lease payments 139.2
- ------------------------------------------------------------------------------
Present value of future minimum
lease payments $159.9
- ------------------------------------------------------------------------------
4. EMPLOYEE BENEFITS
A. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The NU system companies, participate in a uniform noncontributory defined
benefit retirement plan covering substantially all regular NU system employees.
Benefits are based on years of service and the employees' highest eligible
compensation during 60 consecutive months of employment. The total pension
credit, part of which was credited to utility plant, was $97.9 million in
2000, $33.7 million in 1999 and $44.1 million in 1998.
Currently, the NU system companies' policy is to annually fund an amount at
least equal to that which will satisfy the requirements of the Employee
Retirement Income Security Act and Internal Revenue Code.
The NU system companies also provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees. These benefits are available for employees retiring from
the NU system who have met specified service requirements. For current
employees and certain retirees, the total benefit is limited to two times
the 1993 per retiree health care cost. These costs are charged to expense
over the estimated work life of the employee. The NU system companies annually
fund postretirement costs through external trusts with amounts that have been
rate-recovered and which also are tax deductible.
Pension and trust assets are invested primarily in domestic and international
equity securities and bonds.
In December 2000, NU announced the details of a voluntary separation program
designed to reduce NU's generation-related support staff in 2001. NU will
reflect the program's costs in first quarter 2001 results.
The following table represents information on the plans' benefit obligation,
fair value of plan assets, and the respective plans' funded status:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------
(Millions of Dollars) 2000 1999 2000 1999
- -------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation
at beginning of year......... $(1,516.6) $(1,479.2) $(306.8) $(305.2)
Yankee merger.................. (66.7) - (26.9) -
Service cost................... (41.2) (43.7) (7.6) (7.6)
Interest cost.................. (118.5) (106.3) (25.5) (21.8)
Employee contribution.......... - - (0.1) -
Plan amendment................. - (79.6) - -
Actuarial (loss)/gain.......... (39.4) 133.8 (13.6) (1.3)
Benefits paid.................. 109.5 78.3 27.5 28.9
Settlements and other.......... 2.0 (19.9) 0.7 0.2
- -------------------------------------------------------------------------------
Benefit obligation
at end of year............... $(1,670.9) $(1,516.6) $(352.3) $(306.8)
- -------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets
at beginning of year......... $ 2,330.2 $ 2,098.0 $ 170.7 $ 151.2
Yankee merger.................. 107.5 - 16.1 -
Actual return on plan assets... (8.8) 310.5 8.6 18.7
Employer contribution.......... - - 29.6 29.7
Employee contribution.......... - - 0.1 -
Benefits paid.................. (109.5) (78.3) (27.5) (28.9)
- -------------------------------------------------------------------------------
Fair value of plan assets
at end of year............... $ 2,319.4 $ 2,330.2 $ 197.6 $ 170.7
- -------------------------------------------------------------------------------
Funded status at December 31... $ 648.5 $ 813.6 $(154.7) $(136.1)
Unrecognized transition
(asset)/obligation........... (5.8) (7.4) 180.9 196.6
Unrecognized prior
service cost................. 90.9 99.2 - -
Unrecognized net gain.......... (594.1) (904.7) (35.5) (60.4)
- -------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost. $ 139.5 $ 0.7 $ (9.3) $ 0.1
- -------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plans' year
end funded status:
- -------------------------------------------------------------------------------
At December 31,
- -------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------
2000 1999 2000 1999
- -------------------------------------------------------------------------------
Discount rate..................... 7.50% 7.75% 7.50% 7.75%
Compensation/progression rate..... 4.50 4.75 4.50 4.75
Health care cost trend rate (a)... N/A N/A 5.26 5.57
- -------------------------------------------------------------------------------
(a) The annual per capita cost of covered health care benefits was assumed to
decrease to 4.91 percent by 2001.
The components of net periodic benefit (credit)/cost are:
- -------------------------------------------------------------------------------
For the Years Ended December 31,
- -------------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
- -------------------------------------------------------------------------------
(Millions of Dollars) 2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------
Service cost......... $ 41.2 $ 43.7 $ 37.4 $ 7.6 $ 7.6 $ 6.6
Interest cost........ 118.5 106.3 96.8 25.5 21.8 20.9
Expected return
on plan assets..... (205.1) (175.5) (153.2) (15.3) (11.7) (9.9)
Amortization of
unrecognized net
transition (asset)/
obligation......... (1.4) (1.5) (1.5) 15.1 15.1 15.1
Amortization of prior
service cost....... 7.9 7.9 2.1 - - -
Amortization of
actuarial gain..... (52.4) (33.5) (25.7) - - -
Other amortization,
net................ - - - (4.3) (3.1) (3.8)
Settlements and
other.............. (6.6) 18.9 - - - -
- -------------------------------------------------------------------------------
Net periodic benefit
(credit)/cost....... $(97.9) $(33.7) $(44.1) $28.6 $29.7 $28.9
- -------------------------------------------------------------------------------
For calculating pension and postretirement benefit costs, the following
assumptions were used:
- -------------------------------------------------------------------------------
For the Years Ended December 31,
- -------------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
- -------------------------------------------------------------------------------
2000 1999 1998 2000 1999 1998
- -------------------------------------------------------------------------------
Discount rate........ 7.75% 7.00% 7.25% 7.75% 7.00% 7.25%
Expected long-term
rate of return..... 9.50 9.50 9.50 N/A N/A N/A
Compensation/
progression rate.... 4.75 4.25 4.25 4.75 4.25 4.25
Long-term rate
of return -
Health assets,
net of tax....... N/A N/A N/A 7.50 7.50 7.75
Life assets........ N/A N/A N/A 9.50 9.50 9.50
- -------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plans. The effect of changing the assumed health
care cost trend rate by one percentage point in each year would have the
following effects:
- -------------------------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
- -------------------------------------------------------------------------------
Effect on total service and
interest cost components $ 1.6 $ (1.6)
Effect on postretirement
benefit obligation $17.9 $(16.6)
- -------------------------------------------------------------------------------
The trust holding the health plan assets is subject to federal income taxes.
B. 401(k) SAVINGS PLAN
NU maintains a 401(k) Savings Plan for substantially all NU system employees.
This savings plan provides for employee contributions up to specified limits.
NU matches employee contributions up to a maximum of 3 percent of eligible
compensation with cash and NU stock. The matching contributions made by NU
were $13.6 million in 2000, $13.8 million in 1999 and $13.2 million in 1998.
C. ESOP
NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating
shares to employees participating in the NU system's 401(k) Savings Plan.
Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling
$250 million, the proceeds of which were lent to the ESOP trust for the
purchase of 10.8 million newly issued NU common shares (ESOP Shares). The
ESOP trust is obligated to make principal and interest payments on the ESOP
notes at the same rate that ESOP Shares are allocated to employees. NU makes
annual contributions to the ESOP equal to the ESOP's debt service, less
dividends received by the ESOP. All dividends received by the ESOP on
unallocated shares are used to pay debt service and are not considered
dividends for financial reporting purposes. During the fourth quarter of
1999 through December 31, 2000, NU paid a 10 cent per share quarterly dividend.
In 2000 and 1999, the ESOP trust issued 572,863 and 556,978 of NU common
shares, respectively, to satisfy 401(k) Savings Plan obligations to employees.
As of December 31, 2000 and 1999, the total allocated ESOP shares were
5,854,699 and 5,281,836, respectively, and total unallocated ESOP shares were
4,945,486 and 5,518,349, respectively. The fair market value of unallocated
ESOP shares as of December 31, 2000 and 1999, was $119.9 million and $113.5
million, respectively.
D. STOCK-BASED COMPENSATION
Employee Stock Purchase Plan (ESPP): Since July 1998, the NU system maintained
an ESPP for all eligible employees. Under the ESPP, shares of NU common stock
were purchased at 6-month intervals at 85 percent of the lower of the price on
the first or last day of each 6-month period. Employees purchased shares
having a value not exceeding 25 percent of their compensation at the beginning
of the purchase period. During 2000 and 1999, employees purchased 199,520 and
253,853 shares, respectively, at discounted prices ranging from $17.48 to
$18.49 in 2000, and $13.76 to $14.93 per share in 1999. At December 31, 2000
and 1999, 1,417,156 and 1,616,676 shares remained reserved for future issuance
under the ESPP, respectively. Effective January 1, 2001, the ESPP was
terminated.
Incentive Plans: The NU system has long-term incentive plans authorizing
various types of share-based awards, including stock options, to be made to
eligible employees and board members. The exercise price of stock options, as
set at the time of grant, is generally equal to the fair market value per
share at the date of grant. Under the Northeast Utilities Incentive Plan
(Incentive Plan), the number of shares which may be utilized for awards granted
during a given calendar year may not exceed one percent of the total number of
shares of NU common stock outstanding as of the first day of that calendar
year.
Stock option transactions for 1998, 1999 and 2000, including those options
acquired in connection with the Yankee merger, are as follows:
- -------------------------------------------------------------------------------
Exercise Price Per Share
------------------------
Options Range Weighted
------- ----- Average
- -------------------------------------------------------------------------------
Outstanding December 31, 1997 500,000 $ 9.6250 $ 9.6250
Granted 741,273 $14.8750 - $16.8125 $16.1780
Forfeited (7,595) $16.3125 $16.3125
- -------------------------------------------------------------------------------
Outstanding December 31, 1998 1,233,678 $ 9.6250 - $16.8125 $13.5213
Granted 644,123 $14.9375 - $21.1250 $15.2514
Exercised (19,368) $16.3125 - $16.8125 $16.3986
Forfeited (32,177) $14.9375 - $16.3125 $15.8714
- -------------------------------------------------------------------------------
Outstanding December 31, 1999 1,826,256 $ 9.6250 - $21.1250 $14.0585
Granted 669,470 $18.4375 - $22.2500 $18.7029
Yankee merger 10,167 $ 9.3640 - $12.6888 $10.7653
Exercised (43,750) $14.9375 - $19.5000 $16.0658
Forfeited (28,281) $14.9375 - $19.5000 $16.6515
- -------------------------------------------------------------------------------
Outstanding December 31, 2000 2,433,862 $ 9.3640 - $22.2500 $15.2569
- -------------------------------------------------------------------------------
Exercisable December 31, 1998 232,936 $14.8750 - $16.8125 $16.2972
Exercisable December 31, 1999 711,787 $ 9.6250 - $21.1250 $14.0102
Exercisable December 31, 2000 1,298,339 $ 9.3640 - $22.2500 $14.2021
- -------------------------------------------------------------------------------
The vesting schedule for the options granted in 1998 is one-third upon grant,
two-thirds after one year and the total award after two years. For the options
that were granted in 1999 and for certain options that were granted in 2000,
the vesting schedule for these options is ratably over three years from the
date of grant. Other options granted in 2000 vest 50 percent at the date of
grant and 50 percent one year from the date of grant.
Also under the Incentive Plan, the NU system awarded 91,120 of restricted
shares in 1999. These shares have the same vesting schedule as the options
granted under the Incentive Plan. The NU system has also made several small
grants of restricted stock and other incentive-based stock compensation.
During 2000, 1999 and 1998, $1.9 million, $2.2 million and $0.8 million,
respectively, was expensed for stock-based compensation.
Had compensation cost been determined for the ESPP and the incentive plan stock
options under the fair value method as opposed to the intrinsic value method
followed by the NU system, net (loss)/income and net (loss)/income per share
would have been as follows:
- -------------------------------------------------------------------------------
(Millions of Dollars,
except per share amounts) 2000 1999 1998
- -------------------------------------------------------------------------------
Net (loss)/income $(33.9) $29.6 $(149.1)
Basic (loss)/income per common share $(0.24) $0.23 $ (1.14)
Diluted (loss)/income per common share $(0.24) $0.22 $ (1.14)
- -------------------------------------------------------------------------------
The fair value of each stock option grant has been estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions:
- -------------------------------------------------------------------------------
2000 1999 1998
- -------------------------------------------------------------------------------
Risk-free interest rate 6.56% 5.69% 5.82%
Expected life 10 years 10 years 10 years
Expected volatility 26.15% 36.21% 35.05%
Expected dividend yield 1.82% 1.89% 5.46%
- -------------------------------------------------------------------------------
The weighted average grant date fair values of options granted during 2000,
1999 and 1998 were $7.50, $6.79 and $3.98, respectively. As of December 31,
2000 and 1999, the weighted average remaining contractual lives for those
options outstanding are 7.92 years and 8.47 years, respectively.
5. SALE OF CUSTOMER RECEIVABLES
As of December 31, 2000 and 1999, CL&P had sold accounts receivable of $170
million to a third-party purchaser with limited recourse through the CL&P
Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. In addition,
at December 31, 2000 and 1999, $18.9 million and $22.5 million, respectively,
of accounts receivable were designated as collateral under the agreement with
the CRC.
Concentrations of credit risk to the purchaser under the company's agreement
with respect to the receivables are limited due to CL&P's diverse customer base
within its service territory.
6. COMMITMENTS AND CONTINGENCIES
A. RESTRUCTURING
Connecticut: The 1999 restructuring orders allowed for securitization of
CL&P's nonnuclear regulatory assets and the costs to buyout or buydown the
various purchased-power contracts. On November 8, 2000, the DPUC approved
CL&P's request to securitize an amount not to exceed $1.55 billion of approved,
eligible stranded costs, primarily related to above-market purchased-power
contracts and generation related regulatory assets. However, the Office of
Consumer Counsel (OCC) appealed the securitization order to the Connecticut
Superior Court and it remains unclear when securitization financing can be
undertaken.
New Hampshire: In September 2000, the NHPUC approved a comprehensive
restructuring order that would allow PSNH to securitize up to $670 million of
stranded costs. In January 2001, the New Hampshire Supreme Court upheld this
restructuring order on appeal. However, one of the appellants indicated
publicly it would request a review of the New Hampshire Supreme Court decision
by the United States Supreme Court. Such a request must be filed by May 1,
2001. Management believes that such an appeal would have a low probability of
success, but cannot determine what effect it might have on the timing of the
issuance of securitization bonds and the implementation of customer choice in
New Hampshire. PSNH currently expects to work with the State of New Hampshire
to issue securitization bonds early in the second quarter of 2001.
In October 2000, NU reached an agreement with an unaffiliated joint owner, who
owns approximately 15 percent of Seabrook, to auction its share of the plant
with NU's share. As part of the agreement, if the unaffiliated joint owner's
share of Seabrook sells for less than $87.2 million, NU will provide up to
$17.4 million to compensate for any shortfall. NU also will share in the
benefits if that share of Seabrook exceeds $87.2 million. Additionally, under
the agreement, NU will top-off certain decommissioning obligations above a
defined level.
Massachusetts: A settlement has been reached with the Massachusetts Attorney
General finalizing a $155 million securitization plan. WMECO expects to
receive approval of its securitization plan in February 2001.
B. NUCLEAR GENERATION ASSETS DIVESTITURE
On August 7, 2000, CL&P, WMECO and certain other joint owners reached an
agreement to sell substantially all of the Millstone units, located in
Waterford, Connecticut, to Dominion, for approximately $1.3 billion, including
approximately $105 million for nuclear fuel. Dominion has also agreed to
assume responsibility for decommissioning the three units and NU will transfer
to Dominion all funds in the Millstone decommissioning trust. Additionally,
NU is obligated to top-off the decommissioning trust if its value does not
equal a previously agreed upon level as defined. NU expects to close on the
sale of Millstone as early as the end of March 2001.
If the transaction is consummated as proposed, CL&P and WMECO would receive
gross proceeds of approximately $843.2 million and $196.2 million on a pretax
basis for their respective ownership interests. The proceeds from the sale of
these interests will be used to reduce the companies' stranded costs under
restructuring and the cash proceeds will be used to repay subsidiary debt and
capital lease obligations and to return equity capital to the parent company.
The DPUC approved the recovery of Millstone-related stranded costs not offset
by asset divestiture proceeds. Pursuant to the DPUC order, CL&P will seek
recovery of Millstone post-1997 capital additions totaling $50 million. The
OCC has appealed CL&P's ability to recover these costs. PSNH will receive
$26 million on a pretax basis, which will be reflected as a gain in accordance
with the Settlement Agreement.
In connection with the prior settlement of Millstone 3 joint owner claims, if
the aforementioned transaction is consummated as proposed, the NU system will
record a pretax gain in excess of $150 million. These settlements included
clauses which allowed NU to retain sale proceeds for the joint owners interests
in the units in excess of certain agreed upon amounts.
By the end of 2002, PSNH expects to complete the sale of its fossil and
hydroelectric generation assets, as well as NAEC's ownership share of Seabrook.
CL&P intends to sell its interest in Seabrook, when NAEC sells theirs.
C. ENVIRONMENTAL MATTERS
The NU system is subject to environmental laws and regulations intended to
mitigate or remove the effect of past operations and improve or maintain the
quality of our environment. As such, the NU system has an active environmental
auditing and training program and believes it is substantially in compliance
with the current laws and regulations.
However, the normal course of operations may involve activities and substances
that expose the NU system to potential liabilities of which management cannot
determine the outcome. Additionally, management cannot determine the outcome
for liabilities that may be imposed for past acts, even though such past acts
may have been lawful at the time they occurred. Management does not believe,
however, that this will have a material impact on the NU system's financial
statements.
Based upon currently available information for the estimated remediation costs
as of December 31, 2000 and 1999, including Yankee in 2000, the liability
recorded by the NU system for its estimated environmental remediation costs
amounted to $58.2 million and $24.8 million, respectively.
D. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must
pay the DOE for the disposal of spent nuclear fuel and high-level radioactive
waste. The DOE is responsible for the selection and development of
repositories for, and the disposal of, spent nuclear fuel and high-level
radioactive waste. For nuclear fuel used to generate electricity prior to
April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full
liability and payment must be made prior to the first delivery of spent fuel
to the DOE. Until such payment is made, the outstanding balance will continue
to accrue interest at the 3-month treasury bill yield rate. As of December 31,
2000 and 1999, fees due to the DOE for the disposal of Prior Period Fuel were
$240.3 million and $226.5 million, respectively, including interest costs of
$158.2 million and $144.3 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, are billed currently
to customers and paid to the DOE on a quarterly basis. NU is responsible for
fees to be paid for fuel burned until the divestiture of the Millstone and
Seabrook nuclear units.
E. NUCLEAR INSURANCE CONTINGENCIES
Insurance policies covering the NU system's nuclear facilities have been
purchased for the primary cost of repair, replacement or decontamination of
utility property, certain extra costs incurred in obtaining replacement power
during prolonged accidental outages and the excess cost of repair, replacement
or decontamination or premature decommissioning of utility property.
The NU system is subject to retroactive assessments if losses under those
policies exceed the accumulated funds available to the insurer. The maximum
potential assessments with respect to losses arising during the current policy
year for the primary property insurance program, the replacement power policies
and the excess property damage policies are $8.2 million, $4.1 million and
$10.2 million, respectively. In addition, insurance has been purchased in the
aggregate amount of $200 million on an industry basis for coverage of worker
claims.
Under certain circumstances, in the event of a nuclear incident at one of the
nuclear facilities covered by the federal government's third-party liability
indemnification program, the NU system could be assessed liabilities in
proportion to its ownership interest in each of its nuclear units up to $83.9
million. The NU system's payment of this assessment would be limited to, in
proportion to its ownership interest in each of its nuclear units, $10 million
in any one year per nuclear unit. In addition, if the sum of all claims and
costs from any one nuclear incident exceeds the maximum amount of financial
protection, the NU system would be subject to an additional 5 percent, or $4.2
million, liability, in proportion to its ownership interests in each of its
nuclear units. Based upon its ownership interests in the Millstone units and
in Seabrook, the NU system's maximum liability, including any additional
assessments, would be $271 million per incident, of which payments would be
limited to $30.8 million per year. In addition, through purchased-power
contracts with VYNPC, the NU system would be responsible for up to an
additional assessment of $14.1 million per incident, of which payments would
be limited to $1.6 million per year.
NU expects to terminate its nuclear insurance upon the divestiture of its
nuclear units.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS
Yankee Companies: Under the terms of their agreements, the NU system companies
paid their ownership (or entitlement) shares of costs, which included
depreciation, operation and maintenance (O&M) expenses, taxes, the estimated
cost of decommissioning, and a return on invested capital. These costs were
recorded as purchased-power expenses. The total cost of purchases under
contracts with VYNPC amounted to $24.9 million in 2000, $29.2 million in 1999
and $27.3 million in 1998. VYNPC is in the process of selling its nuclear
unit. Upon completion of the sale, these long-term contracts will be
terminated.
Nonutility Generators (NUGs): CL&P, PSNH and WMECO have entered into various
arrangements for the purchase of capacity and energy from NUGs. The total cost
of purchases under these arrangements amounted to $482.1 million in 2000,
$461.8 million in 1999 and $459.7 million in 1998. The companies are in the
process of renegotiating the terms of these contracts through either a contract
buydown or buyout. The companies expect any payments to the NUGs as result of
these renegotiations to be recovered from the companies' customers.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and
HWP have entered into agreements to support transmission and terminal
facilities to import electricity from the Hydro-Quebec system in Canada. CL&P,
PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in
2020, their proportionate shares of the annual O&M expenses and capital costs
of those facilities.
Estimated Annual Costs: The estimated annual costs of the NU system's
significant long-term contractual arrangements, absent the effects of any
contract terminations, buydowns or buyouts are as follows:
- ------------------------------------------------------------------------------
2001 2002 2003 2004 2005
- ------------------------------------------------------------------------------
(Millions of Dollars)
VYNPC............. $ 28.5 $ 28.9 $ 29.1 $ 32.0 $ 30.1
NUGs.............. 480.2 489.2 500.6 487.3 496.8
Hydro-Quebec...... 27.9 27.0 26.0 25.0 24.1
- ------------------------------------------------------------------------------
Select Energy: Select Energy maintains long-term agreements to purchase energy
in the normal course of business as part of its portfolio of resources to meet
its actual or expected sales commitments. The aggregate amount of these
purchase contracts was $1.94 billion at December 31, 2000.
These contracts extend through 2004 as follows:
- -------------------------------------------------------------------------------
(Millions of Dollars)
- -------------------------------------------------------------------------------
Year
- -------------------------------------------------------------------------------
2001 $1,418.3
2002 266.2
2003 228.5
2004 28.0
- -------------------------------------------------------------------------------
Total $1,941.0
- -------------------------------------------------------------------------------
7. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS
Millstone and Seabrook: The NU system operating nuclear power plants,
Millstone 2 and 3 and Seabrook, have service lives that are expected to end
during the years 2015 through 2026, and upon retirement, must be
decommissioned. Millstone 1's expected service life was to end in 2010,
however, in July 1998, restart activities were discontinued and decommissioning
of the unit began. In connection with the sale of the Millstone units,
Dominion has agreed to assume responsibility for decommissioning. Until the
divestiture, CL&P, PSNH and WMECO recover sufficient amounts through their
allowed rates related to decommissioning costs.
The estimated cost of decommissioning Millstone 2, in year end 2000 dollars,
is $430.6 million. The NU system's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook, in year end 2000 dollars, is $440.8
million and $234.6 million, respectively. Nuclear decommissioning costs are
accrued over the expected service lives of the units and are included in
depreciation expense and the accumulated provision for depreciation. Nuclear
decommissioning expenses for these units amounted to $35.5 million in 2000,
$30.6 million in 1999 and $27.9 million in 1998. Nuclear decommissioning
expenses for Millstone 1 were $23.1 million in 2000, $25.7 million in 1999
and $19.8 million in 1998. Through December 31, 2000 and 1999, total
decommissioning expenses of $304.4 million and $260.6 million, respectively,
have been collected from customers and are reflected in the accumulated
provision for depreciation.
External decommissioning trusts have been established for the costs of
decommissioning the Millstone units. Payments for the NU system's ownership
share of the cost of decommissioning Seabrook are paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assumes after-tax earnings
on the Millstone and Seabrook decommissioning funds of 5.5 percent and
6.5 percent, respectively.
As of December 31, 2000 and 1999, $278.5 million and $239.7 million,
respectively, have been transferred to external decommissioning trusts.
Earnings on the decommissioning trusts increase the decommissioning trust
balances and the accumulated provisions for depreciation. Unrealized gains and
losses associated with the decommissioning trusts also impact the balance of
the trusts and the accumulated provisions for depreciation. The fair values
of the amounts in the external decommissioning trusts were $450.8 million and
$410.2 million at December 31, 2000 and 1999, respectively. Upon divestiture,
balances in the decommissioning trusts will be transferred to the buyer.
NU is obligated to top-off the Millstone decommissioning trust if its value
does not equal an agreed upon amount at closing, pursuant to the conditions
set forth in the purchase and sale agreement.
Yankee Companies: VYNPC owns and operates a nuclear generating unit with a
service life that is expected to end in 2012. The NU system's ownership share
of estimated costs, in year end 2000 dollars, of decommissioning this unit is
$72.3 million. In 1999, VYNPC agreed to sell its nuclear generating unit for
$22 million to an unaffiliated company. Among other commitments, the acquiring
company agreed to assume the obligation to decommission the unit after it is
taken out of service, and the owners of VYNPC (including CL&P, WMECO and PSNH)
agreed to fund their shares of the decommissioning costs up to a negotiated
amount. Subsequent to the time that agreement was executed, the original
proposed acquiring company has increased the price it agreed to pay and three
other unaffiliated companies have indicated their interest in buying VYNPC's
generating unit on terms that have not been disclosed. At present, CL&P,
WMECO and PSNH expect that the unit will be sold, but the identity of the owner
and the terms of sale, including price, future decommissioning obligations and
future power purchase obligations, are not known.
As of December 31, 2000 and 1999, NU's remaining estimated obligation,
including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which
have been shut down was $244.6 million and $358.4 million, respectively.
8. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS
Competitive Energy Subsidiaries: Select Energy provides both firm requirement
energy services to its customers and performs energy trading and marketing
activities. Select Energy manages its exposure to risk from existing
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 the 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 area of the United States, Select Energy conducts commodity-trading
activities in electricity and its related products, oil and natural gas 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.
Commodity derivatives 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." Under this methodology, 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 operating expenses - other and in the consolidated balance sheets
as prepayments and other. The mark-to-market position at December 31, 2000,
was a positive $13.8 million.
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 subject to market, based on closing
exchange prices.
As of December 31, 2000, 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 $1 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 sensitivity analysis above.
Commodity Price Risk - Nontrading 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.
Gains or losses on derivatives associated with firm commitments are recognized
as adjustments to cost of sales or revenues when the associated transactions
affect earnings. Gains and losses on derivatives associated with forecasted
transactions are recognized when such forecasted transactions affect earnings.
If a derivative instrument is terminated early because it is probable that a
transaction or forecasted transaction will not occur, any gain or loss as of
such date is immediately recognized in earnings.
When conducting sensitivity analysis of the change in the fair value of Select
Energy's electricity, oil and natural gas portfolio, which would result from
a hypothetical change in the future market price of electricity, oil and
natural gas, the fair value of the contracts are determined from models which
take into account estimated future market prices of electricity, oil and
natural gas, 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 electricity, natural gas and oil contracts, assuming a 10 percent
unfavorable change in forward market prices. As of December 31, 2000, an
unfavorable 10 percent change in forward market price would have resulted in
a decrease in fair value of approximately $52 million.
The impact of a change in electricity, natural gas and oil prices on Select
Energy's nontrading contracts on December 31, 2000, is not necessarily
representative of the results that will be realized when these contracts go to
eventual physical delivery.
Select Energy also maintains natural gas service agreements with certain
customers to supply gas at fixed prices for terms extending through 2003.
Select Energy has hedged its gas supply risk under these agreements through
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 extend through 2002. As of December 31, 2000, the NYMEX
contracts had a notional value of $18.8 million and a positive mark-to-
market position of $14.9 million.
Regulated Entities:
Interest Rate Risk - Nontrading Activities: The company manages its interest
rate risk exposure by maintaining a mix of fixed and variable rate debt. In
addition, Yankee has entered into an interest rate sensitive derivative.
Yankee uses swap instruments with financial institutions to exchange fixed-rate
interest obligations to a blend between fixed and variable-rate obligations
without exchanging the underlying notional amounts. These instruments convert
fixed interest rate obligations to variable rates. The notional amounts
parallel the underlying debt levels and are used to measure interest to be paid
or received and do not represent the exposure to credit loss. As of
December 31, 2000, Yankee had outstanding agreements with a total notional
value of $48 million and a negative mark-to-market position of $0.8 million.
For the fair value, see Note 10 for the disclosure of NU's debt.
Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a master
swap agreement with a certain customer to supply gas at fixed prices for a
10-year term extending through 2005. Under this master swap agreement, the
purchase price of a specified quantity of gas is effectively fixed over the
term of the gas service agreement, which extends through 2005. As of
December 31, 2000, the commodity swap agreement had a notional value of
$17.1 million and a positive mark-to-market position of $5.4 million.
9. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100
million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS),
Series A. CL&P has the sole ownership in CL&P LP, as a general partner,
and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance,
CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1
million capital contribution, back to CL&P in the form of an unsecured
debenture. CL&P consolidates CL&P LP for financial reporting purposes.
Upon consolidation, the unsecured debenture is eliminated, and the MIPS
securities are accounted for as a minority interest.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each of the following financial instruments:
Cash and cash equivalents: The carrying amounts approximate fair value due to
the short-term nature of cash and cash equivalents.
Supplemental Executive Retirement Plan (SERP) Investments: Investments held
for the benefit of the SERP are recorded at fair market value. The investments
having a cost basis of $6.5 million and $5.8 million held for benefit of the
SERP were recorded at their fair market values at December 31, 2000 and 1999,
of $10.1 million and $9.2 million, respectively.
Nuclear decommissioning trusts: The investments held in the NU system
companies' nuclear decommissioning trusts were marked-to-market by $117.6
million as of December 31, 2000, and $129 million as of December 31, 1999,
with corresponding offsets to the accumulated provision for depreciation.
The amounts adjusted in 2000 and in 1999 represent cumulative net unrealized
gains. Cumulative gross unrealized holding losses were immaterial for both
2000 and 1999.
Preferred stock and long-term debt: The fair value of the NU system's fixed-
rate securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair value
equal to their carrying value. The carrying amounts of the NU system's
financial instruments and the estimated fair values are as follows:
- -------------------------------------------------------------------------------
At December 31, 2000
- -------------------------------------------------------------------------------
Carrying Fair
(Millions of Dollars) Amount Value
- -------------------------------------------------------------------------------
Preferred stock not subject to
mandatory redemption............... $ 136.2 $ 159.9
Preferred stock subject to
mandatory redemption............... 40.8 42.0
Long-term debt -
First mortgage bonds............... 1,008.1 1,012.5
Other long-term debt............... 1,342.2 1,290.6
MIPS.................................. 100.0 100.5
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
At December 31, 1999
- -------------------------------------------------------------------------------
Carrying Fair
(Millions of Dollars) Amount Value
- -------------------------------------------------------------------------------
Preferred stock not subject to
mandatory redemption............... $ 136.2 $ 164.0
Preferred stock subject to
mandatory redemption............... 167.5 166.8
Long-term debt -
First mortgage bonds............... 1,193.2 1,209.5
Other long-term debt............... 1,638.3 1,593.1
MIPS.................................. 100.0 97.3
- -------------------------------------------------------------------------------
11. OTHER COMPREHENSIVE INCOME
The accumulated balance for each other comprehensive income item is as follows:
- -------------------------------------------------------------------------------
Current
December 31, Period December 31,
(Thousands of Dollars) 1999 Change 2000
- -------------------------------------------------------------------------------
Foreign currency translation
adjustments....................... $ - $ - $ -
Unrealized gains on securities...... 2,137 245 2,382
Minimum pension liability
adjustments....................... (613) - (613)
- -------------------------------------------------------------------------------
Accumulated other
comprehensive income............ $1,524 $245 $1,769
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
Current
December 31, Period December 31,
(Thousands of Dollars) 1998 Change 1999
- -------------------------------------------------------------------------------
Foreign currency translation
adjustments....................... $ (1) $ 1 $ -
Unrealized gains on securities...... 2,019 118 2,137
Minimum pension liability
adjustments....................... (613) - (613)
- -------------------------------------------------------------------------------
Accumulated other
comprehensive income............ $1,405 $119 $1,524
- -------------------------------------------------------------------------------
The changes in the components of other comprehensive income are reported net of
the following income tax effects:
- -------------------------------------------------------------------------------
(Thousands of Dollars) 2000 1999 1998
- -------------------------------------------------------------------------------
Foreign currency translation adjustments $ - $ - $ -
Unrealized gains on securities (147) (71) (1,222)
Minimum pension liability adjustments - - 398
- -------------------------------------------------------------------------------
Other comprehensive income $(147) $(71) $ (824)
- -------------------------------------------------------------------------------
12. EARNINGS PER SHARE
Earnings per share (EPS) is computed based upon the weighted average number of
common shares outstanding during each year. Diluted earnings per share is
computed on the basis of the weighted average number of common shares
outstanding plus the potential dilutive effect if certain securities are
converted into common stock.
The following table sets forth the components of basic and diluted EPS:
- -------------------------------------------------------------------------------
(Millions of Dollars,
except share information) 2000 1999 1998
- -------------------------------------------------------------------------------
Income/(loss) after
interest charges $219.5 $57.0 $ (120.4)
Preferred dividends
of subsidiaries 14.2 22.8 26.4
- -------------------------------------------------------------------------------
Income/(loss) before
extraordinary loss 205.3 34.2 (146.8)
Extraordinary loss,
net of tax benefit (233.9) - -
- -------------------------------------------------------------------------------
Net (loss)/income $(28.6) $34.2 $(146.8)
- -------------------------------------------------------------------------------
Basic EPS common shares
outstanding (average) 141,549,860 131,415,126 130,549,760
Dilutive effect of
employee stock options 417,356 616,447 - (a)
- -------------------------------------------------------------------------------
Diluted EPS common
shares outstanding (average) 141,967,216 132,031,573 130,549,760
- -------------------------------------------------------------------------------
Basic earnings/(loss)
per common share:
Income/(loss) before
extraordinary loss $ 1.45 $0.26 $(1.12)
Extraordinary loss,
net of tax benefit (1.65) - -
- -------------------------------------------------------------------------------
Net (loss)/income $(0.20) $0.26 $(1.12)
- -------------------------------------------------------------------------------
Diluted earnings/(loss)
per common share:
Income/(loss) before
extraordinary loss $ 1.45 $0.26 $(1.12)
Extraordinary loss,
net of tax benefit (1.65) - -
- -------------------------------------------------------------------------------
Net (loss)/income $(0.20) $0.26 $(1.12)
- -------------------------------------------------------------------------------
(a) The addition of dilutive potential common shares would be anti-dilutive
for 1998 and was not included.
13. MODE 1
On November 23, 1999, NEON Communications, Inc. (NEON) entered into agreements
with two unaffiliated companies. Under the terms of the agreements, NEON will
provide network transport and carrier services in its service areas and that of
the two unaffiliated companies and each company will provide connectivity from
the backbone system to their respective local loops. Additionally, each
company will manage their local distribution into their respective end-users'
locations. NEON will also develop, operate and market the combined
telecommunications infrastructure created under the two agreements. As the
agreements are implemented, the two unaffiliated companies will ultimately
obtain a total of approximately 4.6 million shares of NEON common stock, or
approximately 12 percent and 10 percent ownership interests, respectively.
Each unaffiliated company will also nominate one member to the NEON Board of
Directors. Prior to the implementation of these agreements, Mode 1 had
approximately a 29 percent ownership interest in the common shares of NEON.
In conjunction with the consummation of the agreements on September 14, 2000,
a portion of the total common shares to be issued were issued to the two
unaffiliated companies. The remainder of these shares will be issued as the
two unaffiliated companies complete certain milestones, as defined in their
respective agreements.
The issuance of these shares had the effect of decreasing Mode 1's ownership
interest in NEON's outstanding common shares to approximately 25 percent.
However, these shares were issued at an amount greater than Mode 1's
investment, resulting in a $19.8 million pretax increase to Mode 1's equity.
NU's accounting policy is to recognize the gain or loss from this type of
change in ownership interest in net income.
14. SEGMENT INFORMATION
The NU system is organized between regulated utilities (electric and gas for
the 12 months and 10 months, respectively, ended December 31, 2000, and
electric only for the year ended December 31, 1999) and competitive energy
subsidiaries. The regulated utilities segment represents approximately 85
percent and 86 percent of the NU system's total revenues for the year ended
December 31, 2000 and 1999, respectively, and is comprised of several business
units.
Regulated utilities revenues primarily are derived from residential, commercial
and industrial customers and are not dependent on any single customer. The
competitive energy subsidiaries segment has two major customers, one
unaffiliated company and CL&P. Their purchases represented approximately 15
percent and 34 percent, respectively, of total competitive energy subsidiaries'
revenues for the year ended December 31, 2000. Purchases from the unaffiliated
company represented approximately 43 percent of total competitive energy
subsidiaries' revenues for the year ended December 31, 1999. There were no
purchases from CL&P in 1999.
The competitive energy subsidiaries segment in the following table includes
HEC, a provider of energy management, demand-side management and related
consulting services for commercial, industrial and institutional electric
companies and electric utility companies; HWP, a company engaged in the
production and distribution of electric power; NGC, a corporation that acquires
and manages generation facilities; NGS, a corporation that maintains and
services any fossil or hydroelectric facility that is acquired or contracted
with for fossil or hydroelectric generation services, and; Select Energy, a
corporation engaged in the marketing, transportation, storage, and sale of
energy commodities, at wholesale, in designated geographical areas and in the
marketing of electricity to retail customers.
Other in the following table includes the results for Mode 1, an investor in
a fiber-optic communications network. Mode 1 had earnings of $3.8 million
and a net loss of $4.3 million for years ended December 31, 2000 and 1999,
respectively. See Note 13 for further information related to Mode 1's
earnings for the year ended December 31, 2000. Other also includes the results
of the nonenergy related subsidiaries of Yankee. Interest expense included in
Other primarily relates to the debt of NU parent. Inter-segment eliminations
of revenues and expenses are also included in Other.
- --------------------------------------------------------------------------------------------
For the Year Ended December 31, 2000
- --------------------------------------------------------------------------------------------
Regulated Utilities Competitive Eliminations
(Millions of ------------------- Energy and
Dollars) Electric Gas Subsidiaries Other Total
- --------------------------------------------------------------------------------------------
Operating revenues $4,738.5 $251.2 $1,894.9 $(1,008.0) $ 5,876.6
Operating expenses (4,311.3) (233.7) (1,831.7) 964.9 (5,411.8)
- --------------------------------------------------------------------------------------------
Operating income/(loss) 427.2 17.5 63.2 (43.1) 464.8
Other income/(loss) 48.2 (4.1) (3.1) 13.0 54.0
Interest expense (191.9) (12.2) (53.4) (41.8) (299.3)
Preferred dividends (14.2) - - - (14.2)
- --------------------------------------------------------------------------------------------
Income/(loss) before
extraordinary loss 269.3 1.2 6.7 (71.9) 205.3
Extraordinary loss,
net of tax benefit (214.2) - (19.7) - (233.9)
- --------------------------------------------------------------------------------------------
Net income/(loss) $ 55.1 $ 1.2 $ (13.0) $ (71.9) $ (28.6)
- --------------------------------------------------------------------------------------------
Total assets $9,620.0 $912.6 $ 684.1 $ (999.6) $10,217.1
- --------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
For the Year Ended December 31, 1999
- -------------------------------------------------------------------------------
Regulated Competitive Eliminations
Electric Energy and
(Millions of Dollars) Utilities Subsidiaries Other Total
- -------------------------------------------------------------------------------
Operating revenues $3,846.1 $648.8 $(23.7) $4,471.2
Operating expenses (3,454.3) (688.2) 15.8 (4,126.7)
- -------------------------------------------------------------------------------
Operating income/(loss) 391.8 (39.4) (7.9) 344.5
Other (loss)/income (43.2) 5.6 13.7 (23.9)
Interest expense (245.5) (3.2) (14.9) (263.6)
Preferred dividends (22.8) - - (22.8)
- -------------------------------------------------------------------------------
Net income/(loss) $ 80.3 $(37.0) $ (9.1) $ 34.2
- -------------------------------------------------------------------------------
Total assets $9,302.6 $308.2 $ 77.3 $9,688.1
- -------------------------------------------------------------------------------
15. SUBSEQUENT EVENTS
A. MERGER AGREEMENT WITH CONSOLIDATED EDISON, INC.
In 2000, NU and Consolidated Edison, Inc. (Con Edison) received most of the
approvals needed to complete the merger announced in October 1999.
Shareholders from both companies approved the merger in April 2000, and all
state regulatory approvals were granted by the end of the year. Additionally,
the FERC approved the merger in May 2000, the Nuclear Regulatory Commission
approved the transaction in August 2000, and the United States Department of
Justice approved the merger in February 2001. Necessary approval from the SEC
was expected to be received in mid-March 2001.
On February 28, 2001, NU's Board of Trustees requested that Con Edison provide
reasonable assurance, in writing, that it intended to comply with the terms
of the definitive merger agreement between the two companies. This included
assurances that Con Edison would consummate the pending merger at the price set
forth in the agreement promptly following the receipt of SEC approval.
The original request for assurance was to be received by March 2, 2001, however
that date was later extended to March 5, 2001. On March 5, 2001, Con Edison
advised NU that it was not willing to close the merger on the agreed terms.
NU notified Con Edison that it was treating its refusal to proceed on the terms
set forth in the merger agreement as a repudiation and breach of the merger
agreement, and that NU would file suit to obtain the benefits of the
transaction as negotiated for NU shareholders. On March 6, 2001, Con Edison
filed suit in the U.S. District Court for the Southern District of New York
(Southern District), seeking declaratory judgment that NU failed to satisfy
conditions precedent under the merger agreement. On March 12, 2001, NU filed
suit against Con Edison in the Southern District seeking damages in excess of
$1 billion arising from Con Edison's breach of the merger agreement.
Under the terms of the proposed transaction, had it proceeded to closing, NU
shareholders would have received a base price of $25 per share, in a
combination of cash and Con Edison common stock, plus $0.0034 per share per
day, or approximately $0.10 per share per month, for each day that the merger
did not close after August 5, 2000. Additionally, NU shareholders would have
received another $1 per share as a result of a recommendation by the DPUC's
Utility Operations Management Analysis Unit that the DPUC accept the results
of the Millstone auction that were announced on August 7, 2000. The DPUC
approved the sale in January 2001. The $25 per share base price, the
$0.0034 per share per day compensation and the additional $1 per share
resulting from the Millstone auction would have been subject to the collar
mechanism described in the merger proxy statement dated February 29, 2000,
to the extent NU shareholders received Con Edison stock. Assuming that Con
Edison's stock price had averaged between $36 and $46 per share during the
applicable pricing period, as defined, NU shareholders would have received
approximately $26.84 per share, were the merger to have closed on April 10,
2001.
B. FERC DECISION
On March 6, 2001, the FERC issued an order on rehearing related to the
price for installed capacity (ICAP) in New England. The FERC reinstituted
the previously approved $8.75 per kilowatt-month charge for installed
capacity, but made the price effective April 1, 2001. In an earlier
decision in December 2000, the FERC had made the charge effective as of
August 1, 2000, but in its revised decision, the FERC substituted a $0.17
per kilowatt-month charge for the period of August 2000 through March 2001.
Because NU was a major seller of installed generating capacity during the
last five months of 2000, the FERC's revised decision with respect to the
August through March time period reduced NU's fourth quarter revenues by
$24.6 million and lowered earnings by $14.8 million, or $0.10 per share.
Although it is important that FERC understood the going forward need for a
capacity charge that approximates the cost of installing new generation in
New England, management currently plans on requesting that FERC review the
inconsistency of their decision with regard to the change in the effective
date of the $8.75 charge.
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter Ended (a) (b)
---------------------
(Thousands of Dollars,
except per share information) March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
2000
Operating Revenues $1,382,321 $1,414,973 $1,581,947 $1,497,379
Operating Income $ 135,409 $ 99,092 $ 115,761 $ 114,501
Income Before Extraordinary
Loss $ 74,587 $ 12,206 $ 65,543 $ 52,959
Extraordinary Loss,
Net of Tax Benefit - - - (233,881)
---------- ---------- ---------- ----------
Net Income/(Loss) $ 74,587 $ 12,206 $ 65,543 $ (180,922)
========== ========== ========== ==========
Basic Earnings/(Loss) Per Common Share:
Income Before Extraordinary
Loss $ 0.55 $ 0.09 $ 0.46 $ 0.37
Extraordinary Loss,
Net of Tax Benefit $ - $ - $ - $ (1.63)
---------- ---------- ---------- ----------
Net Income/(Loss) $ 0.55 $ 0.09 $ 0.46 $ (1.26)
========== ========== ========== ==========
Diluted Earnings/(Loss) Per Common Share:
Income Before Extraordinary
Loss $ 0.55 $ 0.08 $ 0.45 $ 0.37
Extraordinary Loss,
Net of Tax Benefit $ - $ - $ - $ (1.63)
---------- ---------- ---------- ----------
Net Income/(Loss) $ 0.55 $ 0.08 $ 0.45 $ (1.26)
========== ========== ========== ==========
1999
Operating Revenues $1,043,407 $1,038,569 $1,240,539 $1,148,736
Operating Income $ 89,638 $ 56,492 $ 110,544 $ 87,863
Net Income/(Loss) $ 18,444 $ 228 $ 31,218 $ (15,674)
Basic and Diluted Earnings/(Loss)
Per Common Share $ 0.14 $ - $ 0.24 $ (0.12)
(a) Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
(b) Summation of quarterly data may not equal annual data due to rounding.
CONSOLIDATED GENERATION STATISTICS (UNAUDITED)
Source of Electric
Energy: (kWh-millions) 2000 1999 1998 1997 1996
------ ------ ------ ------ ------
Nuclear - Steam (a) 16,306 13,558 5,679 3,778 9,405
Fossil - Steam 5,584 10,959 12,505 13,155 9,188
Hydro - Conventional 686 1,206 1,510 1,260 1,544
Hydro - Pumped Storage 240 944 819 959 1,217
Internal Combustion 7 262 80 184 206
Energy Used for Pumping (343) (1,318) (1,130) (1,327) (1,668)
------ ------ ------ ------ ------
Net Generation 22,480 25,611 19,463 18,009 19,892
Purchased and Net Interchange 56,280 43,849 24,945 24,377 22,111
Company Use and Unaccounted For (3,100) (2,612) (2,566) (2,802) (2,473)
------ ------ ------ ------ ------
Net Energy Sold 75,660 66,848 41,842 39,584 39,530
====== ====== ====== ====== ======
(a) Includes the NU system's entitlements in regional nuclear generating
companies, net of capacity sales and purchases.
SELECTED CONSOLIDATED FINANCIAL DATA (UNAUDITED)
(Thousands of Dollars,
except percentages and
share information) 2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------
Balance Sheet Data:
Net Utility Plant $ 3,547,215 $ 3,947,434 $ 6,170,881 $ 6,463,158 $ 6,732,165
Total Assets 10,217,149 9,688,052 10,387,381 10,414,412 10,741,748
Total Capitalization (a) 4,739,417 5,216,456 6,030,402 6,472,504 6,659,617
Obligations Under
Capital Leases (a) 159,879 181,293 209,279 207,731 206,165
Income Data:
Operating Revenues $ 5,876,620 $ 4,471,251 $ 3,767,714 $ 3,834,806 $ 3,792,148
Income/(Loss) Before
Extraordinary Loss $ 205,295 $ 34,216 $ (146,753) $ (129,962) $ 38,929
Extraordinary Loss,
Net of Tax Benefit (233,881) - - - -
----------- ----------- ----------- ----------- -----------
Net (Loss)/Income $ (28,586) $ 34,216 $ (146,753) $ (129,962) $ 38,929
=========== =========== =========== =========== ===========
Common Share Data:
Basic and Diluted
Earnings/(Loss)
Per Common Share:
Income/(Loss) Before
Extraordinary Loss $ 1.45 $ 0.26 $(1.12) $(1.01) $ 0.30
Extraordinary Loss,
Net of Tax Benefit (1.65) - - - -
------ ------ ------ ------ ------
Net (Loss)/Income $(0.20) $ 0.26 $(1.12) $(1.01) $ 0.30
====== ====== ====== ====== ======
Basic Common Shares
Outstanding
(Average) 141,549,860 131,415,216 130,549,760 129,567,708 127,960,382
Fully Diluted
Common Shares
Outstanding
(Average) 141,967,216 132,031,573 130,549,760 129,567,708 128,073,261
Dividends Per Share $ 0.40 $ 0.10 $ - $ 0.25 $ 1.38
Market Price -
Closing (high) $24.25 $22.00 $17.25 $14.25 $25.25
Market Price -
Closing (low) $18.25 $13.56 $11.69 $ 7.63 $ 9.50
Market Price -
Closing (end of year) $24.25 $20.56 $16.00 $11.81 $13.13
Book Value Per
Share (end of year) $15.43 $15.80 $15.63 $16.67 $18.02
Rate of Return Earned
on Average
Common Equity (%) (1.3) 1.6 (7.0) (5.8) 1.6
Market-to-Book
Ratio (end of year) 1.6 1.3 1.0 0.7 0.7
Capitalization:
Common Shareholders'
Equity 47% 40% 34% 34% 35%
Preferred Stock (a) (b) 4 5 5 6 6
Long-Term Debt (a) 49 55 61 60 59
------- ------- ------- ------- -------
100% 100% 100% 100% 100%
======= ======= ======= ======= =======
(a) Includes portions due within one year.
(b) Excludes $100 million of MIPS.
CONSOLIDATED ELECTRIC SALES STATISTICS (UNAUDITED)
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
Revenues: (Thousands)
Residential $1,469,439 $1,517,913 $1,475,363 $1,499,394 $1,501,465
Commercial 1,256,126 1,272,969 1,273,146 1,266,449 1,246,822
Industrial 566,625 560,801 568,913 560,782 565,900
Other Utilities 1,884,082 926,056 336,623 329,764 315,577
Streetlighting
and Railroads 45,998 45,564 47,682 48,867 48,053
Non-Franchised Sales 16,932 24,659 22,479 21,476 8,360
Miscellaneous 96,666 52,357 16,429 47,446 23,513
---------- ---------- ---------- ---------- ----------
Total Electric 5,335,868 4,400,319 3,740,635 3,774,178 3,709,690
Gas 461,716 - - - -
Other 79,036 70,932 27,079 60,628 82,458
---------- ---------- ---------- ---------- ----------
Total $5,876,620 $4,471,251 $3,767,714 $3,834,806 $3,792,148
========== ========== ========== ========== ==========
Sales: (kWh - Millions)
Residential 12,940 12,912 12,162 12,099 12,241
Commercial 13,023 12,850 12,477 12,091 12,012
Industrial 7,130 7,050 6,948 6,801 6,820
Other Utilities 42,127 33,575 9,742 8,034 8,032
Streetlighting
and Railroads 333 314 320 318 319
Non-Franchised Sales 107 147 193 241 50
---------- ---------- ---------- ---------- ----------
Total 75,660 66,848 41,842 39,584 39,474
========== ========== ========== ========== ==========
Customers: (average)
Residential 1,576,068 1,569,932 1,555,013 1,535,134 1,532,015
Commercial 166,114 164,932 162,500 159,350 157,347
Industrial 7,701 7,721 7,847 7,804 7,792
Other 3,917 3,908 3,890 3,929 3,916
---------- ---------- ---------- ---------- ----------
Total Electric 1,753,800 1,746,493 1,729,250 1,706,217 1,701,070
Gas 187,000 - - - -
---------- ---------- ---------- ---------- ----------
Total 1,940,800 1,746,493 1,729,250 1,706,217 1,701,070
========== ========== ========== ========== ==========
Average Annual Use
Per Residential
Customer (kWh) 8,233 8,243 7,799 7,898 8,005
========== ========== ========== ========== ==========
Average Annual Bill
Per Residential
Customer $ 934.94 $ 969.38 $ 946.80 $ 978.72 $ 980.19
========== ========== ========== ========== ==========
Average Revenue per kWh:
Residential 11.36 cents 11.76 cents 12.14 cents 12.39 cents 12.27 cents
Commercial 9.65 9.91 10.20 10.47 10.38
Industrial 7.95 7.95 8.19 8.25 8.30