<PAGE>
As filed with the Securities and Exchange Commission on August 28, 1997
Registration No. 333-30911
================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------
Amendment No. 1
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
---------------
THE CONNECTICUT LIGHT AND POWER COMPANY
(Exact name of registrant as specified in its charter)
Connecticut 4911 06-0303850
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or Classification Code Number) Identification Number)
organization)
---------------
Selden Street
Berlin, Connecticut 06037
(860) 665-5000
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
---------------
Robert P. Wax, Senior Vice President, Secretary and General Counsel
The Connecticut Light and Power Company
Selden Street, Berlin, Connecticut 06037
(860) 665-5000
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
---------------
Copy to:
JEFFREY C. MILLER, Esq. PAULA L. HERMAN, Esq.
Northeast Utilities Service Company Day, Berry & Howard
P.O. Box 270 CityPlace I
Hartford, CT 06141-0270 Hartford, CT 06103-3499
(860) 665-3532 (860) 275-0270
Approximate date of commencement of proposed sale to the public: As soon as
practicable after the effective date of this Registration Statement.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
---------------
The Registrant hereby amends this registration statement on such date
or dates as may be necessary to delay its effective date until the registrant
shall file a further amendment which specifically states that this registration
statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until the registration statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
<PAGE>
PROSPECTUS
Offer For All Outstanding
First and Refunding Mortgage Bonds,
1997 Series B Due June 1, 2002
In Exchange For
First and Refunding Mortgage 7 3/4% Bonds,
1997 Series C Due June 1, 2002
Each Issued By
THE CONNECTICUT LIGHT AND POWER COMPANY
-----------------
The Exchange Offer will expire at 5:00 p.m.,
New York City time, on September 30, 1997
unless extended.
-----------------
The Connecticut Light and Power Company, a Connecticut corporation (the
Company or CL&P), hereby offers, upon the terms and subject to the conditions
set forth in this Prospectus and the accompanying Letter of Transmittal (which
together constitute the Exchange Offer), to exchange an aggregate principal
amount of up to $200,000,000 of its First and Refunding Mortgage 7 3/4% Bonds,
1997 Series C Due June 1, 2002 (the New Bonds) for a like principal amount of
its issued and outstanding First and Refunding Mortgage Bonds, 1997 Series B Due
June 1, 2002 (the Old Bonds and together with the New Bonds, the Bonds). The
Company will not receive any proceeds from the Exchange Offer and will pay all
the expenses incident to the Exchange Offer. The New Bonds will be issued under,
and entitled to the benefits of, the Indenture (as defined) governing the Old
Bonds. The New Bonds are identical in all material respects to the Old Bonds,
except for the elimination of certain transfer restrictions, registration rights
and interest rate provisions relating to the Old Bonds. The New Bonds are being
offered hereunder in order to satisfy certain obligations of the Company
contained in a Registration Rights Agreement dated as of June 19, 1997 (the
Registration Rights Agreement).
The Company will accept for exchange any and all Old Bonds validly tendered
and not withdrawn prior to 5:00 p.m. New York City time on September 30, 1997,
unless extended (as so extended, the Expiration Date).
The Bonds will mature on June 1, 2002 and will bear interest from June 1,
1997 at the rate of 7 3/4% per annum. Interest will be payable semiannually on
June 1 and December 1, commencing December 1, 1997 at the principal office of
the Trustee in New York City, to registered owners at the close of business on
the May 15 or November 15, as the case may be, preceding such June 1 or December
1, or if such record date is a legal holiday or a day on which banks are
authorized to close in New York City, on the next preceding day which is not a
legal holiday or a day on which banks are so authorized to close.
See "Risk Factors" beginning on page 13 for a discussion of certain risks
that should be considered by holders of Old Bonds in considering
whether to tender their Old Bonds in the Exchange Offer.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON
THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
September 2, 1997
<PAGE>
The New Bonds will be redeemable at the option of the Company, as a
whole or in part, at a redemption price equal to the greater of (i) 100% of
their principal amount and (ii) the sum of the present values of the
remaining scheduled payments of principal and interest thereon discounted
to the date of redemption on a semiannual basis (assuming a 360-day year
consisting of twelve 30-day months) at the Treasury Yield (as defined),
plus in each case accrued interest to the date of redemption.
Tenders of Old Bonds pursuant to the Exchange Offer may be withdrawn
at any time prior to the Expiration Date. Subject to certain conditions,
the Company may terminate the Exchange Offer. In the event the Company
terminates the Exchange Offer and does not accept for exchange any Old
Bonds, the Company will promptly return the Old Bonds to the Holders
thereof. See "The Exchange Offer."
The Old Bonds were sold to Morgan Stanley & Co. Incorporated and
Salomon Brothers Inc (collectively, the Initial Purchasers) in the Original
Offering (as defined), in a transaction not registered under the Securities
Act of 1933, as amended (the Securities Act), in reliance upon the
exemption provided in Section 4(2) of the Securities Act. The Initial
Purchasers subsequently placed the Old Bonds with "qualified institutional
buyers," as defined in Rule 144A under the Securities Act. Accordingly,
the Old Bonds may not be reoffered, resold or otherwise transferred in the
United States unless so registered or unless an applicable exemption from
the registration requirements of the Securities Act is available. The New
Bonds are being offered hereunder in order to satisfy the obligations of
the Company under the Registration Rights Agreement.
Based on interpretations by the staff of the Securities and Exchange
Commission (the Commission) issued to other issuers in similar contexts,
New Bonds issued pursuant to the Exchange Offer in exchange for Old Bonds
may be offered for resale, resold and otherwise transferred by holders
thereof (other than any such holder which is an "affiliate" of the Company
within the meaning of Rule 405 under the Securities Act) without compliance
with the registration and prospectus delivery provisions of the Securities
Act provided that such New Bonds are acquired in the ordinary course of
such holders' business and such holders have no arrangement with any person
to participate in the distribution of such New Bonds.
Each broker-dealer that receives New Bonds for its own account
pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such New Bonds. The Letter of
Transmittal states that by so acknowledging and by delivering a prospectus,
a broker-dealer will not be deemed to admit that it is an "underwriter"
within the meaning of the Securities Act. This Prospectus, as it may be
amended or supplemented from time to time, may be used by a broker-dealer
in connection with resales of New Bonds received in exchange for Old Bonds
where such Old Bonds were acquired as a result of market-making activities
or other trading activities. The Company has agreed, for a period of 180
days after the Expiration Date, that it will make this Prospectus available
to any broker-dealer for use in connection with any such resale. See "Plan
of Distribution."
Prior to this Exchange Offer, there has been no public market for the
New Bonds. The Company does not intend to list the New Bonds on any
securities exchange or to seek approval for quotation through any automated
quotation system. There can be no assurance that an active market for the
New Bonds will develop. See "Risk Factors--Market for the New Bonds."
Moreover, to the extent that Old Bonds are tendered and accepted in the
Exchange Offer, the trading market for untendered and tendered but
unaccepted Old Bonds could be adversely affected. If a market for the New
Bonds should develop, the New Bonds could trade at a discount from their
face amount. There can be no assurance that an active public market for the
New Bonds will develop.
Holders whose Old Bonds are not tendered and accepted in the Exchange
Offer will continue to hold such Old Bonds and will be entitled to all the
rights and preferences, and will be subject to the limitations applicable
thereto under the Indenture (as herein defined) and, with respect to
transfer, under the Securities Act. See "Risk Factors--Consequences of
Failure to Exchange."
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<PAGE>
THIS PROSPECTUS (PROSPECTUS) DOES NOT CONSTITUTE AN OFFER TO SELL,
OR THE SOLICITATION OF AN OFFER TO BUY, ANY OF THE NEW BONDS OFFERED HEREBY
BY ANY PERSON IN ANY JURISDICTION IN WHICH IT IS UNLAWFUL FOR SUCH PERSON
TO MAKE AN OFFERING OR A SOLICITATION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES IMPLY
THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY OR THAT THE
INFORMATION SET FORTH HEREIN IS CORRECT AS OF ANY DATE SUBSEQUENT TO THE
DATE HEREOF.
IN MAKING AN INVESTMENT DECISION, INVESTORS MUST RELY ON THEIR OWN
EXAMINATION OF THE COMPANY AND THE TERMS OF THE NEW BONDS, INCLUDING THE
MERITS AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED,
APPROVED OR DISAPPROVED BY ANY FEDERAL OR STATE SECURITIES COMMISSION OR
REGULATORY AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT
CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS DOCUMENT. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
THE COMPANY IS NOT MAKING ANY REPRESENTATION TO ANY OFFEREE OR
PURCHASER OF THE NEW BONDS REGARDING THE LEGALITY OF AN INVESTMENT BY SUCH
OFFEREE OR PURCHASER UNDER APPROPRIATE LEGAL INVESTMENT OR SIMILAR LAWS.
EACH INVESTOR SHOULD CONSULT WITH HIS OWN ADVISORS AS TO LEGAL, TAX,
BUSINESS, FINANCIAL AND RELATED ASPECTS OF A PURCHASE OF THE NEW BONDS.
-------------------
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<PAGE>
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on
Form S-1 (the Registration Statement) under the Securities Act for the
registration of the New Bonds offered hereby. This Prospectus, which
constitutes a part of the Registration Statement, does not contain all the
information set forth in the Registration Statement, certain portions of
which are omitted from the Prospectus as permitted by the rules and
regulations of the Commission. For further information with respect to the
Company and the New Bonds offered hereby, reference is made to the
Registration Statement, including the exhibits thereto, and financial
statements and notes filed as a part thereof. Statements made in this
Prospectus concerning the contents of any documents referred to herein are
not necessarily complete. With respect to each such document filed with
the Commission as an exhibit to the Registration Statement, reference is
made to the exhibit for a more complete description of the matter involved,
and each such statement shall be deemed qualified in its entirety by such
reference.
The Company is subject to the periodic reporting and certain other
informational requirements of the Securities Exchange Act of 1934, as
amended (Exchange Act) and files periodic reports and other information
with the Commission. The Registration Statement in which this Prospectus
is included and the exhibits and schedules thereto, as well as such
reports and other information filed by the Company with the Commission may
be inspected and copied at prescribed rates, at the public reference
facility of the Commission, at Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, or at the Commission's regional
offices at 7 World Trade Center, 13th Floor, New York, New York 10048, and
CitiCorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois
60661. Copies of such material also can be obtained by mail from the
public reference facilities of the Commission, at Room 1024, Judiciary
Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates.
In addition, the aforementioned material can be inspected at the offices of
The New York Stock Exchange, Inc., 20 Broad Street, New York, New York
10005. The Commission also maintains a Website that contains reports and
other information regarding registrants, such as the Company, that file
electronically with the Commission. The address of such site is
(http://www.sec.gov/).
Anyone who receives this Prospectus may obtain a copy of the
Indenture and the Registration Rights Agreement (as defined herein) without
charge by writing to Theresa H. Allsop, Assistant Secretary, at the
Company's principal executive offices at Selden Street, Berlin, Connecticut
06037-1616 or by telephone at 860/665-3019.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this Prospectus are "forward-
looking statements" within the meaning of the Securities Act and the
Exchange Act, such as forecasts and projections of expected future
performance or statements of plans and objectives of the Company and/or the
Northeast Utilities (NU) system (NU system). Although such forward-looking
statements have been based
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<PAGE>
on reasonable assumptions, there is no assurance that the expected results
will be achieved, and actual results could differ materially from these
statements. Some of the factors that could cause actual results to differ
materially include, but are not limited to: governmental and regulatory
actions and initiatives; the impact of deregulation and increased
competition in the industry; generating plant performance; weather
conditions; fuel prices and availability; general economic conditions,
including the effects of inflation; and technological changes.
-5-
<PAGE>
PROSPECTUS SUMMARY
The following material is qualified in its entirety by, and
should be considered in conjunction with, the detailed information and
financial statements appearing elsewhere in this Prospectus.
The Company
The Company, a Connecticut corporation organized in 1907, is a
wholly-owned subsidiary of NU. The Company is the largest electric utility
in Connecticut and is engaged principally in the production, purchase,
transmission, distribution and sale of electricity at retail for
residential, commercial, industrial and municipal purposes to approximately
1.1 million customers in 149 cities and towns in Connecticut.
The Exchange Offer
Old Bonds............... The Old Bonds were sold by the Company to the Initial
Purchasers on June 26, 1997 (the Issue Date) pursuant
to an exemption from or in transactions not subject to
the registration requirements of the Securities Act and
applicable state securities laws. The Initial
Purchasers resold the Old Bonds to "qualified
institutional buyers," as defined in Rule 144A under
the Securities Act. The Registration Statement of
which this Prospectus is a part relates only to the
registration of the New Bonds in exchange for the Old
Bonds.
Registration Rights..... The Company and the Initial Purchasers entered into a
Registration Rights Agreement, dated as of June 19,
1997 (Registration Rights Agreement), which grants the
holders of the Old Bonds certain exchange and
registration rights. The New Bonds are being offered
hereunder in order to satisfy the obligations of the
Company under the Registration Rights Agreement.
The Exchange Offer...... Up to $200,000,000 aggregate principal amount of the
New Bonds are being offered in exchange for a like
principal amount of the Old Bonds. No accrued interest
will be paid on the Old Bonds upon the exchange
thereof, but interest will accrue on the New Bonds from
June 1, 1997. Holders of the Old Bonds to whom this
Exchange Offer is made have special rights under the
Registration Rights Agreement that will terminate upon
the consummation of the Exchange Offer. For procedures
for tendering the Old Bonds, see "The Exchange Offer."
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<PAGE>
Based on interpretations by the staff of the Commission
set forth in certain no-action letters issued by the
Commission to third parties, the Company believes that
New Bonds issued pursuant to the Exchange Offer in
exchange for Old Bonds may be offered for resale,
resold and otherwise offered by any holder thereof
(other than any such holder that is an "affiliate" of
the Company within the meaning of Rule 405 under the
Securities Act) without compliance with the
registration and (except as set forth below) the
prospectus delivery provisions of the Securities Act,
provided that such New Bonds are acquired in the
ordinary course of such holder's business and that such
holder does not intend to participate and has no
arrangement or understanding with any person to
participate in the distribution of such New Bonds. Both
(i) Broker-dealers and (ii) holders of Old Bonds who
are considering tendering Old Bonds in order to
participate in the distribution of the New Bonds should
see "Risk Factors--Consequences of Failure to
Exchange,""The Exchange Offer--Purpose and Effect of
the Exchange Offer" and "--Resales of the New Bonds"
and "Plan of Distribution" for information concerning
certain requirements that may apply to their
activities.
New Bonds............... The New Bonds are identical in all material respects to
the Old Bonds, except for the elimination of certain
transfer restrictions, registration rights and interest
rate provisions. The New Bonds will be represented by a
global security registered in the name of The
Depository Trust Company (DTC) or its nominee. Book-
entry interests in the global security will be shown
on, and transfers thereof will be effected only
through, records maintained by DTC or its nominee.
Conditions of the
Exchange Offer......... The Exchange Offer is not conditioned upon any minimum
principal amount of Old Bonds being tendered for
exchange except that Old Bonds may be tendered only in
integral multiples of US$1,000 principal amount.
Notwithstanding any other provision of the Exchange
Offer, the Company shall not be required to accept for
exchange, or to issue New Bonds in exchange for, any
Old Bonds and may terminate or amend the Exchange
Offer, at any time prior to the consummation of the
Exchange Offer if: (i) the Exchange Offer would violate
applicable law or any applicable interpretation of the
staff of the Commission, (ii) an action or proceeding
is instituted or threatened in any court or by any
governmental agency which
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<PAGE>
might materially impair the ability of the Company to
proceed with the Exchange Offer or a material adverse
development has occurred in any existing action or
proceeding with respect to the Company, or (iii) all
governmental approvals which the Company deems
necessary for the consummation of the Exchange Offer
have not been obtained. See "The Exchange Offer--
Certain Conditions to the Exchange Offer."
Tenders; Expiration
Date; Withdrawal....... The Exchange Offer will expire at 5:00 p.m., New York
City time, on September 30, 1997, or such later date
and time to which it is extended (as so extended, the
Expiration Date). The tender of Old Bonds pursuant to
the Exchange Offer may be withdrawn at any time prior
to the Expiration Date. Any Old Bonds not accepted for
exchange for any reason will be returned without
expense to the tendering holder thereof as promptly as
practicable after expiration or termination of the
Exchange Offer.
Procedures for Tendering
Old Bonds.............. Each holder of Old Bonds desiring to accept the
Exchange Offer must complete and sign the Letter of
Transmittal in accordance with the instructions
contained herein and therein, and mail or deliver the
Letter of Transmittal, together with the Old Bonds and
any other required documents to the Exchange Agent (as
defined herein) at the address set forth herein and in
the Letter of Transmittal prior to 5:00 p.m., New York
City time, on the Expiration Date. By executing the
Letter of Transmittal, each holder will represent to
the Company that, among other things, the New Bonds
acquired pursuant to the Exchange Offer are being
obtained in the ordinary course of business of the
person receiving such New Bonds, whether or not such
person is the holder, that neither the holder nor any
such other person has any arrangement or understanding
with any person to participate in the distribution of
such New Bonds and that neither the holder nor any such
other person is an "affiliate" of the Company, as
defined under Rule 405 of the Securities Act.
Consequences of Failure
to Exchange............ Holders of Old Bonds eligible to participate who do not
exchange their Old Bonds for New Bonds pursuant to the
Exchange Offer will not have any further registration
rights and such Old Bonds will continue to be subject
to the restrictions on
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<PAGE>
transfer as set forth in the legend thereon as a
consequence of the issuance of the Old Bonds pursuant
to exemptions from, or in transactions not subject to,
the registration requirements of the Securities Act and
applicable state securities laws. The Company does not
currently anticipate that it will register the Old
Bonds under the Securities Act. Accordingly, the market
for such Old Bonds could be highly illiquid. See "Risk
Factors-Consequences of Failure to Exchange."
Guaranteed Delivery
Procedures............. Holders of Old Bonds who wish to tender their Old Bonds
and (i) whose Old Bonds are not immediately available
or (ii) who cannot deliver their Old Bonds, the Letter
of Transmittal and any other documents required by the
Letter of Transmittal to the Exchange Agent (or comply
with the procedures for book-entry transfers) prior to
5:00 p.m., New York City time, on the Expiration Date,
must tender their Old Bonds according to the guaranteed
delivery procedures set forth in "The Exchange Offer--
Guaranteed Delivery Procedures."
Acceptance of Old Bonds
and Delivery of New
Bonds.................. Subject to the satisfaction or waiver of all conditions
of the Exchange Offer, the Company will accept for
exchange any and all Old Bonds that are properly
tendered in the Exchange Offer prior to 5:00 p.m., New
York City time, on the Expiration Date. The New Bonds
issued pursuant to the Exchange Offer will be delivered
in exchange for the applicable Old Bonds accepted in
the Exchange Offer promptly following the Expiration
Date. See "The Exchange Offer--Acceptance of Old Bonds
for Exchange; Delivery of New Bonds."
Federal Income Tax
Consequences........... The exchange pursuant to the Exchange Offer will not
result in any income, gain or loss to the holders of
the Bonds or the Company for federal income tax
purposes. See "Certain Federal Income Tax
Considerations."
Use of Proceeds......... There will be no cash proceeds to the Company from the
exchange pursuant to the Exchange Offer.
Exchange Agent.......... Bankers Trust Company has agreed to act as Exchange
Agent for the Exchange Offer.
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<PAGE>
Summary Description of the New Bonds
Interest Rate........... 7 3/4% per annum.
Interest Payment Dates.. June 1 and December 1, commencing December 1, 1997
Maturity................ June 1, 2002.
Security................ The New Bonds will be secured by the Indenture (as
defined herein), which constitutes a first mortgage
lien (subject to liens permitted by the Indenture,
including liens and encumbrances existing at the time
of acquisition by the Company) on substantially all of
the Company's physical property and franchises,
including the Company's generating stations (but not
including the Company's interest in the plants of the
four regional nuclear generating companies described
herein) and its transmission and distribution
facilities.
Optional Redemption..... The New Bonds will be redeemable at any time on not
less than 30 days notice by the Company, in whole or in
part, at a redemption price equal to the greater of (i)
100% of the principal amount thereof, and (ii) the sum
of the present values of the remaining scheduled
payments of principal and interest thereon, plus
accrued interest to the date of redemption, if any. See
"Description of the New Bonds--Redemption Provisions."
Sinking Fund Redemption. There will be no sinking fund requirements.
Form and Denomination... The New Bonds will be issued in fully registered form
without coupons in denominations of US$1,000 and
integral multiples thereof. The New Bonds will be
represented by a single permanent Global Security,
registered in the name of Cede & Co., as nominee of
DTC. See "Book-Entry; Delivery and Form."
Use of Proceeds......... The Company will receive no cash proceeds from the
issuance of the New Bonds. The net proceeds from the
sale of the Old Bonds were or will be used for the
repayment of the Company's short term debt incurred for
general working capital purposes, including costs
associated with the current outages at Millstone.
For additional information regarding the New Bonds, see "Description of the New
Bonds."
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<PAGE>
Risk Factors
See "Risk Factors" beginning on page 13 for a discussion of certain
risks that should be considered by holders of Old Bonds in evaluating whether
to tender the Old Bonds.
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<PAGE>
Summary Consolidated Financial Data
(thousands, except percentages and ratios)
<TABLE>
<CAPTION>
12 Months
Ended
June 30, 1997 Year Ended December 31,
-------------- ----------------------------------
(unaudited) 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C> <C>
Income Summary:
Operating Revenues.............. $2,394,854 $2,397,460 $2,387,069 $2,328,052
Operating (Loss) Income......... (55,840) 29,773 324,026 286,948
Net (Loss) Income.............. (172,908) (80,237) 205,216 198,288
Total Assets (end of period).. $6,399,072 $6,244,036 $6,045,631 $6,217,457
</TABLE>
<TABLE>
<CAPTION>
As of June 30, 1997
----------------------------------------------
(unaudited)
As % of Adjusted
Actual Adjusted (a) Capitalization
---------- ------------ --------------
<S> <C> <C> <C>
Capitalization Summary:
Long-Term Debt (including current
maturities)............................. $2,044,077 $2,044,077 57.66%
Preferred Stock Subject to Mandatory
Redemption.............................. 155,000 155,000 4.37%
Preferred Stock Not Subject to
Mandatory Redemption.................... 116,200 116,200 3.28%
Common Stockholder's Equity.............. 1,230,014 1,230,014 34.69%
========== ============ ==============
Total Capitalization $3,545,291 $3,545,291 100.00%
========== ============ ===============
</TABLE>
<TABLE>
<CAPTION>
12 Months Ended
June 30, 1997 Year Ended December 31,
--------------- ------------------------------------------------------------
(unaudited) 1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Ratio of Earnings to Fixed
Charges (c)........................... (0.67)(b) 0.30(b) 3.64 3.65 2.71 2.96
</TABLE>
(a) Because the New Bonds will be exchanged for issued and outstanding Old
Bonds, the New Bonds will not increase the amount of the Company's
outstanding total long-term debt.
(b) For the twelve-month periods ended December 31, 1996 and June 30,
1997, the ratio of earnings to fixed charges reflects the effects of
additional costs, including replacement power costs, associated with
the outages at the three Millstone units. For such periods, earnings
were inadequate to cover fixed charges; the additional earnings
required to bring the ratio of earnings to fixed charges to 1.0 for
such periods would have been $102,872,000 and $256,769,000,
respectively. See "Risk Factors."
(c) The "Earnings" component of the "Ratio of Earnings to Fixed Charges"
represents the aggregate of net income or loss, taxes based on income,
investment tax credit adjustments, and fixed charges. "Fixed
Charges" represent the aggregate of interest (whether capitalized or
expensed), related amortizations, and the interest component of
leases.
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<PAGE>
RISK FACTORS
Prospective investors should consider carefully all of the
information set forth in this Prospectus, including the following risks,
before investing in the New Bonds.
Nuclear Plant Outages and Liquidity
As a result of the prolonged outages at the three Millstone
nuclear units (Millstone) located in Waterford, Connecticut, the Company
faced an extremely difficult year in 1996 and continues to face some of the
most severe regulatory scrutiny and financial challenges in the history of
the United States nuclear industry, including numerous civil lawsuits and
criminal investigations and regulatory proceedings, requesting among other
things license revocation. These outages have resulted in significantly
increased expenditures for replacement power and work undertaken at
Millstone. The length of the outages and the high costs of the recovery
efforts weakened the Company's 1996 earnings, balance sheet and cash flows
and continue to have an adverse impact on the Company's financial
condition.
The Company currently anticipates that Millstone 3 will be ready
for restart by the end of the third quarter of 1997, Millstone 2 in the
fourth quarter of 1997 and Millstone 1 in the first quarter of 1998.
Because of the need for completion of independent inspections and reviews
and for the Nuclear Regulatory Commission (NRC) to complete its processes
before the NRC Commissioners can vote on permitting a unit to restart, the
actual beginning of operations is expected to take several months beyond
the time when a unit is declared ready for restart. The NRC's internal
schedules at present indicate that a meeting of the Commissioners to act
upon a Millstone 3 restart request could occur by mid-December if NU, the
independent review teams and NRC staff concur that the unit can return to
operation by that time. A similar schedule indicates a mid-March meeting
of the Commissioners to act upon a Millstone 2 restart request. Management
hopes that Millstone 3 can begin operating by the end of 1997. There can be
no assurances, however, that the Company's expectations will be met. If
the return to service of one or more of the Millstone units is delayed
substantially, or if any needed waivers or modifications to the Company's
financing arrangements are not forthcoming on reasonable terms, or if the
Company encounters additional significant costs or other significant
deviations from management's current assumptions, resulting in the
Company's inability to meet its cash requirements, management would take
actions to reduce costs and to obtain additional sources of funds. The
availability of these funds would be dependent upon general market
conditions and the Company's and the NU system's credit and financial
condition at that time. Both Moody's Investors Service (Moody's) and
Standard and Poor's Corporation (S&P) have recently downgraded the
Company's senior debt to Ba1 and BB+, respectively.
Management has committed not to seek recovery of the portion of
these costs attributable to the failure to meet industry standards in
operating Millstone. In light of that commitment, and in recognition of
the NRC's watch list designation of Millstone and that numerous internal
and external reports have been critical of the operation of Millstone,
management has said that the Company will not seek recovery for a
substantial portion of such costs. While the Company
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believes that it is entitled to recovery of a portion of the costs that
have been and will be incurred, and intends to apply for recovery of such
costs, the Connecticut Department of Public Utility Control (DPUC) on June
27, 1997 orally granted summary judgment in a prudence proceeding
disallowing recovery by the Company of substantially all of its Millstone
outage related costs. On July 30, 1997, the DPUC issued a purported
"written decision" in the same case, which disallowed recovery of an
estimated $600 million of replacement power costs related to the Millstone
outages, and found that the Company had waived recovery of an additional
$360 million of incremental operations and maintenance (O&M). The written
decision, like the oral decision, recognized the Company's right to seek
recovery, in a future rate proceeding, of $40 million related to
reliability enhancements. The Company has appealed the DPUC's decision.
Management currently does not intend to request any such cost recoveries
until after the Millstone units begin returning to service, so it is
unlikely that any additional revenues from any permitted recovery of these
costs will be available while the units are out of service to contribute to
funding the recovery efforts. Any requests for recovery would include only
costs for projects the Company would have undertaken under normal operating
conditions or that provide long-term value for the Company customers.
In a separate proceeding, the DPUC ordered the Company to submit
studies by July 1, 1997 that analyze the economic benefits from continued
operation of Millstone 1 and 2. On July 1, 1997, the Company submitted
continued unit operation studies to the DPUC showing that, under base case
assumptions, Millstone 1 will have a value to NU system customers (as
compared to the cost of shutting down the unit and incurring replacement
power costs) of approximately $70 million during the remaining thirteen
years of its operating license and Millstone 2 will have a value to NU
system customers (on the same assumptions as used with Millstone 1) of
approximately $500 million during the remaining eighteen years of its
operating license. Two other cases submitted to the DPUC based on higher
assumed O&M costs, which the Company considers less likely, indicated that
Millstone 1 would be uneconomic in varying degrees. Based on these
economic analyses, the Company expects to continue operating both Millstone
1 and Millstone 2 for the remaining terms of their respective operating
licenses. The DPUC has stated it will consider these analyses in the
context of the Company's next integrated resource planning proceeding which
begins in April 1998. The Company cannot predict the outcome of this
proceeding.
In addition, the DPUC is required to review a utility's rates
every four years if there has not been a rate proceeding during such
period. On June 16, 1997, the Company filed with the DPUC certain
financial information consistent with the DPUC's filing requirements
applicable to such four year review. The Company expects hearings before
the DPUC with respect to such review could begin as early as September,
1997. The Company cannot predict the outcome of this proceeding.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands
for arbitration with the Company and Western Massachusetts Electric Company
(WMECO) as well as lawsuits in Massachusetts Superior Court against NU and
its current and former trustees. The non-NU owners raise a number of
contract, tort and statutory claims, arising out of the operation of
Millstone 3. The arbitrations and lawsuits seek to recover compensatory
damages, punitive damages, treble damages and attorneys' fees. Owners
representing approximately two-thirds of the non-NU interests in Millstone
3 have claimed compensatory damages in excess of $200 million. In addition,
one of the
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lawsuits seeks to restrain NU from disposing of its shares of the stock of
WMECO and Holyoke Water Power Company (HWP), pending the outcome of the
lawsuit. The NU companies believe there is no legal basis for the claims
and intend to defend against them vigorously.
Each major company in the NU system finances its own needs.
Neither the Company nor WMECO has any agreements containing cross defaults
based on events or occurrences involving NU, Public Service Company of New
Hampshire (PSNH) or North Atlantic Energy Corporation (NAEC). Similarly,
neither PSNH nor NAEC has any agreements containing cross defaults based on
events or occurrences involving NU, the Company or WMECO. Nevertheless, it
is possible that investors will take negative operating results or
regulatory developments at one company in the NU system into account when
evaluating other companies in the NU system. That could, as a practical
matter and despite the contractual and legal separations among the NU
companies, negatively affect each company's access to the financial
markets.
If the return to service of one or more of the Millstone units is
delayed substantially, or if some borrowing facilities become unavailable
because of difficulties in meeting borrowing conditions, or if the NU
system encounters additional significant costs or any other significant
deviations from management's current assumptions, the currently available
borrowing facilities could be insufficient to meet all of the NU system's
cash requirements. In those circumstances, management would take actions to
reduce costs and cash outflows and would attempt to take other actions to
obtain additional sources of funds. The availability of these funds would
be dependent upon the general market conditions and the NU system's credit
and financial condition at the time.
For more information, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations," "Business--Overview of
Nuclear and Related Financial Matters," "--Electric Operations--Nuclear
Plant Performance and Regulatory Oversight," "--Competition and Cost
Recovery," "--Rates" and "--Financing Program--Financing Limitations," and
"Legal Proceedings."
Industry Restructuring and Competition
Competition in the energy industry continues to grow as a result
of legislative and regulatory action, technological advances, relatively
high electric rates in certain regions of the country, including New
England, surplus generating capacity and the increased availability of
natural gas. These competitive pressures are particularly strong in the NU
system's service territories, where legislators and regulatory agencies
have been at the forefront of the restructuring movement. Changes in the
industry are expected to place downward pressure on prices and to increase
customer choice through competition.
Although the Company continues to operate predominantly in a
state-approved franchise territory under traditional cost-of-service
regulation, restructuring initiatives in the State of Connecticut have
created uncertainty with respect to future rates and the recovery of
"strandable investments." Strandable investments are expenditures that
have been made by utilities in the past to meet their public service
obligations, with the expectation that they would be recovered from
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customers in the future. However, under certain circumstances these costs
might not be recoverable from customers in a fully competitive electric
utility industry. The Company continues to believe such costs will be
recoverable. The Company is particularly vulnerable to strandable
investments because of (i) the Company's relatively high investment in
nuclear generating capacity, which had a high initial cost to build, (ii)
state-mandated purchased power arrangements priced above market, and (iii)
significant regulatory assets, which are those costs that have been
deferred by state regulators for future collection from customers. As of
June 30, 1997, the Company's net investment in nuclear generating capacity,
excluding its investment in certain regional nuclear companies, was
approximately $2.3 billion, and its regulatory assets were approximately
$1.2 billion. The Company's exposure to strandable investments and above-
market purchased power obligations exceeds its shareholder's equity. The
Company's ability to compete in a restructured environment would be
negatively affected unless the Company were able to recover substantially
all of the past investments and commitments. Unless amortization levels are
changed from currently scheduled rates, the Company's regulatory assets are
expected to be substantially decreased over the next five years.
For more information regarding electric industry restructuring,
see "Business--Competition and Cost Recovery," "Business--Rates" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Regulatory Accounting and Assets
The accounting policies of the Company conform to generally
accepted accounting principles applicable to rate regulated enterprises and
reflect the effects of the ratemaking process in accordance with Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation." Assuming a cost-of-service based
regulatory structure, regulators may permit incurred costs, normally
treated as expenses, to be deferred and recovered through future revenues.
Through their actions, regulators may also reduce or eliminate the value of
an asset, or create a liability.
Recently, the Commission has questioned the ability of certain
utilities to continue to follow SFAS No. 71 in light of state legislation
regarding the transition to retail competition. The industry expects
guidance on this issue from the Financial Accounting Standards Board's
Emerging Issues Task Force in the near future. The Company is not yet
subject to a transition plan. Criteria that could give rise to
discontinuation of the application of SFAS No. 71 include: (1) increasing
competition which significantly restricts the Company's ability to charge
prices which allow it to recover operating costs, earn a fair return on
invested capital and recover the amortization of regulatory assets, and (2)
a significant change in the manner in which rates are set by the DPUC from
cost-based regulation to some other form of regulation. In the event the
Company determines it no longer meets the criteria for following SFAS No.
71, the Company would be required to write off its regulatory assets and
liabilities. At June 30, 1997, the Company's regulatory assets were
approximately $1.2 billion. In addition, the Company would be required to
evaluate whether the changes in the competitive and regulatory environment
which led to discontinuing the application of SFAS No. 71 would also result
in an impairment of the net book value of the Company's long-
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lived assets in accordance with SFAS No. 121, "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to be Disposed
Of."
SFAS No. 121 requires the evaluation of long-lived assets,
including regulatory assets, for impairment when certain events occur or
when conditions exist that indicate the carrying amounts of assets may not
be recoverable. SFAS No. 121 requires that any long-lived assets which
are no longer probable of recovery through future revenues be revalued
based on estimated future cash flows. If the revaluation is less than the
book value of the asset, an impairment loss would be charged to earnings.
Management continues to believe that it is probable that the Company will
recover its investments in long-lived assets, including regulatory assets,
through future revenues. This conclusion may change in the future as
competitive factors influence wholesale and retail pricing in the electric
utility industry or if the cost-of-service based regulatory structure were
to change.
Environmental Regulation
The Company is subject to federal, state and local regulations
with respect to water quality, air quality, toxic substances, hazardous
waste and other environmental matters. Similarly, the Company'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. See
"Business--Other Regulatory and Environmental Matters--Environmental
Regulation."
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations, and
other facilities. Changing environmental requirements could also require
extensive and costly modifications to the Company's existing generating
units and transmission and distribution systems, and could limit operations
and/or raise operating costs significantly. As a result, the Company may
incur significant additional environmental costs, greater than amounts
included in reserves, in connection with the generation and transmission of
electricity and the storage, transportation and disposal of by-products and
wastes. The Company may also encounter significantly increased costs to
remedy the environmental effects of prior waste handling activities. The
cumulative long-term cost impact of increasingly stringent environmental
requirements cannot accurately be estimated.
Market for the New Bonds
The New Bonds are a new issue of securities with no established
trading market, and the Company does not intend to apply for listing of the
New Bonds on a national securities exchange, but has been advised by the
Initial Purchasers that they presently intend to make a market in the New
Bonds, as permitted by applicable law and regulations. The Initial
Purchasers are not obligated, however, to make a market in the New Bonds,
and any such market making may be discontinued at any time at the sole
discretion of the Initial Purchasers. Accordingly, no assurance can be
given as to the liquidity of the trading market for the New Bonds.
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Consequences of Failure to Exchange
Holders of Old Bonds who do not participate in the Exchange Offer
will continue to be subject to the restrictions on transfer of the Old
Bonds as set forth in the legend thereon. In general, the Old Bonds may
not be offered or sold, unless registered under, except pursuant to an
exemption from, or in a transaction not subject to, the Securities Act and
applicable state securities laws. The Company does not currently
anticipate that it will register the Old Bonds under the Securities Act.
Based on interpretations of the Securities Act by the staff of the
Commission, New Bonds issued pursuant to the Exchange Offer in exchange for
Old Bonds may be offered for resale, resold, or otherwise transferred by
holders thereof (other than any such holder which is an "affiliate" of the
Company within the meaning of Rule 405 under the Securities Act) without
compliance with the registration and prospectus delivery provisions of the
Securities Act, provided that such New Bonds are acquired in the ordinary
course of such holders' business and such holders have no arrangement with
any person to participate in the distribution of such New Bonds.
Notwithstanding the foregoing, each broker-dealer that receives New Bonds
for its own account pursuant to the Exchange Offer must acknowledge that it
will deliver a prospectus in connection with any resale of such New Bonds.
The Letter of Transmittal states that by so acknowledging and by delivering
a prospectus, a broker-dealer will not be deemed to admit that it is an
"underwriter" within the meaning of the Securities Act. This Prospectus,
as it may be amended or supplemented from time to time, may be used by a
broker-dealer in connection with any resale of New Bonds received in
exchange for Old Bonds where such Old Bonds were acquired by such broker-
dealer as a result of market-making activities or other trading activities
(other than Old Bonds acquired directly from the Company). The Company has
agreed that, for a period of 180 days from the consummation of the Exchange
Offer, it will make this Prospectus available to any broker-dealer for use
in connection with any such resale. See "Plan of Distribution."
Compliance with Exchange Offer Procedures
To participate in the Exchange Offer and to avoid the
restrictions on transfer of the Old Bonds, holders of Old Bonds must
transmit a properly completed Letter of Transmittal, including all other
documents required by such Letter of Transmittal, to the Exchange Agent at
the address set forth below under "The Exchange Offer--Exchange Agent" on
or prior to the Expiration Date. In addition, either (i) certificates for
such Old Bonds must be received by the Exchange Agent along with the Letter
of Transmittal, or (ii) a timely confirmation of a book-entry transfer of
such Old Bonds, if such procedure is available, into the Exchange Agent's
account at the DTC pursuant to the procedure for book-entry transfer
described herein, must be received by the Exchange Agent prior to the
Expiration Date, or (iii) the holder must comply with the guaranteed
delivery procedures described herein.
THE COMPANY
The Company, a Connecticut corporation organized in 1907, is a
wholly-owned subsidiary of NU. Four wholly-owned operating subsidiaries of
NU--the Company, PSNH, WMECO and HWP--furnish electric service in portions
of Connecticut and New Hampshire and in western
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Massachusetts. A fifth wholly-owned subsidiary of NU, NAEC, owns a 35.98
percent interest in the Seabrook nuclear generating facility (Seabrook) in
Seabrook, New Hampshire and sells its share of the output and capacity of
Seabrook to PSNH. The Company is the largest electric utility in
Connecticut and is engaged principally in the production, purchase,
transmission, distribution and sale of electricity at retail for
residential, commercial, industrial and municipal purposes to approximately
1.1 million customers in 149 cities and towns in Connecticut.
The principal executive offices of the Company are located at
Selden Street, Berlin, Connecticut 06037-1616 (telephone 860/665-5000).
THE ORIGINAL OFFERING
On June 26, 1997, in the Original Offering, the Company issued
and sold to the Initial Purchasers $200,000,000 in aggregate principal
amount of the Old Bonds. The Old Bonds were sold pursuant to exemptions
from or in transactions not subject to the registration requirements of the
Securities Act and applicable state securities laws. The Initial
Purchasers subsequently placed the Old Bonds with "qualified institutional
buyers," as defined in Rule 144A under the Securities Act. See "The
Exchange Offer." The Company received approximately $197 million of net
proceeds from the Original Offering. The entire net proceeds of the
Original Offering have been used for general working capital purposes,
including payment of costs associated with the current outages at
Millstone.
THE EXCHANGE OFFER
Purpose and Effect of the Exchange Offer
The Old Bonds were sold to Initial Purchasers in the Original
Offering in a transaction not registered under the Securities Act, in
reliance upon the exemption provided in Section 4(2) of the Securities Act.
The Initial Purchasers subsequently placed the Old Bonds with "qualified
institutional buyers," as defined in Rule 144A under the Securities Act.
Accordingly, the Old Bonds may not be reoffered, resold or otherwise
transferred in the United States unless so registered or unless an
applicable exemption from the registration requirements of the Securities
Act is available. The New Bonds are being offered hereunder in order to
satisfy the obligations of the Company under the Registration Rights
Agreement. Capitalized terms used under this heading and not otherwise
defined shall have the meaning set forth in the Registration Rights
Agreement.
Pursuant to the Registration Rights Agreement, the Company
agreed, for the benefit of the holders of the Old Bonds, that (i) unless
the Exchange Offer would not be permitted by applicable law or Commission
policy, the Company would use its best efforts to have a registration
statement (the Exchange Offer Registration Statement) on the appropriate
form under the Securities Act, with respect to an offer to exchange the Old
Bonds for a like aggregate amount of New Bonds declared effective by the
Commission on or prior to 150 days after the date of original issuance of
the Old Bonds (the Issue Date) and (ii) if obligated to file the Shelf
Registration Statement (defined below), the Company will file prior to 30
days after such filing obligation arises and use its best efforts to
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cause the Shelf Registration Statement to be declared effective by the
Commission on or prior to 150 days after such obligation arises. The
Registration Statement of which this Prospectus is a part is intended to
satisfy the Company's obligation to file an Exchange Offer Registration
Statement.
In the event that any change in law or currently prevailing
interpretations of law by the Commission's staff do not permit the Company
to effect the Exchange Offer, or if for any reason the Exchange Offer is
not consummated within 180 days of the Issue Date and the holders of a
majority in principal amount of the Old Bonds so request, or if a holder of
the Old Bonds notifies the Company that (a) due to a change in law or
policy it is not entitled to participate in the Exchange Offer; (b) due to
a change in law or policy it may not resell the Exchange Bonds acquired by
it in the Exchange Offer to the public without delivering a prospectus and
the prospectus contained in the Exchange Offer Registration Statement is
not appropriate or available for such resales by such Holder or (c) it is a
broker-dealer and owns Bonds acquired directly from the Company or any
affiliate of the Company, the Company agreed to use its best efforts to
cause to be filed a registration statement (the Shelf Registration
Statement) with respect to the resale of such Old Bonds or New Bonds, as
the case may be. The Company further agreed to use its best efforts to
keep such Shelf Registration Statement continuously effective, supplemented
and amended until the second anniversary of the Issue Date or such shorter
period that will terminate when all the Old Bonds covered by the Shelf
Registration Statement have been sold pursuant thereto or cease being
Bonds.
If (a) the Company fails to consummate the Exchange Offer within
180 days after the Issue Date, or (b) the Shelf Registration Statement or
the Exchange Offer Registration Statement is declared effective but
thereafter, subject to certain exceptions, ceases to be effective or usable
in connection with the Exchange Offer or resales of Old Bonds, as the case
may be, during the periods specified in the Registration Rights Agreement
(each such event referred to in clauses (a) and (b) above, a Registration
Default), then the interest rate on transfer restricted bonds will increase
(Additional Interest), with respect to the first 90-day period immediately
following the occurrence of such Registration Default by 0.50% per annum
and will increase by an additional 0.50% per annum with respect to each
subsequent 90-day period until all Registration Defaults have been cured,
up to a maximum amount of 1.50% per annum. Following the cure of all
Registration
Defaults, the accrual of Additional Interest will cease and the interest
rate will revert to the original rate.
Based on interpretations by the staff of the Commission issued to
other issuers in similar contexts, the Company believes that New Bonds
issued pursuant to the Exchange Offer in exchange for Old Bonds may be
offered for resale, resold and otherwise transferred by any holder of such
New Bonds (other than any such holder which is an "affiliate" of the
Company within the meaning of Rule 405 under the Securities Act) without
compliance with the registration and prospectus delivery provisions of the
Securities Act, provided that such New Bonds are acquired in the ordinary
course of such holder's business and such holder has no arrangement or
understanding with any person to participate in the distribution of such
New Bonds. Each holder is required to acknowledge in the Letter of
Transmittal that it is not engaged in, and does not intend to engage in, a
distribution of the New Bonds. Any holder who tenders in the Exchange
Offer for the purpose of participating
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in a distribution of the New Bonds must comply with the registration and
prospectus delivery requirements of the Securities Act in connection with a
secondary resale transaction.
Each broker-dealer that receives New Bonds for its own account
pursuant to the Exchange Offer will also be required to acknowledge that
(i) Old Bonds tendered by it in the Exchange Offer were acquired in the
ordinary course of its business as a result of market-making or other
trading activities, and (ii) it will deliver a prospectus in connection
with any resale of New Bonds received in the Exchange Offer. The Letter of
Transmittal will also state that by so acknowledging and by delivering a
prospectus, a broker-dealer will not be deemed to admit that it is an
"underwriter" within the meaning of the Securities Act. This Prospectus,
as it may be amended or supplemented from time to time, may be used by a
broker-dealer in connection with resales of New Bonds received in exchange
for Old Bonds where such Old Bonds were acquired by such broker-dealer as a
result of market-making activities or other trading activities (other than
Old Bonds acquired directly from the Company). The Company has agreed
that, for a period of 180 days after Consummation of the Exchange Offer, it
will make this Prospectus available to any broker-dealer for use in
connection with any such resale. See "Plan of Distribution."
Notwithstanding the foregoing, based on the above-mentioned interpretations
by the staff of the Commission, the Company believes that broker-dealers
who acquired the Old Bonds directly from the Company and not as a result of
market-making activities or other trading activities cannot rely on such
interpretations by the staff of the Commission and must, in the absence of
an exemption, comply with the registration and prospectus delivery
requirements of the Securities Act in connection with secondary resales of
the New Bonds. Such broker-dealers may not use this Prospectus, as it may
be amended or supplemented from time to time, in connection with any such
resales of the New Bonds.
Terms of the Exchange Offer; Period for Tendering Old Bonds
Upon the terms and subject to the conditions set forth in this
Prospectus and in the accompanying Letter of Transmittal (which together
constitute the Exchange Offer), the Company will accept for exchange Old
Bonds which are properly tendered on or prior to the Expiration Date and
not withdrawn as permitted below. As used herein, the term "Expiration
Date" means 5:00 p.m., New York City time, on September 30, 1997; provided,
however, that if the Company, in its sole discretion, has extended the
period of time for which the Exchange Offer is open, the term "Expiration
Date" means the latest time and date to which the Exchange Offer is
extended.
As of the date of this Prospectus, $200,000,000 aggregate
principal amount of the Old Bonds was outstanding. This Prospectus,
together with the Letter of Transmittal, is first being sent to all holders
of Old Bonds known to the Company on or about September 2, 1997. The
Company's obligation to accept Old Bonds for exchange pursuant to the
Exchange Offer is subject to certain conditions as set forth under "--
Certain Conditions to the Exchange Offer" below.
The Company expressly reserves the right, at any time or from
time to time, to extend the period of time during which the Exchange Offer
is open, and thereby delay acceptance for exchange of any Old Bonds, by
giving oral or written notice of such extension to the holders thereof.
During
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any such extension, all Old Bonds previously tendered will remain subject
to the Exchange Offer and may be accepted for exchange by the Company. Any
Old Bonds not accepted for exchange for any reason will be returned without
expense to the tendering holder thereof as promptly as practicable after
the expiration or termination of the Exchange Offer.
Procedures for Tendering Old Bonds
The tender to the Company of Old Bonds by a holder thereof as set
forth below and acceptance thereof by the Company will constitute a binding
agreement between the tendering holder and the Company upon the terms and
subject to the conditions set forth in this Prospectus and in the
accompanying Letter of Transmittal. Except as set forth below, a holder
who wishes to tender Old Bonds for exchange pursuant to the Exchange Offer
must transmit a properly completed and duly executed Letter of Transmittal,
including all other documents required by such Letter of Transmittal, to
Bankers Trust Company (the Exchange Agent), at the address set forth below
under "Exchange Agent" on or prior to the Expiration Date. In addition,
either (i) certificates for such Old Bonds must be received by the Exchange
Agent along with the Letter of Transmittal, or (ii) a timely confirmation
of a book-entry transfer (a Book-Entry Confirmation) of such Old Bonds, if
such procedure is available, into the Exchange Agent's account at the DTC
(the Book-Entry Transfer Facility) pursuant to the procedure for book-entry
transfer described below, must be received by the Exchange Agent on or
prior to the Expiration Date, or (iii) the holder must comply with the
guaranteed delivery procedures described below. THE METHOD OF DELIVERY OF
OLD BONDS, LETTERS OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS IS AT
THE ELECTION AND RISK OF THE HOLDERS. INSTEAD OF DELIVERY BY MAIL, IT IS
RECOMMENDED THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL
CASES, SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE TIMELY DELIVERY. NO
LETTERS OF TRANSMITTAL OR OLD BONDS SHOULD BE SENT TO THE COMPANY.
Signatures on a Letter of Transmittal or a notice of withdrawal,
as the case may be, must be guaranteed unless the Old Bonds surrendered for
exchange pursuant thereto are tendered (i) by a registered holder of the
Old Bonds who has not completed the box entitled "Special Issuance
Instructions" or "Special Delivery Instructions" on the Letter of
Transmittal, or (ii) for the account of a registered national securities
exchange, a member of the National Association of Securities Dealers, Inc.
or a commercial bank or trust company having an officer or correspondent in
the United States (collectively, Eligible Institutions.) In the event that
signatures on a Letter of Transmittal or a notice of withdrawal, as the
case may be, are required to be guaranteed, such guarantees must be by an
eligible guarantor institution which is a member of one of the following
recognized Medallion Signature Guarantee Programs: the Securities Transfer
Agents Medallion Program (STAMP), the New York Stock Exchange Medallion
Signature Program (MSP) or the Stock Exchanges Medallion Program (SEMP)
(collectively, Eligible Guarantor Institutions). If Old Bonds are
registered in the name of a person other than a signer of the Letter of
Transmittal, the Old Bonds surrendered for exchange must be endorsed by, or
be accompanied by a written instrument or instruments of transfer or
exchange, in satisfactory form as determined by the Company in its sole
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discretion, duly executed by the registered holder with the signature
thereon guaranteed by an Eligible Guarantor Institution.
All questions as to the validity, form, eligibility (including
time of receipt), acceptance and withdrawal of Old Bonds tendered for
exchange will be determined by the Company in its sole discretion, which
determination shall be final and binding. The Company reserves the
absolute right to reject any and all tenders of any particular Old Bonds
not properly tendered or to not accept any particular Old Bonds which
acceptance might, in the judgment of the Company or its counsel, be
unlawful. The Company also reserves the absolute right to waive any
defects, irregularities or conditions of the Exchange Offer as to any
particular Old Bonds either before or after the Expiration Date (including
the right to waive the ineligibility of any holder who seeks to tender Old
Bonds in the Exchange Offer). The interpretation of the terms and
conditions of the Exchange Offer as to any particular Old Bonds either
before or after the Expiration Date (including the Letter of Transmittal
and the instructions thereto) by the Company shall be final and binding on
all parties. Unless waived, any defects or irregularities in connection
with tenders of Old Bonds for exchange must be cured within such reasonable
period of time as the Company shall determine. Neither the Company, the
Exchange Agent nor any other person shall be under any duty to give
notification of any defect or irregularity with respect to any tender of
Old Bonds for exchange, nor shall any of them incur any liability for
failure to give such notification.
If the Letter of Transmittal is signed by a person or persons
other than the registered holder or holders of Old Bonds, such Old Bonds
must be endorsed or accompanied by appropriate powers of attorney in either
case signed exactly as the name or names of the registered holder or
holders appear on the Old Bonds.
If the Letter of Transmittal or any Old Bonds or powers of
attorney are signed by trustees, executors, administrators, guardians,
attorneys-in-fact, officers of corporations or others acting in fiduciary
or representative capacity, such persons should so indicate when signing
and, unless waived by the Company, proper evidence satisfactory to the
Company of their authority to so act must be submitted.
By tendering, each holder will represent to the Company that,
among other things (i) the New Bonds acquired pursuant to the Exchange
Offer are being obtained in the ordinary course of business of the person
receiving such New Bonds, whether or not such person is the holder, (ii)
neither the holder nor any such other person has an arrangement or
understanding with any person to participate in the distribution of such
New Bonds, and (iii) neither the holder nor any such other person is an
"affiliate," as defined under Rule 405 of the Securities Act, of the
Company. Each broker-dealer that receives New Bonds for its own account in
exchange for Old Bonds will also acknowledge that it will deliver a
prospectus meeting the requirements of the Securities Act in connection
with any resale of such New Bonds.
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<PAGE>
Acceptance of Old Bonds for Exchange; Delivery of New Bonds
Upon satisfaction or waiver of all of the conditions to the
Exchange Offer, the Company will accept, promptly after the Expiration
Date, all Old Bonds properly tendered and will issue the New Bonds promptly
after acceptance of the Old Bonds. See "--Certain Conditions to the
Exchange Offer" below. For purposes of the Exchange Offer, the Company
shall be deemed to have accepted properly tendered Old Bonds for exchange
when as and if the Company has given oral or written notice thereof to the
Exchange Agent.
In all cases, issuance of New Bonds for Old Bonds that are
accepted for exchange pursuant to the Exchange Offer will be made only
after timely receipt by the Exchange Agent of certificates for such Old
Bonds or a timely Book-Entry Confirmation of such Old Bonds into the
Exchange Agent's account at the Book-Entry Transfer Facility, a properly
completed and duly executed Letter of Transmittal and all other required
documents. If any tendered Old Bonds are not accepted for any reason set
forth in the terms and conditions of the Exchange Offer or if Old Bonds are
submitted for a greater principal amount than the holder desires to
exchange, such unaccepted or non-exchanged Old Bonds will be returned
without expense to the tendering holder thereof (or, in the case of Old
Bonds tendered by book-entry transfer into the Exchange Agent's account at
the Book-Entry Transfer Facility pursuant to the book-entry procedures
described below, such non-exchanged Old Bonds will be credited to an
account maintained with such Book-Entry Transfer Facility) as promptly as
practicable after the expiration or termination of the Exchange Offer.
Book-entry Transfer
The Exchange Agent will make a request to establish an account
with respect to the Old Bonds at the Book-Entry Transfer Facility for
purposes of the Exchange Offer within two business days after the date of
this Prospectus, and any financial institution that is a participant in the
Book-Entry Transfer Facility's systems may make book-entry delivery of Old
Bonds by causing the Book-Entry Transfer Facility to transfer such Old
Bonds into the Exchange Agent's account at the Book-Entry Transfer Facility
in accordance with such Book-Entry Transfer Facility's procedures for
transfer. However, although delivery of Old Bonds may be effected through
book-entry transfer at the Book-Entry Transfer Facility, the Letter of
Transmittal, together with any required signature guarantees and any other
required documents, must, in any case, be transmitted to and received by
the Exchange Agent at one of the addresses set forth below under "Exchange
Agent" on or prior to the Expiration Date or the guaranteed delivery
procedures described below must be complied with.
Guaranteed Delivery Procedure
If a registered holder of the Old Bonds desires to tender such
Old Bonds and the Old Bonds are not immediately available, or time will not
permit such holder's Old Bonds or other required documents to reach the
Exchange Agent before the Expiration Date, or the procedure for book-entry
transfer cannot be completed on a timely basis, a tender may be effected if
(i) the tender is made through an Eligible Institution, (ii) prior to the
Expiration Date, the Exchange Agent received from such Eligible Institution
a properly completed and duly executed Letter of Transmittal and Notice
-24-
<PAGE>
of Guaranteed Delivery, substantially in the form provided by the Company
(by mail or hand delivery), setting forth the name and address of the
holder of Old Bonds, the certificate number or numbers of such Old Bonds
and the principal amount of Old Bonds tendered, stating that the tender is
being made thereby and guaranteeing that within five business days after
the Expiration Date, the certificates for all physically tendered Old
Bonds, in proper form for transfer, or a Book-Entry Confirmation, as the
case may be, the Letter of Transmittal and any other documents required by
the Letter of Transmittal will be deposited by the Eligible Institution
with the Exchange Agent, and (iii) the certificates for all physically
tendered Old Bonds, in proper form for transfer, or a Book-Entry
Confirmation, as the case may be, and all other documents required by the
Letter of Transmittal are received by the Exchange Agent within five
business days after the Expiration Date.
Withdrawal Rights
Tenders of Old Bonds may be withdrawn at any time prior to the
Expiration Date.
For a withdrawal to be effective, a written notice of withdrawal
must be received by the Exchange Agent at the address set forth below under
"Exchange Agent." Any such notice of withdrawal must specify the name of
the person having tendered the Old Bonds to be withdrawn, identify the Old
Bonds to be withdrawn (including the principal amount of such Old Bonds),
and (where certificates for Old Bonds have been transmitted) specify the
name in which such Old Bonds are registered, if different from that of the
withdrawing holder. If certificates for Old Bonds have been delivered or
otherwise identified to the Exchange Agent, then, prior to the release of
such certificates the withdrawing holder must also submit the serial
numbers of the particular certificates to be withdrawn and a signed notice
of withdrawal and signatures guaranteed by an Eligible Institution unless
such holder is an Eligible Institution. If Old Bonds have been tendered
pursuant to the procedure for book-entry transfer described above, any
notice of withdrawal must specify the name and number of the account at the
Book-Entry Transfer Facility to be credited with the withdrawn Old Bonds
and otherwise comply with the procedures of such facility. All questions
as to the validity, form and eligibility (including time of receipt) of
such notices will be determined by the Company, whose determination shall
be final and binding on all parties. Any Old Bonds so withdrawn will be
deemed not to have been validly tendered for exchange for purposes of the
Exchange Offer. Any Old Bonds which have been tendered for exchange but
which are not exchanged for any reason will be returned to the holder
thereof without cost to such holder (or, in the case of Old Bonds tendered
by book-entry transfer procedures described above, such Old Bonds will be
credited to an account maintained at such Book-Entry Transfer Facility for
the Old Bonds) as soon as practicable after returned by following one of
the procedures described under "--Procedures for Tendering Old Bonds" above
at any time on or prior to the Expiration Date.
Certain Conditions to the Exchange Offer
Notwithstanding any other provision of the Exchange Offer, the
Company shall not be required to accept for exchange, or to issue New Bonds
in exchange for, any Old Bonds and may terminate or amend the Exchange
Offer, at any time prior to the consummation of the Exchange Offer if: (i)
the Exchange Offer would violate applicable law or any applicable
interpretation of the
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<PAGE>
staff of the Commission, (ii) an action or proceeding is instituted or
threatened in any court or by any governmental agency which might
materially impair the ability of the Company to proceed with the Exchange
Offer or a material adverse development has occurred in any existing action
or proceeding with respect to the Company, or (iii) all governmental
approvals which the Company deems necessary for the consummation of the
Exchange Offer have not been obtained.
If the Company determines in its sole discretion that the
conditions to the Exchange Offer are not satisfied, the Company may (i)
refuse to accept any Old Bonds and return all tendered Old Bonds to the
tendering holders, (ii) extend the Exchange Offer and retain all Old Bonds
tendered prior to 5:00 p.m. New York City time, on the Expiration Date,
subject, however, to the rights of holders to withdraw such Old Bonds (see
"--Withdrawal Rights") or (iii) waive such unsatisfied conditions with
respect to the Exchange Offer and accept all validly tendered Old Bonds.
If such waiver constitutes a material change to the Exchange Offer, the
Company will promptly disclose such waiver by means of a prospectus
supplement that will be distributed to the registered holders, and the
Company will extend the Exchange Offer for a period of five to 10 business
days, depending upon the significance of the waiver and the manner of
disclosure to the registered holders, if the Exchange Offer would otherwise
expire during such five to 10 business day period.
Termination of Certain Rights
Holders of the Old Bonds to whom this Exchange Offer is made have
special rights under the Registration Rights Agreement that will terminate
upon the consummation of the Exchange Offer. The Registration Rights
Agreement provides that certain rights under such agreement shall terminate
upon the occurrence of (i) the filing with the Commission of the Exchange
Offer Registration Statement, (ii) the effectiveness under the Securities
Act of the Exchange Offer Registration Statement, and (iii) the
consummation of the Exchange Offer.
Exchange Agent
Bankers Trust Company has been appointed as the Exchange Agent
for the Exchange Offer. All executed Letters of Transmittal should be
directed to the Exchange Agent at the address set forth below. Questions
and requests for assistance, requests for additional copies of this
Prospectus or of the Letter of Transmittal and requests for Notices of
Guaranteed Delivery should be directed to the Exchange Agent addressed as
follows:
By Overnight Courier
By Mail: By Hand Delivery: or Certified Mail:
BT Services Tennessee, Inc. Bankers Trust Company BT Services Tennessee, Inc.
Reorganization Unit Corporate Trust & Corporate Trust &
P.O. Box 292737 Agency Group Agency Group
Nashville, TN 37229-2737 Receipt & Delivery Reorganization Unit
Window 648 Grassmere Park Road
123 Washington Street, Nashville, TN 37211
1st Floor
New York, NY 10006
DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET
FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY.
-26-
<PAGE>
Fees and Expenses
The expenses of soliciting tenders will be borne by the Company. The
principal solicitation is being made by mail; however, additional solicitation
may be made by telegraph, telephone or in person by officers and regular
employees of the Company and its affiliates.
The Company has not retained any dealer-manager in connection with the
Exchange Offer and will not make any payments to brokers, dealers or others
soliciting acceptances of the Exchange Offer. The Company, however, will pay
the Exchange Agent reasonable and customary fees for its services and will
reimburse it for its reasonable out-of-pocket expenses in connection therewith.
The fees and expenses incident to the Exchange Offer will be paid by the
Company. Such expenses include fees and expenses of the Exchange Agent and
Trustee, accounting and legal fees and printing costs, among others.
Consequences of Failure to Exchange
Holders of Old Bonds eligible to participate who do not exchange their Old
Bonds for New Bonds pursuant to the Exchange Offer will not have any further
registration rights and such Old Bonds will continue to be subject to the
restrictions on transfer as set forth in the legend thereon as a consequence of
the issuance of the Old Bonds pursuant to exemptions from, or in transactions
not subject to, the registration requirements of the Securities Act and
applicable state securities laws. The Company does not currently anticipate
that it will register the Old Bonds under the Securities Act. See "Risk
Factors-Consequences of Failure to Exchange."
Resales of the New Bonds
With respect to resales of New Bonds, based on an interpretation by the
staff of the Commission set forth in no-action letters issued to third parties,
the Company believes that a holder (other than a person that is an affiliate of
the Company within the meaning of Rule 405 under the Securities Act) who
exchanges Old Bonds for New Bonds in the ordinary course of business and who is
not participating, does not intend to participate, and has no arrangement or
understanding with any person to participate, in the distribution of the New
Bonds, will be allowed to resell the New Bonds to the public without further
registration under the Securities Act and without delivering to the purchasers
of the New Bonds a prospectus that satisfies the requirements of Section 10
thereof. However, if any holder acquires New Bonds in the Exchange Offer for
the purpose of distributing or participating in a distribution of the New
Bonds, such holder cannot rely on the position of the staff of the Commission
enunciated in Exxon Capital Holdings Corporation (available May 13, 1988) or
similar no-action letters or any similar interpretive letters and must comply
with the registration and prospectus delivery requirements of the Securities
Act in connection with a secondary resale transaction, unless an exemption from
registration is otherwise available. Further, each broker-dealer that receives
New Bonds for its own account in exchange for Old Bonds, where such Old Bonds
were acquired by such broker-dealer as a result of market-
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<PAGE>
making activities or other trading activities, must acknowledge that it
will deliver a prospectus in connection with any resale of such New Bonds.
The Shelf Registration Statement
In the event that applicable law or applicable interpretations of the
staff of the Commission do not permit the Company to effect the Exchange
Offer, or if a holder of the Bonds is not permitted to participate in the
Exchange Offer or does not receive freely tradeable New Bonds pursuant to
the Exchange Offer or is an affiliate of the Company, the Company will file
a Shelf Registration Statement prior to 30 days after such filing
obligation arises, relating to all Bonds for which the holders have
provided the necessary information. The Company will use its best efforts
to have the Shelf Registration Statement declared effective within 150 days
after such obligation arises and to keep the Shelf Registration Statement
continuously effective until two years after the Issue Date or such shorter
period that will terminate when all the registrable Bonds covered by the
Shelf Registration Statement have been sold pursuant to the Shelf
Registration Statement or otherwise cease being registrable Bonds.
The summary herein of the material provisions of the Registration
Rights Agreement is believed by the Company to be accurate and complete in
all material respects, but is subject to and is qualified in its entirety
by reference to, all provisions of the Registration Rights Agreement which
provisions are incorporated by reference herein. A copy of the
Registration Rights Agreement has been filed with the Commission as an
Exhibit to the Registration Statement of which this Prospectus is a part.
Accounting Treatment
The New Bonds will be recorded at the same carrying value as the Old
Bonds, which is face value, as reflected in the Company's accounting
records on the date of the exchange. Accordingly, no gain or loss for
accounting purposes will be recognized. The expenses of the Exchange Offer
and the unamortized expenses related to the issuance of the Old Bonds will
be amortized over the term of the New Bonds.
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<PAGE>
The Connecticut Light and Power Company and Subsidiaries
SELECTED FINANCIAL DATA/(a)/
(Thousands of Dollars)
<TABLE>
<CAPTION>
For the Six Months
a Ended June 30, For the Year Ended December 31,
------------------------- ----------------------------------------------------------------------
1997 1996 1996 1995 1994 1993 1992
------------------------- ----------------------------------------------------------------------
(unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues............... $1,199,749 $1,202,354 $2,397,460 $2,387,069 $2,328,052 $2,366,050 $2,316,451
Operating (Loss) Income.......... (10,439) 75,174 29,773 324,026 286,948 241,655 288,088
Net (Loss) Income................ (70,520) 22,151 (80,237) 205,216 198,288 191,449/(b)/ 206,714
Cash Dividends on
Common Stock.................. 5,989 103,528 138,608 164,154 159,388 160,365 164,277
<CAPTION>
At June 30, At December 31,
------------------------- ----------------------------------------------------------------------
1997 1996 1996 1995 1994 1993 1992
------------------------- ----------------------------------------------------------------------
(unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
Total Assets..................... $6,097,331 $6,134,723 $6,244,036 $6,045,631 $6,217,457 $6,397,405 $5,582,831
Long-Term Debt /(c)/............. 2,044,077 2,038,336 2,038,521 1,822,018 1,823,690 2,057,280 2,087,936
Preferred Stock Not
Subject to Mandatory
Redemption................... 116,200 116,200 116,200 116,200 166,200 166,200 231,196
Preferred Stock
Subject to Mandatory
Redemption /(c)/............. 155,000 155,000 155,000 155,000 230,000 230,000 200,000
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
Obligations Under
Capital Leases /(c)/......... 156,990 154,625 155,708 172,264 175,969 177,418 197,404
</TABLE>
a) Reclassifications of prior data have been made to conform with the current
presentation.
b) Includes the cumulative effect of change in accounting for municipal
property tax expense, which increased earnings for common shares by $47.7
million.
c) Includes portion due within one year.
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<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This following discussion and analysis of the results of operations
for the six months ended June 30, 1997 and the three years ended December
31, 1996 contains management's assessment of the Company's financial
condition and the principal factors having an impact on the results of
operations. This discussion should be read in conjunction with the
Company's Consolidated Financial Statements and footnotes appearing
elsewhere in this Prospectus.
Overview
The outages at Millstone have resulted in significantly increased
expenditures for replacement power and work undertaken at Millstone, which
resulted in a net loss for the Company for the year 1996 and the first six
months of 1997. In 1997, while all three units are out of service, the
Company expects to continue operating at a loss. The combination of higher
expenditures and the uncertainty surrounding when the units will return to
service made it necessary to ensure that access to adequate cash levels
would be available for the duration of the outages. Management has taken
various actions to address NU's nuclear program and liquidity issues;
however, these areas continue to be a serious challenge.
The Company faces future uncertainty with the rapidly moving trend
toward industry restructuring. While restructuring had little direct
impact on 1996 or the first six months of 1997 financial results, it
creates an environment of significant uncertainty and financial risk for
the coming years. As discussed in further detail in "--Restructuring," the
financial treatment that strandable investments will be accorded will
impact the Company's ability to compete in a restructured environment.
The NU Board of Trustees (NU Board) appointed Michael G. Morris as
Chairman, President and Chief Executive Officer of NU effective August 19,
1997. Mr. Morris has been elected to comparable positions at most of the
subsidiaries of NU, and to Chairman of the Board of Directors of the
Company, also effective August 19, 1997.
Millstone Outages
The Company has an 81 percent joint ownership interest in Millstone 1
and 2 and a 52.93 percent joint ownership interest in Millstone 3.
Millstone 1, 2 and 3 have been out of service since November 4, 1995,
February 21, 1996 and March 30, 1996, respectively.
Subsequent to its January 31, 1996, announcement that Millstone had
been placed on its watch list, the NRC has stated that the units cannot
return to service until independent, third-party verification teams have
reviewed the actions taken to improve the design, configuration and
employee concerns issues that prompted the NRC to place the units on its
watch list. Upon successful completion of these reviews, the NRC must
approve the restart of each unit through a formal commission vote.
-30-
<PAGE>
Management took several key steps toward improving NU's nuclear
program during 1996 and will continue to place a high priority on its
recovery in 1997. The NU Board formed a committee in April 1996, to
provide high-level oversight of the safety and effectiveness of NU's
nuclear operations, progress toward resolving open NRC issues and progress
in resolving employee, community and customer concerns. In September 1996,
Bruce D. Kenyon was appointed President and Chief Executive Officer of
Northeast Nuclear Energy Company (NNECO), a wholly-owned subsidiary of NU
that operates Millstone, and retired Admiral David M. Goebel was selected
to serve as Vice President for Nuclear Oversight. In early 1997, Neil S.
Carns was selected to serve as Senior Vice President and Chief Nuclear
Officer to oversee Millstone operations. Shortly after his arrival, Mr.
Kenyon unveiled a reorganization of NU's nuclear organization that includes
executives loaned from unaffiliated utility companies.
Millstone 3 has been designated by NU management as the lead unit for
restart. Millstone 2 remains on a schedule to be ready for restart shortly
after Millstone 3. To provide the resources and focus for Millstone 3, the
pace of work on the restart of Millstone 1 was reduced until late in 1997
at which time the full work effort is expected to be resumed.
Management believes that Millstone 3 will be ready for restart by the
end of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997
and Millstone 1 in the first quarter of 1998. Because of the need for
completion of independent inspections and reviews and for the NRC to
complete its processes before the NRC Commissioners can vote on permitting
a unit to restart, the actual beginning of operations is expected to take
several months beyond the time when a unit is declared ready for restart.
The NRC's internal schedules at present indicate that a meeting of the
Commissioners to act upon a Millstone 3 restart request could occur by mid-
December if NU, the independent review teams and NRC staff concur that the
unit can return to operation by that time. A similar schedule indicates a
mid-March meeting of the Commissioners to act upon a Millstone 2 restart
request. Management hopes that Millstone 3 can begin operating by the end
of 1997.
As management continues to proceed with its current work towards
restart, the Independent Corrective Action Verification Program began on
May 27, 1997 for Millstone 3 and June 30, 1997 for Millstone 2. The program
is expected to end in mid-November 1997 for Millstone 3 and late November
1997 for Millstone 2. The NRC Operational Safety Team Inspection for
Millstone 3 is expected to begin in October 1997.
Based on a recent review of work efforts and budgets, management
believes that the overall 1997 nuclear spending levels, which include both
nuclear O&M expenditures and associated support services and capital
expenditures, will be slightly higher than previously estimated. The 1997
projected nuclear O&M expenditures are expected to increase, while 1997
projected capital expenditures are expected to decrease. The Company's
share of nonfuel O&M costs for Millstone to be expensed in 1997 is now
projected to be approximately $353 million compared to $309 million
previously estimated. The 1997 projection includes $12 million of restart
costs identified to date which are expected to be incurred in 1998 and is
net of $50 million of Millstone costs reserved in 1996. The Company's share
of 1997 projected capital expenditures for Millstone is expected to
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<PAGE>
decrease from the $48 million previously estimated to $35 million. The
Company's share of nonfuel O&M costs for Millstone in 1996 totalled $322
million, including $93 million for incremental costs related to the outages
and $50 million reserved for future costs.
For the six months ended June 30, 1997, the Company's share of nonfuel
O&M costs expensed for Millstone totaled $211 million. The actual
expenditures include $40 million reserved for future 1997 restart costs and
$12 million reserved for 1998 restart costs, and is net of $50 million of
spending against the reserve established in 1996. The reserve balance at
June 30, 1997, was approximately $52 million. Nonfuel O&M costs have been
and will continue to be absorbed by the Company without adjustment to its
current rates.
Although 1998 nuclear operating budgets have not been established at
this time, management believes that the nuclear spending levels at
Millstone will be reduced considerably from 1997 levels, although they will
be higher than before the station was placed on the NRC's watch list. The
actual level of 1998 spending will depend on when the units return to
operation and the cost of restoring them to service. The total cost to
restart the units cannot be estimated at this time. Management will
continue to evaluate the costs to be incurred for the remainder of 1997 and
in 1998 to determine whether adjustments to the existing reserves are
required.
Replacement power costs for the Company averaged approximately $23
million a month during the first six months of 1997, and are projected to
average approximately $21 million a month for the remainder of 1997.
Replacement power costs for the Millstone units expensed in 1996 were $216
million, which was a substantial portion of the total 1996 replacement
power costs. The Company will continue to expense its replacement power
costs in 1997. See "Risk Factors--Nuclear Plant Outages and Liquidity," "-
-Rate Matters" and "Business --Overview of Nuclear and Related Financial
Matters" and "--Rates" for information relating to the Company's ability to
recover these replacement power costs.
On July 1, 1997, the Company submitted continued unit operation
studies to the DPUC showing that, under base case assumptions, Millstone 1
will have a value to NU system customers (as compared to the cost of
shutting down the unit and incurring replacement power costs) of
approximately $70 million during the remaining thirteen years of its
operating license and Millstone 2 will have a value to NU system customers
(on the same assumptions as used with Millstone 1) of approximately $500
million during the remaining eighteen years of its operating license. Two
other cases submitted to the DPUC based on higher assumed O&M costs, which
the Company considers less likely, indicated that Millstone 1 would be
uneconomic in varying degrees. Based on these economic analyses, the
Company expects to continue operating both Millstone 1 and Millstone 2 for
the remaining terms of their respective operating licenses. The DPUC has
stated it will consider these analyses in the context of the Company's next
integrated resource planning proceeding which begins in April 1998.
As a result of the nuclear situation, a number of civil lawsuits,
criminal investigations and regulatory proceedings have been initiated,
including litigation by NU's shareholders. On August 7, 1997, the non-NU
owners of Millstone 3 filed demands for arbitration with the Company and
-32-
<PAGE>
WMECO as well as lawsuits in Massachusetts Superior Court against NU and
its current and former trustees. The NU companies believe there is no legal
basis for the claims and intend to defend against them vigorously. To date,
no reserves have been established for existing or potential litigation.
See "Legal Proceedings" and the notes to the Company's Consolidated
Financial Statements, Note 11B, for further information on litigation.
Capacity
During 1996 and continuing into 1997, the NU system companies have
taken measures to improve their capacity position. The Company anticipates
spending approximately $56 million for additional capacity-related costs in
1997, of which $38 million is expected to be expensed. The projected 1997
capacity-related expenditures have increased from previous estimates due to
additional improvements to existing fossil units and the Company's
estimated share of costs to reactivate generating units in New England. In
the first six months of 1997, the Company spent approximately $29 million
to ensure adequate generating capacity, of which $14 million was expensed.
During 1996, the Company spent approximately $60 million of which $42
million was expensed.
Despite record-breaking demand in mid-July, the NU system companies
has been able to meet capacity requirements without any supply
interruptions. Assuming normal weather conditions and generating unit
availability, management expects that the Company will have sufficient
capacity to meet peak load demands for the remainder of 1997. If there are
high levels of unplanned outages at other units in New England, or if any
transmission lines used to import power from other states are unavailable,
at times of peak load demand, the Company and the other New England
utilities may have to resort to operating procedures designed to reduce
customer demand.
On June 28, 1997, the Seabrook nuclear unit in New Hampshire returned
to service following a 50-day planned refueling and maintenance outage.
In December 1996, all of the seven power cables installed in the Long
Island Sound between the Company's Norwalk Harbor and the Long Island
Lighting Company's Northport generating plants were damaged. Repair work
has been completed and all cables were back in service by June 26, 1997.
The Company has a 12 percent equity ownership interest in Maine Yankee
Atomic Power Company (MYAPC), the owner of the Maine Yankee nuclear
generating facility (MY).
On August 6, 1997, the board of directors of MYAPC voted to permanently
close the plant after efforts to sell the nuclear power plant were
unsuccessful. MYAPC had previously announced that it was considering
permanent closure of the plant based on economic concerns and uncertainty
about the operation of the plant.
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<PAGE>
Liquidity and Capital Resources
Cash provided from operations decreased approximately $241 million in
the first six months of 1997, from 1996 and was a use of funds, primarily
due to higher 1997 cash expenditures related to the Millstone outages, and
the pay down of the 1996 year end accounts payable balance. The year end
accounts payable balance was relatively high due to costs related to a
severe December storm and costs associated with the Millstone outages that
had been incurred but not yet paid by the end of 1996. Net cash from
financing activities increased approximately $43 million, primarily due to
an increase in short-term borrowings through the use of the $100 million of
the accounts receivable facility established in 1996. Net cash from
financing activities was also impacted by lower cash dividends on common
shares, partially offset by higher long-term debt retirements. Cash used
for investments decreased approximately $197 million, primarily due to
lower investments in the Money Pool (defined below).
Cash provided from operations decreased by approximately $229 million
in 1996 compared to 1995, primarily due to higher cash operating costs
related to the Millstone outages and costs associated with ensuring
adequate generating capacity, partially offset by higher retail sales and
lower income tax payments. Cash flows from operations were also impacted
by a sharp increase in the level of accounts payable principally caused by
costs related to a severe December 1996 storm and costs associated with the
Millstone outages that had not been paid by year end. Net cash used for
financing activities decreased by approximately $350 million in 1996,
primarily due to higher long-term debt issuances, lower repayment of short-
term debt and lower common dividend payments. Cash used for investments
increased by approximately $122 million in 1996, primarily due to an
increase in investments under the Money Pool.
On April 1, 1997, $193 million of the Company's first mortgage bonds
matured. The Company funded the maturity with cash available and from
long-term debt issuances that took place in 1996 in anticipation of this
maturity.
The Company established a facility in 1996 under which it may sell up
to $200 million of its accounts receivable and accrued utility revenues. As
of June 30, 1997, the Company had sold approximately $100 million of its
receivables and accrued revenues under this facility.
Additionally, the Company, NU, and WMECO entered into a new three-year
revolving credit agreement (the New Credit Agreement) in November 1996. On
May 30, 1997, the First Amendment and Waiver to the New Credit Agreement
became effective. This amendment permits $313.75 million of credit in the
aggregate to remain available to the Company and WMECO through the securing
of such borrowings with first mortgage bonds. Interest coverage and common
equity ratios were revised to enable the companies to meet certain
financial tests. The Company will be able to borrow up to $225 million on
the strength of bonds it has provided as collateral for borrowings under
the revolving credit agreement. WMECO will be able to borrow up to $90
million on the basis of bonds it has provided as collateral. The NU parent
company, which as a holding company cannot issue first mortgage bonds, will
be able to borrow up to $50 million if the Company, WMECO and
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<PAGE>
NU consolidated financial statements meet certain interest coverage tests
for two consecutive quarters. This is not expected to occur until mid-1998.
The Company issued the Old Bonds on June 26, 1997. The net proceeds of
the sale of the Old Bonds were used for repayment of short-term debt
incurred for general working capital purposes, including costs associated
with the current outages at the Millstone units. The Company is obligated
to offer to exchange publicly tradeable New Bonds for the Old Bonds within
180 days after the issue of the Old Bonds or the interest on the Old Bonds
could increase in stages up to a maximum amount of 1.50 percent per annum.
In April, 1997, Moody's downgraded most of its ratings of the Company
and WMECO securities because of the extended Millstone outages. In May,
1997, S&P also downgraded its ratings of the Company and WMECO securities
as a result of the Connecticut legislature failing to approve a utility
restructuring bill during the recently completed legislative session. As a
result, all NU system securities are currently rated below investment grade
by Moody's and S&P. These actions could adversely affect the availability
and cost of funds for the NU system companies.
On April 17, 1997, the holders of approximately $38 million of notes
issued by NU's real estate company (Rocky River Realty Company or RRR)
required RRR to repurchase the notes at par. The notes are secured by real
estate leases between RRR as lessor and Northeast Utilities Service Company
(NUSCO) as lessee. On July 1, 1997, RRR received commitments for the
purchase of approximately $12 million of the notes and RRR repurchased the
remaining $26 million of notes on July 14, 1997. On July 30, 1997,
approximately $6 million of the $12 million were purchased by an
alternative purchaser. The remaining $6 million of the notes is expected to
be purchased by another purchaser by September 2, 1997. See the notes to
the Company's Consolidated Financial Statements, Note 11G for further
information.
On June 21, 1996, the Company entered into an operating lease with a
third party to acquire the use of four turbine generators having an
installed cost of approximately $70 million. During the first quarter of
1997, it was determined that the Company would not be in compliance with a
financial coverage test required under the lease agreement. The Company
has reached an agreement with the lessors for a resolution of this matter.
Management believes that the terms and conditions of this agreement will
not have a material adverse impact on the Company's financial position or
results of operations.
Each major company in the NU system finances its own needs. Neither
the Company nor WMECO has any agreements containing cross defaults based on
events or occurrences involving NU, PSNH or NAEC. Similarly, neither PSNH
nor NAEC has any agreements containing cross defaults based on events or
occurrences involving NU, the Company or WMECO. Nevertheless, it is
possible that investors will take negative operating results or regulatory
developments at one company in the NU system into account when evaluating
other companies in the NU system. That could, as a practical matter and
despite the contractual and legal separations among the NU companies,
negatively affect each company's access to the financial markets.
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If the return to service of one or more of the Millstone units is
delayed substantially, or if the needed waivers or modifications discussed
above are not forthcoming on reasonable terms, or if some borrowing
facilities become unavailable because of difficulties in meeting borrowing
conditions, or if the NU system encounters additional significant costs or
any other significant deviations from management's current assumptions, the
currently available borrowing facilities could be insufficient to meet all
of the NU system's cash requirements. In those circumstances, management
would take actions to reduce costs and cash outflows and would attempt to
take other actions to obtain additional sources of funds. The availability
of these funds would be dependent upon the general market conditions and
the Company's and the NU system's credit and financial condition at the
time.
Restructuring
The movement toward electric industry restructuring continues to gain
momentum nationally as well as within Connecticut. Factors that are
driving the move toward restructuring, in the Northeast in particular,
include legislative and regulatory actions and relatively high electricity
prices. These actions will impact the way that the Company has
historically conducted its business.
Although the Company continues to operate under cost-of-service based
regulation, various restructuring initiatives in Connecticut have created
uncertainty with respect to future rates and the recovery of strandable
investments. Strandable investments are regulatory assets or other assets
that would not be economical in a competitive environment. The Company has
exposure to strandable investments for its investment in high-priced
nuclear generating plants, state mandated purchased power arrangements that
are priced above the market and significant regulatory assets that
represent costs deferred by state regulators for future recovery. The
Company's exposure to strandable investments and purchased power
obligations exceeds its shareholder's equity. The Company's ability to
compete in a restructured environment would be negatively affected unless
the Company were able to recover substantially all of these past
investments and commitments.
On June 4, 1997, the Connecticut legislature completed its session
without passage of a proposed electric industry restructuring bill. The
legislature may consider restructuring legislation in the future.
The Company follows accounting principles in accordance with SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation," which
allows the economic effects of rate regulation to be reflected. Recently,
the Commission has questioned the ability of certain utilities to remain on
SFAS No. 71 in light of state legislation regarding the transition to
retail competition. The industry expects guidance on this issue from the
Financial Accounting Standards Board's Emerging Issues Task Force in the
near future. While there are restructuring initiatives pending in
Connecticut, the Company is not yet subject to transition plans.
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If future competition or regulatory actions cause any portion of its
operations to no longer be subject to SFAS No. 71, the Company would no
longer be able to recognize regulatory assets and liabilities for that
portion of its business unless these costs would be recoverable by a
portion of the business remaining on cost-of-service based regulation.
Under its current regulatory environment, management believes that the
Company's use of SFAS No. 71 remains appropriate.
If events create uncertainty about the recoverability of any of the
Company's remaining long-lived assets, the Company would be required to
determine the fair value of its long-lived assets, including regulatory
assets, in accordance with SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The
implementation of SFAS 121 did not have a material impact on the Company's
financial position or results of operations as of December 31, 1996.
Management believes it is probable that the Company will recover its
investments in long-lived assets through future revenues. This conclusion
may change in the future as competitive factors influence wholesale and
retail pricing in the electric utility industry or if the cost-of-service
based regulatory structure were to change. See "Risk Factors--Regulatory
Accounting and Assets."
Competition
In addition to legislative and regulatory actions, competition in the
electric utility industry continues to grow at a rapid pace as a result of
technological advances; relatively high electricity prices in certain
regions of the country, including New England; surplus generating capacity;
and the increased availability of natural gas. Competitive forces in the
electric utility industry have already caused some customers to choose
alternative energy suppliers or relocate outside of the Company's
territory. In response, the Company is preparing for a competitive
environment by expanding previously established programs and developing new
ways to fortify its relationships with existing customers and attract new
customers, both within and outside its service territory.
The Company has continued to negotiate long-term power supply
arrangements with certain large commercial and industrial retail customers
that require an incentive to locate or expand their operations within the
Company's service territory, are considering leaving or reducing operations
in the service territory, are facing short-term financial problems, or are
considering generating their own electricity. Approximately 10 percent of
the Company's commercial and industrial retail revenues were under
negotiated rate agreements at the end of 1996. These negotiated rate
reductions amounted to approximately $19 million in 1996 and 1995. These
activities are expected to continue in 1997.
During 1996, the NU system devoted significantly more resources to its
retail marketing organization, whose primary mission is to provide value
added energy solutions to customers. Training was emphasized for its 170
new employees, the majority of whom are account executives charged with
developing tailored solutions for the NU system's customers and positioning
NU as a valuable partner for the future. The ability of these account
executives to
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obtain an intimate understanding of customers' needs and concerns and
provide value added energy solutions will play a key role in the NU
system's ability to effectively compete in the future.
Revenue erosion from traditional retail electric sales may be
significant after restructuring. While margins on retail electric sales are
likely to be thin, utilities can compete successfully if they are allowed
to recover their strandable investments. During 1997 and beyond, the NU
system plans to continue to participate in state sanctioned retail access
programs; invest in new unregulated businesses; develop new energy-related
products and services; and pursue strategic alliances with companies in
various energy-related fields, including fuel supply and management, power
quality, energy efficiency and load management services. Strategic
alliances will allow NU subsidiaries to enter markets that provide access
to new product lines and technologies that complement the NU system's
current products and services.
Rate Matters
In July 1996, the DPUC approved a rate settlement agreement with the
Company (the Settlement). Under the Settlement, the Company froze base
rates until at least December 31, 1997, accelerated the amortization of
regulatory assets by $73 million in 1996 and between $54 million and $68
million in 1997, and extended the depreciable lives of transmission and
distribution assets by ten years. Additionally, the Settlement terminated
all pending litigation, as of March 31, 1996, among the parties that could
potentially affect the Company's rates. The Settlement does not impact
costs incurred subsequent to March 31, 1996 that are associated with the
Millstone outages. The Settlement reduced 1996 earnings by approximately
$35 million. The impact on 1997 earnings is not significant.
In October 1996, the DPUC issued a final order establishing an Energy
Adjustment Clause (EAC), which replaced both the Company's fossil-fuel
adjustment clause and its generation utilization adjustment clause (GUAC).
The EAC, which is designed to calculate the difference between actual fuel
costs and fuel costs collected through base rates, took effect on January
1, 1997. The order includes an incentive mechanism which disallows
recovery of the first $9 million of actual fuel costs in excess of base
rate levels, but permits the Company to retain the first $9 million in
actual fuel costs below base rate levels.
In connection with an ongoing management audit of the Company,
including matters related to the NRC watch list designation, the two
consulting firms hired by the DPUC to review such matters issued reports in
December 1996 that were highly critical of NU's management of its nuclear
program. The results of these reports may affect future DPUC positions
with respect to the NU system's nuclear related operations and costs.
On January 15, 1997, the DPUC notified the Company that it would be
conducting its prudence review of nuclear cost recovery issues in multiple
phases. The first phase, covering the period April 1 through June 30,
1996, was in progress when various intervenors moved for
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summary judgment with respect to the costs for the entire outage. On June
27, 1997, the DPUC orally granted summary judgment disallowing recovery by
the Company of substantially all of its Millstone outage related costs. On
July 30, 1997, the DPUC issued a purported "written decision" in the same
case disallowing such costs. The Company has not requested cost recovery at
this time and has said that it will not seek recovery for a substantial
portion of these costs and will not request any cost recovery until the
units have returned to operation. Any requests by the Company for recovery
would include only costs for projects the Company would have undertaken
under normal operating conditions or that provide long-term value for the
Company's customers. The Company has appealed the DPUC's decision to the
Connecticut Superior Court. The Company has expensed, and continues to
expense, the bulk of the Millstone outage costs as they are incurred.
Therefore, the Company does not expect this decision to have a material
financial impact on projected 1997 results.
The DPUC is required to review a utility's rates every four years if
there has not been a rate proceeding during such period. On June 16, 1997,
the Company filed with the DPUC certain financial information consistent
with the DPUC's filing requirements applicable to such four year review.
The Company expects hearings before the DPUC to begin soon. The Company
cannot predict the outcome of this proceeding.
Nuclear Decommissioning
The Company has a 34.5 percent equity ownership interest in the
Connecticut Yankee nuclear generating facility (CY). On December 4, 1996,
the CYAPC Board of Directors voted unanimously to cease permanently the
production of power at CY. The decision to retire CY from commercial
operation was based on an economic analysis of the costs of operating it
compared to the costs of closing it and incurring replacement power costs
over the remaining period of CY's operating license, which expires in 2007.
The economic analysis showed that closing CY and incurring replacement
power costs produced substantial savings.
CYAPC has undertaken a number of regulatory filings intended to
implement the decommissioning. In late December 1996, CYAPC filed an
amendment to its power contracts with the Federal Energy Regulatory
Commission (FERC) to clarify the obligations of its purchasing utilities
following the decision to cease power production. At December 31, 1996,
the Company's share of these obligations was approximately $263 million,
including the cost of decommissioning and the recovery of existing assets.
Management expects that the Company will continue to be allowed to recover
such FERC-approved costs from its customers. Accordingly, the Company has
recognized its share of the estimated costs as a regulatory asset, with a
corresponding obligation, on its balance sheets.
The Company's estimated cost to decommission its shares of Millstone
1, 2 and 3 and Seabrook is approximately $858 million in year end 1996
dollars. These costs are being recognized over the lives of the respective
units with a portion being currently recovered through rates. As of
December 31, 1996, the market value of the contributions already made to
the decommissioning trusts, including their investment returns, was
approximately $297 million.
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On August 6, 1997, the board of directors of MYAPC voted unanimously
to cease permanently the production of power at MY. MYAPC has begun to
prepare the regulatory filings intended to implement the decommissioning
and the recovery of remaining assets of MYAPC. During the latter part of
1997, MYAPC plans to file an amendment to its power contracts to clarify
the obligations of its purchasing utilities following the decision to cease
power production. MYAPC is currently updating its decommissioning cost
estimates. These estimates are expected to be completed during the third
quarter of 1997. At this time, the Company is unable to estimate its
obligation to MYAPC. Under the terms of the contracts with MYAPC, the
shareholders-sponsor companies, including the Company, are responsible for
their proportionate share of the costs of the unit, including
decommissioning. Management expects that the Company will be allowed to
recover these costs from its customers.
See the notes to the Company's Consolidated Financial Statements, Note
3, for further information on nuclear decommissioning, including the
Company's share of costs to decommission the regional nuclear generating
units.
Environmental Matters
The Company is potentially liable for environmental cleanup costs at a
number of sites inside and outside its service territory. To date, the
future estimated environmental remediation liability has not been material
with respect to the earnings or financial position of the Company. For the
period ended June 30, 1997, the Company had recorded an environmental
reserve of approximately $8 million, the most probable amount as required
by SFAS No. 5, "Accounting for Contingencies."
See the notes to the Company's Consolidated Financial Statements, Note
11C, for further information on environmental matters.
Risk Management Instruments
The Company uses fuel price management instruments to reduce a portion
of the fuel price risk associated with certain of its long-term negotiated
energy contracts and replacement-power expense during the Millstone
outages. The Company's fuel price management instruments seek to minimize
exposure associated with rising fuel prices and effectively fix the cost of
fuel and maintain the profitability of certain of its long-term negotiated
contract sales.
These instruments are not used for trading purposes. The differential
paid or received as fuel prices change is recognized in income when
realized.
As of June 30,1997, the Company had outstanding fuel price management
instruments with a total notional value of approximately $318 million. The
settlement amounts for the
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second quarter of 1997 associated with the instruments decreased fuel
expense by approximately $0.8 million. Since March 31, 1997, the Company
has entered into additional fuel price management agreements with a total
notional value of approximately $75 million. As of December 31, 1996, the
Company had outstanding fuel-price management instruments with a total
notional value of approximately $229 million. The settlement amounts
associated with the instruments reduced fuel expense by approximately $7.5
million for the Company during 1996. The Company's fuel-price management
instruments seek to minimize exposure associated with rising fuel prices
and effectively fix the cost of fuel and profitability of certain of its
long-term negotiated contract sales.
For further information on risk management instruments, see the notes
to the Company's Consolidated Financial Statements, Note 12.
Results Of Operation
Comparison of the First Six Months of 1997 to the First Six Months of 1996
The Company had a net loss of approximately $64 million in the second
quarter of 1997 compared to a net loss of approximately $11 million in the
second quarter of 1996, and a net loss of approximately $71 million for the
six months ended June 30, 1997, compared to net income of approximately $22
million for the same period in 1996. The losses for the three-and six-month
periods were primarily attributable to replacement-power and nuclear
O&M expenses for the Millstone units in 1997 including amounts reserved for
future spending. The loss for the first six months of 1997 was also
attributable to lower retail sales. Retail kilowatt-hour sales for the
first half of 1997 were 1.9 percent below the same period in 1996 primarily
due to mild weather in the first quarter of 1997.
Total operating revenues decreased in 1997, primarily due to lower
retail sales ($16 million), lower wholesale revenues ($11 million), lower
fuel recoveries ($8 million), partially offset by higher revenues from
regulatory decisions ($14 million) and higher transmission and other
revenues ($9 million). Wholesale revenues decreased primarily due to lower
1997 capacity sales. Retail sales decreased 1.9 percent primarily due to
mild weather in the first quarter of 1997. Revenues from regulatory
decisions increased primarily due to higher recoveries of demand-side-
management costs.
Fuel, purchased and net interchange power expense increased in 1997,
primarily due to higher replacement-power costs expensed in 1997 due to the
nuclear outages.
Other operation expense decreased $31 million and maintenance expense
increased $36 million in 1997. The major factors were the higher costs
associated with the Millstone outages ($60 million) and higher capacity
charges from MY ($7 million); partially offset by lower recognition of
nuclear refueling outage costs as a result of the Rate Settlement ($34
million); lower 1997 administrative and general expenses primarily due to
lower pensions and benefit costs ($15 million) and lower capacity charges
from purchased power ($9 million).
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Amortization of regulatory assets, net increased in 1997, primarily
due to the higher amortization of cogeneration deferrals in 1997 ($23
million) and higher amortizations as a result of the Rate Settlement
($9 million). These were partially offset by the completion of the
amortization of phase-in costs for Seabrook ($6 million).
Federal and state income taxes decreased in 1997, primarily due to
lower book taxable income.
Interest charges increased in 1997, primarily due to higher 1997
average long-term debt levels and interest expense associated with the sale
of the accounts receivable.
Comparison of 1996 to 1995
The Company had a net loss of approximately $80 million in 1996,
compared to net income of approximately $205 million in 1995. The 1996
loss was primarily due to costs related to the ongoing outages at Millstone
which totaled approximately $400 million and reduced the Company's 1996
earnings by approximately $232 million. These costs included replacement
power, higher 1996 Millstone O&M costs, a reserve recognized in 1996 for
1997 expenditures to return the Millstone units to service and costs
associated with ensuring adequate generating capacity. In addition, 1996
earnings decreased due to the impact of the Company's approved rate
settlement agreement, higher recognition of cogeneration costs and higher
nonnuclear O&M costs. These decreases were partially offset by higher
retail sales and lower recognition of Millstone 3 phase-in costs.
Total operating revenues increased in 1996, primarily due to higher
retail sales and regulatory decisions, partially offset by lower fuel
recoveries and lower wholesale revenues. Retail sales increased 1.8 percent
($29 million) primarily due to modest economic growth in 1996. Regulatory
decisions increased revenues by $15 million primarily due to the mid-1995
retail rate increase, partially offset by 1996 reserves for over-recoveries
of demand side management costs. Fuel recoveries decreased $24 million
primarily due to lower average fossil fuel prices. Wholesale revenues
decreased $18 million primarily due to higher recognition in 1995 of lump-
sum payments for the termination of a long-term contract and capacity sales
contracts that expired in 1995.
Fuel, purchased and net interchange power expense increased in 1996,
primarily due to replacement power due to the nuclear outages and the 1996
write-off of GUAC balances under the Settlement, partially offset by lower
nuclear generation and the timing of the recognition of costs under the
Company's fuel clauses.
Other O&M expenses increased in 1996, primarily due to higher costs
associated with the Millstone outages ($143 million, including $50 million
reserved for future costs) and 1996 costs to ensure adequate generating
capacity ($39 million). In addition, these costs reflect higher
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storm and reliability expenditures, higher recognition of conservation
expenses and higher marketing costs.
Higher plant balances and higher decommissioning levels in 1996 were
partially offset by longer depreciable lives of transmission and
distribution assets under the Settlement.
Amortization of regulatory assets, net increased in 1996, primarily
due to lower cogeneration deferrals and the accelerated amortization of
regulatory assets as a result of the Settlement, partially offset by the
completion of the Millstone 3 phase-in amortization in 1995.
Federal and state income taxes decreased in 1996, primarily due to
lower book taxable income, partially offset by 1995 tax benefits from a
favorable tax ruling.
Although the change in 1996 was not significant, deferred nuclear
plants return decreased in 1995, primarily due to the completion of the
Millstone 3 phase-in in 1995.
Other, net increased in 1996, primarily due to higher income on
temporary cash investments in 1996.
Comparison of 1995 to 1994
Total operating revenues increased in 1995, primarily due to
regulatory decisions and higher fuel recoveries, partially offset by lower
retail sales and wholesale revenues. Revenues related to regulatory
decisions increased $61 million primarily due to the effects of the mid-
1994 and 1995 retail rate increases and higher recoveries for demand side
management costs. Fuel and purchased power cost recoveries increased $25
million primarily due to higher energy costs and the recovery of GUAC
costs. Wholesale revenues decreased $16 million primarily due to capacity
sales contracts that expired in 1994.
Fuel, purchased and net interchange power expense increased in 1995,
primarily due to higher fossil generation and higher priced outside energy
purchases from other utilities.
Other O&M expenses increased in 1995, primarily due to higher
recognition of conservation expense, higher recognition of post-retirement
benefit costs and higher capacity charges from the regional nuclear
generating units, partially offset by higher reserves for excess/obsolete
inventory in 1994 and lower maintenance costs at the fossil units.
Depreciation increased in 1995, primarily due to higher plant balances
and higher decommissioning levels.
Amortization of regulatory assets, net decreased in 1995, primarily
due to higher cogeneration deferrals in 1995 and the completion during 1994
of the amortization of a 1993
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cogeneration buyout, partially offset by higher 1995 amortization of
Millstone 3 and Seabrook 1 phase-in costs.
Federal and state income taxes decreased in 1995, primarily due to tax
benefits from a favorable tax ruling, partially offset by higher book
taxable income.
Other, net decreased in 1995, primarily due to the 1993 property tax
accounting change as ordered in the 1993 rate decision. The allocation of
this change to customers occurred in 1994 and amortization began in 1995.
Minority interest in income of subsidiary increased in 1995, primarily
due to the issuance of Monthly Income Preferred Securities in 1995.
BUSINESS
Overview of Nuclear and Related Financial Matters
On January 29, 1996, Millstone was placed on the NRC's watch list as a
Category 2 facility. As set forth below, the Company has significant
financial and capacity interests in Millstone. Facilities in Category 2
have been identified by the NRC as having weaknesses that warrant increased
attention until the licensee, NNECO, demonstrates a period of improved
performance. Millstone was subsequently reclassified as a Category 3
facility, which requires NNECO to receive formal NRC Commissioners'
approval to restart any of the units. Millstone 1, 2 and 3 have been out
of service since November 4, 1995, February 21, 1996 and March 30, 1996,
respectively. Following these decisions, the NU system faced in 1996, and
continues to face, some of the most severe regulatory scrutiny and
financial challenges in the history of the United States nuclear industry,
including numerous civil lawsuits and criminal investigations and
regulatory proceedings. See "Risk Factors--Nuclear Plant Outages and
Liquidity" and "Legal Proceedings."
Millstone 1, a 660-MW boiling water reactor, and Millstone 2, an 870-
MW pressurized water reactor, are each jointly owned 81 percent by the
Company and 19 percent by WMECO. Millstone 3, a 1,154-MW pressurized water
reactor, is jointly owned by the Company (52.93 percent), WMECO (12.24
percent), PSNH (2.85 percent) and other New England utilities.
The NU system companies have initiated a number of changes in the
management of the NU system's nuclear program to address the problems at
Millstone. In April 1996, the NU Board announced the formation of a special
committee of the NU Board to provide high-level oversight of the safety and
effectiveness of NU's nuclear operations and the progress toward resolving
open NRC issues and employee, community and customer concerns. The
committee consists exclusively of outside trustees. It is chaired by E.
Gail de Planque, who is a former NRC Commissioner. In light of substantial
NU Board activities associated with the current nuclear situation, the NU
Board elected Elizabeth T. Kennan in 1996 as Lead Trustee to facilitate the
extensive ongoing communications and activities between the NU Board and
management. In addition, on June 17,
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1997, the shareholders elected William F. Conway, a nuclear power industry
consultant, and former executive with several power companies, to the NU
Board .
In response to various internal reports and other reviews that focused
on nuclear management as a fundamental cause for the decline in the
performance of Millstone, the NU Board elected Bruce D. Kenyon as
President--Nuclear Group of NU, in September 1996. Following this
appointment, management unveiled a reorganization of NU senior nuclear
management at each of the nuclear power units that the NU system operates.
The new management team, including executives loaned from unaffiliated
utility companies with excellent nuclear programs, has focused in the near-
term on the recovery efforts of Millstone and improving nuclear oversight
and the NU system's employee concerns program. In January 1997, Neil S.
Carns was elected to the position of Senior Vice President and Chief
Nuclear Officer of NNECO to oversee the operations of Millstone. Both Mr.
Kenyon and Mr. Carns have extensive experience at other utilities with
reputations for excellent nuclear operation.
The new nuclear management team has developed comprehensive plans for
restarting each of the Millstone units. The Company currently anticipates
that Millstone 3 will be ready for restart by the end of the third quarter
of 1997, Millstone 2 in the fourth quarter of 1997 and Millstone 1 in the
first quarter of 1998. Because of the need for completion of independent
inspections and reviews and for the NRC to complete its processes before
the NRC Commissioners can vote on permitting a unit to restart, the actual
beginning of operations is expected to take several months beyond the time
when a unit is declared ready for restart. The NRC's internal schedules at
present indicate that a meeting of the Commissioners to act upon a
Millstone 3 restart request could occur by mid-December if NU, the
independent review teams and NRC staff concur that the unit can return to
operation by that time. A similar schedule indicates a mid-March meeting
of the Commissioners to act upon a Millstone 2 restart request. Management
hopes that Millstone 3 can begin operating by the end of 1997. There can
be no assurances, however, that the Company's expectations will be met.
Before and following notification to the NRC that a unit is ready to
resume operations, management expects that the NRC staff will conduct
extensive reviews and inspections, and before such notification,
independent corrective action verification teams also will inspect each
unit. The NU system also will need to comply with an NRC order regarding
the development of a comprehensive employee concerns program, which will
need to be reviewed by an independent third party. Furthermore, because of
the length of the outages, management cannot estimate the time it will take
for the units to resume full power after NRC approval to restart.
For more information regarding specific regulatory actions related to
NU's nuclear units and the December 4, 1996 decision of the board of
directors of Connecticut Yankee Atomic Power Company (CYAPC) to retire CY
from commercial operation, see "--Electric Operations--Nuclear Generation."
For information regarding actions taken to meet NU system capacity needs
caused by the Millstone outages, see "--Electric Operations--Distribution
and Load."
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As a result of the extended Millstone outages, the NU system companies
have incurred and will continue to bear substantial costs at least until
the three Millstone units have been restarted. Most of the costs are being
borne by the Company and WMECO, which have the greatest investment share of
the Millstone units. In 1996, the Company expensed a total of
approximately $322 million for Millstone-related non-fuel O&M costs, which
included among other costs $93 million for non-fuel incremental O&M costs
related to the Millstone outages and $50 million reserved for future
Millstone incremental O&M costs.
Based on a recent review of work efforts and budgets, management
believes that the overall 1997 nuclear spending levels for both projected
nuclear O&M expenditures and associated support services and projected
capital expenditures will be slightly higher than previously estimated.
1997 projected nuclear O&M expenditures and related support services are
expected to increase, while 1997 projected capital expenditures are
expected to decrease. For further information concerning estimated 1997
spending levels, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and notes to the Company's
Consolidated Financial Statements, Notes 11B and 11E.
The Company also expensed approximately $216 million for replacement
power costs in 1996. Management cannot predict when the NRC will allow any
of the Millstone units to return to service and thus cannot estimate the
total replacement power costs the Company will ultimately incur.
Replacement power costs incurred by the Company attributable to the
Millstone outages averaged approximately $23 million per month during the
first six months of 1997, and are projected to average approximately $21
million per month for the remainder of 1997. The Company expensed a
significant portion of its 1996 replacement power costs related to the
nuclear outages and it is continuing to expense 1997 replacement power
costs. Based on current estimates of expenditures and restart dates,
management believes the NU system has sufficient resources to fund the
restoration of the Millstone units and related replacement power costs.
Management has committed not to seek recovery of the portion of these
costs attributable to the failure to meet industry standards in operating
Millstone. In light of that commitment, management has said that the
Company will not seek recovery of a substantial portion of such costs.
While the Company believes that it is entitled to recovery of a portion of
the costs that have been and will be incurred, and intends to apply for
recovery of such costs, the DPUC on June 27, 1997 orally granted summary
judgment in a prudence proceeding disallowing recovery by the Company of
most of its Millstone outage related costs. On July 30, 1997, the DPUC
issued a purported "written decision" in the same case, which disallowed
recovery of an estimated $600 million of replacement power costs related to
the Millstone outages, and found that the Company had waived recovery of an
additional $360 million of incremental O&M. The written decision, like the
oral decision, recognized the Company's right to seek recovery, in a future
rate proceeding, of $40 million related to reliability enhancements. The
Company has appealed the DPUC's decision. Management currently does not
intend to request any such cost recoveries until after the Millstone units
begin returning to service, so it is unlikely that any additional revenues
from any permitted recovery of these costs will be available while the
units are out of service to contribute to funding the recovery efforts.
Any requests for recovery would include only costs for projects the Company
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<PAGE>
would have undertaken under normal operating conditions or that provide
long-term value for the Company's customers.
The Company has arranged a variety of borrowing facilities to fund its
cash requirements, including the nuclear recovery efforts. See "--Financing
Program--1997 Financing Requirements." The length of the Millstone outages
and the high costs of the recovery efforts weakened the Company's 1996
earnings, balance sheet and cash flows, and they continue to have a
significant negative impact on the Company's earnings. The Company had a
net loss of approximately $70 million in the first half of 1997. In 1997,
while all three units are out of service the Company expects to continue
operating at a loss. Management believes that the borrowing facilities that
are currently in place provide the Company with adequate access to the
funds needed to bring the Millstone units back to service if those units
begin operating close to the currently envisioned schedules and if the
other assumptions, on which management has based its planning, do not
substantially change.
If the return to service of one or more Millstone units is delayed
substantially, or if any needed waivers or modifications to the Company's
financing arrangements are not forthcoming on reasonable terms, or if the
Company encounters additional significant costs or other significant
deviations from management's current assumptions, the currently available
borrowing facilities could be insufficient to meet all of the Company's
cash requirements, and some facilities could become unavailable because of
difficulties in meeting borrowing conditions. In those circumstances,
management would take actions to reduce costs and cash outflows and would
attempt to take actions to arrange additional sources of funds. The
availability of such sources would be dependent on general market
conditions and the Company's and the NU system's credit and financial
condition at the time. Both Moody's and S&P have recently downgraded the
Company's senior debt to Ba1 and BB+, respectively.
Electric Operations
Distribution and Load
The NU system companies own and operate a fully integrated electric
utility business. The Company's retail electric service territory covers
approximately 4,400 square miles and has an estimated total population of
approximately 2.5 million. The Company furnishes retail electric franchise
service in 149 cities and towns in Connecticut. In December 1996 the
Company furnished retail electric franchise service to approximately 1.1
million customers.
The following table shows the sources of the Company's 1996 electric
revenues based on categories of customers:
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<PAGE>
<TABLE>
<CAPTION>
<S> <C>
Residential........................ 42%
Commercial......................... 35
Industrial......................... 13
Wholesale*......................... 8
Other.............................. 2
---
Total.............................. 100%
</TABLE>
* Includes capacity sales
Through December 31, 1996, the all-time peak demand on the NU
system was 6,358 MW, which occurred on August 2, 1995. At the time of the
peak, the NU system's generating capacity, including capacity purchases,
was 8,035 MW.
NU system energy requirements were met in 1996 and 1995 as set
forth below:
<TABLE>
<CAPTION>
Source 1996 1995
------- ----- -----
<S> <C> <C>
Nuclear.......... 28% 52%
Oil.............. 12 4
Coal............. 11 10
Hydroelectric.... 5 3
Natural gas...... 3 5
NUGs............. 13 13
Purchased-power.. 28 13
---- ----
100% 100%
</TABLE>
The actual changes in retail KWh sales for the last two years and
the forecasted sales growth estimates for the ten-year period 1996 through
2006, in each case exclusive of wholesale revenues, for the Company are set
forth below:
<TABLE>
<CAPTION>
1996 compared to 1995 compared to Forecast 1996-2006
1995 1994 Compound Rate of Growth
- ------------------ ----------------- ------------------------
<S> <C> <C>
1.8% (.3)% 1.1%
</TABLE>
Retail electric sales for the Company rose by 1.8 percent in 1996
compared to 1995, primarily due to moderate growth in the residential and
commercial classes, which increased by 2.0 and 2.9 percent, respectively,
in 1996. Industrial sales decreased by 1.0 percent in 1996. Weather has
had a minimal effect on 1996 growth rates because the increase in winter
heating requirements due to abnormally cold winter weather was offset by
the decrease in summer cooling requirements due to a relatively cool
summer.
In spite of further defense and insurance curtailments, moderate
growth is forecasted to resume over the next ten years. The forecasted
annual growth rate for the Company of one percent
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<PAGE>
is significantly below historic rates due to a general slow down of
economic growth in the region and, in part, because of forecasted savings
from Company-sponsored DSM programs that are designed to minimize operating
expenses for Company customers and reduce their demand for electricity. The
forecasted ten-year annual growth rate of the Company sales would be
approximately 1.7 percent if the Company did not pursue DSM programs at the
forecasted levels. See "--Rates" for information about rate treatment of
DSM costs.
The Company also acts as both a buyer and a seller of electricity in
the highly competitive wholesale electricity market in the Northeastern
United States (Northeast). The Company's revenues from long-term contracts
were $188 million in 1995 and $177 million in 1996, and are expected to be
at approximately the same level in 1997. The Company's most important
wholesale market at this time remains New England.
With the NU system's generating capacity of 8,034 MW (which includes
the Millstone units) as of January 1, 1997 (including the net of capacity
sales to and purchases from other utilities, and approximately 660 MW of
capacity purchased from NUGs under existing contracts), the NU system
expects to meet reliably its projected annual peak load growth of 1.6
percent until at least the year 2010 without adding new capacity.
The NU system companies operate and dispatch their generation as
provided in the New England Power Pool (NEPOOL) Agreement (as defined
below). In 1996, the peak demand on the NEPOOL system was 19,507 MW in
August, which was 992 MW below the 1995 peak load of 20,499 MW in July of
that year. NEPOOL has projected that there will be an increase in demand
in 1997 and estimates that the summer 1997 peak load could reach 21,390 MW.
Management expects that the NU system and NEPOOL will have sufficient
capacity to meet peak load demands for New England even if Millstone and
the 300 MW Long Island Cable are not operational at any time during the
1997 summer season, so long as the remaining generating units and
transmission systems in Connecticut and the New England region have normal
operability. If high levels of unplanned outages in New England were to
occur, or if any of the NU system's transmission lines used to import power
from other states were unavailable at times of peak load demand, NU and the
other New England utilities may have to resort to operating procedures
designed to reduce load. The Company spent approximately $60 million in
1996 to reduce the risk of unplanned outages and expects to spend
approximately $55 million in 1997. Most of the money budgeted for 1997
will be used to improve the NU system's network of transmission lines to
increase imports into Connecticut and for lease payments for additional
capacity.
Regional and System Coordination
The NU system companies and most other New England utilities are
parties to an agreement (NEPOOL Agreement), which coordinates the planning
and operation of the region's generation and transmission facilities. NU
system transmission lines form part of the New England transmission system
linking NU system generating plants with one another and with the
facilities of other utilities in the Northeast and Canada. The generating
facilities of all NEPOOL participants are dispatched
-49-
<PAGE>
as a single system through the New England Power Exchange, a central
dispatch facility. The NEPOOL Agreement provides for a determination of the
generating capacity responsibilities of participants and certain
transmission rights and responsibilities. NEPOOL's objectives are to assure
that the bulk power supply of New England and adjoining areas conforms to
proper standards of reliability, to attain maximum practical economy in the
bulk power supply system consistent with such reliability standards and to
provide for equitable sharing of the resulting benefits and costs.
Pursuant to the NEPOOL Agreement, if a participant is unable to meet
its capacity responsibility obligations, the participant is required to pay
NEPOOL a deficiency charge based on the cost of a proxy generating unit .
In the event that none of the Millstone units is returned to service by
November 1, 1997, the NU system companies could be required to begin paying
this deficiency charge under the NEPOOL Agreement. Management, however,
expects to meet its capacity responsibility obligations even if the
Millstone units do not return to service as currently scheduled through
purchased power contracts with other utilities and/or reactivating NU
system fossil generating units and thus avoid the deficiency charge. The
costs of these alternative plans cannot be estimated at this time.
A restated and revised NEPOOL Agreement, providing for pool-wide open
access transmission tariff and a proposal for the creation of an
Independent System Operator (ISO), became effective on March 1, 1997.
Under these new arrangements (1) the ISO, a non-profit corporation, whose
board of directors and staff will not be controlled by or affiliated with
market participants, will ensure the reliability of the NEPOOL transmission
system, administer the NEPOOL tariff and oversee the efficient and
competitive functioning of the regional power market, (2) the NEPOOL tariff
will provide for non-discriminatory open access to the regional
transmission network at one rate regardless of transmitting distance for
all transactions, and (3) the new NEPOOL Agreement will establish a broader
governance structure for NEPOOL and develop a more open, competitive market
structure.
There are two agreements that determine the manner in which costs and
savings are allocated among the NU system companies. Under an agreement
among the Company, WMECO and HWP (Initial System Companies), such parties
pool their electric production costs and the costs of their principal
transmission facilities (NUG&T). Pursuant to the merger agreement between
NU and PSNH, the Initial System Companies and PSNH entered into a ten-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.
Transmission Access and FERC Regulatory Changes
On April 24, 1996, FERC issued its final open access rule (the Rule)
to promote competition in the electric industry. As required by the Rule,
all public utilities that own, control or operate facilities used for
transmitting electric energy in interstate commerce must file an open
access, non-discriminatory transmission tariff and take transmission
service for their own new wholesale sales and purchases under the open
access tariffs. The Rule also requires public utilities to develop and
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<PAGE>
maintain a same-time information system that will give existing and
potential transmission users the same access to transmission information
that the public utility enjoys, and requires public utilities to separate
transmission from generation marketing functions and communications. The
Rule also supports full recovery of legitimate, prudent and verifiable
wholesale strandable investments. On February 26, 1997, FERC reaffirmed
the Rule with a few minor clarifications.
On July 8, 1996, NU refiled its transmission tariffs to conform with
the minimum terms and conditions set forth in the Rule. On December 31,
1996, NU filed amendments to its transmission tariff and several other
compliance filings to meet the Rule's year-end requirements, including
standards of conduct ensuring that transmission and wholesale generation
personnel function independently. As of January 3, 1997, NU operates
pursuant to the requirements of the standards of conduct and participates
in a NEPOOL-wide Open Access Same-Time Information System, which provides
transmission customers with electronic access to information on available
capacity, tariffs and other information. On January 22, 1997, NU refiled
its transmission tariff to account for certain transmission services that
would be provided by NEPOOL under the new NEPOOL Agreement (discussed
above), which was filed on December 31, 1996.
In 1996, the Company collected approximately $30 million in
incremental transmission revenues from other electric utility generators.
Fossil Fuels
In 1996, 12 percent and 11 percent of the NU system's generation was
oil and coal-derived, respectively. The Company's residual oil-fired
generation stations used approximately 5.8 million barrels of oil in 1996.
The Company obtained the majority of its oil requirements in 1996 through
contracts with several large, independent oil companies. Those contracts
allow for some spot purchases when market conditions warrant. Spot
purchases represented approximately 15 percent of the Company's fuel oil
purchases in 1996. The contracts expire annually or biennially. The
Company currently does not anticipate any difficulties in obtaining
necessary fuel oil supplies on economic terms.
The Company has four generating stations, aggregating approximately
2,060 MW, which can fully or partially burn either residual oil or natural
gas, as economics, environmental concerns or other factors dictate. In
addition, the Company has converted two of the four units at its oil-fired
Middletown Station in Connecticut comprising approximately 350 MW of
capacity to a dual-fuel generating facility. The Company has contracts with
the local gas distribution companies where the dual-fuel generating units
are located, under which natural gas is made available by those companies
on an interruptible basis. In addition, gas for the Company's Devon and
Montville generating stations is being purchased directly from producers
and brokers on an interruptible basis and transported through the
interstate pipeline system and the local gas distribution company. The
Company expects that interruptible natural gas will continue to be
available for its dual-fuel electric generating units on economic terms and
will continue to economically supplement fuel oil requirements.
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<PAGE>
Nuclear Generation
General
Certain NU system companies have joint ownership interests in four
operating nuclear units, Millstone 1, 2 and 3 and Seabrook 1, and equity
interests in four regional nuclear companies (the Yankee Companies) that
separately own CY, MY, Vermont Yankee (VY) and the Yankee Rowe nuclear
generating facility (Yankee Rowe). NU system companies operate the three
Millstone units and Seabrook 1. Yankee Rowe was permanently removed from
service in 1992, CY was permanently removed from service on December 4,
1996 and MY was permanently removed from service on August 6, 1997. The NU
system companies will have responsibility for administering the
decommissioning of CY.
The Company 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.
The Company, PSNH and WMECO have agreements with other New England
utilities covering their joint ownership as tenants in common of Millstone
3. The Company's ownership interest in the unit is 52.93 percent, PSNH's
ownership interest in the unit is 2.85 percent and WMECO's interest is
12.24 percent. NAEC and the Company have 35.98 percent and 4.06 percent
ownership interests, respectively, in Seabrook. 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. The Company 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 the Company and WMECO
would only be liable for damages to the non-NU owners for a deliberate
breach of the agreement pursuant to authorized corporate action.
The Company, 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 costs of
the respective Yankee company and are entitled to proportional shares of
the electrical output. 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. The Yankee Companies and the Company's,
PSNH's and WMECO's stock ownership percentages in the Yankee Companies are
set forth below:
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<PAGE>
<TABLE>
<CAPTION>
CL&P PSNH WMECO NU system
----- ---- ----- ---------
<S> <C> <C> <C> <C>
Connecticut Yankee Atomic
Power Company (CYAPC)...................... 34.5% 5.0% 9.5% 49.0%
Maine Yankee Atomic Power
Company.................................... 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%
</TABLE>
The Company is obligated to provide its percentage of any
additional equity capital necessary for the Yankee Companies, but does not
expect to need to contribute additional equity capital in the future. The
Company believes that VY could require additional external financing in the
next several years to finance construction expenditures, nuclear fuel and
for other purposes. Although the ways in which VYNPC would attempt to
finance these expenditures, if they are needed, have not been determined,
the Company could be asked to provide further direct or indirect financial
support for these companies.
The operators of Millstone 1, 2 and 3, MY, VY and Seabrook 1 hold
full power operating licenses from the NRC. As holders of licenses to
operate nuclear reactors, the Company, WMECO, North Atlantic Energy Service
Corporation (NAESCO), NNECO and the Yankee Companies 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 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. For information regarding
recent actions taken by the NRC with respect to the NU system's nuclear
units, see "--Overview of Nuclear and Related Financial Matters" and "--
Nuclear Generation--Nuclear Plant Performance and Regulatory Oversight."
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<PAGE>
Nuclear Plant Performance and Regulatory Oversight
Millstone Units
Millstone 1, 2 and 3 are located in Waterford, Connecticut and
have license expirations of October 6, 2010, July 31, 2015 and November 25,
2025, respectively and are currently out of service. These units are
presently on the NRC's watch list as Category 3 plants, the lowest such
category. Plants in this category are required to receive formal NRC
Commissioners' approval to resume operations.
Millstone 1 began a planned refueling and maintenance outage on
November 4, 1995. Millstone 2 was shut down on February 21, 1996 as a
result of an engineering evaluation that determined that some valves could
be inoperable in certain emergency scenarios. On March 30, 1996, Millstone
3 was shut down by NNECO following an engineering evaluation which
determined that four safety-related valves would not be able to perform
their design function during certain postulated events.
Each of these outages has been extended in order to respond to
various NRC requests to describe actions taken, including the resolution of
specific technical issues, and to ensure that future operation of the units
will be conducted in accordance with the terms and conditions of their
operating licenses, NRC regulations and their Updated Final Safety Analysis
Report. The NU system also must demonstrate that it maintains an effective
corrective action program for Millstone, as required by NRC regulations, to
identify and resolve conditions that are adverse to safety or quality. For
more information regarding nuclear management changes and costs related to
the outages, see "--Overview of Nuclear Matters and Related Financial
Matters."
Based upon management's current plans, it is estimated that
Millstone 3 will be ready for restart by the end of the third quarter of
1997, Millstone 2 in the fourth quarter of 1997, and Millstone 1 in the
first quarter of 1998. Prior to and following notification to the NRC that
the units are ready to resume operations, management expects that the NRC
staff will conduct extensive reviews and inspections, and prior to such
notification, independent corrective action verification teams (as
discussed more fully below) also will inspect each unit. The NU system
also will need to comply with an NRC order regarding the implementation of
a comprehensive employee concerns program, which will need to be reviewed
by an independent third party (as discussed more fully below). The units
will not be allowed to restart without an affirmative vote of the NRC
Commissioners following completion of these reviews and inspections.
Because of the need for completion of independent inspections and reviews
and for the NRC to complete its processes before the NRC Commissioners can
vote on permitting a unit to restart, the actual beginning of operations is
expected to take several months beyond the time when a unit is declared
ready for restart. The NRC Commissioners' vote on a Millstone 3 restart
request could occur by mid-December if NU, the independent review teams and
NRC staff concur that the unit can return to operation by that time.
Management hopes that Millstone 3 can begin operating by the end of 1997.
Because of the length of the outages, however, management cannot estimate
the time it will take for the units to resume full power after NRC approval
to restart.
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<PAGE>
On August 14, 1996, the NRC issued an order confirming NNECO's
agreement to conduct an Independent Corrective Action Verification Program
(ICAVP) prior to the restart of each of the Millstone units. The order
requires that an independent, third-party team, whose appointment is
subject to NRC approval, verify the results of the corrective actions taken
to resolve identified design and configuration management issues. NNECO
has submitted to the NRC its selection of an ICAVP contractor for each of
the units and the NRC has approved those selections. The ICAVP for
Millstone 3 began on May 27, 1997, as scheduled. On June 30, 1997, the
Company announced that Millstone 2 was ready to begin the ICAVP, as
scheduled, and requested that the NRC identify the particular systems to be
reviewed by the Millstone 2 ICAVP contractor. The ICAVP is expected to end
in mid-November 1997 for Millstone 3 and late November 1997 for Millstone
2. The NRC Operational Safety Team Inspection for Millstone 3 is expected
to begin in October 1997.
In the fall of 1996, the NRC established a Special Projects
Office to oversee inspection and licensing activities at Millstone. The
Special Projects Office is responsible for (1) licensing and inspection
activities at Millstone, (2) oversight of the independent corrective action
verification program, (3) oversight of NU's corrective actions related to
safety issues involving employee concerns, and (4) inspections necessary to
implement NRC oversight of the plants' restart activities.
On December 5, 1996, the NRC conducted an enforcement conference
regarding numerous apparent regulatory violations at Millstone that were
discovered during routine and special inspections at the units between
November 1995 and November 1996. It is likely that this proceeding will
result in the issuance of notices of violation and the imposition of
significant civil penalties for each of the Millstone units.
In addition to the various technical and design basis issues at
Millstone, the NRC continues to focus on the NU system's response to
employee concerns at the units. On October 24, 1996, the NRC issued an
order that requires NNECO to devise and implement a comprehensive plan for
handling safety concerns raised by Millstone employees and for assuring an
environment free from retaliation and discrimination. The NRC also ordered
NNECO to contract for an independent third party to oversee this
comprehensive plan. The members of the independent third-party organization
must not have had any direct previous involvement with activities at
Millstone and must be approved by the NRC. Oversight by the third-party
group will continue until NNECO demonstrates, by performance, that the
conditions leading to this order have been corrected. NNECO has submitted
to the NRC its selection of the third-party oversight organization and the
NRC has approved that selection. NNECO has submitted to the NRC its
comprehensive employee concerns plan.
On March 7, 1997, the NRC issued a letter to NNECO confirming
NNECO's commitment to evaluate and correct problems identified within its
licensed operator training programs at Millstone and CY. On June 27, 1997,
NNECO temporarily suspended all nuclear training programs at Millstone to
address programmatic deficiencies identified by NNECO and NRC inspectors
during reviews of the NU system's licensed operator training programs at
Millstone and CY.
Since then, a Training Restart Plan has been established and various
training programs have been restarted, including the licensed operator
training programs for Millstone. Management continues to believe
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<PAGE>
that the suspension will not affect the schedule to restart the Millstone
units See "Legal Proceedings--NRC Office of Investigations and U.S.
Attorney Investigations and Related Matters."
Nuclear management is investigating the cause of a temperature
rise in the Millstone 3 spent fuel pool that occurred during the last week
of June 1997. Preliminary analysis indicates that the cause of the event
was an incomplete changeover from one cooling system to another. Nuclear
management does not believe that this incident, when considered in
isolation, presented a significant safety issue, but is taking steps to
prevent it from recurring and identify lessons to be learned from the
event. The NRC has been informed of the event but is not expected to impose
any material sanctions on the Company. However, the event has indicated to
nuclear management that further focus on operational matters will be
necessary to ensure proper operation of the units.
For information regarding replacement power costs and incremental
nuclear O&M costs associated with the extended Millstone outages, see "Risk
Factors--Nuclear Plant Outages and Liquidity" and "--Overview of Nuclear
and Related Financial Matters." For information regarding the
recoverability of these costs, see "--Rates." For information regarding
the 1996 nuclear workforce reduction, see "Employees." For information
regarding criminal investigations by the NRC's Office of Investigations
(OI) and the Office of the U.S. Attorney for the District of Connecticut
related to various matters at Millstone and CY; certain citizens petitions
related to NU's nuclear operations; and joint owner litigation related to
the extended outages, see "Legal Proceedings."
Seabrook
Seabrook 1, a 1,148-MW pressurized-water reactor, has a license
expiration date of October 17, 2026. The Seabrook operating license
expires 40 years from the date of issuance of authorization to load fuel,
which was about three and one-half years before Seabrook's full-power
operating license was issued. The NU system will determine at the
appropriate time whether to seek recapture of some or all of this period
from the NRC and thus add up to an additional three and one-half years to
the operating term for Seabrook. In 1996, Seabrook operated at a capacity
factor of 96.5 percent. On June 28, 1997, the unit completed a planned
refueling and maintenance outage that lasted 50 days.
On October 9, 1996, the NRC issued a request for information
concerning all nuclear plants in the United States, except the three
Millstone units and CY, which had previously received such requests. Such
information will be used to verify that these facilities are being operated
and maintained in accordance with NRC regulations and the unit's specific
licenses. The NRC has indicated that the information will be used to
determine whether future inspection or enforcement activities are warranted
for any plant. NAESCO has submitted its response to the NRC's request
with respect to Seabrook. Seabrook's operations have not been restricted by
the request. The NRC's April 1996 comprehensive review found Seabrook to be
a well-operated facility without any major safety issues or weaknesses and
noted that it would reduce its future inspections in a number of areas as a
result of its findings.
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<PAGE>
Yankee Units
Connecticut Yankee. CY, a 582-MW pressurized-water reactor, has
a license expiration date of June 29, 2007. On July 22, 1996, CY began an
unscheduled outage as a precautionary measure to evaluate the plant's
service water system, which provides cooling water to certain critical
plant components. On August 8, 1996, after evaluating certain other
pending technical and regulatory issues, CY's management decided to delay
the restart of the unit and to begin a scheduled September refueling
outage. The refueling outage was accelerated in order to allow time to
resolve the pending issues.
On December 4, 1996, the board of directors of CYAPC voted
unanimously to retire CY. The decision to shut down CY was based on
economic analyses that showed that shutting down the unit prematurely and
incurring replacement power costs could produce potential savings compared
to the costs of operating it over the remaining period of the unit's
operating license. These analyses indicated that this shutdown decision
could produce savings in excess of $130 million on a net present value
basis. These analyses did not consider the costs of addressing concerns
about CY's design and licensing basis raised by the NRC during the summer
of 1996 similar to those raised at Millstone. If these costs had been
considered, the economic analyses would have favored shutdown by an even
greater margin. CYAPC has undertaken a number of regulatory filings
intended to implement the decommissioning. For more information regarding
the CYAPC revised decommissioning estimate that was submitted to FERC in
December 1996, see "--Decommissioning."
In late December 1996, CY filed amendments to its power contracts
with FERC to clarify any obligations of its purchasing utilities, including
the Company. This filing estimated the unrecovered obligations, including
the funding of decommissioning, to be approximately $762.8 million. On
February 27, 1997, FERC approved an order for hearing which, among other
things, accepted CY's contract amendments for filing and suspended the new
rates for a nominal period. The new rates became effective March 1, 1997,
subject to a refund. At June 30, 1997, the Company's share of the CY
unrecovered contractual obligation which also has been recorded as a
regulatory asset, was approximately $235 million.
Based upon FERC regulatory precedent, CYAPC believes it will be
allowed to continue to collect from its power purchasers, including the
Company, WMECO and PSNH, CYAPC's decommissioning costs, the owners'
unrecovered investments in CYAPC, and other costs associated with the
permanent closure of the plant over the remaining period of its NRC
operating license. Management in turn expects that the Company, WMECO and
PSNH will continue to be allowed to recover such FERC-approved costs from
their customers.
On May 12, 1997 the NRC staff assessed a $650,000 fine against
CYAPC for more than 70 alleged violations of regulatory requirements, which
CYAPC paid on June 13, 1997. Most of the violations cited by the NRC
pertain to numerous longstanding deficiencies in engineering programs and
practices, as well as errors related to an event involving a nitrogen
buildup in the reactor vessel in 1996.
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<PAGE>
As confirmed by the NRC on March 4, 1997, CYAPC has agreed to
undertake various steps to resolve deficiencies and weaknesses in the
radiation protection program at CY. Management does not believe that this
undertaking will have a material adverse effect on the NU system companies
or CYAPC.
Maine Yankee. The Company has a twelve percent equity ownership
interest in MYAPC. At June 30, 1997, the Company's equity investment in
MYAPC was approximately $8.9 million. The NU system companies had relied on
MY for approximately two percent of their capacity. On August 6, 1997, the
board of directors of MYAPC voted unanimously to cease permanently the
production of power at MY. MYAPC has begun to prepare the regulatory
filings intended to implement the decommissioning and the recovery of
remaining assets of MYAPC. During the latter part of 1997, MYAPC plans to
file an amendment to its power contracts to clarify the obligations of its
purchasing utilities following the decision to cease power production.
MYAPC is currently updating its decommissioning cost estimates. These
estimates are expected to be completed during the third quarter of 1997. At
this time, the Company is unable to estimate its obligation to MYAPC. Under
the terms of the contracts with MYAPC, the shareholders-sponsor companies,
including the Company, are responsible for their proportionate share of the
costs of the unit, including decommissioning. Management expects that the
Company will be allowed to recover these costs from its customers.
Vermont Yankee. VY, a 514-MW boiling water reactor, has a
license expiration date of March 21, 2012. In 1996, VY operated at a
capacity factor of 81.4 percent. VY had a 57-day planned refueling outage
during 1996 that ended on November 1, 1996. The unit expects to begin a
56-day planned refueling and maintenance outage on September 28, 1998.
Yankee Rowe. In 1992, YAEC's owners voted to shut down Yankee
Rowe permanently based on an economic evaluation of the cost of a proposed
safety review, the reduced demand for electricity in New England, the price
of alternative energy sources and uncertainty about certain regulatory
requirements. The power contracts between the Company, PSNH, WMECO, and
other owners and YAEC permit YAEC to recover from each its proportional
share of the Yankee Rowe shutdown and decommissioning costs. For more
information regarding the decommissioning of Yankee Rowe, see "--
Decommissioning."
Nuclear Insurance
The NRC requires nuclear plant licensees to maintain a minimum of
$1.06 billion in nuclear property and decontamination insurance coverage.
The NRC requires that proceeds from the policy following an accident that
exceed $100 million will first be applied to pay expenses. The insurance
carried by the licensees of the Millstone units, Seabrook 1, CY, MY and VY
meets the NRC's requirements. YAEC has obtained an exemption for Yankee
Rowe from the $1.06 billion requirement and currently carries $25 million
of insurance that otherwise meets the requirements of the rule. CYAPC
expects to seek a similar exemption for CY in 1997. For more information
regarding nuclear insurance, see "Commitments and Contingencies--Nuclear
Insurance Contingencies" in the notes to the Company's Consolidated
Financial Statements, Note 11D.
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<PAGE>
Nuclear Fuel
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. The majority of the NU system
companies' uranium enrichment services requirements is provided under a
long-term contract with the United States Enrichment Corporation (USEC), a
wholly-owned United States government corporation. The majority of
Seabrook's uranium enrichment services requirements is furnished through a
Russian trading company. 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.
In August 1995, NAESCO filed a complaint in the United States
Court of Federal Claims challenging the propriety of the prices charged by
the USEC for uranium enrichment services procured for Seabrook Station in
1993. The complaint is an appeal of the final decision rendered by the
USEC contracting officer denying NAESCO's claims, which range from $2.5 to
$5.8 million, and will likely be considered along with similar complaints
that are pending before the court on behalf of 13 other utilities. The
NAESCO complaint has been suspended pending the outcome of an appeal in
another proceeding involving a similar complaint.
As a result of the Energy 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 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 Company's total share of the estimated assessment was approximately
$49.3 million at June 30, 1997 and approximately $49.2 million at December
31, 1996. Management believes that the DOE assessments against the Company
will be recoverable in future rates. Accordingly, the Company has
recognized these costs as a regulatory asset, with a corresponding
obligation on its consolidated balance sheet.
In June 1995, the United States Court of Federal Claims held
that, as applied to YAEC, the Uranium Enrichment Decontamination and
Decommissioning Fund is an unlawful add-on to the bargained-for contract
price for enriched uranium. As a result of that ruling, the federal
government would be required to refund the approximately $3.0 million that
YAEC has paid into the fund since its inception. On May 6, 1997, the United
States Court of Appeals for the Federal Circuit issued a 2-1 panel decision
reversing the Court of Federal Claims' decision. YAEC has filed a motion
for rehearing en banc with the Appeals Court. NU is evaluating the
applicability of these decisions to
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<PAGE>
the $21 million that the NU system companies have already paid into the
fund for the NU system companies' obligation to pay such special
assessments in the future.
Nuclear fuel costs associated with nuclear plant operations
include amounts for disposal of nuclear waste. The NU system companies
include in their nuclear fuel expense spent fuel disposal costs accepted by
the DPUC, NHPUC and DPU in rate case or fuel adjustment decisions. Spent
fuel disposal costs also are reflected in 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 and high-level waste. As required by the NWPA,
electric utilities generating spent nuclear fuel (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 starting in April 1983 on a quarterly basis since
July 1983. The DPUC, NHPUC and DPU permit the fee to be recovered through
rates.
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 spent nuclear fuel. The NWPA provides that a disposal
facility be operational and for the DOE to accept nuclear waste for
permanent disposal in 1998. On March 3, 1997 CYAPCO, NAESCO and NUSCO
intervened as parties in a lawsuit brought in the U.S. Court of Appeals for
the District of Columbia Circuit by 35 nuclear utilities in late January,
seeking additional action based on the DOE's assertion that it expects to
be unable to begin acceptance of spent nuclear fuel for disposal by January
31, 1998. Among other requests for relief, the lawsuit requests that
utilities be relieved of their contractual obligation with DOE to pay fees
into the Nuclear Waste Fund and be authorized to place such fee payments
into escrow "unless and until" DOE begins accepting spent fuel for
disposal. The DOE's current estimate for an available site is 2010.
Until the federal government begins accepting nuclear waste for
disposal, operating 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 projected life of the unit.
With the implementation of currently planned modifications, the storage
facilities for Millstone 1 and 2 are expected to be adequate (maintaining
the capacity to accommodate a full-core discharge from the reactor) until
2003 and 2004, respectively. Fuel consolidation, which has been licensed
for Millstone 2, could provide adequate storage capability for the
accommodation of all of the SNF at CY. In addition, other licensed
technologies, such as dry storage casks or on-site transfers, are being
considered to accommodate spent fuel storage requirements. With the
current installation of new racks in its existing spent fuel pool, Seabrook
is expected to have spent fuel storage capacity until at least 2010.
The storage capacity of the spent fuel pool at VY is expected to
be reached in 2005 and the available capacity of the pool is expected to be
able to accommodate full-core removal until 2001.
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<PAGE>
Because the Yankee Rowe plant was permanently shut down in
February 1992, YAEC is considering the construction of a temporary facility
to store the spent nuclear fuel produced by the Yankee Rowe plant over its
operating lifetime until that fuel is removed by the DOE.
Low-Level Radioactive Waste
The NU system currently has contracts to dispose its low-level
radioactive waste (LLRW) at two privately operated facilities in Clive,
Utah and in Barnwell, South Carolina.
Because access to LLRW disposal may be lost at any time, the NU system has
plans that will allow for onsite storage of LLRW for at least five years.
Neither Connecticut nor New Hampshire has developed alternatives to out-of-
state disposal of LLRW to date. Both Maine and Vermont are in the process
of implementing an agreement with Texas to provide access to an LLRW
disposal facility that is to be developed in that state. All three states
plan to form an LLRW compact that is currently awaiting approval by
Congress.
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 at
their retirement. The table below sets forth the estimated Millstone and
Seabrook decommissioning costs for the Company. The estimates are based on
the latest site studies, escalated to June 30, 1997 dollars.
<TABLE>
<CAPTION>
(Millions)
<S> <C>
Millstone 1 $ 428.2
Millstone 2 324.6
Millstone 3 282.0
Seabrook 18.8
--------
Total $1,053.6
</TABLE>
As of June 30, 1997, the Company recorded balances (at market) in
its external decommissioning trust funds as follows:
<TABLE>
<CAPTION>
(Millions)
<S> <C>
Millstone 1 $151.9
Millstone 2 100.3
Millstone 3 68.3
Seabrook 2.5
------
Total $323.0
</TABLE>
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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. The DPUC has authorized the Company to collect its current
decommissioning estimate for the three Millstone units from customers.
This estimate includes an approximate 16 percent contingency factor for the
decommissioning cost of each unit.
The decommissioning cost estimates for the Company's nuclear units
are reviewed and updated regularly to reflect inflation and changes in
decommissioning requirements and technology.
Changes in requirements or technology, or adoption of a decommissioning
method other than immediate dismantlement, could change these estimates.
The Company attempts to recover sufficient amounts through its allowed
rates to cover its expected decommissioning costs. Only the portion of
currently estimated total decommissioning costs that has been accepted by
the DPUC and FERC is reflected in rates of the Company. Based on present
estimates, and assuming its nuclear units operate to the end of their
respective license periods, the Company expects that the decommissioning
trust funds will be substantially funded when those expenditures have to be
made.
CYAPC, YAEC, VYNPC and MYAPC are all collecting revenues for
decommissioning from their power purchasers. The table below sets forth
the Company's estimated share of decommissioning costs of the Yankee units.
The estimates are based on the latest site studies, escalated to December
31, 1996 dollars. For information on the equity ownership of the NU system
companies in each of the Yankee units, see "--Electric Operations--Nuclear
Generation--General."
<TABLE>
<CAPTION>
(Millions)
<S> <C>
VYNPC $ 34.8
YAEC* 42.5
CYAPC* 263.2
MYAPC **
</TABLE>
* As discussed more fully below, the costs shown include
all remaining decommissioning costs and other closing costs
associated with the early retirement of Yankee Rowe and CY as of
December 31, 1996. See "--Electric Operations--Nuclear Generation--
Yankee Units--Maine Yankee." The Company expects to recover all
decommissioning costs from its customers pursuant to FERC tariffs.
** MYAPC is currently updating its decommissioning cost estimates.
These estimates are expected to be completed during the
third quarter of 1997. At this time, the Company is unable to
estimate its obligation to MYAPC.
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As of June 30, 1997, the Company's share of the respective
external decommissioning trust fund balances (at market), which have been
recorded on the books of each of the respective Yankee Companies, is as
follows:
<TABLE>
<CAPTION>
(Millions)
<S> <C>
VYNPC $ 16.6
YAEC 31.3
CYAPC 73.9
</TABLE>
<TABLE>
<S> <C>
MYAPC 22.0
------
Total $143.8
</TABLE>
Effective January 1996, YAEC began billing its sponsors, including
the Company, WMECO and PSNH, amounts based on a revised estimate approved
by the FERC that assumes decommissioning by the year 2000. This revised
estimate was based on continued access to the Barnwell, South Carolina,
low-level radioactive waste facility, changes in assumptions about earnings
on decommissioning trust investments, and changes in other decommissioning
cost assumptions.
CYAPC accrues decommissioning costs on the basis of immediate
dismantlement at retirement. In late December 1996, CYAPC made a filing
with FERC to amend the wholesale power contracts between the owners of the
facility, and revise decommissioning cost estimates and other cost
estimates for the facility. The amendments clarify the owners' entitlement
to full recovery of amounts previously invested and the ongoing costs of
maintaining the plant in accordance with NRC rules until decommissioning
begins, and ensures that decommissioning will continue to be funded through
June 2007, the full license term, despite the unit's early shutdown. On
February 26, 1997, FERC approved a draft order setting for hearing the
prudence of the decision to close CY. On February 27, 1997, FERC approved
an order for hearing which, among other things, accepted CYAPC's contract
amendments for filing and suspended the new rates for a nominal period.
The new rates became effective March 1, 1997, subject to refund. FERC will
determine the prudence of CYAPC's decision to retire the plant before it
finally determines the justness and reasonableness of CYAPC's proposed
amended power contract rates.
For more information regarding nuclear decommissioning, see "Nuclear
Decommissioning" in the notes to the Company's Consolidated Financial
Statements, Note 3.
Competition and Cost Recovery
Competition in the energy industry continues to grow as a result of
legislative and regulatory action, technological advances, relatively high
electric rates in certain regions of the country, including New England,
surplus generating capacity and the increased availability of natural gas.
These competitive pressures are particularly strong in the NU system's
service territories, where legislators and regulatory agencies have been at
the forefront of the restructuring movement.
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<PAGE>
A major risk of competition for the Company is "strandable
investments." These are expenditures that have been made by utilities in
the past to meet their public service obligations, with the expectation
that they would be recovered from customers in the future. However, under
certain circumstances these costs might not be recoverable from customers
in a fully competitive electric utility industry. The Company is
particularly vulnerable to strandable investments because of (i) the
Company's relatively high investment in nuclear generating capacity, which
had a high initial cost to build, (ii) state-mandated purchased power
arrangements priced above market, and (iii) significant regulatory assets,
which are those costs that have been deferred by state regulators for
future collection from customers. See "Risk Factors--Industry Restructuring
and Competition."
As of June 30, 1997, the Company's net investment in nuclear
generating capacity, excluding its investment in certain regional nuclear
companies, was approximately $2.3 billion, and in its regulatory assets was
approximately $1.2 billion. The Company expects to recover substantially
all of its nuclear investment and its regulatory assets from customers.
The Company is currently collecting its nuclear investment through
depreciation charges approved by the DPUC. See "Depreciation" in the notes
to the Company's Consolidated Financial Statements. Unless amortization
levels are changed from currently scheduled rates, the Company's regulatory
assets are expected to be substantially decreased in the next five years.
Although the Company continues to operate predominantly in a state-approved
franchise territory under traditional cost-of-service regulation,
restructuring initiatives in the State of Connecticut have created
uncertainty with respect to future rates and the recovery of strandable
investments. See "Risk Factors--Regulatory Accounting and Assets."
In 1995 regulators in Connecticut concluded that electric utilities
should be allowed a reasonable opportunity to recover strandable
investments. Various electric utility restructuring legislative proposals
were introduced in the Connecticut legislature in 1997. On June 4, 1997,
the Connecticut legislature completed its most recent session without
passage of a proposed electric restructuring bill. The legislature may
consider restructuring legislation in the future.
Notwithstanding these legislative and regulatory initiatives, the NU
system has developed, and is continuing to develop, a number of marketing
initiatives to retain and continue to serve its existing customers. In
particular, the NU system has been devoting increasing attention in recent
years to negotiating long-term power supply arrangements with certain large
commercial and industrial retail customers. Approximately 10 percent of
the Company's commercial and industrial retail revenues were under
negotiated rate agreements at the end of 1996. The Company was a party to
negotiated rate agreements which accounted for approximately $19 million of
rate reductions in 1996. The average term of these agreements is
approximately 5.2 years.
The NU system has expanded its retail marketing organization to
provide value-added solutions to its customers. The NU system devoted
significantly more resources to its retail marketing efforts in 1996 than
in prior years. In particular, NUSCO hired approximately 170 new employees
as part of its retail sales organization. The new employees will allow the
NU system to have more direct contact with customers in order to develop
tailor-made solutions for customers' energy needs. In addition, the NU
system companies, as well as other NU subsidiaries, received
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orders from the Commission and FERC in 1996 that increased their
flexibility to market and broker electricity, gas, oil and other forms of
energy throughout the United States and to provide various services related
thereto.
Rates
General
The Company's retail rates are subject to the jurisdiction of the
DPUC. Connecticut law provides that revised rates may not be put into
effect without the prior approval of the DPUC. Connecticut law also
authorizes the DPUC to order a rate reduction under certain circumstances
before holding a full-scale rate proceeding. The DPUC is further required
to review a utility's rates every four years if there has not been a rate
proceeding during such period. On June 16, 1997, the Company filed with
the DPUC certain financial information consistent with the DPUC's filing
requirements applicable to such four year review. The Company expects
hearings before the DPUC with respect to such review to begin during the
summer of 1997. Based on recently enacted legislation, if the DPUC
approves performance-based incentives for a particular company, the DPUC
will include in such an order periodic monitoring and review of the
Company's performance in lieu of the four-year review.
On July 1, 1996, the DPUC approved a settlement agreement
(Settlement) that had been jointly submitted to the DPUC by the Company,
the Connecticut Office of Consumer Counsel (OCC) and the independent
Prosecutorial Division of the DPUC. The Settlement provides that the
Company's base rates will be frozen until at least December 31, 1997. The
Settlement provides that during the rate freeze, the Company's target
return on equity (ROE) will be 10.7 percent, but the Settlement does not
alter Company's allowed ROE of 11.7 percent. One-third of earnings above
the target ROE will be refunded to customers. The Settlement also
accelerated the amortization of the Company's regulatory assets ($73
million in 1996 and $54 to $68 million in 1997). As of June 30, 1997, the
Company's regulatory assets totaled approximately $1.2 billion.
The Settlement terminated all outstanding litigation pending as of
March 31, 1996 among the parties that potentially could affect the
Company's rates. Such litigation included appeals by the Company and the
OCC from the Company's 1993 rate case decision, appeals from the DPUC's
decisions concerning the 1992-1993 and 1993-1994 fuel-recovery periods,
nuclear operating prudence review proceedings pending at the time of the
settlement, and OCC's appeal from the DPUC guidelines adopted in 1995
allowing additional flexibility in negotiating special rates with electric
customers. In exchange, the Company agreed not to seek recovery from its
customers of approximately $115 million in uncollected nuclear costs
incurred before March 31, 1996.
The Settlement does not affect issues to be addressed by the DPUC in
future restructuring proceedings and the recovery of costs related to the
ongoing Millstone outages. For information regarding the prudence
proceeding related to nuclear operations for the period March 31, 1996 to
June 30, 1996. See "--Rates--CL&P Adjustment Clauses and Prudence."
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Electric Industry Restructuring in Connecticut
Pursuant to legislation introduced in 1995, a legislative task force
was created to consider electric industry restructuring in Connecticut.
Although the members of the task force did not come to a consensus on
restructuring, the task force's December 1996 report included several
recommendations on legislation, including, among other things, legislation
to enable securitization of strandable investments; reduction of tax
burdens incorporated in electric rates; reduction of rate impacts of
government-mandated contracts with NUGs; and elimination of obsolete
regulation. On June 4, 1997, the Connecticut legislature completed its
most recent session without passage of a proposed electric industry
restructuring bill. The legislature may consider restructuring legislation
in the future.
CL&P Adjustment Clauses and Prudence
On October 8, 1996, the DPUC issued its final order establishing an
EAC in place of the Company's existing Fuel Adjustment Clause and GUAC.
The EAC took effect on January 1, 1997. The EAC is designed to reconcile
and adjust every six months the difference between actual fuel costs and
the fuel revenue collected through base rates. The EAC includes an
incentive mechanism that disallows recovery of the first $9 million in fuel
costs that exceeds base levels and permits the Company to retain the first
$9 million in fuel cost savings. The EAC also designates a 60 percent
nuclear capacity factor floor. When the six-month nuclear capacity factor
falls below 60 percent, related energy costs are deferred to the subsequent
EAC period for consideration for recovery. Finally, the costs to serve
nonfirm wholesale transactions will continue to be removed from the
calculation of fuel costs at actual marginal cost.
On December 31, 1996, the DPUC issued a decision approving the
Company's request to recover $25 million, excluding replacement power costs
(see below), through the GUAC for the period April 1-July 31, 1996. The
$25 million will be recovered over a twelve-month period beginning January
1, 1997. On June 6, 1997, the Company filed with the DPUC a request to
recover approximately $28 million of fuel costs for the period August 1,
1996 through April 30, 1997, through the EAC, which includes $5.3 million
of fuel costs from 1996, which would have been recovered through the GUAC.
Pursuant to a DPUC order in the prudence proceeding discussed below, the
filing excluded any fuel cost associated with the current outages at
Millstone. On the same date, the DPUC issued a procedural order, which
stated that the Company could not include CY replacement power costs in its
EAC until the DPUC concluded its prudence investigation, discussed more
fully below, and that this prudence decision would be directly affected by
the on-going FERC proceeding regarding the decision to retire CY before the
expiration of its operating license. In response to the June 6, 1997 DPUC
order, the Company revised its EAC filing on June 13, 1997 to identify
approximately $17 million of replacement power costs incurred by the
Company as a result of the retirement of CY on December 4, 1996 . On July
17, 1997, the Company filed an appeal of the June 6th DPUC order. The
Company takes the position that unless and until there is a determination
that such post-retirement costs are unreasonable, it is entitled to current
recovery. See "--Nuclear Plant Performance and Regulatory Oversight--Yankee
Units--Connecticut Yankee" and "--Decommissioning."
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<PAGE>
In connection with an ongoing management audit of the Company,
including matters related to the NRC watch list designation, the two
consulting firms hired by the DPUC to review such matters issued reports in
December 1996 that were highly critical of NU's management of its nuclear
program. The results of these reports may affect future DPUC positions
with respect to the NU system's nuclear-related operations and costs.
Despite an earlier procedural order indicating that prudence
hearings on the current nuclear outages at Millstone would take place after
the nuclear plants return to service, on January 15, 1997, the DPUC
notified the Company that it would be conducting its prudence review of
nuclear cost recovery issues in multiple phases. The first phase, covering
the period April 1 through June 30, 1996, was in progress when various
intervenors moved for summary judgment with respect to the costs for the
entire outage. On June 27, 1997, the DPUC orally granted summary judgment
in the prudence docket, disallowing recovery of substantially costs
associated with the ongoing outages at Millstone. The Company has
projected that its share of the total costs for the Millstone outages,
including replacement power, operation and maintenance and capacity
reliability projects, will be about $990 million. The Company has not
requested cost recovery at this time and has said that it will not seek
recovery for a substantial portion of these costs and will not request any
cost recovery until the units had returned to operation. Any requests by
the Company for recovery would include only costs for projects the Company
would have undertaken under normal operating conditions or that provide
long-term value for the Company's customers. On July 30, 1997, the DPUC
issued a purported "written decision" in the same case, which disallowed
recovery of an estimated $600 million of replacement power costs related to
the Millstone outages, and found that the Company had waived recovery of an
additional $360 million of incremental O&M. The written decision, like the
oral decision, recognized the Company's right to seek recovery, in a future
rate proceeding, of $40 million related to reliability enhancements. The
Company has appealed the DPUC's decision. Management currently does not
intend to request any such cost recoveries until after the Millstone units
begin returning to service, so it is unlikely that any additional revenues
from any permitted recovery of these costs will be available while the
units are out of service to contribute to funding the recovery efforts.
Any requests for recovery would include only costs for projects the Company
would have undertaken under normal operating conditions or that provide
long-term value for the Company's customers. The Company does not expect
this decision to have any immediate material financial impact on 1997
results. The Company has expensed, and continues to expense, the bulk of
the Millstone outage costs as they are incurred. Therefore, the Company
does not expect this decision to have a material financial impact on 1997
results.
In a separate proceeding, the DPUC ordered the Company to submit
studies by July 1, 1997 that analyze the economic benefits from the
continued operation of Millstone 1 and 2. The DPUC stated that these
studies were necessary in light of the uncertainty regarding restart dates
of the units and the costs associated with returning these units to
operation. On July 1, 1997, the Company submitted continued unit operation
studies to the DPUC showing that, under base case assumptions, Millstone 1
will have a value to NU system customers (as compared to the cost of
shutting down the unit and incurring replacement power costs) of
approximately $70 million during the remaining thirteen years of its
operating license and Millstone 2 will have a value to NU system customers
(on the same assumptions as used with Millstone 1) of approximately $500
million during the remaining
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eighteen years of its operating license. Two other cases submitted to the
DPUC based on higher assumed O&M costs, which the Company considers less
likely, indicated that Millstone 1 would be uneconomic in varying degrees.
Based on these economic analyses, the Company expects to continue operating
both Millstone 1 and Millstone 2 for the remaining terms of their
respective operating licenses. The DPUC has stated it will consider these
analyses in the context of the Company's next integrated resource planning
proceeding which begins in April 1998. The Company cannot predict the
outcome of this proceeding.
In May 1996, the Connecticut state legislature enacted legislation
to create the Nuclear Energy Advisory Council (NEAC), a volunteer group of
fourteen members. The NEAC was charged with conducting a broad review of
safety and operations of the NU system's four Connecticut nuclear units and
to advise the Governor, the legislature and affected municipalities on
these issues. The NEAC issued its first report on February 7, 1997, which
provided a wide range of preliminary recommendations, including legislation
and additional public hearings related to nuclear spent fuel, federal
congressional hearings, review by the Connecticut Attorney General of the
NRC's oversight of the NU system's nuclear operations and the requirement
for a state nuclear plant resident inspector. These recommendations are
similar to various legislative proposals currently pending at the state
legislature related to nuclear oversight, operations and cost recovery.
Management cannot predict the ultimate effect of this report or such
proposed legislation.
Demand-Side Management
The Company provides demand-side management (DSM) programs for its
residential, commercial and industrial customers. The Company is allowed
to recover DSM costs in excess of costs reflected in base rates over
periods ranging from approximately two to ten years.
On April 9, 1996, the DPUC issued an order approving the Company's
budget of $37.1 million for 1996 DSM expenditures, which will be recovered
over a 2.43-year amortization period. In November 1996, the Company filed
its 1996 DSM program and forecasted conservation adjustment mechanism (CAM)
for 1997 with the DPUC. The filing proposed expenditures of $36 million in
1997. In April 1997, the DPUC approved 1997 expenditures of $36 million.
The Company's unrecovered DSM costs at December 31, 1996, excluding
carrying costs, which are collected currently, were approximately $90
million.
Resource Plans
Construction
The Company's construction program in the period 1997 through 2001
is estimated as follows:
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
(Millions)
$148 $180 $164 $163 $170
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The 1997 data include costs of approximately $18 million related to
upgrading the Company's transmission facilities to meet capacity needs
caused by the extended Millstone outages. See "--Electric Operations--
Distribution and Load."
The construction program data shown above include all anticipated
capital costs necessary for committed projects and for those reasonably
expected to become committed, regardless of whether the need for the
project arises from environmental compliance, nuclear safety, reliability
requirements or other causes. The construction program's main focus is
maintaining and upgrading the existing transmission and distribution system
and nuclear and fossil-generating facilities.
The construction program data shown above generally include the
anticipated capital costs necessary for fossil-generating units to operate
at least until their scheduled retirement dates. Whether a unit will be
operated beyond its scheduled retirement date, be deactivated or be retired
on or before its scheduled retirement date is regularly evaluated in light
of the NU system's needs for resources at the time, the cost and
availability of alternatives and the costs and benefits of operating the
unit compared with the costs and benefits of retiring the unit. Retirement
of certain of the units could, in turn, require substantial compensating
expenditures for other parts of the NU system's bulk power supply system.
Those compensating capital expenditures have not been fully identified or
evaluated and are not included in the table.
Future Needs
The NU system periodically updates its long-range resource needs
through its integrated demand and supply planning process. While the NU
system does not foresee the need for any new major generating facilities at
least until 2010, it has reactivated some older facilities and leased
additional facilities in 1996 to supplement its capacity requirements due
to the extended Millstone outages.
The NU system's long-term plans rely, in part, on certain DSM
programs. These NU system companies-sponsored measures, including
installations to date, are projected to lower the NU system summer peak
load in 2010 by 703 MW and lower the winter peak load as of January 1, 2011
by 482 MW. See "--Rates" for information about rate treatment of DSM costs.
In addition, NU system companies have long-term arrangements to
purchase the output from certain NUGs under federal and state laws,
regulations and orders mandating such purchases. NUGs supplied 660 MW of
firm capacity in 1996. The NU system companies, including the Company, do
not expect to purchase additional new capacity from NUGs for the
foreseeable future. See "Cogeneration Costs" in the notes to the Company's
Consolidated Financial Statements, Note 1L, for information regarding the
Company's renegotiation of one of its purchased-power agreements.
The NU system's need for new resources may be affected by premature
retirements of existing generating units, regulatory approval of the
continued operation of certain fossil fuel units past scheduled retirement
dates, and the possible deactivation of plants resulting from environmental
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compliance costs, licensing decisions and other regulatory matters. The NU
system's need for new resources also may be substantially affected by
restructuring of the electric industry. For more information regarding
restructuring, see "--Rates."
Financing Program
Recent Financing Activity
On May 21, 1996, the Connecticut Development Authority issued $62
million of tax-exempt pollution control revenue bonds. Concurrent with that
issuance, the proceeds of the bonds were loaned to the Company for the
reimbursement of a portion of the Company's share of the previously
incurred costs of financing, acquiring, constructing, and installing
pollution control, sewage, and solid waste disposal facilities at Millstone
3. The bonds were issued with an initial variable interest rate of 3.7
percent per annum, which is reset on a weekly basis. The bonds will mature
on May 1, 2031 and may bear, at the Company's discretion, a variable or
fixed interest rate, which may not exceed 12 percent. The bonds were
originally backed by a five-year letter of credit, which was secured by a
second mortgage on the Company's interest in Millstone 1. On January 23,
1997, the letter of credit was replaced with an insurance facility and a
standby bond purchase agreement. The second mortgage was replaced with the
issuance of $62 million of First and Refunding Mortgage Bonds, 1996 Series
B, bearing the same interest rate as the underlying bonds.
On June 21, 1996, the Company entered into an operating lease
agreement for the Company to acquire the use of four turbine generators
having an installed cost of approximately $70 million. The initial lease
term is for a five-year period. The lease agreement provides for five
consecutive renewal options under which the Company may lease the turbines
for five additional twelve-month terms. The rental payments are based on a
30-day floating interest rate plus 1 percent. The interest rate averaged
6.4 percent during 1996. Upon termination of the lease agreement, ownership
of the turbines will remain with the lessor, unless the Company exercises
its purchase option. During the first quarter of 1997, it was determined
that the Company would not be in compliance with a financial coverage test
required under the lease agreement. The Company has reached an agreement
with the lessors for a resolution of this matter. Management believes that
the terms and conditions of this agreement will not have a material adverse
impact on the company's financial position or results of operations.
On June 25, 1996, the Company issued $160 million of First and
Refunding Mortgage Bonds, 1996 Series A. The 1996 Series A Bonds bear
interest at an annual rate of 7.875%, and will mature on June 1, 2001. The
net proceeds from the issuance and sale of the 1996 Series A Bonds, plus
funds from other sources, were used to repay approximately $193.3 million
in principal amount of the Company's Series UU bonds, which matured April
1, 1997.
On July 11, 1996, the Company entered into an agreement to sell up to
$200 million of fractional undivided percentage interests in its eligible
accounts receivable and accrued utility revenues with limited recourse. The
agreement provides for a loss reserve pursuant to which additional customer
receivables may be allocated to the purchaser on an interim basis, to
protect
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against bad debt. To the extent actual loss experience of the pool
receivables exceeds the loss reserve, the purchaser absorbs the excess. For
receivables sold, the Company has retained collection and servicing
responsibilities as agent for the purchaser. In order to comply with new
accounting requirements, which were effective January 1, 1997, the
Company's accounts receivable sales agreement is being restructured.
On November 21, 1996, NU, the Company and WMECO entered into a new
three-year Revolving Credit Agreement (the New Credit Agreement) with a
group of banks. On May 30, 1997, the New Credit Agreement was amended to
reflect (i) the provision by the Company of first mortgage bonds in the
principal amount of $225,000,000 and by WMECO of first mortgage bonds in
the principal amount of $90,000,000 as collateral for their respective
obligations under the New Credit Agreement (ii) revised financial covenants
consistent with NU's, the Company's and WMECO's financial forecasts, and
(iii) an upfront payment to the lenders in order to maintain commitments
under the New Credit Agreement. Following such amendment, the Company is
able to borrow up to approximately $225,000,000 (which may increase to
approximately $313,750,000 with the provision of additional first mortgage
bonds as collateral in an amount which would bring the total Company
collateral to $313,750,000) and WMECO will be able to borrow up to
approximately $90,000,000 (which may increase to approximately $150,000,000
with the provision of additional first mortgage bonds as collateral in an
amount which would bring total WMECO collateral to $150,000,000), subject
to a total borrowing limit of $313,750,000 for all three borrowers. NU will
be able to borrow up to $50,000,000 when each of the parties to the New
Credit Agreement has maintained a consolidated operating income to
consolidated interest expense ratio of at least 2.50 to 1 for two
consecutive fiscal quarters. For information regarding issues related to
financial covenants under the New Credit Agreement, see "--Financing
Limitations" below.
On April 17, 1997, the holders of approximately $38 million of notes
issued by RRR required RRR to repurchase the notes at par. The notes are
secured by real estate leases between RRR as lessor and NUSCO as lessee. On
July 1, 1997, RRR received commitments for the purchase of approximately
$12 million of notes and RRR repurchased the remaining $26 million of notes
on July 14, 1997. On July 30, 1997, approximately $6 million of the $12
million was purchased by an alternative purchaser. The remaining $6 million
of the notes is expected to be purchased by another purchaser by September
2, 1997. See the notes to the Company's Consolidated Financial Statements,
Note 11G for further information.
Total Company debt, including short term and capitalized lease
obligations, was approximately $2.3 billion as of June 30, 1997, compared
with $2.19 billion as of December 31, 1996. For more information regarding
Company financing, see the notes to the Company's Consolidated Financial
Statements and "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
In April, 1997, Moody's downgraded most of the securities ratings of
the Company and WMECO because of the extended Millstone outages. In May,
1997, S&P downgraded the Company and WMECO securities as a result of the
Connecticut legislature's failure to approve a utility restructuring bill
during the recently completed legislative session. As a result, all Company
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securities are currently rated below investment grade by Moody's and S&P.
These actions will adversely affect the availability and cost of funds for
the Company.
1997 Financing Requirements
The Company's aggregate capital requirements for 1997, exclusive of
requirements under the Niantic Bay Fuel Trust (NBFT) are approximately as
follows:
<TABLE>
<CAPTION>
(Millions)
<S> <C>
Construction $148
Nuclear Fuel 5
Maturities 204
----
Total $357
</TABLE>
For further information on NBFT and the Company's financing of its
nuclear fuel requirements, see "Leases" in the notes to the Company's
Consolidated Financial Statements. For further information on the
Company's 1997 and five-year financing requirements, see "Long-Term Debt"
in the notes to the Company's Consolidated Financial Statements and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." For further information concerning the Company's financing of
operations, see "--Overview of Nuclear and Related Financial Matters" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Financing Limitations
The Company's charter and many of its borrowing facilities contain
financial limitations (as discussed more fully below) that must be
satisfied before borrowings can be made and for outstanding borrowings to
remain outstanding.
The amount of short term borrowings that may be incurred by the
Company is subject to periodic approval by the Commission under the Public
Utility Holding Company Act of 1935 (the Holding Company Act).
As of January 1, 1997, the Company's maximum authorized short term
borrowing limit was $375 million. At December 31, 1996, the Company had no
short-term borrowings outstanding. At June 30, 1997, the Company had short
term borrowings of $100 million.
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, neither NU nor the
Company may dispose of voting stock of the Company other than to NU or
another NU system company, except that the
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Company 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
the Company's voting stock after the sale.
The Company's charter contains preferred stock provisions restricting
the amount of unsecured debt the Company may incur. As of June 30, 1997,
the Company's charter permits the Company to incur an additional
$408,914,000 of unsecured debt.
In connection with NU's acquisition of PSNH, the DPUC imposed certain
financial conditions intended to prevent NU from relying on the Company's
resources if the PSNH acquisition strained NU's financial condition. The
principal conditions provided for a DPUC review if the Company's common
equity ratio falls to 36 percent or below, require NU to obtain DPUC
approval to secure NU financings with the Company's stock or assets and
obligate NU to use its best efforts to sell the Company's preferred or
common stock to the public if NU cannot meet the Company's need for equity
capital. If, at any time, the Company projects that its common equity
ratio as of the end of the next fiscal quarter will be below 36% or plans
to take any action that will result or can reasonably be expected to result
in reducing the above ratio below 36% then the Company is required to
notify the DPUC in writing at least 45 days before such action is taken or
event is anticipated to occur. The DPUC may conduct a proceeding after its
receipt of the Company's notice. At June 30, 1997, the Company's common
equity ratio was 34.1 percent. The Company did not expect to meet this
condition as of June 30, 1997 and notified the DPUC in accordance with the
foregoing requirement.
While not directly restricting the amount of short term debt that the
Company, WMECO, RRR, NNECO and NU may incur, the revolving credit
agreements to which the Company, WMECO, HWP, RRR, NNECO and NU are parties
provide that the lenders are not required to make additional loans, and
that the maturity of indebtedness can be accelerated, if NU (on a
consolidated basis) does not meet a common equity ratio test that requires,
in effect, that NU's consolidated common equity (as defined) be not less
than 30 percent for any three consecutive fiscal quarters. At June 30,
1997, NU's common equity ratio was 32.7 percent.
Additionally, under the New Credit Agreement, the Company is
prohibited from incurring additional debt unless it is able to demonstrate,
on a pro forma basis for the prior quarter and going forward, that its
equity ratio will be at least 31 percent of its total capitalization
through December 31, 1997 and 32 percent thereafter. At June 30, 1997, the
Company's common equity ratio was 32.8 percent. Beginning in the fourth
quarter of 1997, the Company must demonstrate that its ratio of operating
income to interest expense will be at least 1.25 to 1 through December 31,
1997; 1.50 to 1 from January 1, 1998 through June 30, 1998; 2.00 to 1 from
July 1, 1998 through September 30, 1998 and 2.50 to 1 thereafter. For the
three month period ending June 30, 1997, the Company's interest coverage
ratio (computed in accordance with the New Credit Agreement) was negative,
(0.97) to 1.
The Indenture provides that additional bonds may not be issued, except
for certain refunding purposes, unless earnings (as defined in the
Indenture and before income taxes) are at least twice the pro forma annual
interest charges on outstanding bonds and certain prior lien obligations
and
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the bonds to be issued. The Company's 1996 earnings do not permit it to
meet those earnings coverage tests, but as of June 30, 1997, after giving
effect to the amendment of the Indenture to eliminate requirements for the
sinking and improvement fund previously set forth therein, and after giving
effect to the issue of the Old Bonds, the Company would be able to issue up
to approximately $128 million of additional first mortgage bonds on the
basis of previously issued but refunded bonds, without having to meet the
earnings coverage test.
The preferred stock provisions of the Company's charter 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. The Company is currently unable to issue additional preferred
stock under these provisions.
The supplemental indentures under which the Company's first mortgage
bonds have been issued limit the amount of cash dividends and other
distributions the Company can make to NU out of its retained earnings. As
of June 30, 1997, the Company's retained earnings were $72.8 million below
the required level for payment of dividends, and the Company is not
expected to be able to declare any dividends under these provisions in
1997.
Certain subsidiaries of NU, including the Company, have established a
money pool (Money Pool), a system for the pooling of funds established by
certain of the NU system companies to provide a more effective use of their
cash resources and to reduce outside short-term borrowings. NUSCO
administers the Money Pool as agent for the participating companies.
Short-term borrowing needs of the participating companies (except NU) are
first met with available funds of other member companies, including funds
borrowed by NU from third parties. NU may lend to, but not borrow from,
the Money Pool. Investing and borrowing subsidiaries receive or pay
interest based on the average daily Federal Funds rate, except that
borrowings based on loans from NU bear interest at NU's cost. Funds may be
withdrawn or repaid to the Money Pool at any time without prior notice.
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. Similarly,
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
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limit operations or require substantial investments in new equipment at
existing facilities. See "--Resource Plans" for a discussion of the NU
system's construction plans.
Surface Water Quality Requirements
The Federal Clean Water Act (CWA) requires "point source" discharge 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 have all required NPDES permits in effect. Compliance with
NPDES and state water discharge permits has necessitated substantial
expenditures and may require further expenditures because of additional
requirements that could be imposed in the future. For information
regarding ongoing criminal and civil investigations by the Office of the
U.S. Attorney for the District of Connecticut and the Connecticut Attorney
General related to allegations that there were some violations of certain
facilities' NPDES permits, see "Legal Proceedings."
In October 1995, the Connecticut Department of Environmental
Protection (CDEP) issued a consent order to the Company and the Long Island
Lighting Company (LILCO) requiring those companies to address leaks of
dielectric fluids from the Long Island cable, which is jointly owned by the
Company and LILCO. This cable enables the Company to interchange up to 300
MW of capacity with LILCO. In May 1996, the consent order was modified to
address issues relating to a leak, which occurred in January 1996. The
modified order requires the Company and LILCO to study and propose
alternatives for the prevention, detection and mitigation of leaks from the
cable and to evaluate the ecological effects of leaks on the environment.
Alternatives to be studied include cable replacement and alternative
dielectric fluids. These studies are ongoing. The NU system will incur
additional costs to meet the requirements of the order and to meet any
subsequent CDEP requirements that may result from these studies. These
costs, as well as the long-term future and cost-effectiveness of the cable
operation subsequent to any additional CDEP requirements, cannot be
estimated at this time.
The United States Attorney's Office in New Haven, Connecticut has
commenced an investigation and issued subpoenas to the Company, NU, NUSCO,
CONVEX and LILCO seeking documents relating to operation and maintenance of
the cable and the most recent leaks from the cable described above. The
government has not revealed the scope of its investigation, so management
cannot evaluate the likelihood of a criminal proceeding being initiated at
this time. However, management is aware of nothing that would suggest that
any NU system company, officer or employee has engaged in conduct that
would warrant a criminal proceeding. For information regarding a lawsuit
related to discharges from the cable, see "Legal Proceedings."
The ultimate cost impact of the CWA and state water quality
regulations on the Company cannot be estimated because of uncertainties
such as the impact of changes to the effluent guidelines or water quality
standards. Additional modifications, in some cases extensive and involving
substantial cost, may ultimately be required for some or all of the
Company's generating facilities.
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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, including the Company, 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 Company owns facilities and
through which the Company 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 per occurrence for
oil spills.
Air Quality Requirements
The Clean Air Act Amendments of 1990 (CAAA) 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 (CEMs) and expanded
permitting provisions also are included.
Existing and future federal and state air quality regulations,
including recently proposed standards, could hinder or possibly preclude
the construction of new, or the modification of existing, fossil units in
the NU system's service area and could raise the capital and operating cost
of existing units. The ultimate cost impact of these requirements on the
NU system cannot be estimated because of uncertainties about how EPA and
the states will implement various requirements of the CAAA.
Nitrogen Oxide. Title I of the CAAA identifies NOX emissions as a
--------------
precursor of ambient ozone. Connecticut, Massachusetts and New Hampshire,
as well as other Northeastern states, currently exceed the ambient air
quality standard for ozone. Pursuant to the CAAA, states exceeding the
ozone standard must implement plans to address ozone nonattainment. All
three states have issued final regulations to implement Phase I reduction
requirements and the NU system has met these requirements. Compliance with
Phase I requirements has cost the NU system a total of approximately $41
million including $10 million for the Company. Compliance has been
achieved using a combination of currently available technology, combustion
efficiency improvements and emissions trading. Compliance costs for Phase
II, effective in 1999, are expected to result in an additional cost of
approximately $5 million for the Company.
Sulfur Dioxide. The CAAA mandates reductions in SO2 emissions to
--------------
control acid rain. These reductions are to occur in two phases. First,
certain high SO2 emitting plants were required to reduce their emissions
beginning in 1995. All Phase I units have been allocated SO2 allowances for
the period 1995-1999. These allowances are freely tradable. One allowance
entitles a source
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to emit one ton of SO2. No unit may emit more SO2 than the amount for which
it has allowances. The only NU system units subject to the Phase I
reduction requirements are PSNH's Merrimack Units 1 and 2. Newington
Station in New Hampshire and Mt. Tom Station in Massachusetts are
conditional Phase I units, which means that the NU system can decide to
include these plants as Phase I units during any year and obtain allowances
for that year. The NU system included these plants as Phase I units in
1996.
On January 1, 2000, the start of Phase II, a nationwide cap of 8.9
million tons per year of utility SO2 emissions will be imposed and existing
units will be granted allowances to emit SO2. Most of the NU system
companies' allocated allowances will substantially exceed their expected
SO2 emissions for 2000 and subsequent years, except for PSNH, which expects
to purchase additional SO2 allowances.
New Hampshire and Massachusetts have each instituted acid rain control
laws that limit SO2 emissions. The NU system is meeting the new SO2
limitations by using natural gas and/or lower sulfur coal in its plants.
Under the existing fuel adjustment clauses in Connecticut, New Hampshire
and Massachusetts, the NU system should be able to recover the additional
fuel costs of compliance with the CAAA and state laws from its customers.
Management does not believe that the acid rain provisions of the CAAA
will have a significant impact on the NU system's overall costs or rates
due to the very strict limits on SO2 emissions already imposed by
Connecticut, New Hampshire and Massachusetts. In addition, management
believes that Title IV of the CAAA (acid rain) requirements for NOX
limitations will not have a significant impact on NU system costs due to
the more stringent NOX limitations resulting from Title I of the CAAA
discussed above.
EPA, Connecticut, New Hampshire and Massachusetts regulations also
include other air quality standards, emission standards and monitoring and
testing and reporting requirements that apply to the NU system's generating
stations. They require new or modified fossil fuel-fired electric
generating units to operate within stringent emission limits. The NU
system could incur additional costs to meet these requirements, which costs
cannot be estimated at this time.
Air Toxics. Title III of the CAAA directed EPA to study air toxics
----------
and mercury emissions from fossil fired steam electric generation units to
determine if they should be regulated. EPA exempted these plants from the
hazardous air pollutant program pending completion of the studies, expected
in 1997 or 1998. Should EPA determine that such generating plants'
emissions must be controlled to the same extent as emissions from other
sources under Title III, the NU system, including the Company, could be
required to make substantial capital expenditures to upgrade or replace
pollution control equipment, but the amount of these expenditures cannot be
readily estimated.
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Toxic Substances and Hazardous Waste Regulations
PCBs. Under the federal Toxic Substances Control Act of 1976 (TSCA),
----
EPA has issued regulations that control the use and disposal of
polychlorinated biphenyls (PCBs). PCBs had been widely used as insulating
fluids in many electric utility transformers and capacitors before TSCA
prohibited any further manufacture of such PCB equipment. NU system
companies have taken numerous steps to comply with these regulations and
have incurred increased costs for disposal of used fluids and equipment
that are subject to the regulations.
In general, the NU system sends fluids with concentrations of PCBs
equal to or higher than 500 ppm to an unaffiliated company to dispose of
using approved methods. Electrical capacitors that contain PCB fluid are
sent off-site to dispose of through burning in high temperature
incinerators approved by EPA. The NU system disposes of solid wastes
containing PCBs in secure chemical waste landfills.
Asbestos. Federal, Connecticut, New Hampshire and Massachusetts
--------
asbestos regulations have required the NU system to expend significant sums
in the past on removal of asbestos, including measures to protect the
health of workers and the general public and to properly dispose of
asbestos wastes. Asbestos removal costs for the NU system are not expected
to be material in 1997.
RCRA. Under the federal Resource Conservation and Recovery Act of
----
1976, as amended (RCRA), the generation, transportation, treatment, storage
and disposal of hazardous wastes are subject to EPA regulations.
Connecticut, New Hampshire and Massachusetts have adopted state regulations
that parallel RCRA regulations but in some cases are more stringent. The
procedures by which NU system companies handle, store, treat and dispose of
hazardous wastes are regularly revised, where necessary, to comply with
these regulations.
Hazardous Waste Liability. As many other industrial companies have
-------------------------
done in the past, 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 PCBs. 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. As of June 30, 1997, the liability recorded by the
Company for its estimated environmental remediation costs for known sites
needing remediation, including those sites described below, exclusive of
recoveries from insurance or third parties, was approximately $7.8 million.
These costs could be significantly higher if alternative remedies become
necessary.
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Under the federal Comprehensive Environmental, Response, Compensation
and Liability Act of 1980, as amended, commonly known as Superfund, EPA has
the authority to cleanup or order cleanup of hazardous waste sites and to
impose the cleanup 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. It is EPA's position that all
responsible parties are jointly and severally liable, so that any single
responsible party can be required to pay the entire costs of cleaning up
the site. As a practical matter, however, the costs of cleanup are usually
allocated by agreement of the parties, or by the courts on an equitable
basis among the parties deemed responsible, and several federal appellate
court decisions have rejected EPA's position on strict joint and several
liability. Superfund also contains provisions that require NU system
companies to report releases of specified quantities of hazardous materials
and require notification of known hazardous waste disposal sites. NU
system companies are in compliance with these reporting and notification
requirements.
The NU system currently is involved in two Superfund sites in
Connecticut, one in Kentucky, one in New Jersey and two in New Hampshire.
The level of study of each site and the information about the waste
contributed to the site by the NU system and other parties differs from
site to site. Where reliable information is available that permits the NU
system to make a reasonable estimate of the expected total costs of
remedial action and/or the NU system's likely share of remediation costs
for a particular site, those cost estimates are provided below. All cost
estimates were made in accordance with generally accepted accounting
principles where remediation costs were probable and reasonably estimable.
Any estimated costs disclosed for cleaning up the sites discussed below
were determined without consideration of possible recoveries from third
parties, including insurance recoveries. Where the NU system has not
accrued a liability, the costs either were not material or there was
insufficient information to accurately assess the NU system's exposure.
At two Connecticut sites, the Beacon Heights and Laurel Park
landfills, the major parties formed coalitions and joined as defendants a
number of other parties including "Northeast Utilities (Connecticut Light
and Power)". Litigation on both sites was consolidated in a single case in
the federal district court. In 1993, the coalitions' claims against a
number of defendants including NU (CL&P) were dismissed. In 1994, the
Beacon Heights Coalition indicated that they would not pursue NU (CL&P) as
a defendant. As a result, the Company does not expect to incur cleanup
costs for the Beacon Heights site. Meanwhile, the coalitions appealed the
1993 federal district court dismissal, which was overturned. A petition
for rehearing was filed and it is unlikely the district court will take
further action until the petition is resolved. In any event, the Company's
liability at the Laurel Park site is expected to be minimal because of the
non-hazardous nature and small volume of the materials that were sent
there.
The NU system had sent a substantial volume of LLRW from Millstone 1,
Millstone 2 and CY to the Maxey Flats nuclear waste disposal site in
Fleming County, Kentucky. On April 18, 1996, the U.S. District Court for
the Eastern District of Kentucky approved a consent decree between EPA and
members of the Maxey Flats PRP Steering Committee, including NU system
companies, and several federal government agencies, including DOE and the
Department of Defense
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<PAGE>
as well as the Commonwealth of Kentucky. The NU system has recorded a
liability for future remediation costs for this site based on its share of
ultimate remediation costs under the tentative agreement. The NU system's
liability at the site has been assessed at slightly over $1 million.
The Company, as successor to The Hartford Electric Light Company
(HELCO), has been named as one of over 100 defendants in a cost recovery
action filed in the federal district court in New Jersey. Plaintiffs have
not disclosed the amount of the recovery they are seeking and, due to the
nature of HELCO's limited dealings with the plaintiffs, the Company
believes its liability is minimal.
As discussed below, in addition to the remediation efforts for the
above-mentioned Superfund sites, the NU system has been named as a PRP and
is monitoring developments in connection with several state environmental
actions.
In 1987, CDEP published a list of 567 hazardous waste disposal sites
in Connecticut. The Company owns two sites on this list. The Company has
spent approximately $2.7 million, as of December 31, 1996, completing
investigations and limited remediation at these sites. Both sites were
formerly used by CL&P predecessor companies for the manufacture of coal gas
(also known as town gas sites) from the late 1800s to the 1950s. This
process resulted in the production of coal tar and creosote residues and
other byproducts, which, when not sold for other industrial or commercial
uses, were frequently deposited on or near the production facilities. Site
investigations have been completed at these sites and discussions with
state regulators are in progress to address the need and extent of
remediation necessary to protect public health and the environment.
One of the sites is a 25.8-acre site located in the south end of
Stamford, Connecticut. Site investigations have located coal tar deposits
covering approximately 5.5 acres and having a volume of approximately
45,000 cubic yards. A final risk assessment report for the site was
completed in January 1994. The NU system is currently considering
redevelopment of the site in cooperation with the local municipality as
part of the State of Connecticut's Urban Sites Program. Several remedial
options have been evaluated to remediate the site, if necessary to
accommodate redevelopment. The estimated cost of remediation and
institutional controls ranges from $5 to $8 million.
The second site is a 3.5-acre former coal gasification facility that
currently serves as an active substation in Rockville, Connecticut. Site
investigations have located creosote and other polyaromatic hydrocarbon
contaminants. The Company has provided to the CDEP and local officials the
Company's plan to determine whether any remediation of the site will be
necessary or advisable.
As part of the 1989 divestiture of the Company's gas business, site
investigations were performed for properties that were transferred to
Yankee Gas Services Company (Yankee Gas). The Company agreed to accept
liability for any required cleanup for the three sites it retained. These
three sites include Stamford and Rockville (discussed above) and
Torrington, Connecticut. At the Torrington site, investigations have been
completed and the cost of any remediation, if necessary,
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is not expected to be material. The Company and Yankee Gas also share a
site in Winsted, Connecticut and any liability for required cleanup there.
The Company and Yankee Gas will share the costs of cleanup of sites
formerly used in the Company's gas business but not currently owned by
either of them.
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
In recent years, 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 research to date, agree that current information remains
inconclusive, inconsistent and insufficient for risk assessment of EMF
exposures. Most recently, a review issued in October 1996 by the U.S.
National Academy of Sciences concluded "that the current body of evidence
does not show that exposure to these fields presents a human-health
hazard." 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 is closely monitoring
research and government policy developments.
The NU system supports further research into the subject and is
voluntarily participating in the funding of the ongoing National EMF
Research and Public Information Dissemination Program. 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. In addition, if the courts were to conclude that
individuals have been harmed and that utilities are 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.
The Connecticut Interagency EMF Task Force (Task Force) last provided
a report to the state legislature in January 1995. The Task Force advocated
a policy of "voluntary exposure control," which involves providing people
with information to enable them to make individual decisions about EMF
exposure. Neither the Task Force, nor any Connecticut state agency, has
recommended changes to the existing electrical supply system. The Task
Force is required to provide another
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report to the legislature by 1998. The Connecticut Siting Council (Siting
Council) previously adopted a set of EMF "Best Management Practices," which
are now considered in the justification, siting and design of new or
modified transmission lines and substations. In 1996, the Siting Council
concluded a generic proceeding in which it conducted a comparative life-
cycle cost analysis of overhead and underground transmission lines,
pursuant to a law that was adopted in 1994 in part due to public EMF
concerns. This proceeding is expected to be referenced in future
comparisons of overhead and underground alternatives to proposed
transmission line projects.
EMF has become increasingly important as a factor in facility siting
decisions in many states, and local EMF concerns occasionally make the news
when utilities propose new or changed facilities. In prior years, various
bills involving EMF were introduced in the Massachusetts and Connecticut
legislatures with no action taken. No such bills were introduced in either
state in 1996.
The Company has been the focus of media reports since 1990 charging
that EMF associated with a substation and related distribution lines in
Guilford, Connecticut are linked with various cancers and other illnesses
in several nearby residents. See "Legal Proceedings" for information about
two suits brought by plaintiffs who now or formerly lived near that
substation.
FERC Hydro Project Licensing
Federal Power Act licenses may be issued for hydroelectric projects
for terms of 30 to 50 years as determined by FERC. Upon the expiration of
a license, any hydroelectric project so licensed is subject to reissuance
by 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 hold FERC licenses for 19 hydroelectric
projects aggregating approximately 1,375 MW of capacity, located in
Connecticut, Massachusetts and New Hampshire.
The Company's FERC licenses for operation of the Falls Village and
Housatonic Hydro Projects expire in 2001. The relicensing process was
initiated in August of 1996 with the issuance of a Notice of Intent (NOI)
to the FERC indicating the intention of the Company to relicense both
projects. An Initial Consultation Document (ICD) was issued to consulting
agencies in September 1996 and two public meetings were held in early
November 1996 to discuss relicensing issues. The Company is awaiting the
submittal of resource agency comments.
FERC has issued a notice indicating that it has authority to order
project licensees to decommission projects that are no longer economic to
operate. FERC has not required any such project decommissioning to date.
The potential costs of decommissioning a project, however, could be
substantial. It is likely that this FERC decision will be appealed if, and
when, they attempt to exercise this authority.
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EMPLOYEES
As of December 31, 1996, the NU system companies had 8,842 full
and part-time employees on their payrolls, of which 2,194 were employed by
the Company, 1,279 by PSNH, 497 by WMECO, 92 by HWP, 1,274 by NNECO, 2,692
by NUSCO and 814 by NAESCO. NU, NAEC, Charter Oak, Mode 1 Communications,
Inc. and Select Energy, Inc. have no employees.
In 1995 and early 1996, the NU system implemented a program to
reduce the nuclear organization's total workforce by approximately 220
employees, which included both early retirements and involuntary
terminations. The pretax cost of the program was approximately $8.7
million. For information regarding the criminal investigations by the
NRC's Office of Investigation and the Office of the U.S. Attorney for the
District of Connecticut related to this workforce reduction, see "Legal
Proceedings."
In December 1996, the NU system announced a voluntary separation
program affecting approximately 1,100 employees. The separations will be
effected between April 1, 1997 and March 1, 1998. The estimated cost of
the program is approximately $7 million.
Approximately 2,200 employees of the Company, PSNH, WMECO, NAESCO
and HWP are covered by 11 union agreements, which expire between October 1,
1997 and May 31, 1999.
PROPERTIES
The Company's principal plants and other properties are located
either on land which is owned in fee or on land, as to which the Company
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.
In addition, the Company has certain substation equipment, data processing
equipment, nuclear fuel, gas turbines, nuclear control room simulators,
vehicles, and office space that are leased. With few exceptions, the
Company's 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.
Substantially all of the Company's properties are subject to the
lien of the Indenture, subject to the exceptions described herein. See
"Description of the New Bonds--Security." In addition, the Company's
interest in Millstone 1 is subject to second liens for the benefit of
lenders under agreements related to pollution control revenue bonds.
Various of these properties are also subject to minor encumbrances which do
not substantially impair the usefulness of the properties to the Company.
The Company believes its properties to be well maintained and in
good operating condition.
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Transmission and Distribution System
At December 31, 1996, the NU system companies owned 103
transmission and 416 distribution substations that had an aggregate
transformer capacity of 25,200,069 kilovolt amperes (kVa) and 9,127,367
kVa, respectively, 3,057 circuit miles of overhead transmission lines
ranging from 69 kilovolt (kV) to 345 kV, and 192 cable miles of underground
transmission lines ranging from 69 kV to 138 kV; 32,649 pole miles of
overhead and 1,958 conduit bank miles of underground distribution lines;
and 398,452 line transformers in service with an aggregate capacity of
16,472,221 kVa.
Electric Generating Plants
As of June 30, 1997, the electric generating plants, including
leased property, of the Company and the Company's entitlements in the
generating plants of the two operating Yankee regional nuclear generating
companies were as follows:
<TABLE>
<CAPTION>
Claimed
Year Capability*
Plant Name (Location) Type Installed (kilowatts)
- ------------------------------ -------------------- --------------------- ---------------------
<S> <C> <C> <C>
Millstone (Waterford, CT)
Unit 1 Nuclear 1970 524,637
Unit 2 Nuclear 1975 708,345
Unit 3 Nuclear 1986 606,453
Seabrook (Seabrook, NH) Nuclear 1990 47,175
VY (Vernon, VT) Nuclear 1972 45,353
---------
Total Nuclear-Steam Plants (6 Units) 1,931,963
Total Fossil-Steam Plants (10 Units) 1954-73 1,875,000
Total Hydro-Conventional (25 Units) 1903-55 98,970
Total Hydro-Pumped Storage (7 Units) 1928-73 905,150
Total Internal Combustion (21 Units) 1966-96 601,510
---------
Total CL&P Generating Plant (69 Units) 5,412,593
=========
</TABLE>
* Claimed capability represents winter ratings as of June 30, 1997
Franchises
For more information regarding recent regulatory and legislative
decisions and initiatives that may affect the terms under which the Company
provides electric service in its franchised territory, see "--Rates--
Electric Industry Restructuring in Connecticut," and "Legal Proceedings."
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, the Company
has, subject to certain exceptions not deemed material, valid
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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 the Company 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 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 the Company include
the power of eminent domain.
LEGAL PROCEEDINGS
Litigation Relating to Electric and Magnetic Fields
NU and the Company are currently involved in two lawsuits alleging
physical and emotional damages from exposure to "electromagnetic radiation"
generated by the defendants. Management believes that the allegations that
EMF caused or contributed to the plaintiffs' illnesses are not supported by
scientific evidence. One of these cases has been resolved in NU and the
Company's favor at the trial level, but it has been appealed and is now
pending at the Connecticut Supreme Court.
Southeastern Connecticut Regional Resources Recovery Authority (SCRRRA)--
Application of the Municipal Rate
This matter involves three separate disputes over the rates that apply
to the Company's purchases of the generation of the SCRRRA project in
Preston, Connecticut. A favorable ruling on all of these matters could
result in savings to Company customers of approximately $20 million over
the terms of the agreement with the SCRRRA. FERC has ruled in the Company's
favor in one of these matters, but this decision has been appealed to the
United States D.C. Circuit Court of Appeals. A final ruling in this
decision in favor of the Company would also resolve the second dispute. A
Connecticut Superior Court, however, has ruled in favor of the SCRRRA in
the final dispute. The Company appealed this decision to the Connecticut
Appellate Court, and the Connecticut Supreme Court has transferred the
appeal to itself.
Connecticut DPUC-CL&P's Petition for Declaratory Ruling Regarding Proposed
Retail Sales of Electricity by Texas--Ohio Power, Inc. (TOP)
On August 3, 1995, the Company filed a petition for declaratory
rulings with the DPUC to determine whether TOP, which built a small
cogeneration plant in Manchester, Connecticut, can sell electricity from
the facility to two Company retail customers in Manchester. On December 6,
1995, the DPUC ruled that, because TOP's project would not use the public
streets, it did not require specific legislative authorization to make
retail sales of electricity. In February 1997, the Hartford Superior Court
upheld the DPUC's decision. The Company has appealed the decision to the
Connecticut Appellate Court.
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Tax Litigation
In 1991, the Town of Haddam performed a town-wide revaluation of the
CYAPC property in that town. Based on the report of the engineering firm
hired by the town to perform the revaluation, Haddam determined that the
full fair-market value of the property, as of October 1, 1991, was $840
million. At that time, CY's net-book value was $245 million. On September
5, 1996, a Connecticut court ruled that Haddam had over-assessed CY at
three and a half times its proper assessment. The decision set the plant's
fair market value at $235 million. CYAPC estimated that the town owed it
approximately $16.2 million in refunds, including accrued interest, for
taxes that were overpaid from July 31, 1992 through July 31, 1996. On May
9, 1997, Haddam and CYAPC reached an agreement regarding the repayment of
property taxes due CYAPC for the tax years beginning October 1, 1991
through October 1, 1995. Haddam has agreed to repay to CYAPC an amount
totaling $13,990,000 which is inclusive of taxes and interest for those
years. As part of this negotiated settlement, Haddam has paid CYAPC
$2,000,000 and may bond all or part of the remaining $11,990,000.
Long Island Cable--Citizen's Suit
On April 4, 1996, a citizen's suit against Long Island Lighting Company
(LILCO), a non-affiliate of NU, the Company (collectively, the Companies)
and NUSCO was filed in Federal
District Court in Connecticut. The suit alleges the Companies are in
violation of the Federal Clean Water Act because they are maintaining an
unpermitted discharge of pollutants from the Long Island Cable and claims
the pollutants are an imminent danger to the environment and public health.
The suit asks the Court, among other things, to enjoin further operation of
the Long Island Cable without a permit and to impose a civil penalty of
$25,000 for each violation. On April 23, 1997, the Company, NUSCO, LILCO
and the Long Island Soundkeeper Fund, Inc. jointly filed a Stipulation of
Dismissal in Federal District Court, which settled this suit. The
settlement will not impose material costs on the Company or any other NU
system companies.
Connecticut Municipal Electric Energy Cooperative (CMEEC) Dispute
This matter involves a dispute with CMEEC over its obligations under
its Millstone Units 1 & 2 contract with the Company, under which CMEEC has
a 3.49 percent life-of-unit interest in each of the units. CMEEC and the
Company have been negotiating since May 1996 over issues related to
Millstone Units 1 & 2 and have taken preliminary steps to prepare for
arbitration of the matter. Since October 1996, CMEEC has failed to make
payment on its obligations of approximately $1.6 million per month,
claiming that the Company materially breached its contractual obligations,
and requesting arbitration of the issues. The Company has denied the
allegations and filed a petition on July 1, 1997 requesting the Connecticut
Superior Court to order CMEEC to pay its outstanding obligations (about
$13.3 million) and make continuing payments while the arbitration action is
proceeding.
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Millstone 3--Joint Owner Litigation
The Company 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 practices 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 also
provides that the Company and WMECO would only be liable for damages to the
non-NU owners for a deliberate breach of the agreement pursuant to
authorized corporate action.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands for
arbitration with the Company and WMECO as well as lawsuits in Massachusetts
Superior Court against NU and its current and former trustees. The non-NU
owners raise a number of contract, tort and statutory claims, arising out
of the operation of Millstone 3. The arbitrations and lawsuits seek to
recover compensatory damages, punitive damages, treble damages and
attorneys' fees. Owners representing approximately two-thirds of the non-
NU interests in Millstone 3 have claimed compensatory damages in excess of
$200 million. In addition, one of the lawsuits seeks to restrain NU from
disposing of its shares of the stock of WMECO and HWP, pending the outcome
of the lawsuit. The NU system companies believe there is no legal basis for
the claims and intend to defend against them vigorously.
NRC--Section 2.206 Petitions
Spent Fuel Pool Off-Load Practices 2.206 Petition: In August 1995, a
petition was filed with the NRC under Section 2.206 of the NRC's
regulations by the organization We the People and a NUSCO employee. The
petitioners maintained that NU's historic practice of off-loading the full
reactor core at Millstone 1 resulted in spent fuel pool heat loads in
excess of the pool's NRC-approved cooling capability, and asserted that the
practice was a knowing and willful violation of NRC requirements. The
petitioners also filed a supplemental petition concerning refueling
practices at Millstone 2 and 3 and Seabrook Station.
On December 26, 1996, the Acting Director of the Office of Nuclear
Reactor Regulation issued a partial decision granting, in part, the
petition. The decision, which is limited to the NRC staff's technical
review of the issues raised by petitioners, concluded that the design of
the spent fuel pool and related system at Millstone 1 was adequate, and
that the full core off-load practices at that unit, Millstone 3 and
Seabrook were safe. The petitioners' assertions regarding Millstone 2 were
not substantiated. The Director further concluded that the regulatory
actions taken by the NRC to date regarding the three Millstone units,
including the imposition of an Independent Corrective Action Verification
Program prior to restart, were broader than the actions requested by
petitioners and thus constituted a partial grant of petitioners' request.
Issues of wrongdoing raised in the petition remain under consideration by
the NRC staff, and will not be addressed until after the U.S. Attorney has
concluded its investigation of the spent fuel pool issues and decided
whether to commence criminal proceedings. See "--NRC Office of
Investigations and U.S. Attorney Investigations and Related Matters" below.
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In March 1997, a Section 2.206 petition was filed with the NRC seeking
enforcement action and the placement of certain restrictions on the
decommissioning activities at the CY nuclear power plant. Specifically,
the petitioners requested that the NRC issue a civil monetary penalty to
assure compliance with radiation protection requirements, and that CY's
license be modified to prohibit any decommissioning activities for a six
month period following any radiological contamination event. In addition,
petitioners requested that CY be placed on the NRC's "watch list."
Management is currently evaluating whether and how to respond to this
petition.
Other 2.206 Petitions: Two petitions under Section 2.206 have been
filed with the NRC requesting various actions be taken with respect to the
operating licenses for Millstone Units 1, 2 and 3 and CY, including
revocation and suspension, and other enforcement action due to alleged
mismanagement of the units and violations of NRC regulations that
petitioners allege have jeopardized public health and safety. While
management believes that the NRC is already addressing a number of the
issues raised in these petition, it cannot predict the ultimate outcome of
these petition.
NRC Office of Investigations and U.S. Attorney Investigations and Related
Matters
The NRC's Office of Investigations (OI) has been examining various
matters at Millstone and CY, including but not limited to procedural and
technical compliance matters and employee concerns. One of these matters
has been referred, and others may be referred, to the Office of the U.S.
Attorney for the District of Connecticut (U.S. Attorney) for possible
criminal prosecution. The referred matter concerns full core off-load
procedures and related matters at Millstone (see "--NRC--Section 2.206
Petitions"). The U.S. Attorney is also reviewing possible criminal
violations arising out of certain of NNECO's other activities at Millstone
and CY, including the 1996 nuclear workforce reduction and its licensed
operator training programs.
The U.S. Attorney, together with the U.S. EPA and the Connecticut
Attorney General, is also investigating possible criminal violations of
federal environmental laws at certain NU facilities, including Millstone.
NU has been informed by the government that it is a target of the
investigation, but that no one in senior management is either a target or a
subject of the investigation.
Management does not believe that any NU system company or officer has
engaged in conduct that would warrant a federal criminal prosecution. NU
intends to fully cooperate with the OI and the U.S. Attorney in their
ongoing investigations.
Connecticut DEP
The Connecticut Department of Environmental Protection (DEP) has
referred to the Connecticut Attorney General a series of alleged
environmental violations at Millstone for a possible civil penalty action.
Management does not believe that this action will have a material adverse
impact on the NU system.
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Other Legal Proceedings
The following sections of this Prospectus discuss additional legal
proceedings: see "Business --Overview of Nuclear Matters and Related
Financial Matters" for information regarding NRC watch list issues;
"Business --Rates" for information about the Company's rate and fuel clause
adjustment clause proceedings, various state restructuring proceedings and
civil lawsuits related thereto; "Business--Electric Operations--
Transmission Access and FERC Regulatory Changes" for information about
proceedings relating to power and transmission issues; "Business--Electric
Operations--Nuclear Generation" and "Business--Electric Operations--Nuclear
Plant Performance and Regulatory Oversight" for information related to
nuclear plant performance, nuclear fuel enrichment pricing, high-level and
low-level radioactive waste disposal, decommissioning matters and NRC
regulation; and "Business--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.
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MANAGEMENT AND COMPENSATION
Executive Officers and Directors
The following table sets forth certain information concerning the
executive officers and directors of the Company as of the date of this
Prospectus.
<TABLE>
<CAPTION>
First Elected First Elected
Name Positions Held an Officer a Director
- ---------------------------- ----------------- ----------- ----------
<S> <C> <C> <C>
Robert G. Abair D - 01/01/89
John H. Forsgren EVP, CFO, D 02/01/96 06/10/96
William T. Frain, Jr. D - 02/01/94
Cheryl W. Grise SVP, CAO, D 06/01/91 01/01/94
John B. Keane VP, TR, D 08/01/92 08/01/92
Bruce D. Kenyon P, D 09/03/96 09/03/96
Francis L. Kinney SVP 04/24/74 -
Hugh C. MacKenzie P, D 07/01/88 06/06/90
Michael G. Morris CH, D 08/19/97 08/19/97
John J. Roman VP, CONT 04/01/92 -
Robert P. Wax SVP, SEC, GC 08/01/92 -
</TABLE>
Key:
- ----
CAO - Chief Administrative Officer GC - General Counsel
CFO - Chief Financial Officer P - President
CH - Chairman SEC - Secretary
CONT - Controller SVP - Senior Vice President
D - Director TR - Treasurer
EVP - Executive Vice President VP - Vice President
<TABLE>
<CAPTION>
Name Age Business Experience During Past 5 Years
- --------------- --- ---------------------------------------
<S> <C> <C>
Robert G. Abair (1) 58 Elected Vice President and Chief Administrative
Officer of WMECO in 1988.
John H. Forsgren (2) 50 Elected Executive Vice President and Chief
Financial Officer of NU, CL&P, PSNH, WMECO
and NAEC February, 1996; previously Managing
Director of Chase Manhattan Bank since 1995; and
Senior Vice President-Chief Financial Officer of
Euro Disney, The Walt Disney Company.
</TABLE>
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<TABLE>
<CAPTION>
Name Age Business Experience During Past 5 Years
- --------------- --- ---------------------------------------
<S> <C> <C>
William T. Frain, Jr.(3) 55 Elected President and Chief Operating Officer
of PSNH in 1994; previously Senior Vice President
of PSNH since 1992.
Cheryl W. Grise 44 Elected Senior Vice President and Chief Administrative
Officer of CL&P, PSNH and NAEC, and Senior Vice
President of WMECO in 1995; previously Senior Vice
President-Human Resources and Administrative Services of
CL&P, WMECO and NAEC since 1994; Vice President-Human
Resources of NAEC since 1992.
John B. Keane (4) 50 Elected Vice President and Treasurer of NU, CL&P,
PSNH, WMECO and NAEC in 1993; previously Vice President,
Secretary and General Counsel-Corporate of NU, CL&P and
WMECO since 1992; Vice President, Assistant Secretary and
General Counsel-Corporate of PSNH and NAEC, Vice
President, Secretary and General Counsel-Corporate of NU
and CL&P, and Vice President, Secretary, Assistant Clerk
and General Counsel-Corporate of WMECO since 1992.
Bruce D. Kenyon (5) 54 President and Chief Executive Officer of NAEC and
President-Nuclear Group of CL&P, PSNH and WMECO since
1996; previously President and Chief Operating Officer
of South Carolina Electric and Gas Company from 1990.
Francis L. Kinney (6) 64 Elected Senior Vice President-Governmental Affairs of
CL&P, WMECO and NAEC in 1994; previously Vice President-
Public Affairs of NAEC since 1992.
Hugh C. MacKenzie (7) 55 Elected President-Retail Business Group of NU February,
1996 and President of CL&P and WMECO in 1994; previously
Senior Vice President-Customer Service Operations of CL&P
and WMECO since 1990.
Michael G. Morris (8) 50 Elected Chairman of the Board, President and Chief Executive
Officer of NU, Chairman of CL&P, PSNH, WMECO and NAEC,
and Chief Executive Officer of PSNH and NAEC effective
August 19, 1997; previously Executive Vice President of CMS
</TABLE>
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<TABLE>
<CAPTION>
Name Age Business Experience During Past 5 Years
- --------------- --- ---------------------------------------
<S> <C> <C>
Energy Corporationsince 1996; President and Chief Executive
Officer of Consumers Energy Company (prior to March 1997,
called Consumers Power Company) since 1994; Executive Vice
President and Chief Operating Officer of Consumers Power
Company 1992-1994.
John J. Roman 43 Elected Vice President and Controller of NU, CL&P, PSNH,
WMECO and NAEC in 1995; previously Assistant Controller of
CL&P, PSNH, WMECO and NAEC since 1992.
Robert P. Wax 48 Elected Senior Vice President, Secretary and General Counsel of
NU, CL&P, PSNH, NAEC and WMECO in 1997. Previously elected Vice
President, Secretary and General Counsel of PSNH and NAEC in
1994; elected Vice President, Secretary, Assistant Clerk and
General Counsel of WMECO in 1993; previously Vice President,
Assistant Secretary and General Counsel of PSNH and NAEC since
1993; previously Vice President and General Counsel-Regulatory
of NU, CL&P, PSNH, WMECO and NAEC since 1992.
</TABLE>
(1) Member-Advisory Committee, Bank of Boston Springfield/Pioneer Valley.
(2) Director of Connecticut Yankee Atomic Power Company.
(3) Director of the Business and Industry Association of New Hampshire, the
Greater Manchester Chamber of Commerce; Trustee of Optima Health, Inc.
and Saint Anselm College.
(4) Director of Maine Yankee Atomic Power Company, Vermont Yankee Nuclear
Power Corporation, Yankee Atomic Electric Company and Connecticut
Yankee Atomic Power Company, Member-Advisory Committee, Fleet Bank
Connecticut.
(5) Trustee of Columbia College and Director of Connecticut Yankee Atomic
Power Company.
(6) Director of Mid-Conn Bank. Mr. Kinney is retiring from Northeast
Utilities effective September 1, 1997.
(7) Director of Connecticut Yankee Atomic Power Company.
(8) Trustee and member of the executive committee of the Institute of Gas
Technology, and trustee of the Eastern Michigan University Foundation,
the Delta Sigma Phi Foundation, the Olivet College Leadership Advisory
Council, the Library of Michigan Foundation and the Institute of
Nuclear Power Operations.
There are no family relationships between any director or executive
officer and any other director or executive officer of NU, the Company,
PSNH, WMECO or NAEC.
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Executive Compensation and Employment Agreements
The Company does not directly compensate any executive officer. The following
table presents the cash and non-cash compensation received by the CEO and the
next four highest paid executive officers of the NU system (and indicates the
position held by such officer in the Company), and by a retired executive
officer who would have been among the five highest paid executive officers but
for his retirement, in accordance with rules of the Securities and Exchange
Commission (Commission):
<TABLE>
<CAPTION>
Annual Compensation Long Term Compensation Awards
Options/ Payouts
Re- Stock Long Term All
Other stricted Appreci- Incentive Other
Annual Stock ation Program Compen-
Name and Salary Compensa- Awards Rights Payouts sation($)
Principal Position Year ($) Bonus($) tion($) ($) (#) ($) (1)
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Bernard M. Fox 1996 551,300 None None None None 65,420 7,500
Chairman 1995 551,300 246,168 None None None 130,165 7,350
(Note 2) 1994 544,459 308,896 None None None 115,771 4,500
Bruce D. Kenyon 1996 144,231 400,000 None 499,762 None None None
President-Nuclear (Note 3)
Group (Note 2) 1995 None None None None None None None
1994 None None None None None None None
John H. Forsgren 1996 305,577 None 62,390 80,380 None None None
Executive Vice President (Note 4) (Note 4)
and Chief Financial 1995 None None None None None None None
Officer (Note 2) 1994 None None None None None None None
Hugh C. MacKenzie 1996 264,904 None None None None 19,834 7,500
President-Retail 1995 247,665 128,841 None None None 46,789 7,350
Business Group 1994 245,832 113,416 None None None 40,449 4,500
(Note 2)
</TABLE>
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<PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Ted C. Feigenbaum 1996 248,858 (Note 5) None None None 14,770 7,222
(Note 2) 1995 185,300 126,002 None None None None 5,553
1994 183,331 47,739 None None None None 4,500
Robert E. Busch 1996 300,385 None None None None 26,747 2,637,500
Formerly President- (Note 6)
Energy-Resources Group 1995 350,000 147,708 None None None 63,100 7,350
of NU, CL&P, WMECO 1994 346,122 173,366 None None None 44,073 4,500
and PSNH and formerly
President of NAEC
(Note 6)
</TABLE>
Notes:
1. "All Other Compensation" consists of employer matching contributions
under the Northeast Utilities Service Company 401(k) Plan, generally
available to all eligible employees. It also includes, in the case of
Mr. Busch, certain payments made to him pursuant to the terms of his
separation agreement with Northeast Utilities Service Company (see
Note 6).
2. See "Management and Compensation" for information on the directorships
and officer positions held by each active individual named in the
summary compensation table with each of the registrants.
3. The restricted stock will vest when Millstone Station is removed from
the NRC's "watch list," provided that this occurs within three years
of Mr. Kenyon's commencement of employment and the SRLP and INPO
ratings of Seabrook Station have not materially changed from their
1996 levels. Dividends accruing on these shares are reinvested in
additional shares subject to the same restrictions. At the end of
1996, Mr. Kenyon owned 39,585 restricted shares with a market value of
$519,555, plus a $9,896 dividend that was reinvested into an
additional 740 restricted shares on January 2, 1997.
4. The "other annual compensation" consists of tax payments on a
restricted stock award. The restricted stock will vest on January 1,
1999. Dividends accruing on these shares are reinvested in additional
shares subject to the same restrictions. At the end of 1996, Mr.
Forsgren owned 5,305 restricted shares with a market value of $69,621,
plus a $1,326 dividend that was reinvested into an additional 99
restricted shares on January 2, 1997.
5. Awards under the 1996 short term incentive program of the Northeast
Utilities Executive Incentive Plan have not yet been made. Based on
preliminary estimates of corporate performance, no short term awards
will be made.
6. Mr. Busch left the Company during 1996. Pursuant to his separation
agreement with Northeast Utilities Service Company, Mr. Busch received
cash payments of $880,000 during 1996 and $220,000 during 1997, a
supplemental retirement benefit with a present value of $1,400,000,
continued medical coverage for himself and his family with a present
value of $100,000 and career planning with a value of $30,000. See
"Employment Contracts and Termination of Employment Arrangements,"
below.
* Mr. Fox retired effective August 19, 1997.
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<PAGE>
Pension Benefits
The following table shows the estimated annual retirement benefits
payable to an executive officer of the registrant 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 Northeast Utilities System Companies (the
Supplemental Plan). The Supplemental Plan is a non-qualified pension plan
providing supplemental retirement income to NU 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 Compensation Program
and the Executive Incentive Plan 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 of Northeast Utilities to participate in the target
benefit and who remain in the employ of Northeast Utilities companies until
at least age 60 (unless the Board of Trustees sets an earlier age). Each
of the executive officers of Northeast Utilities named in the Summary
Compensation Table is currently eligible for a target benefit, except Mr.
Kenyon, whose Employment Agreement provides a specially calculated
retirement benefit, based on his previous arrangement with South Carolina
Electric and Gas. If Mr. Kenyon retires with at least three but less than
five years of service with NU, he will be deemed to have five years of
service. In addition, if Mr. Kenyon retires with at least three years of
service with NU, he will receive a lump sum payment of $500,000.
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.
Annual Target Benefit
<TABLE>
<CAPTION>
Final Average
Compensation Years of Credited Service
------------ -------------------------
15 20 25 30 35
-- -- -- -- --
<S> <C> <C> <C> <C> <C>
$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
</TABLE>
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<PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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 401(k) 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.
As of December 31, 1996, the five executive officers named in the
Summary Compensation Table (the Named Executive Officers) had the following
years of credited service for retirement compensation purposes: Mr. Fox-
32, Mr. Kenyon-0, Mr. Forsgren-0, Mr. MacKenzie-31, and Mr. Feigenbaum-10.
Assuming that retirement were to occur at age 65 for these officers,
retirement would occur with 43, 11, 15, 41 and 29 years of credited
service, respectively. Mr. Fox retired effective August 19, 1997.
Employment Contracts and Termination of Employment Arrangements
Officer Agreements
NUSCO has entered into employment agreements (the Officer Agreements)
with each of the Named Executive Officers (except for Mr. Fox--see separate
description below) and certain other executive officers and directors of
the registrants. The Officer Agreements are also binding on NU and on each
majority-owned subsidiary of NU with at least fifty employees on its direct
payroll.
Each Officer Agreement obligates the officer to perform such duties as
may be directed by the NUSCO Board of Directors or the NU Board, protect
the NU system's confidential information, and refrain, while employed by
the NU system 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, that the officer will participate in
specified benefits under the Supplemental Executive Retirement Plan (see
Pension Benefits, above), in the applicable divisional officer executive
incentive programs or the Stock Price Recovery Program, as the case may be,
under the Executive Incentive Plan (see Report on Executive Compensation,
above), and, beginning on January 1, 1999, if the employment term has not
ended, in each short term and long term incentive compensation program
established by the NU system for such senior level executives generally, at
an incentive opportunity level not less than that in effect for the officer
as of January 1, 1996 (or January 1, 1997 for certain officers).
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<PAGE>
Each Officer Agreement provides 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 NU
system for "cause", as defined, at any time (in which case no target
benefit, if any, shall be due the officer under the Supplemental Executive
Retirement Plan), or by the officer on thirty days' prior written notice
for any reason. Absent "cause", the NU system may remove the officer from
his or her position on sixty days' prior written notice, but in the event
the officer is so removed and signs a release of all claims against the NU
system, 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 of the officer within two years following a change in control,
as defined, if the officer signs a release of all claims against the NU
system the officer will be entitled to certain payments including two or
three times base salary and 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, Mr. Forsgren's Officer Agreement
provides for a starting salary of $350,000 per year and a $100,000
restricted stock grant. Mr. Feigenbaum's Officer Agreement provides for a
starting salary of $250,000 per year. Mr. Kenyon's Officer Agreement
provides for an initial starting salary of at $500,000 per year, a $500,000
restricted stock grant and a $400,000 cash signing bonus (See Summary
Compensation Table, above). Mr. Kenyon's Officer Agreement also provides
for a special retirement benefit (described above in Pension Benefits)
instead of a target benefit and a make-whole benefit under the Supplemental
Plan, and a special short term incentive compensation program in lieu of a
portion of the Stock Price Recovery Program. Under this incentive program
Mr. Kenyon will be eligible to receive a payment up to 100 percent of base
salary depending on his fulfillment of certain incentive goals for each of
the years ending August 31, 1997 and August 31, 1998, and for the 16 month
period ending December 31, 1999.
On July 8, 1997, the NU Board authorized additional cash and stock
employment retention incentives to certain of the Company's Named Executive
Officers. Mr. Forsgren will receive $50,000 and, if he is still an NU
system officer on July 1, 1998, an additional $100,000. Mr. Forsgren was
also awarded restricted stock units representing 13,500 NU common shares
that will become unrestricted if Mr. Forsgren is still an NU system officer
on December 31, 1998. Mr. MacKenzie will receive $100,000 on December 31,
1998 if he is still an NU system officer on that date. Mr. Kenyon was
awarded restricted stock units representing 12,200 NU common shares that
are subject to the same forfeiture provisions as his earlier award.
Transition and Retirement Agreement
In 1992, NU entered into an agreement with Mr. Fox (the 1992
Agreement) to provide for an orderly chief executive officer succession.
The agreement states that if Mr. Fox is terminated
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<PAGE>
without cause, he will be entitled to two years' base pay; specified
employee welfare benefits; a supplemental retirement benefit equal to the
difference between the target benefit he would be entitled to receive if he
had reached the age of 55 on the termination date and the actual target
benefit to which he is entitled as of the termination date; and a target
benefit under the Supplemental Executive Retirement Plan, notwithstanding
that he might not have reached age 60 on the termination date and
notwithstanding other forfeiture provisions of that plan.
In January 1997, NU entered into a Transition and Retirement Agreement
(the Transition Agreement) with Mr. Fox to reflect his election to retire
on the later of August 1, 1997 and the date his successor is elected. The
Transition Agreement is intended to supersede the 1992 Agreement at the
time of Mr. Fox's retirement. The Transition Agreement obligates Mr. Fox
to maintain the confidentiality of NU system information during his
employment and following his retirement, and not to compete with the NU
system for certain periods of time in specified geographic areas.
The Transition Agreement provides that Mr. Fox will be engaged as a
consultant to the Board of Trustees of NU for 24 months following his
retirement, with a fee of $500,000 for the first 12 months and $300,000 for
the second 12 months, payable in full notwithstanding Mr. Fox's death or
disability during such period or the occurrence of a change in control, as
defined. Mr. Fox retired effective August 19, 1997. The Transition
Agreement also provides that Mr. Fox will be entitled to a target benefit
under the Supplemental Executive Retirement Plan (actuarially reduced, if
applicable, to reflect payments beginning prior to age 57), and for vesting
of all stock appreciation rights granted to him in the Stock Price Recovery
Program. All payments and benefits under the Transition Agreement are
conditioned on Mr. Fox signing a release of claims against the NU system
"and all related parties" with respect to matters arising out of his
employment with the NU system, and the NU system releasing Mr. Fox from all
civil liability which may arise from his being or having been a Trustee or
officer of NU and its subsidiaries, except for any liability which has been
or may be asserted against Mr. Fox by the NU system as the result of an
investigation conducted upon the demand of a shareholder or by a
shareholder on behalf of the NU system. Both the 1992 Agreement and the
Transition Agreement are binding on each majority-owned subsidiary of NU.
Separation Agreement
NUSCO entered into a Separation Agreement with Mr. Busch in August
1996 in connection with the termination of Mr. Busch's employment. The
agreement provided for a severance payment of two times annual
compensation, and specified supplemental employee welfare and pension
benefits. It provides for confidentiality restrictions on Mr. Busch and a
two year non-competition period in specified geographic locations. It
includes a release by Mr. Busch of claims against the NU system and a
release by the NU system of claims against Mr. Busch, except such as might
be brought as the result of an investigation conducted upon the demand of a
shareholder or on behalf of the NU system by shareholders. NUSCO's
obligations under this agreement are binding on each majority-owned
subsidiary of NU with at least fifty employees on its direct payroll.
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<PAGE>
The descriptions of the various agreements set forth above are for
purpose of disclosure in accordance with the disclosure rules of the
Commission and shall not be controlling on any party; the actual terms of
the agreements themselves determine the rights and obligations of the
parties.
Compensation of Directors
No Director of the Company receives any compensation for service as a
Director.
DESCRIPTION OF THE NEW BONDS
General
The terms of the New Bonds are identical in all material respects with
the terms of the Old Bonds, except for the elimination of certain transfer
restrictions, registration rights and interest rate provisions relating to
the Old Bonds.
The Old Bonds are, and the New Bonds will be issued under and secured
by the Indenture of Mortgage and Deed of Trust dated as of May 1, 1921
between the Company and Bankers Trust Company, Trustee, as heretofore
supplemented and amended, and which, as it is to be further supplemented by
the Sixty-Eighth Supplemental Indenture (which is hereinafter referred to
as the Sixty-Eighth Supplemental Indenture), is hereinafter called the
Indenture. The summary description of the provisions of the Indenture
which follows does not purport to be complete or to cover all the
provisions thereof. Copies of the Indenture and the form of Sixty-Eighth
Supplemental Indenture have been filed as exhibits to, or incorporated by
reference in, the Registration Statement of which this Prospectus is a part
(the Registration Statement) and reference is made thereto for a complete
statement of the applicable provisions. Article and section references
herein are to provisions of the original Indenture as heretofore amended
unless otherwise indicated.
The Trustee acts as a depository bank of, makes loans to, and performs
other services for the Company and other companies in the NU system in the
ordinary course of business.
The New Bonds will be issued initially under a book-entry only system,
registered in the name of Cede & Co., as registered bondholder and nominee
for DTC. DTC will act as securities depositary for the New Bonds.
Individual purchases of Book-Entry Interests (as herein defined) in any New
Bonds will be made in book-entry form. Purchasers of Book-Entry Interests
in New Bonds will not receive certificates representing their interests in
such New Bonds. So long as Cede & Co., as nominee of DTC, is the
bondholder, references herein to the bondholders or registered owners will
mean Cede & Co., rather than the owners of Book-Entry Interests in New
Bonds. See "Book-Entry; Delivery and Form" herein for certain information
regarding DTC and DTC's book-entry only system.
General Terms of New Bonds
The New Bonds will mature on June 1, 2002 and will bear interest from
June 1, 1997 at the rate of 7 3/4% per annum. Interest will be payable
semiannually on June 1 and December 1, commencing December 1, 1997 at the
principal office of the Trustee in New York City, to registered
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<PAGE>
owners at the close of business on the May 15 or November 15, as the case
may be, preceding such June 1 or December 1, or if such record date is a
legal holiday or a day on which banks are authorized to close in New York
City, on the next preceding day which is not a legal holiday or a day on
which banks are so authorized to close.
The New Bonds will be issued only in the form of fully registered
bonds without coupons in denominations of US$1,000 or integral multiples
thereof and may be presented for exchange for a like aggregate principal
amount of the same series of New Bonds of other authorized denominations
and for transfer at the principal office of the Trustee in New York City
without payment in either case of any charge other than for any tax or
other governmental charges required to be paid by the Company.
Security
The Indenture constitutes a first mortgage lien (subject to liens
permitted by the Indenture, including liens and encumbrances existing at
the time of acquisition by the Company) on substantially all of the
Company's physical property and franchises, including the Company's
generating stations (but not including the Company's interest in the plants
of the four regional nuclear generating companies described under
"Business--Electric Operations--Nuclear Generation--General") and its
transmission and distribution facilities. Subject to the provisions of the
Federal Bankruptcy Code, the Indenture will also constitute a lien on
after-acquired property. The Indenture also permits after-acquired property
to be subject to liens prior to that of the Indenture. The security
afforded by the Indenture is for the equal and ratable protection of all
the Company's presently outstanding bonds and any bonds which may hereafter
be issued under the Indenture, including the Bonds. (The granting clauses
and (S)(S)6.04 and 6.05.)
Under certain limited circumstances, the lien of the Indenture on real
property in Connecticut acquired by the Company after June 3, 1985 could be
subordinated to a lien in favor of the State of Connecticut pursuant to a
Connecticut law (Connecticut General Statutes Section 22a-452a) providing
for such a lien for reimbursement for expenses incurred in containing,
removing or mitigating hazardous waste.
Also, under certain limited circumstances the lien of the Indenture on
real property in Massachusetts could be subordinated to a lien in favor of
the Commonwealth of Massachusetts pursuant to the Massachusetts Oil and
Hazardous Materials Release Prevention and Response Act, commonly known as
the Massachusetts Superfund.
Further, under certain limited circumstances, the lien of the
Indenture on real property in New Hampshire, personal property located
thereon and business revenues generated therefrom could be subordinated to
a lien in favor of the State of New Hampshire pursuant to New Hampshire
Revised Statutes Annotated 147B:10-b, as amended, for expenses incurred in
containing or removing hazardous waste or materials, and any necessary
mitigation of damages with respect to hazardous waste or materials.
-100-
<PAGE>
If the Trustee exercises its rights to foreclose on the collateral,
the transferral of required governmental approvals to a purchaser or new
operator of the Company's generating facilities, particularly nuclear and
hydro generating facilities, will require additional governmental
proceedings and consequent delays. There can be no assurance that such
transfers would be approved.
Redemption Provisions
The New Bonds will be redeemable at the option of the Company, as a
whole or in part, at any time upon at least 30 days and not more than 60
days prior written notice (which notice may state that it is subject to the
receipt of redemption moneys by the Trustee on or before the date fixed for
redemption and which notice shall be of no effect unless such moneys are so
received on or before such date) at a redemption price equal to the greater
of (i) 100% of their principal amount and (ii) the sum of the present
values of the remaining scheduled payments of principal and interest
thereon discounted to the date of redemption on a semiannual basis
(assuming a 360-day year consisting of twelve 30-day months) at the
Treasury Yield, plus in each case accrued interest to the date of
redemption (the Redemption Date).
"Treasury Yield" means, with respect to any Redemption Date, the rate
per annum equal to the semiannual equivalent yield to maturity of the
Comparable Treasury Issue, assuming a price for the Comparable Treasury
Issue (expressed as a percentage of its principal amount) equal to the
Comparable Treasury Price for such redemption date.
"Comparable Treasury Issue" means the United States Treasury security
selected by an Independent Investment Banker having a maturity comparable
to the remaining term of the New Bonds that would be utilized, at the time
of selection and in accordance with customary financial practice, in
pricing new issues of corporate debt securities of comparable maturity to
the remaining term of the New Bonds. "Independent Investment Banker" means
Morgan Stanley & Co. Incorporated or, if such firm is unwilling or unable
to select the Comparable Treasury Issue, an independent investment banking
institution of national standing selected by the Company and appointed by
the Trustee.
"Comparable Treasury Price" means, with respect to any Redemption Date
(i) the average of the bid and asked prices for the Comparable Treasury
Issue (expressed in each case as a percentage of its principal amount) on
the third business day preceding such Redemption Date, as set forth in the
daily statistical release (or any successor release) published by the
Federal Reserve Bank of New York and designated "Composite 3:30 p.m.
Quotations for U.S. Government Securities" or (ii) if such release (or any
successor release) is not published or does not contain such prices on such
business day, (A) the average of the Reference Treasury Quotations, or (B)
if the Trustee obtains fewer than four Reference Treasury Dealer
Quotations, the average of all such Quotations. "Reference Treasury Dealer
Quotations" means, with respect to each Reference Treasury Dealer and any
Redemption Date, the average, as determined by the Trustee, of the bid and
asked prices for the Comparable Treasury Issue (expressed in each case as a
percentage of its
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<PAGE>
principal amount) quoted in writing to the Trustee by such Reference
Treasury Dealer at 5:00 p.m. on the third business day preceding such
Redemption Date.
"Reference Treasury Dealer" means each of Morgan Stanley & Co.
Incorporated, Salomon Brothers Inc and another Primary Treasury Dealer (as
defined herein) at the option of the Company, provided, however, that if
any of the foregoing shall cease to be a primary U.S. Government Securities
dealer in New York City (a Primary Treasury Dealer), the Company shall
substitute therefor another Primary Treasury Dealer.
Issuance of Additional Bonds; Earnings Coverage
The Indenture permits, subject to various conditions and restrictions
set forth therein, the issuance of an unlimited amount of additional first
mortgage bonds. Additional bonds may be issued under the Indenture (a) to
refund other bonds or certain prior lien obligations, or (b) on the basis
of a certification of unbonded property additions, or (c) against the
deposit of an equal amount of cash with the Trustee. The aggregate amount
of first mortgage bonds (including two collateral series which secure an
identical principal amount of other outstanding debt of the Company)
outstanding on June 30, 1997 was approximately $1,459,000,000.
Additional bonds may be issued to the extent of 60% (or such greater
percent, not exceeding 66-2/3%, as may be authorized by the Commission
under the Holding Company Act of unbonded property additions ((S)3.54).
Additional bonds may also be issued to finance 60% (or such greater
percent, not exceeding 66-2/3%, as may be authorized by the Commission
under the Holding Company Act) of the bondable amount of the Company's
interest in the inventory of nuclear fuel required for a nuclear generating
plant ((S)3.55).
Except in the case of certain refunding issues, the Company may not
issue additional bonds unless its net earnings, as defined and as computed
without deducting income taxes, for 12 consecutive calendar months during
the period of 15 consecutive calendar months immediately preceding the
first day of the month in which the application to the Trustee for
authentication of additional bonds is made were at least twice the annual
interest charges on all the Company's outstanding bonds, including the
proposed additional bonds, and any outstanding prior lien obligations
((S)3.58). On the basis of this formula, based on the bonds and prior lien
obligations outstanding as of June 30, 1997, the earnings coverage was
negative and equalled (.99). The additional earnings required to bring the
ratio of earnings to fixed charges to 2.0 for the twelve-month period ended
June 30, 1997 would have been approximately $405,377,000.
Where cash is deposited with the Trustee as a basis for the issue of
bonds, it may be withdrawn against 60% (or such greater percent, not
exceeding 66-2/3%, as may be authorized by the Commission under the Holding
Company Act) of bondable property additions or against the deposit of bonds
or prior lien obligations that would otherwise be available to be made the
basis of the issue of additional bonds. Such cash may also be used to
purchase or redeem bonds of any series as the Company may designate
((S)3.56).
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<PAGE>
As of June 30, 1997, the Company had unbonded property additions
available that would support the issuance of additional bonds in the
principal amount of $701,870,900, subject to the net earnings and other
requirements of the Indenture. The Bonds are being issued on the basis of
previously retired bonds.
Other Financial Restrictions
In addition to the foregoing restrictions, there are additional
limitations upon the creation and/or issuance by the Company of long-term
debt securities. Under certain bank and bank reimbursement agreements,
lenders are not required to make additional loans or the maturity of
indebtedness can be accelerated if the Company does not meet an equity
ratio that requires, in effect, that the Company's common equity (as
defined) be at least 27 percent of its total capitalization.
On March 31, 1992, the DPUC issued a decision approving NU's
acquisition of PSNH, which occurred on June 5, 1992. The DPUC's approval
included several conditions designed principally to insulate the Company's
customers from possible financial risks associated with NU's investment in
PSNH. Among the conditions is a requirement that the Company use its best
efforts to maintain the amount of common equity in the Company's capital
structure (including short term debt in excess of 7 percent of total
capitalization) above 36 percent. The Company must notify the DPUC if the
ratio is projected to fall below 36 percent, in which case the DPUC may
conduct a review of the Company's financial condition. At June 30, 1997,
the Company's equity ratio (so calculated) was 34.1%. The Company did not
expect to meet this condition at June 30, 1997 and notified the DPUC in
accordance with the foregoing requirement. Also, in future rate cases, the
Company will be required to accept a methodology for determining the
Company's cost of capital for ratemaking purposes without regard to NU's
cost of capital if the DPUC finds that the Company's actual debt costs are
unduly influenced by effects of the PSNH acquisition. These conditions are
to remain in effect until the later of May 15, 1998 and the time at which
PSNH achieves investment grade ratings for its first mortgage bonds and a
common equity to total capitalization ratio of at least 30 percent.
Renewal and Replacement Fund
If, as at the end of any year, the aggregate amount expended by the
Company for property additions since December 31, 1966 is less than the
"replacement fund requirement" (referred to below) for the same period, the
Company is required to make up the deficit by depositing cash with the
Trustee, or by depositing with the Trustee bonds or prior lien obligations
which would otherwise be available as a basis for the issue of additional
bonds or by certifying unbonded property additions taken at 100% of the
amount certified. At the request of the Company, any cash so deposited may
be used to purchase or redeem (at the applicable Special Redemption Price)
bonds of such series as the Company may designate. A replacement fund
deficit may thereafter be offset by expenditures in a later year in excess
of the requirement for such year and thereupon the Company will be
entitled, to the extent of such offset, to the return of cash, bonds or
prior lien obligations deposited to make up the deficit or to reinstate as
bondable any property additions certified for such purpose ((S)6.06).
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<PAGE>
The replacement fund requirement is computed on an annual basis, and
is equal, for each year, to 2.25% of the average of the amounts carried on
the Company's books for depreciable property at the beginning and end of
the year ((S)1.01 (pp)). As of June 30, 1997, the Company's expenditures
for property additions had exceeded the replacement fund requirement by
$4,262,068,539.
Withdrawal or Application of Cash
Cash deposited with the Trustee pursuant to the sinking and
improvement fund or replacement fund requirements may, at the Company's
option, be withdrawn against a certification of unbonded property
additions, or against the deposit of bonds or prior lien obligations which
would otherwise be available to be made the basis of the issue of
additional bonds or may be applied to the purchase or redemption (at the
applicable Special Redemption Price) of bonds of such series as the Company
may designate ((S)(S)6.06, 6.14 and 9.04). When the cash to be withdrawn
has been deposited under the replacement fund requirement, a withdrawal
equal to 100% is permitted ((S)6.06).
Dividend Restrictions
The Indenture contains restrictions on the payment of common stock
dividends, which were included in certain Supplemental Indentures at the
time of issuance of prior series of bonds. The Supplemental Indenture
dated as of July 1, 1992, which contains restrictions applicable so long as
any Series VV Bonds, maturing July 1, 1999, are outstanding, currently
contains the most restrictive provision. Under this provision, the
aggregate amount which may be declared, paid or otherwise applied by the
Company as dividends or other distributions on its common stock (other than
by way of stock dividends or when an equal amount of cash is received
concurrently as a capital contribution or on the sale of common stock) or
to the purchase or other acquisition of common stock may not exceed earned
surplus (as defined, and after deducting accrued preferred stock dividends)
accumulated after June 30, 1993, plus $207,000,000, plus such further
amount as may be authorized by the Commission under the Holding Company
Act. Pursuant to these provisions, unrestricted earned surplus at June 30,
1997 was negative, and would have amounted to approximately $72.8 million.
Similar dividend restrictions are binding on the Company so long as
certain prior series of the Company's bonds are outstanding.
Default
The Indenture provides that the following events will constitute
"events of default" thereunder: failure to pay principal; failure for 90
days to pay interest; failure to perform any of the other Indenture
covenants for 90 days after notice to the Company; failure to perform any
covenant contained in any lien securing prior lien obligations if such
default permits enforcement of the lien; and certain events in bankruptcy,
insolvency or receivership ((S)10.02). The Indenture requires the Company
to deliver to the Trustee an annual officers' certificate as to compliance
with certain provisions of the Indenture ((S)6.16).
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<PAGE>
The Indenture provides that, if any event of default exists, the
holders of a majority in principal amount of the bonds outstanding may,
after tender to the Trustee of indemnity satisfactory to it, direct the
sale of the mortgaged property ((S)10.04).
Modification of the Indenture
The Indenture may be supplemented or amended to convey additional
property, to state indebtedness of companies merged, to add further
limitations to the Indenture, to evidence a successor company, or to make
such provision in regard to questions arising under the Indenture as may be
necessary or desirable and not inconsistent with its terms ((S)14.01).
The Indenture also permits the modification, with the consent of
holders of 66-2/3% of the bonds affected, of any provision of the
Indenture, except that (a) no such modification may effect a reduction of
such percentage or the creation of a lien prior to or concurrent with that
of the Indenture unless all bondholders consent, (b) no bondholder who
refuses to consent may be deprived of his security, and (c) the Company's
obligations as to the maturities, payment of principal, interest or premium
and other terms of payment may not be modified unless all affected
bondholders consent ((S)14.03).
BOOK-ENTRY; DELIVERY AND FORM
The New Bonds will be issued in fully-registered form.
The description which follows of the procedures and recordkeeping with
respect to beneficial ownership interests in the New Bonds, payments of
principal of, and premium, if any, and interest on, the New Bonds to DTC
and its Participants or Beneficial Owners, in each case as defined below,
confirmation and transfer of beneficial ownership interests in the New
Bonds and other related transactions by and among DTC, the DTC Participants
and Beneficial Owners is based solely on information furnished by DTC.
DTC is a limited-purpose trust company organized under the New York
Banking Law, a "banking organization" within the meaning of the New York
Banking Law, a member of the Federal Reserve System, a "clearing
corporation" within the meaning of the New York Uniform Commercial Code,
and a "clearing agency" registered pursuant to the provisions of Section
17A of the Securities Exchange Act of 1934. DTC holds securities that its
participants (Participants) deposit with DTC. DTC also facilitates the
settlement among Participants of securities transactions, such as transfers
and pledges, in deposited securities through electronic computerized book-
entry changes in Participants' accounts, thereby eliminating the need for
physical movement of securities certificates. Direct Participants (Direct
Participants) include securities brokers and dealers, banks, trust
companies, clearing corporations and certain other organizations. DTC is
owned by a number of its Direct Participants and by the New York Stock
Exchange, Inc., the American Stock Exchange, Inc. and the National
Association of Securities Dealers, Inc. Access to the DTC system is also
available to others such as securities brokers and dealers, banks and trust
companies that clear
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<PAGE>
through or maintain a custodial relationship with a Direct Participant,
either directly or indirectly (Indirect Participants). The rules applicable
to DTC and its Participants are on file with the SEC.
Purchases of New Bonds under the DTC system must be made by or through
Direct Participants, which will receive a credit for the New Bonds on DTC's
records. The ownership interest of each actual purchaser of New Bonds
(Beneficial Owner) is in turn to be recorded on the Direct and Indirect
Participants' records. Beneficial Owners will not receive written
confirmation from DTC of their purchase, but Beneficial Owners are expected
to receive written confirmations providing details of the transaction, as
well as periodic statements of their holdings, from the Direct or Indirect
Participant through which the Beneficial Owner entered into the
transaction. Transfers of ownership interests in the New Bonds are to be
accomplished by entries made on the books of Participants acting on behalf
of Beneficial Owners. Beneficial Owners will not receive certificates
representing their ownership interests in the New Bonds, except in the
event that use of the book-entry system for the New Bonds is discontinued.
SO LONG AS CEDE & CO., AS NOMINEE FOR DTC, IS THE SOLE HOLDER OF THE NEW
BONDS, THE TRUSTEE SHALL TREAT CEDE & CO. AS THE ONLY HOLDER OF THE NEW
BONDS FOR ALL PURPOSES UNDER THE INDENTURE, INCLUDING RECEIPT OF ALL
PRINCIPAL OF, AND PREMIUM, IF ANY, AND INTEREST ON SUCH NEW BONDS, RECEIPT
OF NOTICES, AND VOTING AND REQUESTING OR DIRECTING THE TRUSTEE TO TAKE OR
NOT TO TAKE, OR CONSENTING TO, CERTAIN ACTIONS UNDER THE INDENTURE.
To facilitate subsequent transfers, all New Bonds deposited by
Participants with DTC are registered in the name of DTC's partnership
nominee, Cede & Co. The deposit of New Bonds with DTC and their
registration into the name of Cede & Co. effect no change in beneficial
ownership. DTC has no knowledge of the actual Beneficial Owners of the New
Bonds; DTC's records reflect only the identity of the Direct Participants
to whose accounts such New Bonds are credited, which may or may not be the
Beneficial Owners. The Participants will remain responsible for keeping
account of their holdings on behalf of their customers.
The laws of some jurisdictions require that certain purchasers of
securities take physical delivery of securities in definitive form. Such
laws may impair the ability to transfer beneficial interests in any Global
Security.
Conveyance of notices and other communications by DTC to Direct
Participants, by Direct Participants to Indirect Participants, and by
Direct Participants and Indirect Participants to Beneficial Owners will be
governed by arrangements among them, subject to any statutory or regulatory
requirements as may be in effect from time to time.
Redemption notices, if any, shall be sent to Cede & Co. If less than
all of the New Bonds within an issue are being redeemed, DTC's practice is
to determine by lot the amount of the interest of each Direct Participant
in such issue to be redeemed.
Neither DTC nor Cede & Co. will consent or vote with respect to the
New Bonds. Under its usual procedures, DTC mails an Omnibus Proxy to the
Company as soon as possible after the
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<PAGE>
record date. The Omnibus Proxy assigns Cede & Co.'s consenting or voting
rights to those Direct Participants to whose accounts the New Bonds are
credited on the record date (identified in a listing attached to the
Omnibus Proxy).
Principal of, and premium, if any, and interest payments on the New
Bonds will be made to DTC. DTC's practice is to credit Direct
Participants' accounts on the applicable payment date in accordance with
their respective holdings shown on DTC's records unless DTC has reason to
believe that it will not receive payment on such date. Payments by
Participants to Beneficial Owners will be governed by standing instructions
and customary practices, as is the case with securities held for the
accounts of customers in bearer form or registered in "street name," and
will be the responsibility of such Participant and not of DTC, the Trustee
or the Company, subject to any statutory or regulatory requirements as may
be in effect from time to time. Payment of principal, and premium, if any,
and interest to DTC is the responsibility of the Company or the Trustee,
disbursement of such payments to Direct Participants shall be the
responsibility of DTC and disbursement of such payments to the Beneficial
Owners shall be the responsibility of Direct and Indirect Participants.
DTC may discontinue providing its services as securities depositary
with respect to the New Bonds at any time by giving notice to the Company
or the Trustee. Under such circumstances, in the event that a successor
securities depositary is not obtained, individual bond certificates are
required to be printed and delivered.
The Company may decide to discontinue use of the system of book-entry
transfers through DTC (or a successor securities depository). In that
event, individual bond certificates will be printed and delivered.
The information in this section concerning DTC and DTC's book-entry
system has been obtained from sources that the Company believes to be
reliable (including DTC), but the Company takes no responsibility for the
accuracy thereof.
THE COMPANY AND THE TRUSTEE HAVE NO RESPONSIBILITY OR OBLIGATION TO
THE DTC PARTICIPANTS OR THE BENEFICIAL OWNERS WITH RESPECT TO (A) THE
ACCURACY OF ANY RECORDS MAINTAINED BY DTC OR ANY DTC PARTICIPANT, (B) THE
PAYMENT BY ANY DTC PARTICIPANT OF ANY AMOUNT DUE TO ANY BENEFICIAL OWNER IN
RESPECT OF THE PRINCIPAL OF, AND PREMIUM, IF ANY, AND INTEREST ON, THE NEW
BONDS, (C) THE DELIVERY OR TIMELINESS OF DELIVERY BY DTC TO ANY DTC
PARTICIPANT OR BY ANY DTC PARTICIPANT TO ANY BENEFICIAL OWNER OF ANY NOTICE
WHICH IS REQUIRED OR PERMITTED UNDER THE TERMS OF THE INDENTURE TO BE GIVEN
TO HOLDERS OF THE NEW BONDS, OR (D) ANY OTHER ACTION TAKEN BY DTC, OR ITS
NOMINEE, CEDE & CO., AS HOLDER OF THE NEW BONDS.
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<PAGE>
MARKET FOR NEW BONDS
The Company has been advised by the Initial Purchasers that they
presently intend to make a market in the New Bonds as permitted by
applicable laws and regulations. The Initial Purchasers are not obligated,
however, to make a market in the New Bonds and any such market making may
be discontinued at any time without prior notice at the sole discretion of
the Initial Purchasers. Accordingly, no assurance can be given as to the
liquidity of, or trading markets for, the New Bonds.
CERTAIN FEDERAL INCOME TAX CONSIDERATIONS
The following discussion, based on current law, is a general
summary of the anticipated United States federal income tax consequences
relevant to the exchange of Old Bonds for New Bonds and the ownership and
disposition of the New Bonds by holders acquiring New Bonds pursuant to the
Exchange Offer. The summary does not address all aspects of taxation that
may be relevant to particular holders in light of their personal
circumstances (including the effect of any foreign, state or local tax
laws) or to certain types of holders subject to special treatment under
federal income tax laws (such as dealers in securities, options or
currencies, insurance companies, financial institutions, persons holding
Bonds as part of a hedging or conversion transaction or straddle, persons
whose functional currency is not the United States dollar and tax-exempt
entities).
The discussion of the federal income tax consequences set forth
below is based upon the Internal Revenue Code of 1986, as amended (the
Code), and judicial decisions and administrative interpretations
thereunder, as of the date hereof, and such authorities may be repealed,
revoked or modified so as to result in federal income tax consequences
different from those discussed below. For purposes of the discussion set
forth below, the term "Holder" includes a beneficial owner of a Bond. The
discussion below is premised upon the assumption that the New Bonds are
held as capital assets. The discussion below pertains only to Holders that
are citizens or residents of the United States, corporations, partnerships
or other entities created in or under the laws of the United States or any
political subdivision thereof, estates, or trusts the administration over
which a United States court can exercise primary supervision and for which
one or more United States fiduciaries have the authority to control all
substantial decisions, the income of which is subject to United States
federal income taxation regardless of its source.
EACH PROSPECTIVE HOLDER OF BONDS IS STRONGLY URGED TO CONSULT ITS OWN
TAX ADVISOR WITH RESPECT TO ITS PARTICULAR TAX SITUATION, INCLUDING
THE TAX EFFECTS OF ANY STATE, LOCAL, FOREIGN, OR OTHER TAX LAWS AND
POSSIBLE CHANGES IN THE TAX LAWS.
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<PAGE>
Exchange of Bonds
The exchange of Old Bonds for New Bonds pursuant to the Exchange Offer
should not be treated as an exchange or other taxable event for federal
income tax purposes because, under regulations promulgated by the United
States Treasury Department, the New Bonds should not be considered to
significantly modify the Old Bonds and thus should not differ materially in
kind or extent from the Old Bonds. Rather, the New Bonds received by a
Holder should be treated as a continuation of the Old Bonds in the hands of
such Holder. As a result, there should be no federal income tax
consequences to Holders exchanging Old Bonds for New Bonds pursuant to the
Exchange Offer and a Holder should have the same adjusted basis and holding
period in the New Bonds as it had in the Old Bonds immediately before the
exchange.
Sale or Retirement of Bonds
Upon the sale, exchange or retirement of a New Bond, the Holder
generally will recognize gain or loss equal to the difference between the
amount realized on the sale, exchange or retirement and the Holder's
adjusted tax basis in the Bond at the time thereof.
Gain or loss realized on the sale, exchange or retirement of a New
Bond will be capital, and will be long-term if at the time of sale,
exchange or retirement the Holder has a holding period for the Bond of more
than one year. The deductibility of capital losses is subject to
limitations.
Information Reporting and Backup Withholding
Under current United States federal income tax law (i) information
reporting requirements apply to "reportable payments," which include
interest and principal payments made to, and the proceeds of sales by,
certain noncorporate Holders of Bonds, and (ii) a Holder of Bonds may be
subject to backup withholding at the rate of 31% with respect to reportable
payments in respect of Bonds. Backup withholding will not apply to
payments to corporations and certain other exempt recipients, such as tax-
exempt organizations, which demonstrate their entitlement to exemption when
required. The payor will be required to deduct and withhold (at the rate
of 31%) if (i) the payee fails to furnish a taxpayer identification number
(TIN) to the payor in the manner required by the Code and applicable
Treasury regulations, (ii) the Internal Revenue Service notifies the payor
that the TIN furnished by the payee is incorrect, (iii) there has been a
"notified payee underreporting" described in Section 3406(c) of the Code,
or (iv) there has been a failure of the payee to certify under penalty of
perjury that the payee is not subject to withholding under 3406(d) of the
Code. Amounts withheld under these rules do not constitute an additional
tax and will be credited against the Holder's federal income tax liability,
so long as the required information is provided to the Internal Revenue
Service. The Company will report to the Holders of Bonds and to the
Internal Revenue Service the amount of any "reportable payments" for each
calendar year and the amount of tax withheld, if any, with respect to such
payments.
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<PAGE>
PLAN OF DISTRIBUTION
Each broker-dealer that receives New Bonds for its own account
pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such New Bonds. This
Prospectus, as it may be amended or supplemented from time to time, may be
used by a broker-dealer in connection with resale of New Bonds received in
exchange for Old Bonds where such Old Bonds were acquired as a result of
market-making activities or other trading activities. The Company has
agreed that, for a period of 180 days after the Expiration Date, it will
make this Prospectus, as amended or supplemented, available to any broker-
dealer for use in connection with any such resale.
The Company will not receive any proceeds from any sale of New
Bonds by broker-dealers. New Bonds received by broker-dealers for their
own account pursuant to the Exchange Offer may be sold from time to time in
one or more transactions in the over-the-counter market, in negotiated
transactions, through the writing of options on the New Bonds or a
combination of such methods of resale, at market prices prevailing at the
time of resale, at prices related to such prevailing market prices or
negotiated prices. Any such resale may be made directly to purchasers or
to or through brokers or dealers who may receive compensation in the form
of commissions or concessions from any such broker-dealer and/or the
purchasers of any such New Bonds. Any broker-dealer that resells New Bonds
that were received by it for its own account pursuant to the Exchange Offer
and any broker or dealer that participates in a distribution of such New
Bonds may be deemed to be an "underwriter" within the meaning of the
Securities Act and any profit on any such resale of New Bonds any
commission or concessions received by any such persons may be deemed to be
underwriting compensation under the Securities Act. The Letter of
Transmittal states that, by acknowledging that it will deliver and by
delivering a prospectus, a broker-dealer will not be deemed to admit that
it is an "underwriter" within the meaning of the Securities Act.
For a period of 180 days after the Expiration Date, the Company
will promptly send additional copies of this Prospectus and any amendment
or supplement to this Prospectus to any broker-dealer that requests such
documents in the Letter of Transmittal. The Company has agreed to pay all
expenses incident to the Exchange Offer (including the fees and
disbursements of one counsel for the holders of the New Bonds) other than
commissions or concessions of any brokers or dealers and will indemnify the
holders of the New Bonds (including any broker-dealers) against certain
liabilities, including liabilities under the Securities Act.
LEGAL MATTERS AND EXPERTS
Legal matters in connection with the issue of the New Bonds will
be passed upon for the Company by Robert P. Wax, Esq., Senior Vice
President, Secretary and General Counsel of the Company, or Jeffrey C.
Miller, Esq., Assistant General Counsel of NUSCO.
Statements of law and legal conclusions herein and in the
Registration Statement pertaining to the description of the New Bonds have
been reviewed by Mr. Miller. Certain statements of law and legal
conclusions set forth with respect to short term borrowing authority and
the earnings coverage requirement of the Indenture and preferred stock
provisions of the Company, its franchises, its participation in joint
projects, the laws and regulations to which it is or may be
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<PAGE>
subject, and litigation and legal proceedings, have been reviewed by Mr.
Miller and said statements are made upon his authority as an expert.
The Company's audited financial statements included in this
Prospectus and schedules related thereto incorporated by reference in the
Registration Statement have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their reports with respect
thereto, which have also been included or incorporated by reference herein
or therein, in reliance upon the authority of said firm as experts in
accounting and auditing in giving said reports.
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or
acronyms that are found throughout this Prospectus:
<TABLE>
COMPANIES
<S> <C>
NU....................... Northeast Utilities
CL&P or the Company...... The Connecticut Light and Power Company
Charter Oak or COE....... Charter Oak Energy, Inc.
WMECO.................... Western Massachusetts Electric Company
HWP...................... Holyoke Water Power Company
NUSCO.................... Northeast Utilities Service Company
NNECO.................... Northeast Nuclear Energy Company
NAEC..................... North Atlantic Energy Corporation
NAESCO................... North Atlantic Energy Service Corporation
PSNH..................... Public Service Company of New Hampshire
RRR...................... The Rocky River Realty Company
Mode 1................... Mode 1 Communications, Inc.
NU system................ The Northeast Utilities System
CYAPC.................... Connecticut Yankee Atomic Power Company
MYAPC.................... Maine Yankee Atomic Power Company
VYNPC.................... Vermont Yankee Nuclear Power Corporation
YAEC..................... Yankee Atomic Electric Company
the Yankee Companies..... CYAPC, MYAPC, VYNPC, and YAEC
GENERATING UNITS
Millstone 1.............. Millstone Unit No. 1, a 660-MW nuclear
generating unit completed in 1970
Millstone 2.............. Millstone Unit No. 2, an 870-MW nuclear
electric generating unit completed in 1975.
</TABLE>
-111-
<PAGE>
<TABLE>
<S> <C>
Millstone 3.............. Millstone Unit No. 3, a 1,154-MW nuclear
electric generating unit completed in 1986
Seabrook or Seabrook l... Seabrook Unit No. 1, a 1,148-MW nuclear
electric generating unit completed in 1986.
Seabrook 1 went into service in 1990.
REGULATORS
Commission.............. Securities and Exchange Commission
DOE..................... U.S. Department of Energy
DPU..................... Massachusetts Department of Public Utilities
DPUC.................... Connecticut Department of Public Utility
Control
MDEP.................... Massachusetts Department of Environmental
Protection
CDEP.................... Connecticut Department of Environmental
Protection
EPA..................... U.S. 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
OTHER
Holding Company Act..... Public Utility Holding Company Act of 1935
CAAA.................... Clean Air Act Amendments of 1990
DSM..................... Demand-Side Management
Energy Act.............. Energy Policy Act of 1992
EWG..................... Exempt wholesale generator
EAC..................... Energy Adjustment Clause (CL&P)
FAC..................... Fuel Adjustment Clause (CL&P)
FPPAC................... Fuel and purchased power adjustment clause
(PSNH)
GUAC.................... Generation Utilization Adjustment Clause (CL&P)
IRM..................... Integrated resource management
kWh...................... Kilowatt-hour
Money Pool............... A system for the pooling of funds established
by certain of the NU system companies to
provide a more effective use of their cash
</TABLE>
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<PAGE>
<TABLE>
<S> <C>
resources and to reduce outside short-term
borrowings.
MW....................... Megawatt
NBFT..................... Niantic Bay Fuel Trust, lessor of nuclear fuel
used by CL&P and WMECO
NEPOOL................... New England Power Pool
NUGs..................... Nonutility generators
NUG&T.................... Northeast Utilities Generation and
Transmission agreement
QF....................... Qualifying facility
</TABLE>
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<PAGE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants............. F-2
Consolidated Balance Sheets
as of December 31, 1996 and 1995
and June 30, 1997 (unaudited)...................... F-3 - F-4
Consolidated Statements of Income
for the years ended December 31, 1996, 1995 and
1994 and the six months ended June 30, 1997
(unaudited) and 1996 (unaudited)................... F-5
Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1995 and 1994 and the six
months ended June 30, 1997 (unaudited) and
1996 (unaudited)................................... F-6
Consolidated Statements of Common Stockholder's
Equity for the years ended December 31, 1996,
1995 and 1994 and the six months ended
June 30, 1997 (unaudited).......................... F-7
F-1
<PAGE>
Report Of Independent Public Accountants
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The Connecticut
Light and Power Company (a Connecticut corporation and a wholly owned subsidiary
of Northeast Utilities) and subsidiaries as of December 31, 1996 and 1995, and
the related consolidated statements of income, common stockholder's equity and
cash flows for each of the three years in the period ended December 31, 1996.
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 generally accepted auditing
standards. 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 The Connecticut Light and Power
Company and subsidiaries as of December 31, 1996 and 1995, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 21, 1997
F-2
<PAGE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
June 30,
1997 At December 31,
---------- --------------------------
(Unaudited) 1996 1995
---------- ---- ----
<S> <C> <C> <C>
(Thousands of Dollars)
ASSETS
- ------
Utility Plant, at original cost:
Electric............................................ $6,348,007 $6,283,736 $6,147,961
Less: Accumulated provision for
depreciation (Note 1F)..................... 2,776,198 2,665,519 2,418,557
---------- ----------- ----------
3,571,809 3,618,217 3,729,404
Construction work in progress....................... 92,073 95,873 103,026
Nuclear fuel, net................................... 134,453 133,050 138,203
---------- ----------- ----------
Total net utility plant........................... 3,798,335 3,847,140 3,970,633
---------- ----------- ----------
Other Property and Investments:
Nuclear decommissioning trusts, at market........... 322,967 296,960 238,023
Investments in regional nuclear generating
companies, at equity (Note 1E)..................... 59,532 56,925 54,624
Other, at cost...................................... 39,884 16,565 16,241
---------- ----------- ----------
422,383 370,450 308,888
---------- ----------- ----------
Current Assets:
Cash................................................ 263 404 337
Notes receivable from affiliated companies.......... 56,000 109,050 --
Receivables, net.................................... 211,087 226,112 231,574
Accounts receivable from affiliated companies....... 3,615 3,481 3,069
Taxes receivable.................................... 57,986 40,134 --
Accrued utility revenues............................ 83,008 78,451 91,157
Fuel, materials, and supplies, at average cost...... 84,367 79,937 68,482
Recoverable energy costs, net--current portion...... 24,473 25,436 78,108
Prepayments and other............................... 80,059 63,344 42,894
---------- ----------- ----------
600,858 626,349 515,621
---------- ----------- ----------
Deferred Charges:
Regulatory assets (Note 1H)......................... 1,236,418 1,370,781 1,225,280
Unamortized debt expense............................ 19,938 17,033 14,977
Other............................................... 19,399 12,283 10,232
---------- ----------- ----------
1,275,755 1,400,097 1,250,489
---------- ----------- ----------
---------- ----------- ----------
Total Assets.................................... $6,097,331 $6,244,036 $6,045,631
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
June 30,
1997 At December 31,
---------- ----------------------------------
(Unaudited) 1996 1995
---------- ---- ----
<S> <C> <C> <C>
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
- ------------------------------
Capitalization:
Common stock--$10 par value. Authorized
24,500,000 shares; outstanding 12,222,930 shares ....... $ 122,229 $ 122,229 $ 122,229
Capital surplus, paid in................................ 640,495 639,657 637,981
Retained earnings....................................... 467,290 551,410 785,476
---------- ----------- -----------
Total common stockholder's equity.............. 1,230,014 1,313,296 1,545,686
Preferred stock not subject to mandatory redemption..... 116,200 116,200 116,200
Preferred stock subject to mandatory redemption......... 155,000 155,000 155,000
Long-term debt.......................................... 2,018,462 1,834,405 1,812,646
---------- ----------- -----------
Total capitalization........................... 3,519,676 3,418,901 3,629,532
---------- ----------- -----------
Minority Interest in Consolidated Subsidiary (Note 13)... 100,000 100,000 100,000
---------- ----------- -----------
Obligations Under Capital Leases (Note 2)................. 144,583 143,347 108,408
---------- ----------- -----------
Current Liabilities:
Notes payable to banks.................................. 100,000 -- 41,500
Notes payable to affiliated companies................... -- -- 10,250
Long-term debt--current portion......................... 25,615 204,116 9,372
Obligations under capital leases--current
portion (Note 2)....................................... 12,407 12,361 63,856
Accounts payable........................................ 127,563 160,945 110,798
Accounts payable to affiliated companies................ 54,060 78,481 44,677
Accrued taxes........................................... 24,786 28,707 52,268
Accrued interest........................................ 29,695 31,513 30,854
Nuclear compliance (Note 11B)........................... 51,740 50,500 --
Other................................................... 26,107 34,433 20,027
---------- ----------- -----------
451,973 601,056 383,602
---------- ----------- -----------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)............. 1,334,954 1,365,641 1,486,873
Accumulated deferred investment tax credits............. 131,397 135,080 142,447
Deferred contractual obligations (Note 3)............... 271,372 305,627 65,847
Other................................................... 143,376 174,384 128,922
---------- ----------- -----------
1,881,099 1,980,732 1,824,089
---------- ----------- -----------
Commitments and Contingencies (Note 11)
Total Capitalization and Liabilities........... $6,097,331 $6,244,036 $6,045,631
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
June 30, For the Years Ended December 31,
------------------------- ---------------------------------------
1997 1996 1996 1995 1994
--------- ---------- ---------- ---------- ----------
(Unaudited)
<S> <C> <C> <C> <C> <C>
(Thousands of Dollars)
Operating Revenues.................................... $1,199,749 $1,202,354 $2,397,460 $2,387,069 $2,328,052
---------- ---------- ---------- ---------- ----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power........ 479,261 360,847 830,924 608,600 568,394
Other............................................ 355,336 386,570 778,329 614,382 593,851
Maintenance......................................... 168,374 132,168 300,005 192,607 207,003
Depreciation........................................ 118,969 124,500 247,109 242,496 231,155
Amortization of regulatory assets, net.............. 31,361 3,975 57,432 54,217 77,384
Federal and state income taxes (Note 8)............. (28,806) 29,484 (20,174) 178,346 190,249
Taxes other than income taxes....................... 85,693 89,636 174,062 172,395 173,068
---------- ---------- ---------- ---------- ----------
Total operating expenses...................... 1,210,188 1,127,180 2,367,687 2,063,043 2,041,104
---------- ---------- ---------- ---------- ----------
Operating (Loss) Income............................... (10,439) 75,174 29,773 324,026 286,948
---------- ---------- ---------- ---------- ----------
Other Income:
Deferred nuclear plants return--other funds......... 51 907 1,268 4,683 13,373
Equity in earnings of regional nuclear
generating companies.............................. 3,149 3,793 6,619 6,545 7,453
Other, net.......................................... 8,055 8,139 19,442 9,902 5,136
Minority interest in income of
subsidiary (Note 13).............................. (4,650) (4,650) (9,300) (8,732) --
Income taxes........................................ 414 (396) 160 (2,978) 4,248
---------- ---------- ---------- ---------- ----------
Other income, net............................. 7,019 7,793 18,189 9,420 30,210
---------- ---------- ---------- ---------- ----------
(Loss) Income before interest charges......... (3,420) 82,967 47,962 333,446 317,158
---------- ---------- ---------- ---------- ----------
Interest Charges:
Interest on long-term debt.......................... 63,882 60,131 127,198 124,350 119,927
Other interest...................................... 3,286 771 1,147 5,596 6,378
Deferred nuclear plants return--borrowed funds...... (68) (86) (146) (1,716) (7,435)
---------- ---------- ---------- ---------- ----------
Interest charges, net......................... 67,100 60,816 128,199 128,230 118,870
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net (Loss) Income..................................... $ (70,520) $ 22,151 $ (80,237) $ 205,216 $ 198,288
========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
For the Six Months Ended
June 30, For the Years Ended December 31,
--------------------- ----------------------------------
1997 1996 1996 1995 1994
--------------------- ----------------------------------
<S> <C> <C> <C> <C> <C>
(Thousands of Dollars)
Operating Activities: (Unaudited)
Net (Loss) Income .............................................. $ (70,520) $ 22,151 $ (80,237) $205,216 $198,288
Adjustments to reconcile to net cash
from operating activities:
Depreciation.................................................. 118,969 124,500 247,109 242,496 231,155
Deferred income taxes and investment tax credits, net......... (10,465) (46,362) (60,773) 49,520 37,664
Deferred nuclear plants return, net of amortization........... (119) 6,272 7,746 95,559 82,651
Deferred demand-side-management costs, net of amortization.... 37,329 23,306 26,941 (937) (4,691)
Recoverable energy costs, net of amortization................. 11,522 (2,044) (35,567) (16,169) 3,975
Deferred cogeneration costs, net of amortization.............. 16,388 6,193 25,957 (55,341) (36,821)
Nuclear compliance, net....................................... 1,240 38,447 50,500 -- --
Deferred nuclear refueling outage, net of amortization........ (22,667) 24,797 45,643 (20,712) (4,653)
Other sources of cash......................................... 19,899 88,202 75,552 86,956 47,791
Other uses of cash............................................ (27,065) (45,096) (23,862) (53,745) (4,697)
Changes in working capital:
Receivables and accrued utility revenues...................... 10,334 31,484 (22,378) (33,032) 45,386
Fuel, materials, and supplies................................. (4,430) (15,146) (11,455) (4,479) (3,756)
Accounts payable.............................................. (57,803) (5,940) 83,951 9,605 (24,167)
Accrued taxes................................................. (3,921) (38,199) (23,561) 25,855 (9,726)
Other working capital (excludes cash)......................... (44,711) 2,154 (5,385) (1,869) (18,403)
--------- -------- --------- --------- --------
Net cash flows (used for) from operating activities............... (26,020) 214,719 300,181 528,923 539,996
--------- -------- --------- --------- --------
Financing Activities:
Issuance of Monthly Income Preferred Securities................ -- -- -- 100,000 --
Net increase (decrease) in short-term debt...................... 100,000 (51,750) (51,750) (127,000) 82,500
Issuance of long-term debt...................................... 200,000 222,000 222,000 -- 535,000
Reacquisitions and retirements of long-term debt................ (193,288) (9,479) (14,329) (10,866) (774,020)
Reacquisitions and retirements of preferred stock............... -- (125,000) --
Cash dividends on preferred stock............................... (7,611) (7,611) (15,221) (21,185) (23,895)
Cash dividends on common stock.................................. (5,989) (103,528) (138,608) (164,154) (159,388)
--------- -------- --------- --------- --------
Net cash flows from (used for) financing activities............... 93,112 49,632 2,092 (348,205) (339,803)
--------- -------- --------- --------- --------
Investment Activities:
Investment in plant:
Electric utility plant........................................ (74,494) (56,363) (140,086) (131,858) (149,889)
Nuclear fuel.................................................. (669) 2,255 553 (1,543) (20,905)
--------- -------- --------- --------- --------
Net cash flows used for investments in plant.................... (75,163) (54,108) (139,533) (133,401) (170,794)
NU System Money Pool............................................ 53,050 (187,950) (109,050) -- --
Investments in nuclear decommissioning trusts................... (19,194) (22,858) (50,998) (47,826) (28,129)
Other investment activities, net................................ (25,926) 437 (2,625) 581 (1,565)
--------- -------- --------- --------- --------
Net cash flows used for investments............................... (67,233) (264,479) (302,206) (180,646) (200,488)
--------- -------- --------- --------- --------
Net (Decrease) Increase In Cash For The Period.................... (141) (128) 67 72 (295)
Cash - beginning of period........................................ 404 337 337 265 560
--------- -------- --------- --------- --------
Cash - end of period.............................................. $ 263 $ 209 $ 404 $ 337 $ 265
========= ======== ========= ========= ========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized............................ $ 114,458 $ 117,074 $115,120
========= ========= ========
Income taxes............................................. $ 77,790 $ 137,706 $161,513
========= ========= ========
Increase in obligations:
Niantic Bay Fuel Trust and other capital leases................ $ 2,855 $ 33,537 $ 52,353
========= ========= ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
Capital Retained
Common Surplus, Earnings
Stock Paid In (a) Total
---------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
(Thousands of Dollars)
Balance at January 1, 1994........................... $ 122,229 $ 630,271 $ 750,719 $ 1,503,219
Net income for 1994.............................. 198,288 198,288
Cash dividends on preferred stock................ (23,895) (23,895)
Cash dividends on common stock................... (159,388) (159,388)
Capital stock expenses, net...................... 1,846 1,846
---------- ---------- ---------- -----------
Balance at December 31, 1994......................... 122,229 632,117 765,724 1,520,070
Net income for 1995.............................. 205,216 205,216
Cash dividends on preferred stock................ (21,185) (21,185)
Cash dividends on common stock................... (164,154) (164,154)
Loss on the retirement of preferred stock........ (125) (125)
Capital stock expenses, net...................... 5,864 5,864
---------- ---------- ---------- -----------
Balance at December 31, 1995......................... 122,229 637,981 785,476 1,545,686
Net loss for 1996................................ (80,237) (80,237)
Cash dividends on preferred stock................ (15,221) (15,221)
Cash dividends on common stock................... (138,608) (138,608)
Capital stock expenses, net...................... 1,676 1,676
---------- ---------- ---------- -----------
Balance at December 31, 1996......................... 122,229 639,657 551,410 1,313,296
(Unaudited)
Net loss for six months ended
June 30, 1997.................................. (70,520) (70,520)
Cash dividends on preferred stock................ (7,611) (7,611)
Cash dividends on common stock................... (5,989) (5,989)
Capital stock expenses, net...................... 838 838
---------- ---------- ---------- -----------
Balance at June 30, 1997 (unaudited)................. $ 122,229 $ 640,495 $ 467,290 $ 1,230,014
========== ========== ========== ===========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At June 30, 1997 and December 31, 1996, these restrictions
totaled approximately $540 million.
The accompanying notes are an integral part of these financial statements.
F-7
<PAGE>
[THIS PAGE INTENTIONALLY LEFT BLANK]
ILB
F-8
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About The Connecticut Light and Power Company
The Connecticut Light and Power Company and Subsidiaries (the company or
CL&P), Western Massachusetts Electric Company (WMECO), Holyoke Water
Power Company (HWP), Public Service Company of New Hampshire (PSNH), and
North Atlantic Energy Corporation (NAEC) are the operating subsidiaries
comprising the Northeast Utilities system (the system) and are wholly
owned by Northeast Utilities (NU).
The system furnishes franchised retail electric service in Connecticut,
New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and
HWP. A fifth subsidiary, NAEC, sells all of its entitlement to the
capacity and output of the Seabrook nuclear power plant to PSNH. In
addition to its franchised retail electric service, the system furnishes
firm and other wholesale electric services to various municipalities and
other utilities and, on a pilot basis pursuant to state regulatory
experiments, provides off-system retail electric service. The system
serves about 30 percent of New England's electric needs and is one of the
20 largest electric utility systems in the country as measured by
revenues.
Other wholly owned subsidiaries of NU provide support services for the
system companies and in some cases, for other New England utilities.
Northeast Utilities Service Company (NUSCO) provides centralized
accounting, administrative, information resources, engineering,
financial, legal, operational, planning, purchasing, and other services
to the system companies. Northeast Nuclear Energy Company (NNECO) acts
as agent for the system companies in operating the Millstone nuclear
generating facilities. North Atlantic Energy Service Corporation (NAESCO)
acts as agent for CL&P and NAEC and has operational responsibilities for
the Seabrook nuclear generating facility.
B. Presentation
General: The consolidated financial statements of CL&P include the
accounts of all wholly owned subsidiaries. Significant intercompany
transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
F-9
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Certain reclassifications of prior periods' data have been made to
conform with the current period's presentation.
All transactions among affiliated companies are on a recovery of cost
basis which may include amounts representing a return on equity, and are
subject to approval by various federal and state regulatory agencies.
Unaudited Interim Financial Statements: In the opinion of the company,
the accompanying interim financial statements contain all adjustments
necessary to present fairly the financial position as of June 30, 1997,
the results of operations for the six-month periods ended June 30, 1997
and 1996, and the statements of cash flows for the six-month periods
ended June 30, 1997 and 1996. All adjustments are of a normal, recurring,
nature except those described below in Note 11B. The results of
operations for the six-month periods ended June 30, 1997 and 1996 are not
necessarily indicative of the results expected for a full year.
Certain notes to financial statements have not been updated for the
interim periods because there have been no significant events.
C. Public Utility Regulation
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 it and its subsidiaries, including the company, are
subject to the provisions of the 1935 Act. Arrangements among the system
companies, outside agencies and other utilities covering
interconnections, 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 company is subject to further
regulation for rates, accounting and other matters by the FERC and/or the
Connecticut Department of Public Utility Control (DPUC).
D. New Accounting Standards
The Financial Accounting Standards Board (FASB) has issued Statement of
Financial Accounting Standards (SFAS) 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which
established accounting standards for evaluating and recording asset
impairment. The company adopted SFAS 121 as of January 1, 1996. See Note
1H, "Summary of Significant Accounting Policies - Regulatory Accounting
and Assets" for further information on the regulatory impacts of the
company's adoption of SFAS 121.
See Note 10, "Sale of Customer Receivables and Accrued Utility Revenues,"
and Note 11C, "Commitments and Contingencies -
F-10
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Environmental Matters," for information on newly issued accounting and
reporting standards related to those specific areas.
The FASB issued two new accounting standards in February 1997: SFAS No.
128, "Earnings per Share" and SFAS 129, "Disclosure of Information about
Capital Structure." SFAS 128 and SFAS 129 will be effective for 1997
year-end reporting. FASB issued two new accounting standards during June
1997: SFAS No. 130, "Reporting Comprehensive Income" and SFAS 131,
"Disclosures about Segments of an Enterprise and Related Information."
SFAS 130 establishes standards for the reporting and disclosure of
comprehensive income. SFAS 131 determines the standards for reporting and
disclosing qualitative and quantitative information about a company's
operating segments. Both SFAS 130 and SFAS 131 will be effective in 1998.
Management believes that the implementation of SFAS 128, SFAS 129, SFAS
130, and SFAS 131 will not have a material impact on CL&P's financial
position or its results of operations.
E. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: CL&P owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with the company's ownership interests are:
<TABLE>
<CAPTION>
------------------------------------------------------------
<S> <C>
Connecticut Yankee Atomic Power Company (a) (CYAPC).. 34.5%
Yankee Atomic Electric Company (a) (YAEC)............ 24.5
Maine Yankee Atomic Power Company (a)(MYAPC)......... 12.0
Vermont Yankee Nuclear Power Corporation (VYNPC)..... 9.5
------------------------------------------------------------
</TABLE>
(a) YAEC's, CYAPC's, and MYAPC's nuclear power plants were shut down
permanently on February 26, 1992, December 4, 1996, and August 6,
1997, respectively.
CL&P's investments in the Yankee companies are accounted for on the
equity basis due to the company's ability to exercise significant
influence over their operating and financial policies.
F-11
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
CL&P's investments in the Yankee companies at December 31, 1996 are:
<TABLE>
<CAPTION>
------------------------------------------------------------------
(Thousands of Dollars)
<S> <C>
Connecticut Yankee Atomic Power Company.... $36,954
Yankee Atomic Electric Company............. 5,854
Maine Yankee Atomic Power Company.......... 8,956
Vermont Yankee Nuclear Power Corporation... 5,161
-------
$56,925
-------------------------------------------------------------------
</TABLE>
The electricity produced by VY is committed substantially on the basis of
ownership interests and is billed pursuant to contractual agreement.
Under ownership agreements with the Yankee companies, CL&P may be asked
to provide direct or indirect financial support for one or more of the
companies. For more information on these agreements, see Note 11F,
"Commitments and Contingencies - Long-Term Contractual Arrangements."
For more information on the Yankee companies, see Note 3, "Nuclear
Decommissioning" and Note 11B, "Commitments and Contingencies - Nuclear
Performance."
Millstone 1: CL&P has an 81.0 percent joint ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December
31, 1996 and 1995, plant-in-service included approximately $384.5 million
and $372.6 million, respectively, and the accumulated provision for
depreciation included approximately $159.4 million and $148.4 million,
respectively, for CL&P's share of Millstone 1. CL&P's share of Millstone
1 expenses is included in the corresponding operating expenses on the
accompanying Consolidated Statements of Income.
Millstone 2: CL&P has an 81.0 percent joint ownership interest in
Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1996
and 1995, plant-in-service included approximately $690.4 million and
$684.5 million, respectively, and the accumulated provision for
depreciation included approximately $224.1 million and $198.5 million,
respectively, for CL&P's share of Millstone 2. CL&P's share of Millstone
2 expenses is included in the corresponding operating expenses on the
accompanying Consolidated Statements of Income.
Millstone 3: CL&P has a 52.93 percent joint ownership interest in
Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1996
and 1995, plant-in-service included approximately $1.9 billion, and the
accumulated provision for depreciation included approximately $504.1
million and $455.1 million, respectively, for CL&P's share of Millstone
3. CL&P's
F-12
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
share of Millstone 3 expenses is included in the corresponding operating
expenses on the accompanying Consolidated Statements of Income.
For more information regarding the Millstone units, see Note 11B,
"Commitments and Contingencies - Nuclear Performance."
Seabrook 1: CL&P has a 4.06 percent joint ownership interest in Seabrook
1, a 1,148-MW nuclear generating unit. As of December 31, 1996 and 1995,
plant-in-service included approximately $173.7 million and $173.3
million, respectively, and the accumulated provision for depreciation
included approximately $29.7 million and $24.8 million, respectively, for
CL&P's share of Seabrook 1. CL&P's share of Seabrook 1 expenses is
included in the corresponding operating expenses on the accompanying
Consolidated Statements of Income.
F. Depreciation
The provision for depreciation is calculated using the straight-line
method based on estimated remaining lives of depreciable utility plant-
in-service, adjusted for salvage value and removal costs, as approved by
the appropriate regulatory agency. 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
plant, including costs of removal, less salvage, is charged to the
accumulated provision for depreciation. The depreciation rates for the
several classes of electric plant-in-service are equivalent to a
composite rate of 4.0 percent in 1996 and 1995, and 3.9 percent in 1994.
See Note 3, "Nuclear Decommissioning," for information on nuclear plant
decommissioning.
CL&P's nonnuclear generating facilities have limited service lives.
Plant may be retired in place or dismantled based upon expected future
needs, the economics of the closure and environmental concerns. The
costs of closure and removal are incremental costs and, for financial
reporting purposes, are accrued over the life of the asset as part of
depreciation. At December 31, 1996, the accumulated provision for
depreciation included approximately $43 million accrued for the cost of
removal, net of salvage for nonnuclear generation property.
G. Revenues
Other than revenues under fixed-rate agreements negotiated with certain
wholesale, industrial and commercial customers and limited pilot retail
access programs, utility revenues are based on authorized rates applied
to each customer's use of electricity. In general, rates can be changed
only through a
F-13
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
formal proceeding before the appropriate regulatory commission. At the
end of each accounting period, CL&P accrues an estimate for the amount of
energy delivered but unbilled.
H. Regulatory Accounting and Assets
The accounting policies of CL&P and the accompanying consolidated
financial statements conform to generally accepted accounting principles
applicable to rate regulated enterprises and reflect the effects of the
ratemaking process in accordance with SFAS 71, "Accounting for the
Effects of Certain Types of Regulation." Assuming a cost-of-service based
regulatory structure, regulators may permit incurred costs, normally
treated as expenses, to be deferred and recovered through future
revenues. Through their actions, regulators may also reduce or eliminate
the value of an asset, or create a liability. If any portion of the
company's operations were no longer subject to the provisions of SFAS 71,
as a result of a change in the cost-of-service based regulatory structure
or the effects of competition, the company would be required to write off
related regulatory assets and liabilities.
Recently, the SEC has questioned the ability of certain utilities to
remain on SFAS 71 in light of state legislation regarding the transition
to retail competition. The industry expects guidance on this issue from
FASB's Emerging Issues Task Force in the near future. While there are
restructuring initiatives pending in the NU system companies' respective
jurisdictions, CL&P is not yet subject to a transition plan.
The company continues to believe that its use of regulatory accounting
remains appropriate.
SFAS 121 requires the evaluation of long-lived assets, including
regulatory assets, for impairment when certain events occur or when
conditions exist that indicate the carrying amounts of assets may not be
recoverable. SFAS 121 requires that any long-lived assets which are no
longer probable of recovery through future revenues be revalued based on
estimated future cash flows. If the revaluation is less than the book
value of the asset, an impairment loss would be charged to earnings. The
implementation of SFAS 121 did not have a material impact on the
company's financial position or results of operations as of June 30, 1997
and December 31, 1996. Management continues to believe that it is
probable that the company will recover its investments in long-lived
assets through future revenues. This conclusion may change in the future
as competitive factors influence wholesale and retail pricing in the
electric utility industry or if the cost-of-service based regulatory
structure were to change.
F-14
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The components of CL&P's regulatory assets are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
June 30, December 31,
1997 1996 1995
- --------------------------------------------------------------------
<S> <C> <C> <C>
(Unaudited) (Thousands of Dollars)
Income taxes, net (Note 1I)...... $ 722,085 $ 753,390 $ 863,521
Recoverable energy costs,
net (Note 1J)................... 87,341 97,900 9,662
Deferred demand side management
costs (Note 1K)................. 52,800 90,129 117,070
Cogeneration costs (Note 1L)..... 49,817 66,205 92,162
Unrecovered contractual
obligations (Note 3)............ 263,874 300,627 65,847
Other............................ 60,501 62,530 77,018
---------- ---------- ----------
$1,236,418 $1,370,781 $1,225,280
========== ========== ==========
</TABLE>
For more information on the company's regulatory environment and the
potential impacts of restructuring, see Note 11A, "Commitments and
Contingencies - Restructuring" and Management's Discussion and Analysis
of Financial Condition and Results of Operations (MD&A).
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 ratemaking treatment of the
applicable regulatory commissions. The adoption of SFAS 109, "Accounting
for Income Taxes," in 1993 increased the company's net deferred tax
obligation. As it is probable that the increase in deferred tax
liabilities will be recovered from customers through rates, CL&P
established a regulatory asset. See Note 8, "Income Tax Expense" for the
components of income tax expense.
F-15
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The tax effect of temporary differences, including timing differences
accrued under previously approved accounting standards, which give rise
to the accumulated deferred tax obligation is as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
June 30, December 31,
1997 1996 1995
- --------------------------------------------------------------------
(Unaudited) (Thousands of Dollars)
<S> <C> <C> <C>
Accelerated depreciation
and other plant-
related differences...... $1,026,636 $1,032,857 $1,074,242
Regulatory assets -
income tax gross up...... 304,383 313,420 347,673
Other..................... 3,935 19,364 64,958
---------- ---------- ----------
$1,334,954 $1,365,641 $1,486,873
========== ========== ==========
</TABLE>
J. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for
its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (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 is currently recovering these costs through rates. As of June 30,
1997 and December 31, 1996, the company's total D&D deferrals were
approximately $49.3 million and $49.2 million, respectively.
During 1996, retail electric rates included a fuel adjustment clause
(FAC) under which fossil fuel prices above or below base-rate levels are
charged or credited to customers. In addition, CL&P also utilized a
generation utilization adjustment clause (GUAC), which deferred the
effect on fuel costs caused by variations from a specified composite
nuclear generation capacity factor embedded in base rates.
At June 30, 1997 and December 31, 1996, CL&P's net recoverable energy
costs, excluding current net recoverable energy costs, were approximately
$87.3 million and $97.9 million, respectively, which includes the D&D
assessment. For additional information, see Note 11B, "Commitments and
Contingencies - Nuclear Performance."
On October 8, 1996, the DPUC issued an order establishing an Energy
Adjustment Clause (EAC) which became effective
F-16
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
January 1, 1997. The EAC has replaced CL&P's existing FAC and GUAC. For
further information regarding the EAC, see the MD&A.
K. Demand Side Management (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). The $90.1 million of costs on CL&P's books
as of December 31, 1996, will be fully recovered by 2000. During
November, 1996, CL&P filed its 1997 DSM program and forecasted CAM for
1997 with the DPUC. The filing proposes expenditures of $36 million in
1997, with recovery over 1.9 years and a zero CAM rate. In April 1997,
the DPUC approved 1997 expenditures of $36 million, a zero CAM rate for
1997 and recovery of the 1997 expenditures over 1.7 years beginning
January 1, 1998.
L. Cogeneration Costs
Beginning on July 1, 1996, the deferred cogeneration balance of
approximately $86 million is being amortized over a five year period. An
additional $9 million of amortization is being applied to the deferred
balance in 1997, as required under a settlement agreement which CL&P
reached with the DPUC. CL&P will continue to apply any savings associated
with the renegotiation of a certain contract with a cogeneration facility
to the deferred balance. Under current expectations, CL&P expects
complete amortization of the deferred balance by December 31, 1998.
M. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear fuel
and high-level radioactive waste. 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. For nuclear fuel used to generate electricity prior
to April 7, 1983 (prior-period fuel), payment must be made prior to the
first delivery of spent fuel to the DOE. The DOE was originally
scheduled to begin accepting delivery of spent fuel in 1998. However,
delays in identifying a permanent storage site have continually postponed
plans for the DOE's long-term storage and disposal site. The DOE's
current estimate for an available site is 2010.
Until such payment is made, the outstanding balance will continue to
accrue interest at the three-month Treasury Bill Yield Rate. At December
31, 1996, fees due to the DOE for the disposal of prior-period fuel were
approximately $158.0 million, including interest costs of $91.5 million.
At June 30, 1997, fees due to the DOE for the disposal of spent nuclear
fuel were approximately $162.1 million, including
F-17
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
interest costs of $95.6 million. As of June 30, 1997, all fees had been
collected through rates.
N. Fuel Price Management
The company utilizes fuel-price management instruments to manage well
defined fuel price risks. Amounts receivable or payable under fuel-price
management instruments are recognized in income when realized. Any
material unrealized gains or losses on fuel-price management instruments
will be deferred until realized. For further information, see Note 12,
"Fuel Price Management."
2. LEASES
CL&P and WMECO finance up to $450 million of nuclear fuel for Millstone 1
and 2 and their respective shares of the nuclear fuel for Millstone 3 under
the Niantic Bay Fuel Trust (NBFT) capital lease agreement. 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.
CL&P has also entered into lease agreements, some of which are capital
leases, for the use of data processing and office equipment, vehicles, gas
turbines, nuclear control room simulators and office space. The provisions
of these lease agreements generally provide for renewal options. The
following rental payments have been charged to expense:
<TABLE>
<CAPTION>
Year Capital Leases Operating Leases
---- -------------- ----------------
<S> <C> <C>
1996.......... $17,993,000 $22,032,000
1995.......... 56,307,000 23,793,000
1994.......... 60,975,000 24,192,000
</TABLE>
Interest included in capital lease rental payments was $10,144,000 in
1996, $10,587,000 in 1995, and $10,228,000 in 1994.
Substantially all of the capital lease rental payments were made
pursuant to the nuclear fuel lease agreement. Future minimum lease payments
under the nuclear fuel capital lease cannot be reasonably estimated on an
annual basis due to variations in the usage of nuclear fuel.
F-18
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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, 1996 are:
<TABLE>
<CAPTION>
Year Capital Leases Operating Leases
---- -------------- ----------------
(Thousands of Dollars)
<S> <C> <C>
1997...................... $ 2,800 $ 26,100
1998...................... 2,900 21,500
1999...................... 2,900 19,900
2000...................... 2,900 18,800
2001...................... 3,000 13,700
After 2001................ 66,400 46,400
-------- --------
Future minimum lease
payments................ 80,900 $146,400
========
Less amount representing
interest............... 61,900
--------
Present value of future
minimum lease payments
for other than
nuclear fuel............ 19,000
Present value of future
nuclear fuel lease
payments................ 136,800
--------
Total..................... $155,800
========
</TABLE>
It is possible that certain operating lease payments related to NUSCO
leases will be accelerated from future years into 1997. See Note 11G, "The
Rocky River Realty Company - Obligations" for additional information.
On June 21, 1996, CL&P entered into an operating lease with a third party
to acquire the use of four turbine generators having an installed cost of
approximately $70 million. During the first quarter of 1997, CL&P
determined that it would not be in compliance with financial coverage tests
required under the lease agreement. CL&P has reached an agreement with the
lessors for a resolution of this matter. Management believes that the terms
and conditions of this agreement will not have a material adverse impact on
the company's financial position or results of operations.
F-19
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
3. NUCLEAR DECOMMISSIONING
CL&P's nuclear power plants have service lives that are expected to end
during the years 2010 through 2026. Upon retirement, these units must be
decommissioned. Decommissioning studies prepared in 1996 concluded that
complete and immediate dismantlement at retirement continues to be the most
viable and economic method of decommissioning the three Millstone units and
Seabrook 1. Decommissioning studies are reviewed and updated periodically
to reflect changes in decommissioning requirements, costs, technology and
inflation.
The estimated cost of decommissioning CL&P's ownership share of Millstone 1
and 2, in year-end 1996 dollars, is $316.0 million and $279.0 million,
respectively. CL&P's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 in year-end 1996 dollars, is
$244.9 million and $18.3 million, respectively. The Millstone units and
Seabrook 1 decommissioning costs will be increased annually by their
respective escalation rates. Nuclear decommissioning costs are accrued
over the expected service life of the units and are included in
depreciation expense on the Consolidated Statements of Income. Nuclear
decommissioning costs amounted to $37.8 million in 1996, $30.5 million in
1995, and $25.6 million in 1994. Nuclear decommissioning, as a cost of
removal, is included in the accumulated provision for depreciation on the
Consolidated Balance Sheets. At June 30, 1997 and December 31, 1996, the
balance in the accumulated reserve for decommissioning amounted to $361.1
million and $329.1 million, respectively.
CL&P has established external decommissioning trusts through a trustee for
its portion of the costs of decommissioning Millstone 1, 2, and 3. CL&P's
portion of the cost of decommissioning Seabrook 1 is paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
Funding of the estimated decommissioning costs assume levelized collections
for the Millstone units and escalated collections for Seabrook 1 and after-
tax earnings on the Millstone and Seabrook decommissioning funds of 5.8
percent and 6.5 percent, respectively.
As of June 30, 1997 and December 31, 1996, CL&P has collected, through
rates, $259.4 million and $240.8 million, respectively, towards the future
decommissioning costs of its share of the Millstone units, of which $221.7
million and $209.1 million, respectively, have been transferred to external
decommissioning trusts. As of June 30, 1997 and December 31, 1996, CL&P
has paid approximately $2.6 million and $2.4 million, respectively, into
Seabrook 1's decommissioning financing fund. Earnings on the
decommissioning trusts and financing fund increase the decommissioning
trust balance and the accumulated reserve for decommissioning. Unrealized
gains and losses associated with the
F-20
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
decommissioning trusts and financing fund also impact the balance of the
trusts and financing fund and the accumulated reserve for decommissioning.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement would change decommissioning cost estimates and the amounts
required to be recovered. CL&P attempts to recover sufficient amounts
through its allowed rates to cover its expected decommissioning costs.
Only the portion of currently estimated total decommissioning costs that
has been accepted by regulatory agencies is reflected in CL&P's rates.
Based on present estimates and assuming its nuclear units operate to the
end of their respective license periods, CL&P expects that the
decommissioning trusts and financing fund will be substantially funded when
the units are retired from service.
VYNPC: VYNPC owns a single nuclear generating unit (VY). VY has a service
life that is expected to end in 2012. The estimated cost, in year-end 1996
dollars, of decommissioning CL&P's ownership share of the unit owned and
operated by VYNPC is $34.8 million. Under the terms of the contract with
VYNPC, the shareholders-sponsors are responsible for their proportionate
share of the operating costs of the unit, including decommissioning. The
nuclear decommissioning costs of VY is included as part of the cost of
power purchased by CL&P.
MYAPC: MYAPC owns a single nuclear generating unit (MY) with a service
life that was expected to end in 2008. On August 6, 1997, the board of
directors of MYAPC voted unanimously to cease permanently the production of
power at its nuclear plant. The system companies had relied on MY for
approximately two percent of their capacity.
For further information on MY, see Note 11B, "Commitments and Contingencies
- Nuclear Performance."
CYAPC: On December 4, 1996, the board of directors of CYAPC voted
unanimously to cease permanently the production of power at its nuclear
plant (CY). The system companies relied on CY for approximately three
percent of their capacity.
CYAPC has undertaken a number of regulatory filings intended to implement
the decommissioning and the recovery of remaining assets of CY. During
late December, 1996, CYAPC filed an amendment to its power contracts to
clarify the obligations of its purchasing utilities following the decision
to cease power production. At December 31, 1996, the estimated obligation,
including decommissioning, amounted to $762.8 million of which CL&P's share
was approximately $263.2 million.
F-21
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
On February 27, 1997, FERC approved an order for hearing which, among other
things, accepted CYAPC's contract amendments for filing and suspended the
new rates for a nominal period. The new rates became effective March 1,
1997, subject to refund. At June 30, 1997, CL&P's share of the CY
unrecovered contractual obligation, which also has been recorded as a
regulatory asset, was $235.0 million.
YAEC: YAEC is in the process of decommissioning its nuclear facility. At
December 31, 1996, the estimated remaining costs, including
decommissioning, amounted to $173.3 million of which CL&P's share was
approximately $42.5 million. At June 30, 1997, CL&P's share of the YAEC
unrecovered contractual obligation which also has been recorded as a
regulatory asset, was $28.8 million.
Management expects that CL&P will continue to be allowed to recover the
costs associated with CY and YAEC from its customers. Accordingly, CL&P has
recognized these costs as regulatory assets, with corresponding
obligations, on its Consolidated Balance Sheets.
Proposed Accounting: The staff of the SEC has questioned certain of the
current accounting practices of the electric utility industry, including
the company, regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating units in the financial
statements. In response to these questions, FASB agreed to review the
accounting for removal costs, including decommissioning, and issued a
proposed statement entitled "Accounting for Liabilities Related to Closure
or Removal of Long-Lived Assets," in February, 1996. If current electric
utility industry accounting practices for decommissioning are changed in
accordance with the proposed statement: (1) annual provisions for
decommissioning could increase, (2) the estimated cost for decommissioning
could be recorded as a liability with an offset to plant rather than as
part of accumulated depreciation, and (3) trust fund income from the
external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense.
4. SHORT-TERM DEBT
Limits: The amount of short-term borrowings that may be incurred by CL&P is
subject to periodic approval by either the SEC under the 1935 Act or by its
state regulator. In addition, the charter of CL&P contains provisions
restricting the amount of short-term debt borrowings. Under the SEC and/or
charter restrictions, the company was authorized, as of January 1, 1997, to
incur short-term borrowings up to a maximum of $375 million.
F-22
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Credit Agreements: In November, 1996, NU entered into a three-year
revolving credit agreement (New Credit Agreement) with a group of 12 banks.
Under the terms of the New Credit Agreement, NU, CL&P and WMECO will be
able to borrow up to $150 million, $313.75 million, and $150 million,
respectively. The overall limit for all of the borrowing system companies
under the entire New Credit Agreement is $313.75 million. The system
companies are currently obligated to pay a facility fee of .50 percent per
annum of each bank's total commitment under the new credit facility which
will expire November 21, 1999. At December 31, 1996 there were $27.5
million in borrowings under this agreement, all of which were borrowed by
other system companies. At June 30, 1997, there were no borrowings under
this agreement.
Access to the New Credit Agreement is contingent upon certain financial
tests being met. NU is currently renegotiating these restrictions so that
the financial impacts of the current nuclear outages do not impact the
ability to access these facilities. Through February 21, 1997, CL&P and
WMECO have satisfied all financial covenants required under their
respective borrowing facilities, but NU needed and obtained a limited
waiver of an interest coverage covenant that had to be satisfied for NU to
borrow under the New Credit Agreement.
On May 30, 1997, the First Amendment and Waiver became effective, replacing
an interim written agreement and amending the New Credit Agreement. This
closing permitted $313.75 million of credit to remain available to CL&P and
WMECO through securing their borrowings with first mortgage bonds.
Interest coverage and common equity ratios were revised to enable the
companies to meet certain financial tests. CL&P will be able to borrow up
to $225 million on the strength of bonds it has provided as collateral for
borrowings under this agreement. WMECO will be able to borrow up to $90
million on the basis of bonds it has provided as collateral and the NU
parent company, which as a holding company cannot issue first mortgage
bonds, will be able to borrow up to $50 million if CL&P, WMECO, and NU
consolidated financial statements meet certain interest coverage tests for
two consecutive quarters.
In addition to the New Credit Agreement, NU, CL&P, WMECO, HWP, NNECO and
The Rocky River Realty Company (RRR) have various revolving credit lines
through separate bilateral credit agreements. Under the remaining three-
year portion of the facility, four banks maintain commitments to the
respective system companies totaling $56.25 million. NU, CL&P and WMECO
may borrow up to the aggregate $56.25 million, whereas HWP, NNECO and RRR
may borrow up to their short-term debt limit of $5 million, $50 million and
$22 million, respectively. Under the terms of the agreement, the system
companies are obligated to pay a facility fee of .15 percent per annum of
each bank's total commitment
F-23
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
under the three-year portion of the facility. These commitments will expire
December 3, 1998. At December 31, 1996 and 1995, there were $11.3 million
and $42.5 million in borrowings, respectively, under the facility, of which
CL&P had no borrowings in 1996 and $10 million in borrowings in 1995. At
June 30, 1997, CL&P had no borrowings under the facility.
Under both credit facilities above, the company may borrow funds on a
short-term revolving basis under the remaining portion of its agreement,
using either fixed-rate loans or standby loans. Fixed rates are set using
competitive bidding. Standby loans are based upon several alternative
variable rates.
The weighted average annual interest rate on CL&P's notes payable to banks
outstanding at December 31, 1995 was 6.0 percent.
Maturities of CL&P's short-term debt obligations are for periods of three
months or less.
Money Pool: Certain subsidiaries of NU, including CL&P, are members of the
Northeast Utilities System Money Pool (Pool). The Pool provides a more
efficient use of the cash resources of the system, and reduces outside
short-term borrowings. NUSCO administers the Pool as agent for the member
companies. Short-term borrowing needs of the member companies are first
met with available funds of other member companies, including funds
borrowed by NU parent. NU parent may lend to the Pool but may not borrow.
Funds may be withdrawn from or repaid to the Pool at any time without prior
notice. Investing and borrowing subsidiaries receive or pay interest based
on the average daily Federal Funds rate. However, borrowings based on loans
from NU parent bear interest at NU parent's cost and must be repaid based
upon the terms of NU parent's original borrowing. At June 30, 1997 and
December 31, 1996, CL&P had no borrowings outstanding from the Pool. At
December 31, 1995, CL&P had $10.3 million of borrowings outstanding from
the Pool. The interest rate on borrowings from the Pool on December 31,
1995 was 4.7 percent.
For further information on short-term debt see the MD&A.
F-24
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
<TABLE>
<CAPTION>
Shares
December 31, Outstanding
1996 at 6/30/97 June 30, December 31,
Redemption and 1997 -------------------------------
Description Price 12/31/96 (Unaudited) 1996 1995 1994
- ----------------------------- ------------ ----------- ----------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
$1.90 Series of 1947........ $52.50 163,912 $ 8,196 $ 8,196 $ 8,196 $ 8,196
$2.00 Series of 1947........ 54.00 336,088 16,804 16,804 16,804 16,804
$2.04 Series of 1949........ 52.00 100,000 5,000 5,000 5,000 5,000
$2.06 Series E of 1954...... 51.00 200,000 10,000 10,000 10,000 10,000
$2.09 Series F of 1955...... 51.00 100,000 5,000 5,000 5,000 5,000
$2.20 Series of 1949........ 52.50 200,000 10,000 10,000 10,000 10,000
$3.24 Series G of 1968...... 51.84 300,000 15,000 15,000 15,000 15,000
3.90% Series of 1949........ 50.50 160,000 8,000 8,000 8,000 8,000
4.50% Series of 1956........ 50.75 104,000 5,200 5,200 5,200 5,200
4.50% Series of 1963........ 50.50 160,000 8,000 8,000 8,000 8,000
4.96% Series of 1958........ 50.50 100,000 5,000 5,000 5,000 5,000
5.28% Series of 1967........ 51.43 200,000 10,000 10,000 10,000 10,000
6.56% Series of 1968........ 51.44 200,000 10,000 10,000 10,000 10,000
1989 Adjustable Rate DARTS.. -- -- -- -- -- 50,000
Total preferred stock
not subject to
mandatory redemption $116,200 $116,200 $116,200 $166,200
======== ======== ======== ========
</TABLE>
All or any part of each outstanding series of such preferred stock may be
redeemed by the company at any time at established redemption prices plus
accrued dividend to the date of redemption.
F-25
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
<TABLE>
<CAPTION>
Shares
December 31, Outstanding
1996 at 6/30/97 June 30, December 31,
Redemption and 1997 ----------------------------
Description Price* 12/31/96 (Unaudited) 1996 1995 1994
- ------------------------ ------------ ---------- ---------- -------- -------- --------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
9.00% Series of 1989... -- -- $ -- $ -- $ -- $ 75,000
7.23% Series of 1992... $52.41 1,500,000 75,000 75,000 75,000 75,000
5.30% Series of 1993... $51.00 1,600,000 80,000 80,000 80,000 80,000
-------- ------- -------- --------
$155,000 $155,000 $155,000 $230,000
======== ======== ======== ========
Less preferred stock
to be redeemed
within one year........ -- -- -- 3,750
Total preferred stock
subject to mandatory
redemption............. $155,000 $155,000 $155,000 $226,250
======== ======== ======== ========
</TABLE>
*Each of these series is subject to certain refunding limitations
for the first five years after they were issued. Redemption prices
reduce in future years.
The following table details redemption and sinking fund activity for preferred
stock subject to mandatory redemption:
<TABLE>
<CAPTION>
Minimum
Annual Shares Reacquired
Sinking-Fund ----------------------------
Series Requirement 1996 1995 1994
- -------------------------- -------------- --------- --------- --------
(Thousand of Dollars)
<S> <C> <C> <C> <C>
9.00% Series of 1989 $ -- -- 3,000,000 --
7.23% Series of 1992 (1) 3,750 -- -- --
5.30% Series of 1993 (2) 16,000 -- -- --
</TABLE>
(1) Sinking fund requirements commence September 1, 1998.
(2) Sinking fund requirements commence October 1, 1999.
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1998 through 2001, aggregate approximately $3.8
million in 1998, and $19.8 million in 1999, 2000 and 2001. There were no
minimum sinking-fund provisions in 1997. In case of default on sinking-
fund payments or the payment of dividends, 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 the company is in
arrears in the payment of dividends on any outstanding shares of preferred
stock, the company would be prohibited from redemption or
F-26
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
purchase of less than all of the preferred stock outstanding. All or part
of each of the series named above may be redeemed by the company at any
time at established redemption prices plus accrued dividends to the date of
redemption, subject to certain refunding limitations.
7. LONG-TERM DEBT
Details of long-term debt outstanding are:
<TABLE>
<CAPTION>
December 31,
June 30, ----------------------
1997
(Unaudited) 1996 1995
- ---------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds:
7 5/8% Series UU due 1997..... $ -- $ 193,288 $ 197,245
6 1/2% Series T due 1998..... 20,000 20,000 20,000
7 1/4% Series VV due 1999..... 99,000 99,000 100,000
5 1/2% 1994 Series A due 1999. 140,000 140,000 140,000
5 3/4% Series XX due 2000..... 200,000 200,000 200,000
7 7/8% 1996 Series A due 2001. 160,000 160,000 --
7 3/4% 1997 Series B due 2002. 200,000 -- --
6 1/8% 1994 Series B due 2004. 140,000 140,000 140,000
7 3/8% Series TT due 2019..... 20,000 20,000 20,000
7 1/2% Series YY due 2023..... 100,000 100,000 100,000
8 1/2% Series C due 2024...... 115,000 115,000 115,000
7 7/8% Series D due 2024...... 140,000 140,000 140,000
7 3/8% Series ZZ due 2025..... 125,000 125,000 125,000
---------- ---------- ----------
Total First Mortgage
Bonds 1,459,000 1,452,288 1,297,245
Pollution Control Notes:
Variable rate, due 2016-2022. 46,400 46,400 46,400
Tax exempt, due 2028-2031.... 377,500 377,500 315,500
Fees and interest due for
spent fuel disposal
costs (Note 1M).............. 162,116 157,968 149,978
Other......................... 5,691 10,915 20,286
Less: Amounts due within
one year..................... 25,615 204,116 9,372
Unamortized premium and
discount, net................ (6,630) (6,550) (7,391)
---------- ---------- ----------
Long-term debt, net.......... $2,018,462 $1,834,405 $1,812,646
========== ========== ==========
</TABLE>
F-27
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Long-term debt and cash sinking-fund requirements on debt outstanding at
December 31, 1996 for the years 1997 through 2001 are approximately $204.1
million, $20.0 million, $239.0 million, $200.0 million, and $160.0 million,
respectively. In addition, there are annual one-percent sinking- and
improvement-fund requirements, currently amounting to $14.5 million for
1997, $12.6 million for 1998, $12.4 million for 1999, $10.0 million for
2000, and $8.0 million for 2001. Such sinking- and improvement-fund
requirements may be satisfied by the deposit of cash or bonds or by
certification of property additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by the company at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which are
subject to certain refunding limitations during their respective initial
five-year redemption periods.
Essentially all of the company's utility plant is subject to the lien of
its first mortgage bond indenture. As of December 31, 1996 and 1995, the
company has secured $315.5 million of pollution control notes with second
mortgage liens on Millstone 1, junior to the lien of its first mortgage
bond indenture. The average effective interest rate on the variable-rate
pollution control notes ranged from 3.4 percent to 3.6 percent for 1996 and
from 3.8 percent to 4.0 percent for 1995.
On January 23, 1997, the letter of credit associated with CL&P's $62
million tax-exempt PCRBs, issued on May 21, 1996, was replaced with a bond
insurance and liquidity facility secured by First Mortgage Bonds. The bonds
were originally backed by a five-year letter of credit and secured by a
second mortgage on CL&P's interest in Millstone 1.
On June 26, 1997, CL&P issued $200 million of First and Refunding Mortgage
Bonds, 1997 Series B (CL&P 1997 Series B Bonds). The CL&P 1997 Series B
Bonds bear interest at an annual rate of 7.75 percent and will mature on
June 1, 2002.
Downgrade Events: On April 28, 1997, Moody's Investors Service (Moody's)
announced that it was downgrading both CL&P's and WMECO's first mortgage
bonds from their "Baa3" rating to a "Ba1" rating. This rating change has
placed CL&P's and WMECO's first mortgage bonds in Moody's below investment
grade category.
On May 22, 1997, Standard and Poor's Corporation (S&P) announced that it
was downgrading both CL&P's and WMECO's corporate credit and its senior
secured debt from their rating of "BBB-" to "BB+." This rating change has
placed CL&P's and WMECO's first mortgage bonds in S&P'S below investment
grade category.
F-28
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions
charged to operations are:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
Six Months Ended For the Years Ended
June 30, December 31,
1997 1996 1996 1995 1994
-----------------------------------------------------------------------------------------------------------------------
(Unaudited) (Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Current income taxes:
Federal.............................................. $(17,769) $ 56,713 $ 30,650 $ 93,906 $108,371
State................................................ (986) 19,529 9,789 37,898 39,966
-------- -------- -------- -------- --------
Total current........................................ (18,755) 76,242 40,439 131,804 148,337
-------- -------- -------- -------- --------
Deferred income taxes, net:
Federal............................................... (4,687) (31,270) (38,680) 52,075 44,180
State................................................. (2,095) (11,409) (14,726) 5,085 842
-------- -------- -------- -------- --------
Total deferred........................................ (6,782) (42,679) (53,406) 57,160 45,022
Investment tax credits, net............................. (3,683) (3,683) (7,367) (7,640) (7,358)
-------- -------- -------- -------- --------
Total income tax expense.............................. $(29,220) $ 29,880 $(20,334) $181,324 $186,001
======== ======== ======== ======== ========
</TABLE>
The components of total income tax expense are classified as
follows:
<TABLE>
<S> <C> <C> <C> <C> <C>
Income taxes charged to
operating expenses.................................... $(28,806) $ 29,484 $(20,174) $178,346 $190,249
Other income taxes...................................... (414) 396 (160) 2,978 (4,248)
-------- -------- -------- -------- --------
Total income tax expense................................ $(29,220) $ 29,880 $(20,334) $181,324 $186,001
======== ======== ======== ======== ========
</TABLE>
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
Six Months Ended For the Years Ended
June 30, December 31,
1997 1996 1996 1995 1994
-----------------------------------------------------------------------------------------------------------------------
(Unaudited) (Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Depreciation, leased nuclear fuel,
settlement credits and
disposal costs........................................ $ 6,266 $ 962 $ 3,981 $ 44,278 $ 38,874
Energy adjustment clauses............................... (13,870) (3,665) (1,654) 23,302 14,465
Demand-side management.................................. (12,148) (12,970) (17,099) 1,310 203
Nuclear plant deferrals................................. 10,489 (10,929) (18,861) (8,055) (20,452)
Bond redemptions........................................ (681) (938) (1,789) (2,255) 6,826
Contractual settlements................................. 873 1,304 2,513 (9,496) 109
Nuclear compliance reserves............................. (517) (16,085) (21,131) - -
Other................................................... 2,806 (358) 634 8,076 4,997
-------- -------- -------- -------- --------
Deferred income taxes, net.............................. $ (6,782) $(42,679) $(53,406) $ 57,160 $ 45,022
======== ======== ======== ======== ========
</TABLE>
F-29
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rate is as follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
June 30, December 31,
1997 1996 1996 1995 1994
----------------------------------------------------------------------------------------------------------
(Unaudited) (Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Expected federal income tax at
35 percent of pretax income..... $(35,149) $18,211 $(35,931) $135,289 $134,501
Tax effect of differences:
State income taxes, net of
federal benefit............... (2,002) 5,278 (3,209) 27,939 26,526
Depreciation.................... 9,868 11,741 21,313 23,517 18,602
Deferred nuclear plants return.. (18) (318) (444) (1,639) (4,681)
Amortization of
regulatory assets............. 2,437 1,396 8,601 20,218 19,755
Property tax.................... - - - (159) 5,286
Investment tax credit
amortization.................. (3,683) (3,683) (7,367) (7,640) (7,358)
Adjustment for prior years'
taxes......................... - - - (10,442) (2,706)
Other, net...................... (673) (2,745) (3,297) (5,759) (3,924)
-------- ------- -------- -------- --------
Total income tax expense.......... $(29,220) $29,880 $(20,334) $181,324 $186,001
======== ======= ======== ======== ========
</TABLE>
9. EMPLOYEE BENEFITS
A. Pension Benefits
The company participates in a uniform noncontributory defined benefit
retirement plan covering all regular system employees. Benefits are
based on years of service and the employees' highest eligible
compensation during 60 consecutive months of employment. The
company's direct portion of the system's pension income, part of which
was credited to utility plant, approximated $8.8 million in 1996,
$10.4 million in 1995 and $2.3 million in 1994. The company's pension
costs for 1996, 1995, and 1994 included approximately $2.8 million,
$0.1 million, and $4.8 million, respectively, related to workforce
reduction programs.
Currently, the company funds annually an amount at least equal to that
which will satisfy the requirements of the Employee Retirement Income
Security Act and the Internal Revenue Code. Pension costs are
determined using market-related values of pension assets. Pension
assets are invested primarily in domestic and international equity
securities and bonds.
F-30
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The components of net pension cost for CL&P are:
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
-----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost............................................. $ 11,896 $ 7,543 $ 13,072
Interest cost............................................ 37,226 37,110 36,103
Return on plan assets.................................... (103,248) (138,582) 1,020
Net amortization......................................... 45,300 83,516 (52,536)
--------- --------- --------
Net pension income....................................... $ (8,826) $ (10,413) $ (2,341)
========= ========= ========
</TABLE>
For calculating pension cost, the following assumptions were used:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
-------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate............................................ 7.50% 8.25% 7.75%
Expected long-term
rate of return......................................... 8.75 8.50 8.50
Compensation/progression
rate................................................... 4.75 5.00 4.75
-------------------------------------------------------------------------------------------
</TABLE>
The following table represents the plan's funded status reconciled
to the Consolidated Balance Sheets:
<TABLE>
<CAPTION>
----------------------------------------------------------------
At December 31, 1996 1995
----------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Accumulated benefit obligation,
including vested benefits at
December 31, 1996 and 1995 of
$405,340,000 and $404,540,000,
respectively....................... $ 434,473 $ 432,987
========= =========
Projected benefit obligation......... $ 514,989 $ 515,121
Market value of plan assets.......... 736,448 668,929
--------- ---------
Market value in excess of projected
benefit obligation................. 221,459 153,808
Unrecognized transition amount....... (7,365) (8,285)
Unrecognized prior service costs..... 3,818 1,293
Unrecognized net gain................ (198,088) (135,817)
--------- ---------
Prepaid pension asset................ $ 19,824 $ 10,999
========= =========
</TABLE>
F-31
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The following actuarial assumptions were used in calculating
the plan's year-end funded status:
<TABLE>
<CAPTION>
----------------------------------------------
At December 31, 1996 1995
----------------------------------------------
<S> <C> <C>
Discount rate.................. 7.75% 7.50%
Compensation/progression rate.. 4.75 4.75
----------------------------------------------
</TABLE>
B. Postretirement Benefits Other Than Pensions
The company provides certain health care benefits, primarily medical and
dental, and life insurance benefits through a benefit plan to retired
employees (referred to as SFAS 106 benefits). These benefits are
available for employees retiring from the company who have met specified
service requirements. For current employees and certain retirees, the
total SFAS 106 benefit is limited to two times the 1993 per-retiree
health care costs. The SFAS 106 obligation has been calculated based on
this assumption. CL&P's direct portion of SFAS 106 benefits, part of
which were deferred or charged to utility plant, approximated $17.9
million in 1996, $20.7 million in 1995 and $22.3 million in 1994.
During 1996 and 1995, the company funded SFAS 106 postretirement costs
through external trusts. The company is funding, on an annual basis,
amounts that have been rate-recovered and which also are tax deductible
under the Internal Revenue Code. The trust assets are invested primarily
in equity securities and bonds.
The components of health care and life insurance cost are:
<TABLE>
<CAPTION>
-----------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
-----------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost.................. $ 2,270 $ 2,248 $ 2,371
Interest cost................. 10,211 11,510 12,157
Return on plan assets......... (2,904) (1,015) 2
Amortization of unrecognized
transition obligation....... 7,344 7,344 7,344
Other amortization, net....... 956 602 430
------- ------- -------
Net health care and life
insurance costs............. $17,877 $20,689 $22,304
======= ======= =======
</TABLE>
F-32
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
For calculating SFAS 106 benefit costs, the following assumptions were
used:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------
For the Years Ended December 31, 1996 1995 1994
-------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate................................... 7.50% 8.00% 7.75%
Long-term rate of return -
Health assets, net of tax..................... 5.25 5.00 5.00
Life assets................................... 8.75 8.50 8.50
</TABLE>
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheets:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------
At December 31, 1996 1995
-------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Accumulated postretirement
benefit obligation of:
Retirees.................................................. $109,299 $ 126,624
Fully eligible active employees......................... 165 198
Active employees not eligible
to retire............................................. 27,913 29,798
-------- ---------
Total accumulated postretirement
benefit obligation....................................... 137,377 156,620
Market value of plan assets................................ 38,783 11,378
-------- ---------
Accumulated postretirement benefit
obligation in excess of
plan assets............................................... (98,594) (145,242)
Unrecognized transition amount............................. 117,506 124,850
Unrecognized net (gain)/loss............................... (18,912) 1,260
-------- ---------
Accrued postretirement benefit
liability................................................. $ 0 $ (19,132)
======== =========
-------------------------------------------------------------------------------------
</TABLE>
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
<TABLE>
<CAPTION>
-----------------------------------------------
At December 31, 1996 1995
-----------------------------------------------
<S> <C> <C>
Discount rate.................... 7.75% 7.50%
Health care cost trend rate (a).. 7.23 8.40
</TABLE>
F-33
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
(a) The annual growth in per capita cost of covered health care benefits
was assumed to decrease to 4.91 percent by 2001.
The effect of increasing the assumed health care cost trend rate by one
percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1996, by $7.6
million and the aggregate of the service and interest cost components of
net periodic postretirement benefit cost for the year then ended by
$600,000. The trust holding the health plan assets is subject to federal
income taxes at a 39.6 percent tax rate. CL&P is currently recovering
SFAS 106 costs.
10. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES
CL&P has entered into an agreement to sell up to $200 million of eligible
customer receivables and accrued utility revenues. The eligible receivables
and accrued utility revenues are sold with limited recourse. The agreement
was entered into during July, 1996 and will expire in five years. The company
has retained collection responsibilities for receivables which have been sold
under the agreement. The agreement provides for a loss reserve determined by
a formula which reflects credit exposure. There were no accounts receivable
sold under the agreement as of December 31, 1996. As of June 30, 1997, CL&P
had sold approximately $100 million of its accounts receivable under the
agreement.
The FASB issued SFAS 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities," in June, 1996. SFAS 125
became effective on January 1, 1997, and establishes, in part, criteria for
concluding whether a transfer of financial assets in exchange for
consideration should be accounted for as a sale or as a secured borrowing. At
present, CL&P is required to record the sales of its customer accounts
receivable as secured short-term borrowings. CL&P is currently in the
process of restructuring its accounts receivable sales agreement so that CL&P
may treat this transaction as a sale as permitted under SFAS 125. Management
believes that the adoption of SFAS 125 will not have a material impact on the
company's financial position or results of operations.
11. COMMITMENTS AND CONTINGENCIES
A. Restructuring
Although CL&P continues to operate under cost-of-service based
regulation, various restructuring initiatives in its jurisdiction have
created uncertainty with respect to future rates and the recovery of
strandable investments and certain future costs such as purchase power
obligations. Strandable investments are regulatory assets or other
assets that would
F-34
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
not be economical in a competitive environment. Management is unable to
predict the ultimate outcome of restructuring initiatives; however, it
believes that it is entitled to full recovery of its prudently incurred
costs, including regulatory assets and strandable investments based on
the general nature of public utility cost of service regulation. For
further information on restructuring, see the MD&A.
B. Nuclear Performance
Millstone: The three Millstone units are managed by NNECO. Millstone 1,
2, and 3 have been out of service since November 4, 1995, February 21,
1996 and March 30, 1996, respectively, and are on the Nuclear Regulatory
Commission's (NRC) watch list. Management has restructured its nuclear
organization and is currently implementing comprehensive plans to restart
the units.
Millstone 3 has been designated by NU management as the lead unit for
restart. Millstone 2 remains on a schedule to be ready for restart
shortly after Millstone 3. To provide the resources and focus for
Millstone 3, the pace of work on the restart of Millstone 1 was reduced
until late in 1997 at which time the full work effort will be resumed.
Management believes that Millstone 3 will be ready for restart by the end
of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997
and Millstone 1 in the first quarter of 1998. Because of the need for
completion of independent inspections and reviews and for the NRC to
complete its processes before the NRC Commissioners can vote on
permitting a unit to restart, the actual beginning of operations is
expected to take several months beyond the time when a unit is declared
ready for restart. The NRC's internal schedules at present indicate that
a meeting of the Commissioners to act upon a Millstone 3 restart request
could occur by mid-December if NU, the independent review teams and NRC
staff concur that the unit can return to operation by that time. A
similar schedule indicates a mid-March meeting of the Commissioners to
act upon a Millstone 2 restart request. Management hopes that Millstone
3 can begin operating by the end of 1997.
The company is currently incurring substantial costs, including
replacement power costs, while the three Millstone units are not
operating. Management does not expect to recover a substantial portion
of these costs. CL&P expensed approximately $143 million of incremental
nonfuel nuclear operation and maintenance costs (O&M) in 1996, including
a reserve of $50 million against 1997 expenditures. At year-end
management estimated that CL&P will expense approximately $309 million of
nonfuel O&M costs in 1997.
F-35
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Based on a recent review of work efforts and budgets, management believes
that the overall 1997 nuclear spending levels, which include both nuclear
O&M expenditures and associated support services and capital
expenditures, will be slightly higher than previously estimated. The 1997
projected nuclear O&M expenditures are expected to increase, while 1997
projected capital expenditures are expected to decrease. CL&P's share of
nonfuel O&M costs for Millstone to be expensed in 1997 is now projected
to be approximately $353 million compared to $309 million previously
estimated. The 1997 projection includes $12 million of restart costs
identified to date which is expected to be incurred in 1998 and is net of
$50 million of Millstone costs reserved in 1996. CL&P's share of 1997
projected capital expenditures for Millstone is expected to decrease from
the $48 million previously estimated to $35 million.
For the six months ended June 30, 1997, CL&P's share of nonfuel O&M costs
expensed for Millstone totaled $211 million. The actual expenditures
include $40 million reserved for future 1997 restart costs and $12
million reserved for 1998 restart costs, and is net of $50 million of
spending against the reserve established in 1996. The reserve balance at
June 30, 1997, was approximately $52 million. Nonfuel O&M costs have been
and will continue to be absorbed by CL&P without adjustment to its
current rates. Management will continue to evaluate the costs to be
incurred for the remainder of 1997 and in 1998 to determine whether
adjustments to the existing reserves are required.
As discussed above, management cannot predict when the NRC will allow any
of the Millstone units to return to service and thus cannot estimate the
total replacement power costs the company will ultimately incur.
Replacement power costs incurred by CL&P attributable to the Millstone
outages averaged approximately $23 million per month during the first six
months of 1997, and are projected to average approximately $21 million
per month for the remainder of 1997. Based on current estimates of
expenditures and restart dates, management believes the system has
sufficient resources to fund the restoration of the Millstone units and
related replacement power costs.
CL&P Prudence Investigation: In response to motions filed by various
parties and intervenors, the DPUC on June 27, 1997 orally granted summary
judgment in CL&P's nuclear outage investigation docket, disallowing
recovery of costs associated with the ongoing outages at Millstone.
On July 30, 1997, the DPUC issued a purported written decision in the
same case, which disallowed recovery of an estimated
F-36
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
$600 million of replacement power costs related to the Millstone outages,
and found that CL&P had waived recovery of an additional $360 million of
incremental O&M. The written decision, like the oral decision, recognized
CL&P's right to seek recovery, in a future rate proceeding, of $40
million related to reliability enhancements. CL&P has appealed the DPUC's
decision.
CL&P has not requested cost recovery at this time and has said that it
will not seek recovery for a substantial portion of these costs and will
not request any cost recovery until the units are returned to operation.
Any requests for recovery would include only costs for projects CL&P
would have undertaken under normal operating conditions or that provide
long-term value for CL&P customers. CL&P does not expect the DPUC's
decision to have a material financial impact on projected 1997 results.
MY: On August 6, 1997, the board of directors of MYAPC voted unanimously
to cease permanently the production of power at its nuclear generating
facility. MYAPC has begun to prepare the regulatory filings intended to
implement the decommissioning and the recovery of remaining assets of its
nuclear facility. During the latter part of 1997, MYAPC plans to file an
amendment to its power contracts to clarify the obligations of its
purchasing utilities following the decision to cease power production.
MYAPC is currently updating its decommissioning cost estimates. These
estimates are expected to be completed during the third quarter of 1997.
At this time, the company is unable to estimate its obligation to MYAPC.
Under the terms of the contracts with MYAPC, the shareholders-sponsor
companies, including CL&P, are responsible for their proportionate share
of the costs of the unit, including decommissioning. Management expects
that CL&P will be allowed to recover these costs from its customers.
Litigation: CL&P and WMECO, through NNECO, operate Millstone 3 at cost,
and without profit, under a Sharing Agreement that obligates them to
utilize good utility practice and requires the joint owners to share the
risk of employee negligence and other risks of operation and maintenance
pro-rata in accordance with their ownership shares. The Sharing Agreement
also provides that CL&P and WMECO would only be liable for damages to the
non-NU owners for a deliberate violation of the agreement pursuant to
authorized corporate action.
On August 7, 1997, the non-NU owners of Millstone 3 filed demands for
arbitration with CL&P and WMECO as well as lawsuits in Massachusetts
Superior Court against Northeast Utilities and its current and former
trustees. The non-NU owners raise a number of contract, tort and
statutory claims, arising out of
F-37
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
the operation of Millstone 3. The arbitrations and lawsuits seek to
recover compensatory damages, punitive damages, treble damages and
attorneys' fees. Owners representing approximately two-thirds of the non-
NU interests in Millstone 3 have claimed compensatory damages in excess
of $200 million. In addition, one of the lawsuits seeks to restrain NU
from disposing of its shares of the stock of WMECO and Holyoke Water
Power Company, pending the outcome of the lawsuit. The NU companies
believe there is no legal basis for the claims and intend to defend
against them vigorously.
C. Environmental Matters
CL&P is subject to regulation by federal, state and local authorities
with respect to air and water quality, the handling and disposal of toxic
substances and hazardous and solid wastes, and the handling and use of
chemical products. CL&P has an active environmental auditing and training
program and believes that it is in substantial compliance with current
environmental laws and regulations.
Environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations, and
other facilities. Changing environmental requirements could also require
extensive and costly modifications to CL&P's existing generating units
and transmission and distribution systems, and could raise operating
costs significantly. As a result, CL&P may incur significant additional
environmental costs, greater than amounts included in cost of removal and
other reserves, in connection with the generation and transmission of
electricity and the storage, transportation and disposal of by-products
and wastes. CL&P may also encounter significantly increased costs to
remedy the environmental effects of prior waste handling activities. The
cumulative long-term cost impact of increasingly stringent environmental
requirements cannot accurately be estimated.
CL&P has recorded a liability based upon currently available information
for what it believes are its estimated environmental remediation costs
for waste disposal sites. In most cases, additional future environmental
cleanup costs are not reasonably estimable due to a number of factors,
including the unknown magnitude of possible contamination, the
appropriate remediation methods, the possible effects of future
legislation or regulation and the possible effects of technological
changes. At December 31, 1996, the net liability recorded by CL&P for
its estimated environmental remediation costs, excluding any possible
insurance recoveries or recoveries from third parties, amounted to
approximately $7.5 million, which management has determined to be the
most
F-38
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
probable amount within the range of $7.5 million to $14.0 million.
On October 10, 1996, the American Institute of Certified Public
Accountants issued Statement of Position 96-1, "Environmental Remediation
Liabilities" (SOP). The principal objective of the SOP is to improve the
manner in which existing authoritative accounting literature is applied
by entities to specific situations of recognizing, measuring and
disclosing environmental remediation liabilities. The SOP became
effective January 1, 1997. The adoption of the SOP resulted in a $400
thousand increase to CL&P's environmental reserve.
At June 30, 1997, CL&P's net liability recorded for its estimated
environmental remediation costs, excluding any possible insurance
recoveries or recoveries from third parties, amounted to approximately
$7.8 million, which management has determined to be the most probable
amount within the range of $7.8 million to $13.5 million.
CL&P cannot estimate the potential liability for future claims, including
environmental remediation costs, that may be brought against it. However,
considering known facts, existing laws and regulatory practices,
management does not believe the matters disclosed above will have a
material effect on CL&P's financial position or future results of
operations.
D. Nuclear Insurance Contingencies
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 company could be assessed in
proportion to its ownership interest in each nuclear unit up to $75.5
million, not to exceed $10.0 million per nuclear unit in any one year.
Based on its ownership interest in Millstone 1, 2, and 3 and in Seabrook
1, CL&P's maximum liability, including any additional potential
assessments, would be $173.6 million per incident. In addition, through
power purchase contracts with MYAPC, VYNPC and CYAPC, CL&P would be
responsible for up to an additional $44.4 million per incident. Payments
for CL&P's ownership interest in nuclear generating facilities would be
limited to a maximum of $27.5 million per incident per year.
Insurance has been purchased to cover the primary cost of repair,
replacement or decontamination of utility property resulting from insured
occurrences. CL&P is subject to retroactive assessments if losses exceed
the accumulated funds available to the insurer. The maximum potential
assessment against CL&P with respect to losses arising during the current
policy year was approximately $10.4 million under the primary
F-39
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
property insurance program at December 31, 1996. Based on the most recent
renewal, the maximum potential assessment against CL&P with respect to
losses arising during the current policy year is approximately $11.2
million under the primary property insurance program at June 30, 1997.
Insurance has been purchased to cover 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 resulting from insured occurrences.
CL&P is subject to retroactive assessments if losses exceed the
accumulated funds available to the insurer. The maximum potential
assessments against the company with respect to losses arising during
current policy years are approximately $9 million under the replacement
power policies and $20.4 million under the excess property damage,
decontamination and decommissioning policies. The cost of a nuclear
incident could exceed available insurance proceeds.
Insurance has been purchased aggregating $200 million on a industry basis
for coverage of worker claims. All participating reactor operators
insured under this coverage are subject to retrospective assessments of
$3 million per reactor. The maximum potential assessment against CL&P
with respect to losses arising during the current policy period is
approximately $8.9 million.
E. Construction Program
The construction program is subject to periodic review and revision by
management. CL&P currently forecasts construction expenditures of
approximately $842 million for the years 1997-2001, including $165
million for 1997. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $238.4 million for the years 1997-2001, including $12.2
million for 1997. See Note 2, "Leases," for additional information about
the financing of nuclear fuel.
As a result of the most recent capital program review, management has
decreased the construction program forecast for 1997 expenditures from
$165 million to $148 million.
F. Long-Term Contractual Arrangements
Yankee Companies: CL&P, along with PSNH and WMECO, has relied on MY and
VY for approximately three percent of their capacity under long-term
contracts. Under the terms of their agreements, the system companies pay
their ownership (or entitlement) shares of costs, which include
depreciation, O&M expenses, taxes, the estimated cost of decommissioning
and a return on invested capital. These costs are recorded as
F-40
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
purchased power expense and recovered through the company's rates. CL&P's
total cost of purchases under contracts with the Yankee companies,
excluding YAEC, amounted to $96.4 million in 1996, $105.8 million in
1995, and $102.1 million in 1994. See Note 1E, "Summary of Significant
Accounting Policies-Investments and Jointly Owned Electric Utility
Plant," and Note 3, "Nuclear Decommissioning," and Note 11B "Nuclear
Performance" for more information on the Yankee companies.
Nonutility Generators: CL&P has entered into various arrangements for
the purchase of capacity and energy from nonutility generators. These
arrangements have terms from 10 to 30 years, currently expiring in the
years 2001 through 2027, and requires the company to purchase energy at
specified prices or formula rates. For the 12 months ended December 31,
1996, approximately 13 percent of system electricity requirements was met
by nonutility generators. CL&P's total cost of purchases under these
arrangements amounted to $279.5 million in 1996, $282.2 million in 1995,
and $277.4 million in 1994. These costs are eventually recovered through
the company's rates.
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 is obligated to pay, over a 30-year period ending in 2020, its
proportionate share of the annual O&M and capital costs of these
facilities.
The estimated annual costs of CL&P's significant long-term contractual
arrangements are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
1997 1998 1999 2000 2001
- --------------------------------------------------------------------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
MYAPC and VYNPC......... $ 39.0 $ 33.1 $ 39.1 $ 38.9 $ 36.4
Nonutility
generators............ 274.0 281.0 291.0 291.0 294.0
Hydro-Quebec............ 19.4 18.8 18.2 17.9 17.3
</TABLE>
G. The Rocky River Realty Company - Obligations
RRR provides real estate support services which includes the leasing of
property and facilities used by system companies. RRR is the obligor
under financing arrangements for certain system facilities. Under those
financing arrangements, the holders of notes for $38.4 million would be
entitled to request that RRR repurchase the notes if any major subsidiary
of NU (as defined by the notes) has debt ratings below investment grade
as of any year-end during the term of the financing. The notes are
secured by real estate leases between RRR as lessor and
F-41
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
NUSCO as lessee. The leases provide for the acceleration of rent equal to
RRR's note obligations if RRR is unable to repay the obligation. The
operating companies, primarily CL&P, WMECO and PSNH may be billed by
NUSCO for their proportionate share of the accelerated lease obligations
if the rateholders request repurchase of the notes. NU has guaranteed the
notes.
Based on the terms of the notes, PSNH and NAEC were defined as major
subsidiaries of NU, effective as of the end of 1996, and both PSNH's and
NAEC's debt ratings were below investment grade. In April 1997, the
holders of approximately $38 million of the RRR notes elected to have RRR
repurchase the notes at par. On July 1, 1997, RRR received commitments
from alternative purchasers to purchase approximately $12 million of the
notes that RRR had been required to repurchase. On July 30, 1997,
approximately $6 million of the $12 million was purchased by an
alternative purchaser. The remaining $6 million of notes are expected to
be purchased by another purchaser by September 2, 1997.
RRR repurchased the remaining $26 million of the notes on July 14, 1997.
Management does not expect the resolution will have a material impact on
CL&P's financial condition.
12. FUEL PRICE MANAGEMENT
The company utilizes various financial instruments to manage well-defined
fuel price risks. The company does not use these instruments for trading
purposes.
CL&P uses fuel-price management instruments with financial institutions to
hedge against some of the fuel-price risk created by long-term negotiated
energy contracts. These agreements minimize exposure associated with rising
fuel prices and effectively fix a portion of CL&P's cost of fuel for these
negotiated energy contracts. Under the agreements, CL&P exchanges monthly
payments based on the differential between a fixed and variable price for the
associated fuel. As of December 31, 1996, CL&P had outstanding agreements
with a total notional value of approximately $228.8 million, and a positive
mark-to-market position of approximately $1.1 million. As of June 30, 1997,
CL&P had outstanding fuel price management agreements with a total notional
value of approximately $318.4 million with a negative mark-to-market position
of approximately $7.6 million.
Under the terms of CL&P's fuel price management agreements, CL&P can be
required to post cash collateral with its counterparties approximately
equivalent to the amount of a negative mark-to-market position. In general,
the amount of collateral is to be
F-42
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information subsequent to December 31, 1996 is Unaudited)
returned to CL&P when the mark-to-market position becomes positive, when CL&P
meets specified credit ratings, or when an agreement ends and all open
positions are properly settled.
These agreements have been made with various financial institutions, each of
which is rated "A" or better by Standard & Poor's rating group. CL&P is
exposed to credit risk on fuel-price management instruments if the
counterparties fail to perform their obligations. However, management
anticipates that the counterparties will be able to fully satisfy their
obligations under the agreements.
13. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY
In January 1995, CL&P Capital LP (CL&P LP is a subsidiary of CL&P) issued
$100 million of cumulative 9.3 percent Monthly Income Preferred Securities
(MIPS), Series A. CL&P has the sole ownership interest 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 minority interests.
14. 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 nuclear decommissioning trusts: The carrying amounts approximate
fair value.
SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities,"
requires investments in debt and equity securities to be presented at fair
value. As a result of this requirement, the investments held in the
company's nuclear decommissioning trusts were adjusted to market by
approximately $22.3 million as of December 31, 1996 and by approximately
$14.4 million as of December 31, 1995, with corresponding offsets to the
accumulated provision for depreciation. The amounts adjusted in 1996 and
1995, represent cumulative gross unrealized holding gains. The cumulative
gross unrealized holding losses were immaterial for both 1996 and 1995.
Preferred stock and long-term debt: The fair value of CL&P'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.
F-43
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
- -------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- -------------------------------------------------------------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The carrying amounts of CL&P's financial instruments and the estimated fair
values are as follows:
<TABLE>
<CAPTION>
------------------------------------------------------
Carrying Fair
At December 31, 1996 Amount Value
------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Preferred stock not subject
to mandatory redemption.... $ 116,200 $ 111,845
Preferred stock subject to
mandatory redemption....... 155,000 120,900
Long-term debt -
First Mortgage Bonds....... 1,452,288 1,410,665
Other long-term debt....... 592,783 592,783
MIPS......................... 100,000 108,520
------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
-------------------------------------------------------
Carrying Fair
At December 31, 1995 Amount Value
-------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Preferred stock not subject
to mandatory redemption.... $ 116,200 $ 82,448
Preferred stock subject to
mandatory redemption....... 155,000 157,575
Long-term debt -
First Mortgage Bonds....... 1,297,245 1,329,549
Other long-term debt....... 532,164 532,164
MIPS......................... 100,000 108,520
--------------------------------------------------------
</TABLE>
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
F-44
<PAGE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- --------------------------------------------------------------------------------------------------------
Quarter Ended(a)
--------------------------------------------------
1996 March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues.................................. $659,355 $542,999 $599,505 $595,601
======== ======== ======== ========
Operating Income (Loss)............................. $ 59,977 $ 15,197 $ 593 $(45,994)
======== ======== ======== ========
Net Income (Loss)................................... $ 32,851 $(10,700) $(26,938) $(75,450)
======== ======== ======== ========
<CAPTION>
1995
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues.................................. $601,194 $525,147 $638,392 $622,336
======== ======== ======== ========
Operating Income.................................... $ 96,191 $ 65,867 $ 88,012 $ 73,956
======== ======== ======== ========
Net Income.......................................... $ 65,877 $ 38,089 $ 60,462 $ 40,788
======== ======== ======== ========
</TABLE>
(a) Reclassifications of prior data have been made to conform with the current
presentation.
F-45
<PAGE>
The Connecticut Light and Power Company and Subsidiaries
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
STATISTICS
- ----------------------------------------------------------------------------------------------------
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer (kWh) (Average) (December 31)
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1996 $6,512,659 26,043 8,639 1,099,340 2,194
1995 6,389,190 26,366 8,506(a) 1,094,527 2,270
1994 6,327,967 26,975 8,775 1,086,400 2,587
1993 6,214,401 26,107 8,519 1,078,925 2,676
1992 6,100,682 25,809 8,501 1,075,425 3,028
</TABLE>
(a) Effective January 1, 1996, the amounts shown reflect billed and unbilled
sales. 1995 has been restated to reflect this change.
F-46
<PAGE>
================================================================================
No dealer, salesperson, or any other person has been authorized to
give any information or to make any representations other than those contained
in this Prospectus, and, if given or made, such information and representations
must not be relied upon as having been authorized by the Company. Neither the
delivery of this Prospectus nor any sale made hereunder shall, under any
circumstances, create any implication that there has been no change in the
affairs of the Company since the date hereof. This Prospectus does not
constitute an offer to sell or a solicitation by anyone in any jurisdiction in
which such offer or solicitation is not authorized, or in which the person
making such offer or solicitation is not qualified to do so or to any person
whom it is unlawful to make such offer or solicitation.
________________
TABLE OF CONTENTS
<TABLE>
<S> <C>
Available Information 4
Forward-looking Statements 4
Prospectus Summary 6
Risk Factors 13
The Company 18
The Original Offering 19
The Exchange Offer 19
Selected Financial Data 29
Management's Discussion and Analysis of
Financial Condition and Results of Operations 30
Business 44
Employees 83
Properties 83
Legal Proceedings 85
Management And Compensation 90
Description of the New Bonds 99
Book-entry; Delivery and Form 105
Market For New Bonds 108
Certain Federal Income Tax Considerations 108
Plan of Distribution 110
Legal Matters and Experts 110
Glossary of Terms 111
Index to Consolidated Financial Statements F1
</TABLE>
================================================================================
================================================================================
Offer For All Outstanding
First and Refunding Mortgage Bonds
1997 Series B Due
June 1, 2002
In Exchange For
First and Refunding Mortgage 7 3/4%
Bonds 1997 Series C Due
June 1, 2002
Each Issued By
THE CONNECTICUT LIGHT
AND
POWER COMPANY
____________
PROSPECTUS
____________
September 2, 1997
================================================================================
<PAGE>
Part II
Information Not Required In Prospectus
Item 16. Exhibits and Financial Statement Schedules.
(a) The following exhibits are filed herewith.
Exhibit No. Description
- ----------- -----------
10.50 Description of Certain Management Compensation Arrangements.
II-1
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
this amendment to the registration statement has been signed by the following
persons in the capacities and on the dates indicated.
Signature Title )
)
Hugh C. MacKenzie )
Hugh C. MacKenzie )
Principal Executive Officer President and Director )
)
John H. Forsgren )
John H. Forsgren )
Principal Financial Officer Executive Vice President, )
Chief Financial Officer )
and Director )
)
John J. Roman )
John J. Roman )
Principal Accounting Vice President and ) By
Officer Controller ) /s/ Jeffrey C. Miller
) Jeffrey C. Miller
Bernard M. Fox ) Attorney-in-Fact
Bernard M. Fox Chairman and Director ) August 28, 1997
)
Robert G. Abair )
Robert G. Abair Director )
)
William T. Frain, Jr. )
William T. Frain, Jr. Director )
)
Cheryl W. Grise )
Cheryl W. Grise Director )
)
John B. Keane )
John B. Keane Director )
)
- ----------------- )
Bruce D. Kenyon Director )
)
II-2
<PAGE>
EXHIBIT INDEX
Exhibit No. Description
- ----------- -----------
10.50 Description of Certain Management Compensation Arrangements.
23 Consent of Independent Public Accountants
<PAGE>
Exhibit 10.50
Description of Certain Management Compensation Arrangements
The Board of Trustees of Northeast Utilities (NU) appointed Michael G.
Morris as Chairman, President and Chief Executive Officer of NU effective August
19, 1997. Mr. Morris has been elected to comparable positions at most of the
subsidiaries of NU, and to Chairman of the Board of Directors of The Connecticut
Power and Light Company, also effective August 19, 1997. NU intends to enter
into a five year employment agreement with Mr. Morris, the principal terms of
which will provide for a starting salary of $750,000 per annum, a lump sum
payment of $1,350,000, and non-qualified options to purchase 500,000 shares of
NU stock at $9.625 per share, with exercise rights vesting in stages through
August 20, 2001, subject to certain exceptions. Mr. Morris will also be eligible
to participate in the short term and long term incentive compensation programs
established by the NU system for senior level executive officers generally in
1998 and 1999, respectively.
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
-----------------------------------------
As independent public accountants, we hereby consent to the use of our reports
(and to all references to our Firm) included (or incorporated by reference) in
this Registration Statement.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
August 26, 1997
