<PAGE>
Rule 424(b)(5)
Registration No. 33-51185
PROSPECTUS
$60,000,000
Western Massachusetts Electric Company
FIRST MORTGAGE 7 3/8% BONDS,
1997 SERIES B DUE JULY 1, 2001
-----------
Interest payable January 1 and July 1
-----------
THE FIRST MORTGAGE 7 3/8% BONDS, 1997 SERIES B (BONDS) MATURE ON JULY 1, 2001.
INTEREST ON THE BONDS IS PAYABLE SEMIANNUALLY ON JANUARY 1 AND JULY 1, BEGINNING
JANUARY 1, 1998. THE BONDS WILL BE REDEEMABLE, IN WHOLE OR IN PART, AT THE
OPTION OF WESTERN MASSACHUSETTS ELECTRIC COMPANY (THE COMPANY) AT ANY TIME, 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 HEREIN), PLUS IN EACH CASE ACCRUED INTEREST TO
THE DATE OF REDEMPTION. SEE "DESCRIPTION OF THE BONDS--OPTIONAL REDEMPTION"
HEREIN. THE 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.
-----------
SEE "RISK FACTORS" BEGINNING ON PAGE 7 OF THIS PROSPECTUS FOR A DISCUSSION OF
CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN
THE BONDS.
-----------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
-----------
PRICE 99.658% AND ACCRUED INTEREST, IF ANY
-----------
<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC(1) COMMISSIONS(2) COMPANY(3)
----------- -------------- -----------
<S> <C> <C> <C>
Per Bond.............................. 99.658% 1.250% 98.408%
Total................................. $59,784,800 $750,000 $59,044,800
</TABLE>
- -----
(1) Plus accrued interest, if any, from July 31, 1997.
(2) The Company has agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act of 1933.
(3) Before deducting expenses payable by the Company estimated at $212,000.
-----------
The Bonds are offered by the Underwriters, subject to prior sale, when, as
and if issued by the Company and accepted by the Underwriters and subject to
approval of certain legal matters by Winthrop, Stimson, Putnam & Roberts,
counsel for the Underwriters. It is expected that delivery of the Bonds will be
made on or about July 31, 1997 through the book-entry facilities of DTC,
against payment therefor in immediately available funds.
-----------
MORGAN STANLEY DEAN WITTER SALOMON BROTHERS INC
July 29, 1997
<PAGE>
No dealer, salesman or any other person has been authorized to give any
information or to make any representation not contained in this Prospectus in
connection with the offer made by this Prospectus and if given or made, such
information or representation must not be relied upon as having been authorized
by the Company or any of the underwriters. This Prospectus does not constitute
an offer to sell or a solicitation of an offer to buy any of the securities
offered hereby in any jurisdiction to any person to whom it is unlawful to make
such offer or solicitation in such jurisdiction.
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.
TABLE OF CONTENTS
<TABLE>
<CAPTION>
<S> <C>
Available Information..................................... 3
Forward-looking Statements................................ 3
Prospectus Summary........................................ 4
Risk Factors.............................................. 7
The Company............................................... 11
Use of Proceeds........................................... 11
Selected Financial Data................................... 12
Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 13
Business.................................................. 22
Employees................................................. 51
Properties................................................ 51
Legal Proceedings......................................... 53
Management And Compensation............................... 55
Description of the Bonds.................................. 63
Book-entry Only System.................................... 69
Underwriters.............................................. 72
Legal Matters and Experts................................. 73
Glossary of Terms......................................... 73
Index to Financial Statements............................. F1
</TABLE>
-2-
<PAGE>
AVAILABLE INFORMATION
The Company has filed with the Securities and Exchange Commission
(Commission) a Registration Statement on Form S-1 (the Registration Statement)
under the Securities Act of 1933, as amended (the Securities Act) for the
registration of the 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 Bonds offered hereby,
reference is made to the Registration Statement, including the exhibits thereto,
and financial statements and notes filed as 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 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/).
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
(System). Although such forward-looking statements have been based 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.
-------------------------
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE BONDS.
SPECIFICALLY, THE UNDERWRITERS MAY OVERALLOT IN CONNECTION WITH THE OFFERING AND
MAY BID FOR, AND PURCHASE, THE BONDS IN THE OPEN MARKET. FOR A DESCRIPTION OF
THESE ACTIVITIES, SEE "UNDERWRITERS."
-3-
<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 Massachusetts corporation organized in 1886, is a wholly-
owned subsidiary of NU. The Company is an electric utility engaged principally
in the production, purchase, transmission, distribution and sale of electricity
at retail for residential, commercial, industrial and municipal purposes to
approximately 195,000 retail customers in 59 cities and towns in Massachusetts.
The Offering
<TABLE>
<S> <C>
Securities Offered.......... $60,000,000 aggregate principal amount of First
Mortgage 7 3/8% Bonds, 1997 Series B.
Interest Rate............... 7 3/8% per annum.
Interest Payment Dates...... January 1 and July 1, commencing January 1, 1998.
Maturity.................... July 1, 2001.
Security.................... The 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 Cobble Mountain Plant or its interest in
the plants of the four regional nuclear generating
companies described herein) and its transmission and
distribution facilities.
Optional Redemption......... The 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 Bonds--Redemption Provisions."
Sinking Fund Redemption..... There will be no sinking fund requirements.
Use of Proceeds............. The net proceeds of the sale of the Bonds will be used
to repay short term debt that was incurred to refinance
or refund debt and preferred stock and for general
working capital purposes, including costs associated
with the current outages at the Millstone nuclear
units.
</TABLE>
-4-
<PAGE>
<TABLE>
<S> <C>
Form and Denomination....... The Bonds will be issued in fully registered form
without coupons in denominations of $1,000 or multiples
thereof. The Bonds will initially be represented by a
single permanent Global Security, registered in the
name of Cede & Co., as nominee of DTC. See "Book-Entry
Only System."
</TABLE>
For additional information regarding the Bonds, see "Description of the
Bonds."
Risk Factors
See "Risk Factors" beginning on page 7 for a discussion of certain risks
that should be considered by prospective investors in evaluating an investment
in the Bonds.
-5-
<PAGE>
Summary Financial Data
(thousands, except percentages and ratios)
<TABLE>
<CAPTION>
12 Months
Ended
March 31, 1997 Year Ended December 31,
-------------- -----------------------------------------
(unaudited) 1996 1995 1994
---- ---- ----
<S> <C> <C> <C> <C>
Income Summary:
Operating Revenues............ $ 412,594 $ 421,337 $ 420,434 $ 421,477
Operating Income.............. 16,196 26,023 63,064 70,940
Net (Loss) Income............. (6,030) 3,922 39,133 49,457
Total Assets (end of period).... $ 1,173,761 $1,190,137 $1,142,346 $1,183,618
<CAPTION>
As of March 31, 1997
----------------------------------------
(unaudited)
As % of Adjusted
Actual Adjusted (a) Capitalization
------ ------------ --------------
<S> <C> <C> <C>
Capitalization Summary:
Long Term Debt (including current
maturities)............................................ $335,243 $395,243 57.0%
Preferred Stock Subject to
Mandatory Redemption (including portion to be
redeemed within one year).............................. 21,000 21,000 3.0
Preferred Stock Not Subject to
Mandatory Redemption................................... 20,000 20,000 2.9
Common Stockholder's Equity............................. 257,201 257,201 37.1
-------- -------- ------
Total Capitalization................................... $633,444 $693,444 100.0%
======== ======== ======
<CAPTION>
12 Months Ended
March 31, 1997 Year Ended December 31,
-------------- ------------------------------------------
(unaudited) 1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Ratio of Earnings to Fixed
Charges (b)........................................ 0.76(c) 1.26 2.65 3.54 2.81 2.43
</TABLE>
(a) Adjusted to reflect the proposed sale of $60 million principal amount of
Bonds.
(b) 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.
(c) For the twelve-month period ended March 31, 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 the period, earnings were inadequate to cover fixed charges; the
additional earnings required to bring the ratio of earnings to fixed charges
to 1.0 for this period would have been $7.253 million. See "Risk Factors."
-6-
<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
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, 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 having Millstone 3 ready for restart
around 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. Restart of each unit is
contingent upon, among other things, the affirmative vote of the Commissioners
of the Nuclear Regulatory Commission (NRC). 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 System 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.
Although the Company is not precluded from seeking future rate recoveries
of these outage expenses, 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
believes that the Company will not seek rate recovery of a substantial portion
of such costs. Management currently does not intend to request any such
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.
No formal claims have been made, but management believes that it is
possible that some or all of the non-NU owners of Millstone 3 will assert
liability on the part of the System for the additional costs non-NU owners have
borne as a result of the current outage. At March 31, 1997, the costs related to
this potential litigation were estimated to be $3 million for incremental
operating and maintenance (O&M) costs
-7-
<PAGE>
and between $11 million and $13 million for replacement power costs. These costs
are likely to increase as long as Millstone 3 remains out of service. NU will
vigorously contest such suits if they are brought.
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 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 Commonwealth of Massachusetts 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 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. As of March 31, 1997, the
Company's net investment in nuclear generating capacity, excluding its
investment in certain regional nuclear companies, was approximately $436
million, and its regulatory assets were approximately $182 million. 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
-8-
<PAGE>
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
Massachusetts Department of Public Utilities (DPU) 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 March 31, 1997, the
Company's regulatory assets were approximately $182 million. 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-
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
-9-
<PAGE>
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 Bonds
The Bonds are a new issue of securities with no established trading market,
and the Company does not intend to apply for listing of the Bonds on a national
securities exchange, but has been advised by the Underwriters that they
presently intend to make a market in the Bonds, as permitted by applicable law
and regulations. The Underwriters are not obligated, however, to make a market
in the Bonds, and any such market making may be discontinued at any time at the
sole discretion of the Underwriters. Accordingly, no assurance can be given as
to the liquidity of the trading market for the Bonds.
-10-
<PAGE>
THE COMPANY
The Company, a Massachusetts corporation organized in 1886, is a wholly-
owned subsidiary of NU. Four wholly-owned operating subsidiaries of NU--the
Company, Public Service Company of New Hampshire (PSNH), The Connecticut Light
and Power Company (CL&P) and Holyoke Water Power Company (HWP)--furnish electric
service in portions of Connecticut and New Hampshire and in western
Massachusetts. A fifth wholly-owned subsidiary of NU, North Atlantic Energy
Corporation (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 an electric utility
engaged principally in the production, purchase, transmission, distribution and
sale of electricity at retail for residential, commercial, industrial and
municipal purposes to approximately 195,000 retail customers in 59 cities and
towns in Massachusetts.
The principal executive offices of the Company are located at 174 Brush
Hill Avenue, West Springfield, Massachusetts 01090-0010
(telephone 413/785-5871).
USE OF PROCEEDS
The net proceeds from the sale of the Bonds will be used, together with
funds from other sources, to repay short term debt that has been incurred to
refinance or refund debt (including $14,700,000 principal amount of the
Company's Series F, 5 3/4% First Mortgage Bonds) and preferred stock (including
$33,500,000 face amount of the Company's Dutch Auction Rate Transferrable
Securities) and for general working capital purposes, including costs associated
with the current outages at the Millstone nuclear units.
-11-
<PAGE>
Western Massachusetts Electric Company
- --------------------------------------------------------------------------------
SELECTED FINANCIAL DATA/(a)/
- --------------------------------------------------------------------------------
(Thousands of Dollars)
<TABLE>
<CAPTION>
For the Three Months
Ended March 31, For the Year Ended December 31,
-------------------------- -----------------------------------------------------------
1997 1996 1996 1995 1994 1993 1992
-------------------------- -----------------------------------------------------------
(unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues....................... $ 106,054 $ 114,797 $ 421,337 $ 420,434 $ 421,477 $ 415,055 $ 410,720
Operating Income......................... 3,865 13,692 26,023 63,064 70,940 60,348 60,563
Net (Loss) Income........................ (1,843) 8,109 3,922 39,133 49,457 40,594/(b)/ 37,022
Cash Dividends on
Common Stock..................... 15,004 8,987 16,494 30,223 29,514 28,785 29,536
<CAPTION>
At March 31, At December 31,
-------------------------- -----------------------------------------------------------
1997 1996 1996 1995 1994 1993 1992
-------------------------- -----------------------------------------------------------
(unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
Total Assets............................. $1,173,761 $1,129,030 $1,190,137 $1,142,346 $1,183,618 $1,204,642 $1,130,684
Long Term Debt /(c)/..................... 335,243 347,956 349,442 347,470 379,969 393,232 392,976
Preferred Stock Not
Subject to Mandatory
Redemption....................... 20,000 53,500 20,000 53,500 68,500 73,500 73,500
Preferred Stock
Subject to Mandatory
Redemption /(c)/................. 21,000 22,500 21,000 24,000 24,675 27,000 28,500
Obligations Under
Capital Leases /(c)/............. 32,425 33,578 32,234 36,011 36,797 36,902 41,509
</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 $3.9
million.
(c) Includes portion due within one year.
-12-
<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 three months ended March 31, 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 financial statements and footnotes appearing elsewhere in
this Prospectus.
Earnings Overview
The outages at the three Millstone nuclear units (Millstone) have
resulted in significantly increased expenditures for replacement power and
work undertaken at Millstone, which resulted in net income for the year
1996 significantly lower than 1995 for the Company and a net loss for the
first quarter of 1997. Due to the seasonality of consumption and increased
reserves and spending related to the nuclear outages, the Company presently
expects to report a loss in the range of $15 million to $20 million for the
second quarter of 1997. For the calendar year 1997, while all three units
are out of service, the Company expects to operate on a roughly break-even
basis. 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 quarter 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.
Millstone Outages
The Company has a 19 percent ownership interest in Millstone 1
and 2 and a 12.24 percent 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.
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 of Trustees (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
-13-
<PAGE>
reorganization of NU's nuclear organization that includes executives loaned
from unaffiliated utility companies.
Millstone 3 has been designated 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 work
on the restart of Millstone 1 will be reduced until late in 1997 when the
full work effort will be resumed.
Management believes that Millstone 3 will be ready for restart
around 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 is ready for restart by that time. Management
hopes that Millstone 3 can begin operating by the end of 1997.
On July 1, 1997, CL&P submitted continued unit operation studies
to the Connecticut Department of Public Utility Control (DPUC) showing
that, under base case assumptions, Millstone 1 will have a value to 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 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 CL&P considers less likely, indicated that
Millstone 1 would be uneconomic in varying degrees. At the present time,
the Company expects to continue operating both Millstone 1 and Millstone 2
for the remaining terms of their respective operating licenses; however,
the Company cannot predict the outcome of the DPUC proceeding. The unit
operation studies submitted to the DPUC do not bind the Company in future
proceedings before the DPU.
Based on a recent review of the work efforts and budgets,
management believes that the overall 1997 nuclear spending levels-both
nuclear O&M expenditures and associated support services and capital
expenditures-will be slightly higher than previously estimated. 1997
nuclear O&M expenditures and related support services are expected to
increase, while 1997 capital expenditures are expected to decrease.
Management also believes that it is possible that 1997 nuclear spending
will increase somewhat as the detailed work needed to restore the units to
service progresses. A portion of the increased nuclear O&M expenditures in
1997 will be reserved in the second quarter of 1997. The Company's share of
nonfuel O&M costs for Millstone in 1996 totaled $76 million, including $21
million for incremental costs related to the outages and $12 million
reserved for future costs. 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
-14-
<PAGE>
service. Management will continue to evaluate the costs to be incurred in
1998 to determine whether adjustments to the existing reserves are
required.
Replacement power costs for the Company averaged approximately $6
million per month during the first quarter of 1997 and are projected to
average approximately $5 million per month for the remainder of 1997.
Replacement power costs for the Millstone units expensed in 1996 were $41
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.
Although the Company is not precluded from seeking rate
recoveries for replacement power costs, management has committed not to
seek rate recovery for the portion of these costs attributable to 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 believes that the
Company will not seek rate recovery for a substantial portion of these
costs. Management does not currently intend to request any such recoveries
until after the Millstone units begin returning to service; therefore, it
is unlikely that any additional revenues from any permitted recovery of
these costs will be available to contribute to funding the recovery efforts
while the units are out of service. While the Company believes that it is
entitled to recovery of those costs which have been and will be prudently
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 CL&P of substantially all of its Millstone outage
related costs.
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. In addition, there is the
potential for claims by the non-NU owners of Millstone 3 for the costs
associated with the current outage. To date, no reserves have been
established for existing or potential litigation. See "Legal Proceedings"
and "Notes to Financial Statements," Note 11B, for further information on
litigation.
Capacity
During 1996 and continuing into 1997, the System companies have
taken measures to improve their capacity position. The Company did not
spend a significant amount in 1996, but anticipates spending approximately
$12 million for additional capacity-related costs in 1997, of which $7
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 quarter
of 1997, the Company spent approximately $4 million to ensure adequate
generating capacity, of which $1 million was expensed.
Assuming normal weather conditions and generating unit
availability, management expects that the Company will have sufficient
capacity to meet peak load demands in the summer 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.
The Company has a 3 percent ownership interest in the Maine
Yankee nuclear generating facility (MY). MY is projected to incur
substantially increased costs over the balance of 1997 while the unit is
not operating. On May 27, 1997, MY announced that it was considering
permanent closure of the plant based on economic concerns and uncertainty
about the operation of the plant. MY disclosed that it would reduce
-15-
<PAGE>
spending to a level that would preserve the option of restarting the plant
or closing it. The Company's share of replacement-power costs while MY is
out of service is not projected to be material.
Liquidity and Capital Resources
Cash provided from operations decreased approximately $34 million
in the first quarter of 1997, compared to the first quarter of 1996,
primarily due to higher 1997 cash operating costs 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 $36 million,
primarily due to an increase in short term debt. The increase in short
term debt includes the use of $15 million of the accounts receivable
facility established in 1996. Net cash from financing activities was also
impacted by higher reacquisitions and retirements of long term debt and
higher payments of cash dividends on common stocks. Cash used for
investments increased approximately $2 million primarily due to higher 1997
construction expenditures.
Cash provided from operations decreased by approximately $20
million in 1996 compared to 1995, primarily due to higher cash operating
costs related to the Millstone outages, partially offset by higher retail
sales and lower interest charges. 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 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 $26 million in
1996, primarily due to lower reacquisitions and retirements of long term
debt and lower cash dividend payments on common shares, partially offset by
higher reacquisitions and retirements of preferred stock. Cash used for
investments increased by approximately $7 million in 1996, primarily due to
lower loan repayments from other companies under the Money Pool (defined
below), partially offset by lower construction expenditures in 1996.
During 1996, the Company took various actions to ensure that it
will have access to adequate cash resources, at reasonable cost. The
Company established a facility under which it may sell up to $40 million of
its billed and unbilled accounts receivable. As of March 31, 1997, $15
million had been sold using this facility. Additionally, NU, the Company
and CL&P entered into a new $313.75 million three-year revolving credit
agreement (the New Credit Agreement). Under the New Credit Agreement, NU
has a contractual short term borrowing limit of $150 million, the Company
has a limit of $150 million and CL&P has a limit of $313.75 million. The
overall limit for all borrowers is $313.75 million.
Some of the borrowing facilities contain financial covenants that
must be satisfied before borrowings can be made and for outstanding
borrowings to remain outstanding. On May 30, 1997, the First Amendment and
Waiver became effective for the New Credit Agreement. This amendment
permits $313.75 million of credit to remain available to the Company and
CL&P through the securing of such borrowings with first mortgage bonds.
Interest coverage and common equity ratios were also loosened to enable the
companies to meet certain financial tests. The Company will be able to
borrow up to approximately $90 million on the basis of bonds it has
provided as collateral for borrowings under the revolving credit agreement.
CL&P will be able to borrow up to approximately $225 million on the
strength of bonds it has provided as collateral and NU, which as a holding
company cannot issue first mortgage bonds, will be able to borrow up to $50
million, if the Company, CL&P and NU consolidated financial statements meet
certain interest coverage tests for two consecutive quarters.
-16-
<PAGE>
In April 1997, Moody's downgraded most of the securities ratings
of the Company because of the extended Millstone outages. In May, 1997,
S&P further downgraded the Company's 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 System
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 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) notified RRR that it wished RRR to repurchase the notes. The notes are
secured by real estate leases between RRR as lessor and Northeast Utilities
Service Company (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. On July 1, 1997, RRR received a commitment for the purchase of
approximately $12 million of the notes. RRR repurchased the remaining $26
million of notes on July 14, 1997. The Company may be billed by NUSCO for
its proportionate share of the accelerated lease obligations when RRR
repurchases the notes. The Company does not expect the resolution of this
matter to have a material adverse impact on its financial condition or
liquidity. See "Notes to Financial Statements," Note 11G for further
information.
Each major company in the System finances its own needs. Neither
the Company nor CL&P 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 CL&P. Nevertheless, it is
possible that investors will take negative operating results or regulatory
developments at one company in the System into account when evaluating
other companies in the 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 any needed waivers or modifications are not
forthcoming on reasonable terms, or if some borrowing facilities become
unavailable because of difficulties in meeting borrowing conditions, or if
the 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 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
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 Massachusetts. 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 Massachusetts 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
-17-
<PAGE>
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.
The Company follows accounting principles in accordance with
Statement of Financial Accounting Standards (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 Massachusetts, the Company
is not yet subject to transition plans. Management continues to believe
that the application of SFAS No. 71 accounting is appropriate.
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.
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 No. 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 17 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
-18-
<PAGE>
$6 million in 1996, down slightly from $7 million in 1995. These
activities are expected to continue in 1997.
During 1996, the 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 System's customers and positioning NU
as a valuable partner for the future. The ability of these account
executives to obtain an intimate understanding of customers' needs and
concerns and provide value added energy solutions will play a key role in
the 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 System will 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 System's current
products and services.
Rate Matters
In April, 1996, the DPU approved a settlement (the Agreement)
that included the continuation through February, 1998, of the 2.4 percent
rate reduction instituted in June, 1994. Additionally, the Agreement
terminated certain pending and potential reviews of the Company's
generating plant performance and accelerated its amortization of strandable
generation assets by approximately $6 million in 1996 and $10 million in
1997. The Agreement did not have a material impact on earnings for 1996.
In February, 1997, the DPU approved a joint settlement proposed
by the Company and the Massachusetts Attorney General that provides for a
continuation of the Company's August, 1996, fuel adjustment charge (FAC)
through August, 1997, and stipulates that the Company will not seek
carrying charges on any deferred fuel costs not currently recovered as a
result of maintaining the prior FAC rate. In accepting this settlement, the
DPU deferred any inquiry into the Company's replacement power costs related
to the Millstone outages. Management does not expect to seek recovery of a
substantial portion of these costs.
Nuclear Decommissioning
The Company has a 9.5 percent ownership interest in the
Connecticut Yankee nuclear generating facility (CY). On December 4, 1996,
the Connecticut Yankee Atomic Power Company (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
-19-
<PAGE>
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 $73
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 is approximately $196 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 $84 million.
See the "Notes to the Company's Financial Statements" Note 2, 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.
At March 31, 1997, the Company had recorded an environmental reserve of
approximately $2 million, the most probable amount as required by SFAS
No.5, "Accounting for Contingencies."
See the "Notes to Financial Statements," Note 11C, for further
information on environmental matters.
Results of Operation
Comparison of the First Quarter of 1997 to the First Quarter of 1996
The Company had a net loss of approximately $2 million in the
first quarter of 1997 compared to net income of approximately $8 million in
the first quarter of 1996. The first quarter loss was primarily
attributable to replacement-power expenditures for the Millstone units in
the first quarter of 1997. In 1996, two of the Millstone units were
operating for some part of the first quarter. First quarter 1997 earnings
were also negatively affected by a much milder winter. Retail kilowatt-
hour sales for the quarter decreased 4.6 percent from 1996. Although
nuclear O&M spending was higher in 1997, this impact was offset by reserves
for nuclear expenditures recognized in 1996.
Total operating revenues decreased in 1997, primarily due to
lower fuel recoveries and lower retail sales. Fuel recoveries decreased $5
million primarily due to lower recoveries under the Company's fuel clause.
Fuel, purchased and net interchange power expense increased in
1997, primarily due to higher replacement-power costs in 1997 due to the
nuclear outages.
-20-
<PAGE>
Other O&M expenses decreased in 1997. The major factors were the
recognition of nuclear reserves in the first quarter of 1996 ($7 million)
and spending against these reserves in 1997 ($5 million); and lower
conservation expenses in 1997 ($4 million), partially offset by higher
costs in 1997 associated with the Millstone outages ($9 million).
Federal and state income taxes decreased in 1997, primarily due
to lower book taxable income.
Comparison of 1996 to 1995
The Company had a net income of approximately $4 million in 1996,
compared to net income of approximately $39 million in 1995. The 1996
income was significantly lower primarily due to costs related to the
ongoing outages at Millstone which totaled approximately $74 million and
reduced the Company's 1996 earnings by approximately $43 million. These
costs included replacement power, higher 1996 Millstone O&M costs, and a
reserve recognized in 1996 for 1997 expenditures to return the Millstone
units to service. These decreases were partially offset by higher retail
sales and lower regulatory asset amortization.
Total operating revenues increased in 1996, primarily due to
higher retail sales, partially offset by lower fuel and conservation
recoveries. Retail sales increased 2.7 percent ($9 million) primarily due
to modest economic growth in 1996. Fuel recoveries decreased $6 million,
primarily due to the timing of the recovery of costs under the Company's
fuel clause. Conservation recoveries decreased approximately $6 million,
primarily due to lower demand side management costs.
Fuel, purchased and net interchange power expense increased in
1996, primarily due to higher replacement power costs due to the nuclear
outages, partially offset by the timing of the recognition of costs under
the Company's fuel clause and lower nuclear generation.
Other O&M expenses increased in 1996, primarily due to higher
costs associated with the Millstone outages ($33 million, including $12
million reserved for future costs), partially offset by lower costs for
demand side management programs and a 1995 work stoppage.
Amortization of regulatory assets, net decreased in 1996,
primarily due to the completion of the amortization of the Millstone 3
phase-in in 1995 and unuseful investment in June, 1996, partially offset by
higher amortization as a result of the 1996 rate settlement.
Federal and state income taxes decreased in 1996, primarily due
to lower 1996 book taxable income, partially offset by 1995 tax benefits
from a favorable tax ruling and the expiration of the 1991 federal statute
of limitations.
Interest on long term debt decreased in 1996, primarily due to
lower average interest rates.
Comparison of 1995 to 1994
Total operating revenues decreased in 1995, primarily due to
lower retail sales and lower regulatory decisions and lower other revenues,
partially offset by higher fuel recoveries. Regulatory decision revenues
decreased $2 million primarily due to the effects of the June 1994 retail-
rate reduction, partially offset by higher demand side management costs.
Other revenues include higher price discounts to customers in 1995. Fuel
cost recoveries increased $7 million primarily due to higher energy costs,
partially offset by lower interchange revenues.
-21-
<PAGE>
Fuel, purchased and net interchange power expense increased in
1995, primarily due to a one-time benefit in May 1994 from a rate case
settlement agreement and higher energy costs in 1995 as a result of an
extended Millstone 2 outage.
Other O&M expenses increased in 1995, primarily due to higher
capacity charges from the regional nuclear generating units, higher benefit
costs, higher demand side management costs, higher 1995 storm costs, higher
costs associated with a work stoppage, and higher outside services
employed, partially offset by lower reserves for excess/obsolete inventory
in 1995 and lower maintenance costs at the Company's fossil units.
Amortization of regulatory assets, net decreased in 1995,
primarily due to the completion of the Company's amortization of Millstone
3 phase-in costs in June, 1995.
Federal and state income taxes decreased in 1995, primarily due
to tax benefits from a favorable tax ruling, the expiration of the federal
statute of limitations in 1991, and lower taxable income.
Other, net decreased in 1995, primarily because additional
Millstone 3 investments were phased into rates.
BUSINESS
Overview of Nuclear and Related Financial Matters
In January of 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 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 owned 19 percent by the Company
and 81 percent by CL&P. Millstone 3, a 1,154-MW pressurized water reactor,
is jointly owned by the Company (12.24 percent), CL&P (52.93 percent), PSNH
(2.85 percent) and other New England utilities.
The System companies have initiated a number of changes in the
management of the 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, 1997, the
shareholders elected William F. Conway, a nuclear power industry
consultant, and former executive with several power companies, to the NU
Board.
-22-
<PAGE>
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 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
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 having Millstone 3 ready for restart around 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. Restart of each unit is
contingent upon, among other things, the affirmative vote of the
Commissioners of the NRC, which could occur by mid-December 1997 for
Millstone 3. Management hopes that Millstone 3 can begin operating by the
end of 1997. There can be no assurances, however, that this schedule will
be met. 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
a unit is declared ready for restart.
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 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. 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 CYAPC to retire CY from commercial operation, see "-
-Electric Operations--Nuclear Generation." For information regarding
actions taken to meet System capacity needs caused by the Millstone
outages, see "--Electric Operations--Distribution and Load."
As a result of the extended Millstone outages, the 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 CL&P, which have the greatest
investment share of the Millstone units. In 1996, the Company expensed a
total of approximately $76 million for Millstone-related non-fuel O&M
costs, which included among other costs $21 million for non-fuel
incremental O&M costs related to the Millstone outages and $12 million
reserved for future Millstone incremental O&M costs.
Management believes that the overall 1997 nuclear spending levels
for both nuclear O&M expenditures and associated support services and
capital expenditures will be slightly higher than previously estimated.
1997 nuclear O&M expenditures and related support services are expected to
increase, while 1997 capital expenditures are expected to decrease.
Management also believes that it is possible that 1997 nuclear spending
will increase somewhat as the detailed work needed to restore the units to
service progresses. 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 Financial
Statements," Notes 11B and 11E.
-23-
<PAGE>
The Company also expensed approximately $41 million for
replacement power costs in 1996. Monthly replacement power costs for the
Company attributable to the Millstone outages averaged approximately $6
million per month during the first quarter of 1997, and are projected to
average approximately $5 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.
Although the Company is not precluded from seeking rate
recoveries of these costs in the future, 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 believes that the Company will not seek rate
recovery of a substantial portion of such costs. Management currently does
not intend to request any such 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.
While the Company believes that it is entitled to recovery of those costs
which have been and will be prudently 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 CL&P of
substantially all of its Millstone outage related costs.
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 $2 million in the first quarter of 1997.
In 1997, while all three units are out of service the Company expects to
operate on a roughly break-even basis. 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 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 System companies own and operate a fully integrated electric
utility business. The Company's retail electric service territory covers
approximately 1,490 square miles and has an estimated total population of
approximately 582,000. The Company furnishes retail electric franchise
service in 59 cities and towns in Massachusetts. In December 1996, the
Company furnished retail electric franchise service to approximately
195,000 customers.
-24-
<PAGE>
The following table shows the sources of the Company's 1996 electric
revenues based on categories of customers:
<TABLE>
<S> <C>
Residential..................... 38%
Commercial...................... 32
Industrial...................... 19
Wholesale*...................... 7
Other........................... 4
---
Total........................... 100%
</TABLE>
* Includes capacity sales
Through December 31, 1996, the all-time peak demand on the System was 6,358
MW, which occurred on August 2, 1995. At the time of the peak, the System's
generating capacity, including capacity purchases, was 8,035 MW.
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>
2.7% (.1)% 0.4%
</TABLE>
Retail electric sales for the Company rose by 2.7 percent in 1996 compared
to 1995, primarily due to moderate growth in the residential and commercial
classes, which increased by 3.6 and 3.9 percent, respectively, in 1996.
Industrial sales decreased by 0.1 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.
Moderate growth is forecasted over the next ten years. The forecasted
annual growth rate for the Company of .4 percent 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
-25-
<PAGE>
forecasted ten-year annual growth rate of the Company sales would be
approximately 1.1 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 $31
million in 1995 and $30 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 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 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 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 System and NEPOOL will have sufficient capacity
to meet peak load demands for New England even if Millstone, the Maine Yankee
nuclear unit (MY) 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 Massachusetts 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 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 expects to spend approximately $12 million in 1997 to reduce
the risk of unplanned outages. Most of the money budgeted for 1997 will be used
to improve the System's network of transmission facilities to increase imports
into Connecticut and Massachusetts and to reactivate fossil fuel generating
facilities in New England.
Regional and System Coordination
The 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. System transmission lines
form part of the New England transmission system linking 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 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 are returned to service by November 1, 1997,
the
-26-
<PAGE>
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 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 System companies. Under an agreement among the
Company, CL&P 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 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 $6 million in incremental
transmission revenues from other electric utility generators.
-27-
<PAGE>
Fossil Fuels
In 1996, 12 percent and 11 percent of the System's generation was oil and
coal-derived, respectively. The Company's residual oil-fired generation stations
used approximately 66,000 barrels of oil in 1996. Spot purchases represented 100
percent of the Company's fuel oil purchases in 1996. The Company currently does
not anticipate any difficulties in obtaining necessary fuel oil supplies on
economic terms.
The Company has one 107 MW generating station, which can fully or partially
burn either residual oil or natural gas, as economics, environmental concerns or
other factors dictate. The Company has contracts with the local gas distribution
company where the unit is located, under which natural gas is made available by
such company on an interruptible basis. The Company expects that interruptible
natural gas will continue to be available for its dual-fuel electric generating
unit on economic terms and will continue to economically supplement fuel oil
requirements.
Nuclear Generation
General
Certain System companies have 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). System companies operate the three Millstone units and Seabrook 1. Yankee
Rowe was permanently removed from service in 1992, and CY was permanently
removed from service on December 4, 1996. The System companies will have
responsibility for administering the decommissioning of CY.
The Company and CL&P own 100 percent of Millstone 1 and 2 as tenants in
common. Their respective ownership interests in each unit are 19 percent and 81
percent.
The Company, PSNH and CL&P 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 12.24 percent, PSNH's ownership
interest in the unit is 2.85 percent and CL&P's interest is 52.93 percent. The
Millstone 3 joint ownership agreement provides 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 CL&P, 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 CL&P 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, CL&P, PSNH, 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, CL&P's and PSNH's stock ownership percentages in
the Yankee Companies are set forth below:
-28-
<PAGE>
<TABLE>
<CAPTION>
WMECO PSNH CL&P System
----- ---- ---- ------
<S> <C> <C> <C> <C>
Connecticut Yankee Atomic
Power Company (CYAPC)........ 9.5% 5.0% 34.5% 49.0%
Maine Yankee Atomic Power
Company (MYAPC).............. 3.0% 5.0% 12.0% 20.0%
Vermont Yankee Nuclear
Power Corporation (VYNPC).... 2.5% 4.0% 9.5% 16.0%
Yankee Atomic Electric
Company (YAEC)............... 7.0% 7.0% 24.5% 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
the two remaining operating plants, MY and 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 MYAPC and 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. For information regarding additional
capital requirements at MY and related watch list costs, see "--Nuclear Plant
Performance and Regulatory Oversight--Yankee Units--Maine Yankee."
The operators of Millstone 1, 2 and 3, MY and VY hold full power operating
licenses from the NRC. As holders of licenses to operate nuclear reactors, the
Company, CL&P, 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 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 System's nuclear units, see "--Overview of Nuclear and
Related Financial Matters" and "--Nuclear Generation--Nuclear Plant Performance
and Regulatory Oversight."
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.
-29-
<PAGE>
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
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 around 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 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 is ready
for restart 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.
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.
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
-30-
<PAGE>
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 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. Management has already taken
certain steps to address the NRC's concerns in this area and is committed to
making additional significant improvements in its training program. 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 System's training programs at Millstone and CY. The decision to
suspend the nuclear training programs was primarily based on a determination
that there is insufficient feedback between work functions and training so as to
ensure training programs are appropriately refined to reflect such items as
changing needs and experience. Management has not yet determined when the
various training programs will be fully operational, but is currently developing
a list of priorities for programs to get back on line. Management does not
believe at this time that the suspension will affect the System's schedule for
restarting 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 this 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.
On July 1, 1997, CL&P submitted continued unit operation studies to the
Connecticut Department of Public Utility Control (DPUC) showing that, under base
case assumptions, Millstone 1 will have a value to 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 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 CL&P considers less likely,
indicated that Millstone 1 would be uneconomic in varying degrees. At the
present time, the Company expects to continue operating both Millstone 1 and
Millstone 2 for the remaining terms of their respective operating licenses;
however, the Company cannot predict the outcome of this proceeding. The unit
operation studies submitted to the DPUC do not bind the Company in future
proceedings before the DPU.
-31-
<PAGE>
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 potential joint owner
litigation related to the extended outages, see "Legal Proceedings."
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 March 31, 1997,
the Company's share of the CY unrecovered contractual obligation which also has
been recorded as a regulatory asset, was $68.4 million.
Based upon FERC regulatory precedent, CYAPC believes it will be allowed to
continue to collect from its power purchasers, including the Company, CL&P 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, CL&P 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.
-32-
<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 System companies or CYAPC.
Maine Yankee. MY, a 870-MW pressurized-water reactor, has a license
expiration date of October 21, 2008. MY's operating license expires 40 years
from the date of issuance of the construction permit, which was about four years
before MY's full-power operating license was issued. If appropriate, MYAPC will
determine whether to seek recapture of this construction period from the NRC and
add it to the term of the MY operating license. In 1996, MY operated at a
capacity factor of 65.5 percent.
By order issued on January 3, 1996, the NRC suspended MY's authority to
operate at full power and limited MY to operating at 90 percent power pending
the NRC's review and approval of a computer code application used at MY. The
plant was taken out of service on December 5, 1996 after finding that certain
cables did not have the proper separation required by the plant's design and
licensing basis to protect them during accident conditions. MYAPC has agreed not
to restart the plant until it completes a number of actions required by the NRC
and prior to receiving NRC approval.
On January 29, 1997, the NRC announced that MY had been placed on the NRC's
watch list as a Category 2 plant. Plants in this category have been identified
as having weaknesses that warrant increased NRC attention until the licensee
demonstrates a period of improved performance. The NRC cited a number of
deficiencies in the engineering design to support operations at MY, which were
identified by an independent safety assessment team during the latter half of
1996. Although MY has developed a plan and initiated steps to correct the
problems, including entering into an agreement with Entergy Corporation to
acquire outside management expertise in the operation of the facility, the NRC
indicated that increased agency attention was still needed. On May 27, 1997, MY
announced that it was considering permanent closure of the plant based on
economic concerns and uncertainty about the operation of the plant. MY disclosed
that it would reduce spending to a level that would preserve the option of
restarting the plant or closing it.
The Company cannot determine whether or when MY will return to service and
expects that, if the decision is made to restart the plant, there will be
substantial costs associated with the NRC's actions that cannot be accurately
estimated at this time.
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, CL&P, PSNH, 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
-33-
<PAGE>
accident that exceed $100 million will first be applied to pay expenses. The
insurance carried by the licensees of the Millstone units, 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 "Notes to
Financial Statements."
Nuclear Fuel
The supply of nuclear fuel for the 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 System's
units. The majority of the 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 System expects that uranium concentrates and related services
for the units operated by the System and for the other units in which the System
companies are participating, that are not covered by existing contracts, will be
available for the foreseeable future on reasonable terms and prices.
As a result of the Energy 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 $11 million at March 31, 1997 and 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 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 the $21 million that
the System companies have already paid into the fund for the 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 System companies include in their nuclear
fuel expense spent fuel disposal costs accepted by the DPUC, New Hampshire
Public Utilities Commission (NHPUC) and DPU in rate case or fuel adjustment
decisions. Spent fuel disposal costs also are reflected in FERC-approved
wholesale charges.
-34-
<PAGE>
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
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.
MYAPC believes it has adequate storage capacity through MY's current
licensed operating life. 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.
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 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 System has plans that will allow for onsite storage of LLRW for at
least five years. Connecticut has not 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.
-35-
<PAGE>
Decommissioning
Based upon the System's most recent comprehensive site-specific updates of
the decommissioning costs for each of the three Millstone units, 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 decommissioning costs for the Company. The estimates are based on the
latest site studies, escalated to March 31, 1997 dollars.
<TABLE>
<CAPTION>
(Millions)
<S> <C>
Millstone 1 $ 75.1
Millstone 2 66.3
Millstone 3 57.4
------
Total $198.8
</TABLE>
As of March 31, 1997, the Company recorded balances (at market) in its
external decommissioning trust funds as follows:
<TABLE>
<CAPTION>
(Millions)
<S> <C>
Millstone 1 $41.4
Millstone 2 28.0
Millstone 3 17.3
-----
Total $86.7
</TABLE>
The Company has established independent trusts to hold all decommissioning
expense collections from customers. The DPU has authorized the Company to
collect its current decommissioning estimate for the three Millstone units.
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 DPU 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 System companies in each
of the Yankee units, see "--Electric Operations--Nuclear Generation--General."
-36-
<PAGE>
<TABLE>
(Millions)
<S> <C>
VYNPC $ 9.1
YAEC* 12.1
CYAPC* 72.5
MYAPC 11.1
------
Total $104.8
</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. If
the decision is made to retire MY rather than to incur the expenses
required to return the plant to service, decommissioning costs may
increase. See "--Electric Operations--Nuclear Generation--Yankee
Units--Maine Yankee." The Company expects to recover all
decommissioning costs from its customers pursuant to FERC tariffs.
As of March 31, 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 $ 4.1
YAEC 8.6
CYAPC 20.1
MYAPC 5.0
-----
Total $37.8
</TABLE>
Effective January 1996, YAEC began billing its sponsors, including the
Company, CL&P 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.
-37-
<PAGE>
For more information regarding nuclear decommissioning, see
"Nuclear Decommissioning" in the "Notes to Financial Statements."
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
System's service territories, where legislators and regulatory agencies
have been at the forefront of the restructuring movement.
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 March 31, 1997, the Company's net investment in nuclear
generating capacity, excluding its investment in certain regional nuclear
companies, was approximately $436 million, and in its regulatory assets was
approximately $182 million. 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 DPU. See "Depreciation" in the "Notes
to 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
have created uncertainty with respect to future rates and the recovery of
strandable investments. See "Risk Factors--Regulatory Accounting and
Assets."
On December 30, 1996, the DPU issued its Model Rules on
Restructuring (Model Rules). The Model Rules indicate that utilities will
have a reasonable opportunity to recover strandable investments incurred on
or before August 16, 1995, which will be collected through a Stranded Cost
Access Charge. The Massachusetts General Court also has established a
legislative task force to review restructuring during the 1997 legislative
session.
Notwithstanding these legislative and regulatory initiatives, the
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 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 17 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 $6 million of
rate reductions in 1996. The average term of these agreements is
approximately 5.34 years.
The System has expanded its retail marketing organization to
provide value-added solutions to its customers. The 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.
-38-
<PAGE>
The new employees will allow the System to have more direct contact with
customers in order to develop tailor-made solutions for customers' energy
needs. In addition, the System companies, as well as other NU
subsidiaries, received orders from 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
DPU.
On April 30, 1996, the DPU approved a settlement which was
proposed by the Company and the Massachusetts Attorney General (the
Agreement). The Agreement will continue, through February 1998, a 2.4
percent rate reduction instituted in June 1994. The Agreement terminates
pending reviews of the Company's generating plant performance and any
potential reviews associated with Millstone 2's 1994-1995 extended outage.
The Agreement also accelerates its amortization of strandable generation
assets by approximately $6 million in 1996 and $10 million in 1997.
Electric Industry Restructuring in Massachusetts
On December 30, 1996, the DPU issued the Model Rules, which
supplemented an earlier set of draft rules issued on May 1, 1996. The Model
Rules and accompanying order endorsed January 1, 1998 as the date for full
customer choice of energy suppliers in Massachusetts. In addition, the
Model Rules provide that utilities will have a reasonable opportunity to
recover strandable investments and for the functional unbundling of a
utility's distribution, transmission, generation and marketing functions.
The Model Rules also addressed many of the other issues, including the
future structure of the electric utility industry, that were addressed in
the DPU's May 1 explanatory statement. The Model Rules, however, require a
number of statutory changes to be enacted in order to implement these
rules. The Massachusetts legislature has given no formal indication as to
whether it will enact the statutory changes requested by the DPU. It is
unclear at this time how the DPU will proceed if the requested statutory
changes are not enacted.
The DPU also issued regulations establishing standards of conduct
governing the relationship between electric company distribution companies
and their competitive affiliates, which include all affiliates that "engage
in the selling or marketing of natural gas, electricity, or related
services on a competitive basis, including, but not limited to, natural gas
or electric supply or capacity, and demand-side management." Among other
restrictions and reporting requirements, the rules provide a number of
restrictions on the flow of information between a distribution company and
its competitive affiliates, provide that much of the information that is
shared between a distribution company and its competitive affiliate must be
provided to non-affiliates, and provide for physical separation between
employees of a distribution company and its competitive affiliate. The
Company is currently developing and implementing procedures to comply with
this order.
In addition to the proposed rules set forth above, the DPU also
ordered each electric company, including the Company, to develop revenue-
neutral rates unbundled into at least generation, transmission and
distribution components. The Company filed its proposed unbundled rates
with the DPU on March 3, 1997. The DPU approved the Company's filing on
May 19, 1997. The Company began sending unbundled bills to Massachusetts
customers in June 1997. All customers should be in receipt of unbundled
bills by the end of August 1997.
-39-
<PAGE>
On February 28, 1997, the DPU approved a settlement agreement
involving an unaffiliated electric company, Massachusetts Electric Company
(MECO), which is intended to meet the restructuring objectives of the DPU.
This proposal calls for full-retail choice by January 1, 1998 or a later
date when customers of other Massachusetts electric companies have the
opportunity to choose their energy supplier. Under the settlement, MECO's
generating affiliate will divest itself of its generation assets and MECO
will collect strandable investments through a nonbypassable access charge
on customers' bills. The settlement, however, provides that further DPU
approval is required before retail access is triggered and acknowledges
that the legislature can alter the settlement through subsequent
restructuring legislation. Two other Massachusetts electric companies have
indicated that they have reached similar agreements in principal with the
Attorney General, but only one of these companies has filed such agreement
with the DPU.
The Company's Fuel Adjustment Clause and Generating Unit Operating
Performance
In Massachusetts, all fuel costs are collected on a current basis
by means of a forecasted quarterly fuel clause. The DPU must hold public
hearings before permitting adjustments in the Company's retail fuel
adjustment clause. In addition to energy costs, the fuel adjustment clause
includes capacity and transmission charges and credits that result from
short-term transactions with other utilities and from certain FERC-approved
contracts among the System operating companies.
Massachusetts law establishes an annual performance program
related to fuel procurement and use and requires the DPU to review
generating unit performance and related fuel costs. Fuel clause revenues
collected in Massachusetts are subject to potential refund, pending the
DPU's examination of the actual performance of the Company's generating
units. The DPU has found that possession of a minority ownership interest
in a generating plant does not relieve a company of its responsibilities
for the prudent operation of that plant. For information regarding the
Company's ownership interests in nuclear generating units, see "Electric
Operations--Nuclear Generation."
On February 28, 1997, the DPU approved a settlement agreement
between the Company and the Massachusetts Attorney General to maintain the
Company's FAC at its August 1996 level through August 1997. The settlement
also provides that the Company will not seek carrying charges on any
deferred fuel costs incurred as a result of maintaining the FAC at the
agreed-upon level. In accepting the settlement, the DPU deferred any
inquiry into the Company's fuel expenses, including replacement power fuel
expenses related to the current Millstone outages. Management does not
expect to seek rate recovery of a substantial portion of such costs.
Demand-Side Management
In 1992, the DPU established a conservation charge (CC) to be
included in the Company's customers' bills. The CC includes incremental
DSM program costs above or below base rate recovery levels, lost fixed-cost
recovery adjustments and the provision for a DSM incentive mechanism.
In August and November 1995, the DPU issued decisions limiting
the Company's recovery of lost base revenues in calendar year 1996 to those
revenues lost due to implementation of conservation-related costs in the
most recent three-year period. The DPU decision reduced 1996 revenues by
approximately $5.5 million.
On January 17, 1996, the DPU approved a two-year settlement
proposal that resolves the Company's DSM-related proceedings before the
DPU. The settlement resolves: (i) DSM budget levels for 1996 and 1997 (at
$12.4 million and $11.9 million, respectively); (ii) the CC for each rate
class for 1996 and 1997; and
-40-
<PAGE>
(iii) energy savings associated with past DSM activity. The Agreement,
modifies, in part, the above-referenced DSM decisions. The Agreement
shifted $8 million once included in the CC as lost base revenues into base
rates.
On March 3, the DPU approved the Company's proposed conservation
charges for the period March 1, 1997-February 28, 1998. These new charges
are now being included on customers' bills. In addition, the DPU approved
the Company's estimates of energy savings from its DSM programs.
Resource Plans
Construction
The Company's construction program in the period 1997 through
2001 is estimated as follows:
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
(Millions)
<S> <C> <C> <C> <C>
$31 $42 $31 $28 $31
</TABLE>
The 1997 data include costs of approximately $5.6 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 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 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 System periodically updates its long-range resource needs
through its integrated demand and supply planning process. While the
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 System's long term plans rely, in part, on certain DSM
programs. These System companies-sponsored measures, including
installations to date, are projected to lower the 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.
-41-
<PAGE>
In addition, System companies have long term arrangements to
purchase the output from certain nonutility generators (NUGs) under federal
and state laws, regulations and orders mandating such purchases. NUGs
supplied 660 MW of firm capacity in 1996. The System companies, including
the Company, do not expect to purchase additional new capacity from NUGs
for the foreseeable future. See "Cogeneration Costs" in "Notes to
Financial Statements" for information regarding the Company's termination
of one of its purchased-power agreements.
The 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
compliance costs, licensing decisions and other regulatory matters. The
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 September 13, 1996, the Company entered into an agreement to
sell fractional undivided percentage receivable interests in its eligible
billed and unbilled accounts receivable. The amount of receivables sold at
any one time will not exceed $40 million plus limited reserves for losses.
To the extent actual loss experience of the pool receivables exceeds the
loss reserves, the purchaser will absorb the excess. The Company has
retained collection and servicing responsibilities as agent for the
purchaser. As of March 31, 1997, the Company had sold approximately $15
million of its accounts receivable under this Agreement. During May 1997,
the Company restructured its sales agreement to comply with the
requirements of SFAS 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities," which became
effective on January 1, 1997. SFAS 125 required, in part, that the Company
establish a special-purpose, wholly owned subsidiary, WMECO Receivables
Corporation (WRC). WRC's sole purpose is to purchase receivables from the
Company and, at times, resell undivided ownership interests in those
receivables to a third party purchaser.
On November 21, 1996, NU, the Company and CL&P 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 $90,000,000 and by CL&P of first mortgage bonds in the
principal amount of $225,000,000 as collateral for their respective
obligations under the New Credit Agreement, (ii) revised financial
covenants consistent with NU's, the Company's and CL&P's financial
forecasts, and (iii) an up front 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 $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 the total Company collateral to $150,000,000) and CL&P will be 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 CL&P's total collateral
to $313,750,000), 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 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 NU's real estate company (Rocky River Realty Company or
RRR) notified RRR that it wished RRR to repurchase the
-42-
<PAGE>
notes. The notes are secured by real estate leases between RRR as lessor
and Northeast Utilities Service Company (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. On July 1, 1997, RRR received a
commitment for the purchase of approximately $12 million of the notes.
RRR repurchased the remaining $26 million of notes on July 14, 1997. The
Company may be billed by NUSCO for its proportionate share of the
accelerated lease obligations when RRR repurchases the notes. The Company
does not expect the resolution of this matter to have a material adverse
impact on its financial condition or liquidity. See "Notes to Financial
Statements," Note 11G for further information.
Total Company debt, including short term and capitalized lease
obligations, was $458.6 million as of March 31, 1997, compared with $429.1
million as of December 31, 1996. For more information regarding Company
financing, see the "Notes to 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 CL&P because of the extended Millstone outages. In May,
1997, S&P downgraded the Company and CL&P 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 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 $31
Nuclear Fuel 1
Maturities 15
---
Total $47
</TABLE>
For further information on NBFT and the Company's financing of
its nuclear fuel requirements, see "Leases" in the "Notes to 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
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 (Holding Company Act).
-43-
<PAGE>
As of January 1, 1997, the Company's maximum authorized short
term borrowing limit was $150 million. At December 31, 1996, the Company
had short term borrowings of $47 million outstanding. At March 31, 1997,
the Company had short term borrowings of $90.9 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 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 System company.
The Company's charter contains preferred stock provisions
restricting the amount of unsecured debt the Company may incur. As of
March 31, 1997, the Company's charter permits the Company to incur an
additional $28 million of unsecured debt.
While not directly restricting the amount of short term debt that
the Company, CL&P, RRR, NNECO and NU may incur, the revolving credit
agreements to which the Company, CL&P, 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 March 31,
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 March 31, 1997, the
Company's common equity ratio was 37.4 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 ended March 31, 1997, the Company's interest coverage
ratio (computed in accordance with the New Credit Agreement) was 1.5 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 the bonds to be issued. The Company's 1996 earnings do not permit it
to meet those earnings coverage tests, but as of May 31, 1997, the Company
would be able to issue up to approximately $63.9 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 March 31, 1997, the Company's unrestricted earned surplus
was $57,949,978.
-44-
<PAGE>
Certain subsidiaries of NU, including the Company, have
established a system for pooling System resources (Money Pool) to provide a
more effective use of the cash resources of the System 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 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 System's major generation and transmission facilities may not be
constructed or significantly modified without a review by the applicable
state agency of the environmental impact of the proposed construction or
modification. Compliance with environmental laws and regulations,
particularly air and water pollution control requirements, may limit
operations or require substantial investments in new equipment at existing
facilities. See "--Resource Plans" for a discussion of the 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.
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."
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.
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 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
-45-
<PAGE>
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 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 System's service area and could raise the capital and operating cost of
existing units. The ultimate cost impact of these requirements on the
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 System has met these requirements.
Compliance with Phase I requirements has cost the System a total of
approximately $41 million including $1 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 not expected to result in material
additional costs 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 to emit one ton of SO2. No unit may emit more
SO2 than the amount for which it has allowances. The only 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 System
can decide to include these plants as Phase I units during any year and
obtain allowances for that year. The 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 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 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 System should be able to recover the additional fuel
costs of compliance with the CAAA and state laws from its customers.
-46-
<PAGE>
Management does not believe that the acid rain provisions of the
CAAA will have a significant impact on the 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 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 System's
generating stations. They require new or modified fossil fuel-fired
electric generating units to operate within stringent emission limits. The
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 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.
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. 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 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 System disposes of solid wastes
containing PCBs in secure chemical waste landfills.
Asbestos. Federal, Connecticut, New Hampshire and Massachusetts
--------
asbestos regulations have required the 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 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 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, 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
-47-
<PAGE>
or buried wastes, under certain circumstances, could cause groundwater
contamination or create other environmental risks. The 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 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 System companies for
such past disposal. As of March 31, 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 $1.9 million,
which management has determined to be the most probable amount within the
range of $1.9 million to $4.2 million. These costs could be significantly
higher if alternative remedies become necessary.
Under the federal Comprehensive Environmental, Response,
Compensation and Liability Act of 1980, as amended, commonly known as
Superfund, 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 System companies to report releases of specified quantities of
hazardous materials and require notification of known hazardous waste
disposal sites. System companies are in compliance with these reporting
and notification requirements.
The 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 System and other parties differs from site
to site. Where reliable information is available that permits the System
to make a reasonable estimate of the expected total costs of remedial
action and/or the 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 System has not accrued
a liability, the costs either were not material or there was insufficient
information to accurately assess the 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 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
-48-
<PAGE>
the Eastern District of Kentucky approved a consent decree between EPA and
members of the Maxey Flats PRP Steering Committee, including System
companies, and several federal government agencies, including DOE and the
Department of Defense as well as the Commonwealth of Kentucky. The 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 System's liability at the site has been assessed at slightly over $1
million.
CL&P, 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, CL&P believes its
liability is minimal.
In addition to the remediation efforts for the above-mentioned
Superfund sites, the System has been named as a PRP and is monitoring
developments in connection with several state environmental actions,
including the following relating to the Company.
In Massachusetts, System companies have been designated by the
Massachusetts Department of Environmental Protection (MDEP) as PRPs for
twelve sites under MDEP's hazardous waste and spill remediation program.
At two sites, the System may incur remediation costs that may be material
to HWP depending on the remediation requirements. At one site, HWP has
been identified by MDEP as one of three PRPs in a coal tar site in Holyoke,
Massachusetts. HWP owned and operated the Holyoke Gas Works from 1859 to
1902. The site is located on the east side of Holyoke, adjacent to the
Connecticut River and immediately downstream of HWP's Hadley Falls Station.
MDEP has designated both the land and river deposit areas as priority waste
disposal sites. Due to the presence of tar patches in the vicinity of the
spawning habitat of the shortnose sturgeon--an endangered species--the
National Oceanographic and Atmospheric Administration (NOAA) and National
Marine Fisheries Service have taken an active role in overseeing site
activities. Both MDEP and NOAA have notified the PRPs of the need to
remove tar deposits from the river. During 1996, HWP conducted a pilot
project to assess the feasibility and costs of tar removal. Results of
this project are currently being evaluated. To date, HWP has spent
approximately $1 million for river studies and construction costs related
to the site. The total estimated costs for remediation of tar patches at
this site range from approximately $1 to $4 million. Discussions of the
results of the pilot study will be presented to the MDEP in early 1997.
The second site is a former manufactured gas plant facility in
Easthampton, Massachusetts. WMECO predecessor companies owned and operated
the Easthampton Gas Works from 1864 to 1924. Previous investigations have
identified coal tar deposits on the land portion of the site. During fall,
1996, the Company conducted additional investigative work in an adjacent
pond. The results of this work are currently being analyzed. A report
will be submitted to the MDEP in 1997 which will better define the extent
of coal tar deposits in the pond. To date, the Company has spent
approximately $200,000 for investigative work. The total estimated
remediation costs for the site are estimated to range from $1 to $1.5
million.
In the past, the System has received other claims from government
agencies and third parties for the cost of remediating sites not currently
owned by the System but affected by past System disposal activities and may
receive more such claims in the future. The 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.
-49-
<PAGE>
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 System is closely
monitoring research and government policy developments.
The 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 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.
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.
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. On December 31, 1993, the
license for the Company's Gardners Falls Project expired. FERC has issued
an annual license allowing the Gardners Falls project to continue
operations pending completion of the relicensing process. The Final
Environmental Impact Statement for the Gardners Falls Project indicated
that minimum flow requirements, downstream fish passage facilities and
recreational enhancements are needed at the Project and were recommended as
conditions of a new license.
The System companies hold FERC licenses for 19 hydroelectric
projects aggregating approximately 1,375 MW of capacity, located in
Connecticut, Massachusetts and New Hampshire.
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.
-50-
<PAGE>
EMPLOYEES
As of December 31, 1996, the System companies had 8,842 full and
part-time employees on their payrolls, of which 497 were employed by the
Company, 2,194 by CL&P, 1,279 by PSNH, 92 by HWP, 1,274 by NNECO, 2,692 by
NUSCO and 814 by NAESCO. NU, NAEC, Charter Oak, Mode 1 and Select Energy
Inc. have no employees.
In 1995 and early 1996, the 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 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, CL&P, PSNH, 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 a major portion of its other
properties are owned in fee, although one hydroelectric plant is leased.
In addition, the Company has certain substation equipment, data processing
equipment, nuclear fuel, 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 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.
Transmission and Distribution System
At December 31, 1996, the 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.
-51-
<PAGE>
Electric Generating Plants
As of March 31, 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 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 123,063
Unit 2 Nuclear 1975 166,155
Unit 3 Nuclear 1986 140,216
ME Yankee (Wiscasset, ME) Nuclear 1972 23,681
VT Yankee (Vernon, VT) Nuclear 1972 11,948
---------
Total Nuclear-Steam Plants (5 units) 465,063
Total Fossil-Steam Plants (1 unit) 1957 107,000
Total Hydro-Conventional (27 units) 1904-34 110,910**
Total Hydro-Pumped Storage (4 units) 1972-73 205,200
Total Internal Combustion (3 units) 1968-69 60,500
---------
Total WMECO Generating Plant (40 units) 948,673
=========
</TABLE>
* Claimed capability represents winter ratings as of March 31, 1997.
** Total Hydro-Conventional capability includes Cobble Mountain plant's
33,960 KW which is leased from the City of Springfield, MA.
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 Massachusetts," and "Legal Proceedings."
The Company is authorized by its charter to conduct its electric
business in the territories served by it, and has locations in the public
highways for transmission and distribution lines. Such locations are
granted pursuant to the laws of Massachusetts by the Department of Public
Works of Massachusetts or local municipal authorities and are of unlimited
duration, but the rights thereby granted are not vested. Such locations
are for specific lines only, and, for extensions of lines in public
highways, further similar locations must be obtained from the Department of
Public Works of Massachusetts or the local municipal authorities. In
addition, the Company has been granted easements for its lines in the
Massachusetts Turnpike by the Massachusetts Turnpike Authority.
The Company is subject to the jurisdiction of the DPUC as a
result of its interest in the Millstone units.
-52-
<PAGE>
LEGAL PROCEEDINGS
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.
Millstone 3--Potential Joint Owner Litigation
This matter involves claims that the non-NU owners of Millstone 3 could
potentially bring against the System companies for the costs associated with the
current extended outage of this facility.
The non-NU owners of Millstone 3 have been paying their monthly shares of
the cost of that unit since it went out of service in March 1996, but have
reserved their rights to contest whether the NU System companies have any
responsibility for the additional costs the non-NU owners have borne as a result
of the extended outage. No formal claims have been made, but it is possible that
some or all of the non-NU owners will assert liability on the part of the System
companies. The Company and CL&P, 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
CL&P would only be liable for damages to the non-NU owners for a deliberate
breach of the agreement pursuant to authorized corporate action. The non-NU
owners have retained a team of technical and regulatory experts to review and
monitor activities at Millstone 3. As representatives of Millstone 3 joint
owners, NU is cooperating fully with the team.
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
-53-
<PAGE>
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.
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 the other petition, it cannot
predict the ultimate outcome of these petitions.
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 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 System.
-54-
<PAGE>
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, and various state restructuring proceedings; "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.
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 VP, CAO, D 09/06/88 01/01/89
John H. Forsgren EVP, CFO, D 02/01/96 06/10/96
Bernard M. Fox CH, D 05/15/81 05/01/83
William T. Frain, Jr. D - 02/01/94
Cheryl W. Grise SVP, D 06/01/91 01/01/94
Barry Ilberman VP 02/01/89 -
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
John J. Roman VP, CONT 04/01/92 -
Robert P. Wax SVP, SEC, AC, GC 08/01/92 -
<CAPTION>
Key:
- ----
<S> <C> <C> <C>
AC - Assistant Clerk EVP - Executive Vice President
CAO - Chief Administrative Officer GC - General Counsel
CEO - Chief Executive Officer P - President
CFO - Chief Financial Officer SEC - Secretary
CH - Chairman SVP - Senior Vice President
CONT - Controller TR - Treasurer
D - Director VP - Vice President
</TABLE>
-55-
<PAGE>
<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.
Bernard M. Fox (3) 54 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 in 1995; previously Vice Chairman of CL&P and WMECO, and Vice Chairman and
Chief Executive Officer of NAEC since 1994; Chief Executive Officer of NU,
CL&P, PSNH, WMECO and NAEC in 1993; President and Chief Operating Officer of
NU, CL&P and WMECO in 1990 and NAEC since 1991; Vice Chairman of PSNH since
1992.
William T. Frain, Jr.(4) 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.
Barry Ilberman (5) 47 Elected Vice President-Corporate and Environmental Affairs of CL&P, PSNH, WMECO
and NAEC in 1994; previously Vice President-Corporate Planning of CL&P, WMECO
since 1992.
John B. Keane (6) 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 (7) 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.
</TABLE>
-56-
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Francis L. Kinney (8) 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 (9) 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.
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 and
General Counsel of NU and CL&P and 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 Institute of Living, the Institute of Nuclear
Power Operations, the Connecticut Business and Industry Association, Fleet
Financial Group, Inc., CIGNA Corporation, Connecticut Yankee Atomic Power
Company, Edison Electric Institute, Hartford Hospital, The Dexter
Corporation, a Trustee of Mount Holyoke College and The Hartford Courant
Foundation and a Fellow and Founder of the American Leadership Forum.
(4) 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.
(5) Director of Connecticut Yankee Atomic Power Company.
(6) 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.
(7) Trustee of Columbia College and Director of Connecticut Yankee
Atomic Power Company.
(8) Director of Mid-Conn Bank.
(9) Director of Connecticut Yankee Atomic Power Company.
There are no family relationships between any director or executive
officer and any other director or executive officer of NU, the Company, CL&P,
PSNH or NAEC.
-57-
<PAGE>
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 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)
Ted C. Feigenbaum 1996 248,858 (Note 5) None None None 14,770 7,222
</TABLE>
-58-
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(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.
-59-
<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 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
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>
-60-
<PAGE>
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 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 has announced that he will retire in the
second half of 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
System's confidential information, and refrain, while employed by the 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 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).
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 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 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 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.
-61-
<PAGE>
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 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 ended 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 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 System information during his employment and following his
retirement, and not to compete with the 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
-62-
<PAGE>
$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. 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
System "and all related parties" with respect to matters arising out of his
employment with the System, and the 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 System as the result of an investigation
conducted upon the demand of a shareholder or by a shareholder on behalf of the
System. Both the 1992 Agreement and the Transition Agreement are binding on each
majority-owned subsidiary of NU with at least fifty employees on its direct
payroll.
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 System and a release by the 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 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.
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 BONDS
The Indenture and the Trustee
The Bonds are to be issued under and secured by the First Mortgage
Indenture and Deed of Trust dated as of August 1, 1954 between the Company and
State Street Bank and Trust Company, Successor Trustee (the Trustee)
(hereinafter referred to as the Original Indenture) and the eightieth indenture
supplemental thereto (which is hereinafter referred to as the New Supplemental
Indenture). Copies of the Original Indenture and of the First, Twenty-fourth,
Twenty-sixth, Thirty-fifth, Seventy-first, Seventy-second, Seventy-fourth,
Seventy-fifth and Seventy-ninth Supplemental Indentures and the form of the New
Supplemental Indenture (herein collectively referred to as the 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). The
summary description of the provisions of the Indenture which follows does not
purport to be complete or to cover all the provisions thereof.
-63-
<PAGE>
The following summary is qualified in its entirety by express reference to the
provisions of the Indenture and by reference also to the definitions contained
therein, under which many of the terms used have restrictive meanings. 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 System in the ordinary
course of business.
General Terms of Bonds
The Bonds will mature on July 1, 2001, and will bear interest from the
date of original issuance at the rate per annum set forth on the cover of this
Prospectus. Interest will be payable semiannually on January 1 and July 1,
commencing January 1, 1998 at the principal corporate trust office of the
Trustee in Boston, Massachusetts, to registered owners at the close of business
on the December 15 or June 15, as the case may be, preceding such January 1 or
July 1 or if such record date is a legal holiday or a day on which banks are
authorized to close in Boston, Massachusetts, on the next preceding banking
day.
The Bonds are to be issued only in the form of fully registered bonds
without coupons in denominations of $1,000 or multiples thereof and may be
presented for exchange for a like aggregate principal amount of the same series
of Bonds of other authorized denominations and for transfer at the principal
corporate trust office of the Trustee in Boston, Massachusetts, without payment
in either case of any charge other than for any tax or other governmental
charges required to be paid by the Company.
The Bonds will be issued initially under a book-entry only system in the
form of one fully registered certificate, registered in the name of Cede & Co.,
as registered bondholder and nominee of the DTC, New York, New York. DTC will
act as securities depository for the Bonds. So long as Cede & Co., as nominee of
DTC, or any successor nominee of DTC, is the registered bondholder of the Bonds,
references herein and in the Prospectus to the bondholders or registered owners
of the Bonds will mean Cede & Co. or such successor nominee. See "Book-Entry
Only System" for certain information regarding DTC and the book-entry only
system.
The Indenture does not contain any covenants or other provisions that are
specifically intended to afford holders of the Bonds special protection in the
event of a highly leveraged transaction.
Security
In the opinion of counsel for the Company, the Indenture constitutes a
first mortgage (except for encumbrances stated in the granting clauses thereof,
of Schedule A thereto and Permitted Encumbrances) on all property now owned by
the Company (other than certain property hereinafter referred to) and on all the
rents, earnings and income thereof, but prior to a default the Company may
retain possession of the mortgaged property and take the rents, earnings and
income thereof. Certain property is specifically excepted in the granting
clauses of the Indenture, consisting principally of the following: cash,
receivables, contracts, securities, legal claims and claims for tax refunds;
office furniture and equipment; vehicles and their related equipment; materials,
merchandise and supplies held for sale in the ordinary conduct of business;
materials and supplies, fuel and other personal property which are consumable
(otherwise than by ordinary wear and tear) in the operation
-64-
<PAGE>
of the plants and systems of the Company; materials or supplies used as
components in the construction of electric utility or steam plant and held in
advance of use thereof for such purpose; the last day of the term of any lease;
all property, leasehold interests, permits, licenses, franchises and rights
which may not legally be subjected to the lien of the Indenture or which cannot
be so subjected without the consent of other parties whose consent is not
secured; and all small tools and equipment and machinery of portable size. The
property so subject to the lien of the Indenture includes the Company's interest
in all the physical properties referred to under "Properties" above except the
Cobble Mountain Plant and the generating plants of the four regional nuclear
generating companies. The Indenture contains after-acquired property clauses
which, in the opinion of counsel for the Company, will be effective as to the
personal property covered thereby when acquired by the Company. Insofar as such
clauses apply to after-acquired real property they may, in the opinion of
counsel, be effective only upon the filing and recording of a supplemental
indenture in respect of any such real property. (The granting clause, (S) 1.02
and Article VII.)
Under certain limited circumstances, the lien of the Indenture 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. This law creates a lien
effective against all real and personal property of the site owner in favor of
the Commonwealth of Massachusetts for up to three times the Commonwealth's cost
incurred for cleaning up a hazardous waste site. The law also contains a so-
called "super-lien" provision under which the statutory lien is superior to all
other encumbrances, both existing and future, on the site of release of the
hazardous waste.
Also, 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. The principal real property interests owned by the
Company in Connecticut are the Company's joint ownership interests in the
Millstone nuclear electric generating units, substantially all of which were
acquired before June 3, 1985.
The Bonds will rank equally as to security with the bonds now outstanding,
and any additional bonds of other series issued, under the Indenture as from
time to time supplemented, and will have priority as to mortgage security over
any other debt of the Company, except for debt secured by Permitted
Encumbrances, and except for debt secured by liens of after acquired property
existing at the time of acquisition thereof or created contemporaneously to
secure or raise a part of the purchase price thereof which debt under the
Indenture may not exceed 60% of the Cost or Fair Value of such property,
whichever is less. ((S)(S) 4.09 and 4.10.)
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 Bonds will be redeemable in whole or in part, at the option of the
Company at any time, 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
-65-
<PAGE>
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 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
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 Dealer Quotations for such Redemption Date,
after excluding the highest and lowest such Reference Treasury Dealer
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 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.
Holders of Bonds to be redeemed will receive notice thereof sent by first-
class mail at least 30 and not more than 60 days prior to the date fixed for
redemption (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).
-66-
<PAGE>
Issuance of Additional Bonds; Earnings Coverages
The aggregate principal amount of bonds which may be issued under the
Indenture is not limited by its terms. Additional bonds may be issued under the
Indenture (a) to the extent of 60% of the lesser of the Cost or Fair Value (at
date of acquisition) of Available Net Property Additions ((S) 3.08), (b) against
the deposit of cash equal to the principal amount of bonds to be issued
((S) 3.05), and (c) to refund other bonds theretofore outstanding under the
Indenture ((S) 3.04). Such additional bonds, however, may be issued under
(S)(S) 3.05 and 3.08 and in the case of certain refundings under (S) 3.04 only
if the net earnings as defined have been at least twice the annual interest
charges on all bonds outstanding, including the additional bonds applied for but
excluding bonds to be redeemed from the proceeds of such additional bonds, and
all prior lien obligations. Because the Company is issuing the Bonds pursuant to
(S)3.04 of the Indenture in an aggregate principal amount equal to an aggregate
principal amount of bonds that have been previously redeemed or retired and the
total annual interest requirements of the Bonds do not exceed the total annual
interest requirements of such bonds that have been previously redeemed or
retired, the Company is not required to satisfy the earnings coverage provisions
of the Indenture to issue the Bonds. The Company currently does not satisfy the
earnings coverage requirement (as defined in the Indenture).
As of March 31, 1997, the Available Net Property Additions ((S) 3.08)
against which additional bonds might be issued was approximately $122,815,042,
sufficient to permit the issue of approximately $73,689,025 aggregate principal
amount of additional bonds. The aggregate amount of First Mortgage Bonds
outstanding on March 31, 1997 was $244.8 million.
Money received by the Trustee upon the issue of additional bonds against
cash may be withdrawn by the Company, while not in default, in amounts equal to
60% of Available Net Property Additions based on the Cost or Fair Value to the
Company at the date of acquisition, whichever is less, and if not so withdrawn
within three years, shall be applied by the Trustee to the redemption of bonds
of the series in respect of the issue of which it was deposited. ((S)(S) 1.02,
1.03, 3.06 and 3.07)
Maintenance of Property
The Indenture contains a general maintenance covenant. The Company is
required by the Indenture in each fiscal year to charge to current earnings and
to credit to a depreciation reserve an amount not less than 2.1% of the average
of the beginning and ending balances for such year of the total plant and
equipment devoted to utility operation of the Company, exclusive of
undepreciable real estate and rights therein and of unfinished construction.
Inspection by an engineer is required annually, and the Company covenants that
it will make good any maintenance deficiency and record retirements as called
for by the engineer's certificate. ((S)(S) 4.06 and 4.12 of the Original
Indenture and (S) 7.02 of the First Supplemental Indenture.)
Replacement Fund
The Indenture contains a Replacement Fund Requirement effective
January 1, 1967, pursuant to which the Company is required to make, in each
calendar year, expenditures for Property Additions in an amount equal to 2.25%
of the average of the amounts of its Depreciable Property at the beginning and
end of the year and, if it fails so to do, to make up such deficiency on or
before May 1 of the ensuing calendar year by (a) depositing cash with the
Trustee, or (b) depositing outstanding bonds with the Trustee at 100% of the
principal amount
-67-
<PAGE>
thereof, or (c) allocating Available Net Property Additions in
an amount equal to 100% thereof. Any cash or bonds so deposited may be withdrawn
and any Available Net Property Additions so allocated may be reinstated, to the
extent that any such deficiency is made up during an ensuing calendar year.
((S)(S) 1.02(30) and 4.17 of the Original Indenture as supplemented by Article
VII(d) and (i) of the Twenty-fourth Supplemental Indenture.) The Replacement
Fund credit at March 31, 1997 was $419,589,076.
Dividend Restrictions
The Indenture contains restrictions on the payment of dividends, which were
included in Supplemental Indentures at the time of the issuance of prior series
of bonds. The Sixty-fifth Supplemental Indenture, which contains restrictions
applicable so long as any Series G bonds 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 on the purchase or other acquisition of common
stock may not exceed (i) retained earnings accumulated after December 31, 1967,
plus (ii) $3,750,000, plus (iii) such further amount as may be authorized by the
Commission under the Holding Company Act, less (iv) preferred dividends, but not
common dividends, accrued subsequent to December 31, 1967, and also less (v) the
amount, if any, by which the Replacement Fund Requirement exceeds depreciation
charges to income or retained earnings. Pursuant to those provisions,
unrestricted retained earnings at March 31, 1997 amounted to approximately
$57,949,978. The Series G bonds mature on March 1, 1998, after which no
restrictive dividend limitations will be applicable under the Indenture.
Default
The Indenture provides that the following events will constitute "events of
default" thereunder: failure to pay principal; failure for 30 days to pay
interest; failure for 60 days to make any payment in respect of the Improvement
Fund or Replacement Fund; failure to perform any of the other Indenture
covenants for 60 days after notice to the Company; and certain events in
bankruptcy, insolvency or receivership ((S) 9.01). The Indenture requires the
Company to deliver to the Trustee an annual officers' certificate as to
compliance by the Company with its covenants under the Indenture ((S) 4.15).
The Indenture provides that the holders of a majority in principal amount
of the bonds outstanding may direct the time, method and place of conducting any
proceedings for the enforcement of the Indenture; provided, however, that the
Trustee shall have the right to decline to follow any such direction if it shall
be advised by counsel that the action or proceeding so directed may not lawfully
be taken or if the Trustee is not sufficiently indemnified for any expenditures
in any action or proceeding so directed ((S) 9.16).
Issuance of Additional Bonds Based on Retired or Redeemed Bonds
In the future, the Company may seek to amend (S)3.04(h) of the Indenture
which requires the Company to satisfy the earnings coverage provisions of the
Indenture to issue additional first mortgage bonds based on retired or redeemed
bonds if the total annual interest requirements of the bonds to be issued
exceeds the total annual interest requirements of the bonds retired or redeemed.
This amendment of the Indenture would provide that, under (S)3.04(h), the
Company would be required to satisfy the earnings coverage provision of the
Indenture only if (i) the total annual interest requirements of the bonds to be
issued exceed the total annual interest
-68-
<PAGE>
requirements of bonds to be retired or
redeemed, and (ii) such bonds to be retired or redeemed are then outstanding and
mature more than two years from the issuance of the additional bonds. The
Supplemental Indenture under which the Bonds will be issued will provide that
the holders of the Bonds will be deemed to have given their written consent to
such amendment. The consent of 70 percent in principal amount of all bonds
outstanding would be required to effect the amendment.
Other Restrictions Upon Issuance of Debt
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 the Company's revolving bank loan agreement, the 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 31 percent of its total
capitalization through December 31, 1997 and 32 percent thereafter. At March 31,
1997, the Company's common equity ratio was 37.4 percent. Beginning in the third
quarter of 1997, the Company must demonstrate that its ratio of operating income
to interest expense 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 ended
March 31, 1997, the Company's interest coverage ratio was 1.5 to 1.
Modification or Amendment of the Indenture
The Indenture may be modified or amended, without the consent of the
bondholders, to add restrictions on the issue of additional bonds or additional
covenants by the Company, to convey additional property to the Trustee or
correct or amplify the description of the mortgaged property; to correct
ambiguities, defects or inconsistencies in the Indenture; or to provide for
separate or co-Trustees or for meetings of bondholders. The Indenture may be
modified or amended in any respect on 30 days notice published and sent postage
prepaid to registered owners of bonds and with the written consent of holders of
at least 70% in principal amount of all bonds issued under the Indenture then
outstanding; provided that, among other things, no such modification or
amendment shall permit any change in the principal amount or premium, any
extension of the maturity, or reduction of the rate, or extension of the time of
payment for interest, or in any way affect or impair the obligations of the
Company in respect of principal or interest on any bond issued under the
Indenture then outstanding without the written consent of the holder thereof, or
affect the rights of one or more series of bonds differently from other series
except upon the written consent of at least 70% in principal amount of the bonds
of each series so affected then outstanding, or permit the creation, except as
expressly authorized in the Indenture, of any mortgage or other lien prior to or
on parity with the lien of the Indenture or change any of the percentages of
holders of bonds required for the taking of any action to modify or amend the
Indenture. (Article XVI.)
BOOK-ENTRY ONLY SYSTEM
The description which follows of the procedures and recordkeeping with
respect to beneficial ownership interests in the Bonds, payments of principal
of, and premium, if any, and interest on, the Bonds to DTC and its Participants
or Beneficial Owners, in each case as defined below, confirmation and transfer
of beneficial ownership interests in the Bonds and other related transactions by
and among DTC, the DTC Participants and Beneficial Owners is based solely on
information furnished by DTC.
-69-
<PAGE>
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
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 Commission.
Purchases of Bonds under the DTC system must be made by or though Direct
Participants, which will receive a credit for the Bonds on DTC's records. The
ownership interest of each actual purchaser of 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 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 Bonds, except in the event that use of the
book-entry system for the Bonds is discontinued. SO LONG AS CEDE & CO., AS
NOMINEE FOR DTC, IS THE SOLE HOLDER OF THE BONDS, THE TRUSTEE SHALL TREAT CEDE &
CO. AS THE ONLY HOLDER OF THE BONDS FOR ALL PURPOSES UNDER THE INDENTURE,
INCLUDING RECEIPT OF ALL PRINCIPAL OF, AND PREMIUM, IF ANY, AND INTEREST ON SUCH
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 Bonds deposited by Participants
with DTC are registered in the name of DTC's partnership nominee, Cede & Co. The
deposit of Bonds with DTC and their registration in the name of Cede & Co.
effect no change in beneficial ownership. DTC has no knowledge of the actual
Beneficial Owners of the Bonds; DTC's records reflect only the identity of the
Direct Participants to whose accounts such 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.
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.
-70-
<PAGE>
Redemption notices, if any, shall be sent to Cede & Co. If less than all of
the 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 Bonds.
Under its usual procedures, DTC mails an Omnibus Proxy to the Company as soon as
possible after the record date. The Omnibus Proxy assigns Cede & Co.'s
consenting or voting rights to those Direct Participants to whose accounts the
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 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 (with
funds provided by the Company), 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 depository with
respect to the Bonds at any time by giving reasonable notice to the Company or
the Trustee. Under such circumstances, in the event that a successor securities
depository 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, THE UNDERWRITERS 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 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 BONDS;
OR (D) ANY OTHER ACTION TAKEN BY DTC OR ITS NOMINEE, CEDE & CO., AS HOLDER OF
THE BONDS.
-71-
<PAGE>
UNDERWRITERS
Under the terms and subject to the conditions contained in an Underwriting
Agreement dated July 29, 1997, Morgan Stanley & Co. Incorporated and Salomon
Brothers Inc (the Underwriters) have severally agreed to purchase from the
Company, and the Company has agreed to sell to them, severally, the respective
principal amounts of the Bonds set forth opposite their respective names
below.
<TABLE>
Name Principal Amount of Bonds
---- -------------------------
<S> <C>
Morgan Stanley & Co. Incorporated.......... $30,000,000
Salomon Brothers Inc....................... $30,000,000
-----------
$60,000,000
===========
</TABLE>
The Underwriting Agreement provides that the obligation of the Underwriters
to pay for and accept delivery of the Bonds is subject to the approval of
certain legal matters by their counsel and to certain other conditions. The
Underwriters' obligations are such that they are committed to take and pay for
all of the Bonds offered hereby if any are taken, provided, that under certain
circumstances involving a default of an Underwriter, less than all of the Bonds
may be purchased. Default by one Underwriter would not relieve the non-
defaulting Underwriter from its several obligations, and in the event of such a
default, the non-defaulting Underwriter may be required by the Company to
purchase the principal amount of Bonds that it has severally agreed to purchase
and, in addition, to purchase the principal amount of the Bonds that the
defaulting Underwriter shall have failed to purchase up to a principal amount
equal to one-ninth of the principal amount of the Bonds that such non-defaulting
Underwriter has otherwise agreed to purchase.
The Underwriters initially propose to offer part of the Bonds directly to
the public at the public offering price set forth on the cover of this
Prospectus and part to certain dealers at a price which represents a concession
not in excess of .75% of the principal amount of the Bonds. The Underwriters
may allow, and such dealers may reallow, a concession not in excess of .25% of
the principal amount of the Bonds to certain other dealers. After the initial
public offering, the public offering price and concessions may be changed.
The Bonds are a new issue of securities with no established trading market,
and the Company does not intend to apply for listing of the Bonds on a national
securities exchange, but has been advised by the Underwriters that they
presently intend to make a market in the Bonds, as permitted by applicable law
and regulations. The Underwriters are not obligated, however, to make a market
in the Bonds, and any such market making may be discontinued at any time at the
sole discretion of the Underwriters. Accordingly, no assurance can be given as
to the liquidity of the trading market for the Bonds.
In order to facilitate the offering of the Bonds, the Underwriters may
engage in transactions that stabilize, maintain or otherwise affect the price of
the Bonds. Specifically, the Underwriters may overallot in connection with the
offering, creating a short position in the Bonds for their own account. In
addition, to cover overallotments or to stabilize the price of the Bonds, the
Underwriters may bid for, and purchase, the Bonds in an open market. Finally,
the underwriting syndicate may reclaim selling concessions allowed to an
underwriter or a dealer for distributing the Bonds in the offering, if the
syndicate repurchases previously distributed Bonds in transactions to cover
syndicate short positions, in stabilization transactions or otherwise. Any of
these
-72-
<PAGE>
activities may stabilize or maintain the market price of the Bonds above
independent market levels. The Underwriters are not required to engage in these
activities, and may end any of these activities at any time.
The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as amended.
LEGAL MATTERS AND EXPERTS
Legal matters in connection with the issue of the 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 Northeast Utilities Service Company. Certain legal matters relating
to the Bonds will be passed upon for the Underwriters by Winthrop, Stimson,
Putnam & Roberts, One Battery Park Plaza, New York, New York.
Statements of law and legal conclusions herein and in the Registration
Statement pertaining to the description of the 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 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>
<CAPTION>
COMPANIES
<S> <C>
NU.......................................... Northeast Utilities
CL&P........................................ The Connecticut Light and Power Company
Charter Oak or COE.......................... Charter Oak Energy, Inc.
WMECO or the Company........................ Western Massachusetts Electric Company
HWP......................................... Holyoke Water Power Company
NUSCO or the Service Company................ 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
</TABLE>
-73-
<PAGE>
<TABLE>
<S> <C>
Mode 1...................................... Mode 1 Communications, Inc.
System...................................... The Northeast Utilities System
CYAPC....................................... Connecticut Yankee Atomic Power Company
MYAPC....................................... Maine Yankee Atomic Power Company
VYNPC....................................... Vermont Yankee Nuclear Power Corporation
the Yankee Companies........................ CYAPC, MYAPC, VYNPC, and YAEC
</TABLE>
<TABLE>
<CAPTION>
GENERATING UNITS
<S> <C>
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.
Millstone 3................................. Millstone Unit No. 3, a 1,154-MW nuclear electric
generating unit completed in 1986
Seabrook or Seabrook 1...................... Seabrook Unit No. 1, a 1,148-MW nuclear electric
generating unit completed in 1986. Seabrook 1 went
into service in 1990.
<CAPTION>
REGULATORS
<S> <C>
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
<CAPTION>
OTHER
<S> <C>
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
FAC......................................... Fuel Adjustment Clause
IRM......................................... Integrated resource management
</TABLE>
-74-
<PAGE>
<TABLE>
<S> <C>
kWh......................................... Kilowatt-hour
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>
-75-
<PAGE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants.....................................F-2
Balance Sheets as of December 31, 1996 and 1995
and March 31, 1997 (unaudited)........................................F-3 - F-4
Statements of Income for the years ended
December 31, 1996, 1995 and 1994 and the
three months ended March 31, 1997 (unaudited)
and 1996 (unaudited)........................................................F-5
Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994 and the
three months ended March 31, 1997 (unaudited)
and 1996 (unaudited)........................................................F-6
Statements of Common Stockholder's Equity
for the years ended December 31, 1996,
1995 and 1994 and three months
ended March 31, 1997 (unaudited)............................................F-7
</TABLE>
F-1
<PAGE>
Report Of Independent Public Accountants
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying balance sheets of Western Massachusetts
Electric Company (a Massachusetts corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1996 and 1995, and the related
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 Western Massachusetts Electric
Company as of December 31, 1996 and 1995, and the results of its operations and
its 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>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
March 31,
1997 At December 31,
---------------- -----------------------------------
(Unaudited) 1996 1995
---------------- ---- ----
(Thousands of Dollars)
ASSETS
- ------
<S> <C> <C> <C>
Utility Plant, at original cost:
Electric...................................................... $ 1,261,681 $ 1,257,097 $ 1,234,738
Less: Accumulated provision for
depreciation (Note 1F)................................ 514,412 503,989 462,872
---------------- --------------- -----------------
747,269 753,108 771,866
Construction work in progress................................. 16,640 15,968 18,957
Nuclear fuel, net............................................. 30,470 30,296 31,574
---------------- --------------- -----------------
Total net utility plant..................................... 794,379 799,372 822,397
---------------- --------------- -----------------
Other Property and Investments:
Nuclear decommissioning trusts, at market..................... 86,720 83,611 69,903
Investments in regional nuclear generating
companies, at equity (Note 1E)............................... 15,845 15,448 14,820
Other, at cost................................................ 4,369 4,367 4,018
---------------- --------------- -----------------
106,934 103,426 88,741
---------------- --------------- -----------------
Current Assets:
Cash.......................................................... 47 67 202
Receivables, net.............................................. 37,911 40,168 42,164
Accounts receivable from affiliated companies................. 3,411 3,525 951
Accrued utility revenues...................................... 11,280 12,394 11,119
Fuel, materials, and supplies, at average cost................ 5,137 5,317 5,114
Recoverable energy costs, net--current portion................ 16,770 576 2,595
Prepayments and other......................................... 13,590 11,686 6,581
---------------- --------------- -----------------
88,146 73,733 68,726
---------------- --------------- -----------------
Deferred Charges:
Regulatory assets (Note 1H)................................... 182,007 210,852 160,986
Unamortized debt expense...................................... 1,785 1,866 1,496
Other......................................................... 510 888 -
---------------- --------------- -----------------
184,302 213,606 162,482
---------------- --------------- -----------------
---------------- --------------- -----------------
Total Assets............................................... $ 1,173,761 $ 1,190,137 $ 1,142,346
================ =============== =================
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
March 31,
1997 At December 31,
----------------- ---------------------------------------
(Unaudited) 1996 1995
----------------- ---- ----
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
- ------------------------------
<S> <C> <C> <C>
Capitalization:
Common stock--$25 par value. Authorized
and outstanding 1,072,471 shares........................... 26,812 $ 26,812 $ 26,812
Capital surplus, paid in................................... 150,976 150,911 150,182
Retained earnings.......................................... 79,413 97,045 115,296
----------------- ----------------- -----------------
Total common stockholder's equity................. 257,201 274,768 292,290
Preferred stock not subject to mandatory redemption........ 20,000 20,000 53,500
Preferred stock subject to mandatory redemption............ 19,500 21,000 22,500
Long-term debt............................................. 325,443 334,742 347,470
----------------- ----------------- -----------------
Total capitalization.............................. 622,144 650,510 715,760
----------------- ----------------- -----------------
Obligations Under Capital Leases (Note 8).................... 29,460 29,269 20,855
----------------- ----------------- -----------------
Current Liabilities:
Notes payable to banks..................................... 15,000 - -
Notes payable to affiliated companies...................... 75,900 47,400 24,050
Long-term debt and preferred stock--current portion........ 11,300 14,700 1,500
Obligations under capital leases--current
portion................................................... 2,965 2,965 15,156
Accounts payable........................................... 15,959 26,698 14,475
Accounts payable to affiliated companies................... 15,550 20,256 11,604
Accrued taxes.............................................. 7,581 881 1,686
Accrued interest........................................... 4,266 5,643 5,670
Nuclear compliance (Note 11B).............................. 6,550 11,800 -
Other...................................................... 3,178 4,754 7,768
----------------- ----------------- -----------------
158,249 135,097 81,909
----------------- ----------------- -----------------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)................ 237,168 245,253 259,595
Accumulated deferred investment tax credits................ 25,200 24,833 26,302
Deferred contractual obligations (Note 2).................. 79,651 84,598 18,814
Other...................................................... 21,889 20,577 19,111
----------------- ----------------- -----------------
363,908 375,261 323,822
----------------- ----------------- -----------------
Commitments and Contingencies (Note 11)
Total Capitalization and Liabilities.............. $ 1,173,761 $ 1,190,137 $ 1,142,346
================= ================= =================
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
For Three Months Ended
March 31, For the Years Ended December 31,
---------------------------- ---------------------------------------------------
1997 1996 1996 1995 1994
---- ---- ---- ---- ----
(Unaudited)
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Operating Revenues............................. $ 106,054 $ 114,797 $ 421,337 $ 420,434 $ 421,477
------------- ------------- --------------- --------------- ---------------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power. 40,974 25,820 115,664 86,738 67,365
Other..................................... 26,683 41,226 148,724 143,000 130,683
Maintenance.................................. 16,485 9,616 56,201 37,447 35,430
Depreciation................................. 10,182 9,785 39,710 37,924 36,885
Amortization of regulatory assets, net....... 1,615 3,018 9,170 19,562 29,118
Federal and state income taxes (Note 7)...... 793 6,085 5,995 14,060 32,653
Taxes other than income taxes................ 5,457 5,555 19,850 18,639 18,403
------------- ------------- --------------- --------------- ---------------
Total operating expenses............... 102,189 101,105 395,314 357,370 350,537
------------- ------------- --------------- --------------- ---------------
Operating Income............................... 3,865 13,692 26,023 63,064 70,940
------------- ------------- --------------- --------------- ---------------
Other Income:
Equity in earnings of regional nuclear
generating companies....................... 493 500 1,800 1,771 2,031
Other, net................................... 570 (87) 1,153 1,232 3,687
Income taxes................................. 72 178 1,068 262 (71)
------------- ------------- --------------- --------------- ---------------
Other income, net...................... 1,135 591 4,021 3,265 5,647
------------- ------------- --------------- --------------- ---------------
Income before interest charges......... 5,000 14,283 30,044 66,329 76,587
------------- ------------- --------------- --------------- ---------------
Interest Charges:
Interest on long-term debt................... 5,973 5,979 24,094 26,840 27,678
Other interest............................... 870 195 2,028 356 (548)
------------- ------------- --------------- --------------- ---------------
Interest charges, net.................. 6,843 6,174 26,122 27,196 27,130
------------- ------------- --------------- --------------- ---------------
============= ============= =============== =============== ===============
Net (Loss) Income.............................. $ (1,843) $ 8,109 $ 3,922 $ 39,133 $ 49,457
============= ============= =============== =============== ===============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
For the Three Months Ended
March 31, For the Years Ended December 31,
-------------------------- ----------------------------------------------
1997 1996 1996 1995 1994
---- ---- ---- ---- ----
(Unaudited)
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Operating Activities:
Net (Loss) Income........................................$ (1,843) $ 8,109 $ 3,922 $ 39,133 $ 49,457
Adjustments to reconcile to net cash
from operating activities:
Depreciation........................................... 10,182 9,785 39,710 37,924 36,885
Deferred income taxes and investment tax credits, net.. 1,252 (3,234) (3,439) 3,418 10,256
Deferred Millstone 3 return............................ - - - 7,146 13,427
Recoverable energy costs, net of amortization.......... 1,316 2,527 (10,517) 1,285 (8,622)
Nuclear compliance, net................................ (5,250) 7,105 11,800 - -
Deferred nuclear refueling outage, net of amortization. 2,206 (3,000) 6,188 (8,857) (1,016)
Other sources of cash.................................. 3,776 10,059 21,248 32,266 28,569
Other uses of cash..................................... (5,791) (2,790) (10,270) (8,039) (23,701)
Changes in working capital:
Receivables and accrued utility revenues............... 3,485 77 (1,853) (1,933) 6,470
Fuel, materials and supplies........................... 180 (120) (203) (285) 2,228
Accounts payable....................................... (15,445) (7,487) 20,875 (11,669) 8,239
Accrued taxes.......................................... 6,700 8,875 (805) (3,474) (1,862)
Other working capital (excludes cash).................. (4,857) (2) (8,144) 1,256 (2,991)
----------- ---------- ------------ ------------ -------------
Net cash flows (used for) from operating activities........ (4,089) 29,904 68,512 88,171 117,339
----------- ---------- ------------ ------------ -------------
Financing Activities:
Issuance of long-term debt............................... - - - - 90,000
Net increase (decrease) in short-term debt............... 43,500 (11,000) 23,350 24,050 (6,000)
Reacquisitions and retirements of long-term debt......... (14,700) - - (34,550) (104,169)
Reacquisitions and retirements of preferred stock........ - (1,500) (36,500) (15,675) (7,325)
Cash dividends on preferred stock........................ (785) (1,224) (5,305) (4,944) (5,897)
Cash dividends on common stock........................... (15,004) (8,987) (16,494) (30,223) (29,514)
----------- ---------- ------------ ------------ -------------
Net cash flows from (used for) financing activities........ 13,011 (22,711) (34,949) (61,342) (62,905)
----------- ---------- ------------ ------------ -------------
Investment Activities:
Investment in plant:
Electric utility plant................................. (6,056) (4,731) (23,468) (27,084) (32,680)
Nuclear fuel........................................... (30) (3) 541 75 (4,928)
----------- ---------- ------------ ------------ -------------
Net cash flows used for investments in plant............. (6,086) (4,734) (22,927) (27,009) (37,608)
NU System Money Pool..................................... - - - 8,750 (8,750)
Investment in nuclear decommissioning trusts............. (2,455) (2,231) (9,794) (8,503) (7,761)
Other investment activities, net......................... (401) (333) (977) 46 (395)
----------- ---------- ------------ ------------ -------------
Net cash flows used for investments........................ (8,942) (7,298) (33,698) (26,716) (54,514)
----------- ---------- ------------ ------------ -------------
Net (Decrease) Increase In Cash For The Period............. (20) (105) (135) 113 (80)
Cash - beginning of period................................. 67 202 202 89 169
----------- ---------- ------------ ------------ -------------
Cash - end of period.......................................$ 47 $ 97 $ 67 $ 202 $ 89
=========== ========== ============ ============ =============
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized..................... $ 21,725 $ 25,551 $ 25,174
============ ============ =============
Income taxes............................................. $ 7,816 $ 14,385 $ 30,040
============ ============ =============
Increase in obligations:
Niantic Bay Fuel Trust................................... $ 669 $ 7,851 $ 12,237
============ ============ =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
Capital Retained
Common Surplus, Earnings
Stock Paid In (a) Total
-------------- --------------- --------------- ---------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1994.............................. $ 26,812 $ 149,319 $ 97,627 $ 273,758
Net income for 1994................................. 49,457 49,457
Cash dividends on preferred stock................... (5,897) (5,897)
Cash dividends on common stock...................... (29,514) (29,514)
Loss on the retirement of preferred stock........... (87) (87)
Capital stock expenses, net......................... 364 364
-------------- --------------- --------------- ---------------
Balance at December 31, 1994............................ 26,812 149,683 111,586 288,081
Net income for 1995................................. 39,133 39,133
Cash dividends on preferred stock................... (4,944) (4,944)
Cash dividends on common stock...................... (30,223) (30,223)
Loss on the retirement of preferred stock........... (256) (256)
Capital stock expenses, net......................... 499 499
-------------- --------------- --------------- ---------------
Balance at December 31, 1995............................ 26,812 150,182 115,296 292,290
Net income for 1996................................. 3,922 3,922
Cash dividends on preferred stock................... (5,305) (5,305)
Cash dividends on common stock...................... (16,494) (16,494)
Loss on the retirement of preferred stock........... (374) (374)
Capital stock expenses, net......................... 729 729
-------------- --------------- --------------- ---------------
Balance at December 31, 1996............................ 26,812 150,911 97,045 274,768
Net loss for three months ended March 31, 1997...... (1,843) (1,843)
Cash dividends on preferred stock................... (785) (785)
Cash dividends on common stock...................... (15,004) (15,004)
Capital stock expenses, net......................... 65 65
-------------- --------------- --------------- ---------------
Balance at March 31, 1997 (unaudited)................... $ 26,812 $ 150,976 $ 79,413 $ 257,201
============== =============== =============== ===============
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At March 31, 1997 and December 31, 1996, these restrictions
totaled approximately $21.5 million.
The accompanying notes are an integral part of these financial statements.
F-7
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About Western Massachusetts Electric Company
Western Massachusetts Electric Company (WMECO or the company), The
Connecticut Light and Power Company (CL&P), 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 retail electric service in Connecticut, New
Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and
HWP. The fifth subsidiary, NAEC, sells all of its capacity to PSNH. In
addition to its retail service, the system furnishes firm and other
wholesale electric services to various municipalities and other
utilities. 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 an agent for system companies in operating the
Millstone nuclear generating facilities.
B. Presentation
General: 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.
Certain reclassifications of prior periods' data have been made to
conform with the current period's presentation.
F-8
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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 March 31,
1997, the results of operations for the three-month periods ended
March 31, 1997 and 1996, and the statements of cash flows for the
three-month periods ended March 31, 1997 and 1996. All adjustments are
of a normal, recurring, nature except those described below in Note
11B. The results of operations for the three-month periods ended March
31, 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 Massachusetts Department of Public Utilities (DPU).
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.
F-9
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
See Note 10, "Sale of Customer Receivables," and Note 11C,
"Commitments and Contingencies-Environmental Matters," for information
on newly issued accounting and reporting standards related to those
specific areas.
The FASB issued SFAS No. 129, "Disclosure of Information about Capital
Structure" in February 1997. SFAS 129 will be effective for 1997 year-
end reporting. Management believes that the implementation of SFAS 129
will not have a material impact on WMECO's financial position or its
results of operations.
E. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: WMECO owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with the company's ownership interests, are:
<TABLE>
<S> <C>
Connecticut Yankee Atomic Power Company (a) (CY)................. 9.5%
Yankee Atomic Electric Company (a) (YAEC)........................ 7.0
Maine Yankee Atomic Power Company (MY)........................... 3.0
Vermont Yankee Nuclear Power Corporation (VY).................... 2.5
</TABLE>
(a) YAEC's and CY's nuclear power plants were shut down permanently
on February 26, 1992 and December 4, 1996, respectively.
WMECO'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.
WMECO's investments in the Yankee companies at December 31, 1996 are:
<TABLE>
<CAPTION>
(Thousands of Dollars)
<S> <C>
Connecticut Yankee Atomic Power Company....................... $10,165
Yankee Atomic Electric Company................................ 1,673
Maine Yankee Atomic Power Company............................. 2,247
Vermont Yankee Nuclear Power Corporation...................... 1,363
-------
$15,448
=======
</TABLE>
F-10
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited).
The electricity produced by MY and VY is committed substantially on
the basis of ownership interests and is billed pursuant to contractual
agreements. Under ownership agreements with the Yankee companies,
WMECO 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 2, "Nuclear Decommissioning" and Note 11B,
"Commitments and Contingencies - Nuclear Performance."
Millstone 1: WMECO has a 19 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
$90.2 million and $87.4 million, respectively, and the accumulated
provision for depreciation included approximately $37.2 million and
$34.5 million, respectively, for WMECO's share of Millstone 1. WMECO's
share of Millstone 1 expenses is included in the corresponding
operating expenses on the accompanying Statements of Income.
Millstone 2: WMECO has a 19 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 $161.4 million
and $160.0 million, respectively, and the accumulated provision for
depreciation included approximately $51.7 million and $45.8 million,
respectively, for WMECO's share of Millstone 2. WMECO's share of
Millstone 2 expenses is included in the corresponding operating
expenses on the accompanying Statements of Income.
Millstone 3: WMECO has a 12.24 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 $377.7 million
and the accumulated provision for depreciation included approximately
$99.8 million and $90.6 million, respectively, for WMECO's share of
Millstone 3. WMECO's share of Millstone 3 expenses is included in the
corresponding operating expenses on the accompanying Statements of
Income.
For more information regarding the Millstone units, see Note 11B,
"Commitments and Contingencies - Nuclear Performance."
F-11
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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 3.2 percent in 1996 and
3.1 percent in 1995 and 1994. See Note 2, "Nuclear Decommissioning,"
for information on nuclear plant decommissioning.
WMECO's non-nuclear 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 $3.2 million accrued for the cost
of removal, net of salvage for non-nuclear generation property.
G. Revenues
Other than revenues under fixed-rate agreements negotiated with
certain wholesale, industrial and commercial customers, utility
revenues are based on authorized rates applied to each customer's use
of electricity. In general, rates can be changed only through a formal
proceeding before the appropriate regulatory commission. At the end of
each accounting period, WMECO accrues an estimate for the amount of
energy delivered but unbilled.
H. Regulatory Accounting and Assets
The accounting policies of WMECO and the accompanying 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
F-12
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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, WMECO 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 March 31, 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 electric utility industry or if the
cost-of-service based regulatory structure were to change.
F-13
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The components of WMECO's regulatory assets are as follows:
<TABLE>
<CAPTION>
March 31, December 31,
1997 1996 1995
---- ---- ----
(Unaudited)
(Thousands of Dollars)
<S> <C> <C> <C>
Income taxes, net (Note 1I) $ 67,542 $ 71,519 $ 87,829
Unrecovered contractual obligations
(Note 2) 79,651 84,598 18,814
Amortizable property investment -
Millstone 3 - - 5,600
Recoverable energy costs (Note 1J) - 17,510 4,974
Other 34,814 37,225 43,769
-------- -------- --------
$182,007 $210,852 $160,986
======== ======== ========
</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, WMECO established a regulatory asset. See Note 7,
"Income Tax Expense" for the components of income tax expense.
F-14
<PAGE>
Western Massachusetts Electric Company
NOTES TO 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>
March 31, December 31,
1997 1996 1995
---- ---- ----
(Unaudited)
(Thousands of Dollars)
<S> <C> <C> <C>
Accelerated depreciation and
other plant-related differences $217,950 $218,389 $222,520
Regulatory assets -
income tax gross up 28,747 29,457 34,540
Other (9,529) (2,593) 2,535
-------- -------- --------
$237,168 $245,253 $259,595
======== ======== ========
</TABLE>
J. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), WMECO 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. WMECO is currently recovering these costs through rates. As of
March 31, 1997 and December 31, 1996, the company's total D&D
deferrals were approximately $11 million.
For additional information regarding recoverable energy costs see the
MD&A.
K. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, WMECO 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
F-15
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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 $37.1 million, including interest
costs of $21.5 million. At March 31, 1997, fees due to the DOE for
the disposal of prior-period fuel were approximately $37.5 million,
including interest costs of $21.9 million. As of March 31, 1997, all
fees had been collected through rates.
2. NUCLEAR DECOMMISSIONING
WMECO's nuclear power plants have service lives that are expected to end
during the years 2010 through 2025. Upon retirement, these units must be
decommissioned. The company's 1996 decommissioning study concluded that
complete and immediate dismantlement at retirement continues to be the most
viable and economic method of decommissioning the three Millstone units.
Decommissioning studies are reviewed and updated periodically to reflect
changes in decommissioning requirements, costs, technology and inflation.
The estimated cost of decommissioning WMECO's ownership share of Millstone
1, 2, and 3, in year-end 1996 dollars, is $74.1 million, $65.5 million, and
$56.6 million, respectively. The Millstone units 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 Statements of Income.
Nuclear decommissioning costs amounted to $6.2 million in 1996, $5.0
million in 1995, and $4.8 million in 1994. Nuclear decommissioning, as a
cost of removal, is included in the accumulated provision for depreciation
on the Balance Sheets. At March 31, 1997 and December 31, 1996, the balance
in the accumulated reserve for decommissioning amounted to $86.7 million
and $83.6 million, respectively.
WMECO has established external decommissioning trusts through a trustee for
its portion of the costs of decommissioning Millstone 1, 2, and 3. Funding
of the estimated decommissioning costs assumes levelized collections for
the Millstone units and after-tax earnings on the Millstone decommissioning
funds of 5.8 percent.
F-16
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
As of March 31, 1997 and December 31, 1996, WMECO has collected, through
rates, $55.1 million and $53.5 million, respectively, toward the future
decommissioning costs of its share of the Millstone units, all of which has
been transferred to external decommissioning trusts. Earnings on the
decommissioning trusts increase the decommissioning trust balance and the
accumulated reserve for decommissioning. Unrealized gains and losses
associated with the decommissioning trusts also impact the balance of the
trusts 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. WMECO 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 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 trusts will be substantially funded when the units are
retired from service.
MY and VY: Each Yankee company owns a single nuclear generating unit. MY
and VY have service lives that are expected to end in 2008 and 2012,
respectively. The estimated cost, in year-end 1996 dollars, of
decommissioning WMECO's ownership share of units owned and operated by MY
and VY is $11.1 million and $9.1 million, respectively. Under the terms of
the contracts with the Yankee companies, the shareholder-sponsors are
responsible for their proportionate share of the operating costs of each
unit, including decommissioning. The nuclear decommissioning costs of the
Yankee companies are included as part of the cost of power purchased by
WMECO.
On May 27, 1997, MY announced that it was considering permanent closure of
the plant based on economic concerns and uncertainty about the operation of
the plant. MY disclosed that it would reduce spending to a level that would
preserve the option of restarting the plant or closing it.
For further information on MY, see Note 11B, "Commitments and
Contingencies - Nuclear Performance."
CY and YAEC: On December 4, 1996, the board of directors of CY voted
unanimously to cease permanently the production of power at its nuclear
plant. The system companies relied on CY for approximately 3 percent of
their capacity.
F-17
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
CY has undertaken a number of regulatory filings intended to implement the
decommissioning and the recovery of remaining assets of CY. During late
December, 1996, CY 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 WMECO's share was
approximately $72.5 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 refund. At March 31, 1997, WMECO's share of the CY unrecovered
contractual obligation, which also has been recorded as a regulatory asset,
was $68.4 million.
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 the company's share was approximately
$12.1 million. At March 31, 1997, WMECO's share of the YAEC unrecovered
obligation was approximately $11.3 million.
Management expects that WMECO will continue to be allowed to recover these
costs from its customers. Accordingly, WMECO has recognized these costs as
regulatory assets, with corresponding obligations, on its 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.
F-18
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
3. SHORT-TERM DEBT
Limits: The amount of short-term debt borrowings that may be incurred by
WMECO is subject to periodic approval by either the SEC under the 1935 Act
or by its state regulator. In addition, the charter of WMECO contains
provisions restricting the amount of short-term debt borrowings. Under the
SEC and/or charter restrictions, WMECO was authorized, as of January 1,
1997, to incur short-term borrowings up to a maximum of $150 million.
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 March 31, 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. NU, CL&P and WMECO are currently
maintaining their access to the New Credit Agreement under an interim
written arrangement, under which NU agreed not to borrow more than $27.5
million against the facility.
On May 30, 1997, the First Amendment and Waiver became effective, replacing
the 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.
F-19
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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 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 all of which had been borrowed by other
system companies. At March 31, 1997, there were $11.3 million in borrowings
under the facility of which WMECO had no borrowings.
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.
Maturities of WMECO's short-term debt obligations are for periods of three
months or less.
Money Pool: Certain subsidiaries of NU, including WMECO, 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 March 31, 1997 and December
31, 1996 and 1995, WMECO had $75.9 million, $47.4 million, and $24.1
million, respectively, of borrowings outstanding from the Pool. The
interest rate on borrowings from the Pool at March 31, 1997 and December
31, 1996 and 1995 were 7.1 percent, 6.3 percent, and 4.7 percent,
respectively.
For further information on short-term debt see the MD&A.
F-20
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
4. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
<TABLE>
<CAPTION>
December Shares
31, 1996 Outstanding March 31, December 31
Redemption at 3/31/97 1997 -----------
Description Price and 12/31/96 (Unaudited) 1996 1995 1994
----------- ----- -------- --------- ---- ---- ----
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
7.72% Series B of 1971 $103.51 200,000 $20,000 $20,000 $20,000 $20,000
1988 Adjustable Rate
DARTS - - - - 33,500 48,500
------- ------- ------- -------
Total preferred stock not
subject to mandatory
redemption $20,000 $20,000 $53,500 $68,500
======= ======= ======= =======
</TABLE>
All or any part of each outstanding series of preferred stock may be
redeemed by the company at any time at established redemption prices
plus accrued dividends to the date of redemption.
F-21
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
5. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
<TABLE>
<CAPTION>
December 31, Shares Shares March 31, December 31
1996 Redemption Outstanding Outstanding 1997 -----------
Description Price* at 3/31/97 at 12/31/96 (Unaudited) 1996 1995 1994
----------- ----- ---------- ----------- ----------- ---- ---- ----
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
7.60% Series of
1987 $25.76 840,000 840,000 $21,000 $21,000 $24,000 $24,675
Less preferred stock
to be redeemed
within one year,
net of reacquired
stock 60,000 - 1,500 - 1,500 675
------- ------- ------- -------
Total preferred
stock subject to
mandatory
redemption $19,500 $21,000 $22,500 $24,000
======= ======= ======= =======
</TABLE>
*Redemption price reduces in future years.
The minimum sinking-fund provisions of the 1987 Series subject to
mandatory redemption at December 31, 1996, for the years 1997 through
2001, are $0 in 1997 and $1.5 million per year for 1998 through 2001.
In case of default on sinking-fund payments, no payments may be made on
any junior stock by way of dividends or otherwise (other than in shares
of junior stock) so long as the default continues. If 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
purchase of less than all of the preferred stock outstanding. All or
part of the 7.60% Series of 1987 may be redeemed by the company at any
time at an established redemption price plus accrued dividends to the
date of redemption subject to certain refunding limitations.
F-22
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
6. LONG-TERM DEBT
Details of long-term debt outstanding are:
<TABLE>
<CAPTION>
March 31, December 31,
1997 1996 1995
----------- ----------------------
(Unaudited)
(Thousands of Dollars)
<S> <C> <C> <C>
First Mortgage Bonds:
5 3/4% Series F, due 1997 $ - $ 14,700 $ 14,700
6 3/4% Series G, due 1998 9,800 9,800 9,800
6 1/4% Series X, due 1999 40,000 40,000 40,000
6 7/8% Series W, due 2000 60,000 60,000 60,000
7 3/4% Series V, due 2002 85,000 85,000 85,000
7 3/4% Series Y, due 2024 50,000 50,000 50,000
--------- --------- ---------
Total First Mortgage Bonds 244,800 259,500 259,500
Pollution Control Notes:
Tax exempt Series A, due 2028 53,800 53,800 53,800
Fees and interest due for spent fuel
disposal costs (Note 1K) 37,532 37,055 35,180
Less: amounts due within one year 9,800 14,700 -
Unamortized premium and discount, net (889) (913) (1,010)
--------- --------- ---------
Long-term debt, net $ 325,443 $ 334,742 $ 347,470
========= ========= =========
</TABLE>
F-23
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1996 for the years 1997 through 2001 are
approximately $14.7 million, $9.8 million, $40 million, $60 million,
and $0 million, respectively. In addition, there are annual one-percent
sinking- and improvement-fund requirements, currently amounting to $2.6
million for 1997, $2.4 million for 1998 and 1999, $2.0 million for
2000, and $1.4 million for 2001. Such sinking- and improvement-fund
requirements may be satisfied by the deposit of cash or bonds 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 $53.8 million of pollution control notes with
second mortgage liens on Millstone 1, junior to the liens of its first
mortgage bond indenture. The average effective interest rate on the
variable-rate pollution control notes was 3.3 percent for 1996 and 3.7
percent for 1995.
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-24
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
7. INCOME TAX EXPENSE
The components of the federal and state income tax provisions charged
to operations are:
<TABLE>
<CAPTION>
Three Months Ended For the Years Ended
March 31, December 31,
1997 1996 1996 1995 1994
---- ---- ---- ---- ----
(Unaudited)
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Current income taxes:
Federal $(531) $7,571 $7,007 $7,419 $18,358
State - 1,570 1,358 2,961 4,110
------ ------ ------ ------- -------
Total current (531) 9,141 8,365 10,380 22,468
------ ------ ------ ------- -------
Deferred income taxes, net:
Federal 695 (2,429) (1,805) 4,130 9,697
State 190 (438) (165) 1,003 2,267
------ ------ ------ ------- -------
Total deferred 885 (2,867) (1,970) 5,133 11,964
------ ------ ------ ------- -------
Investment tax credits,
net 367 (367) (1,468) (1,715) (1,708)
------ ------ ------ ------- -------
Total income tax
expense $721 $5,907 $4,927 $13,798 $32,724
====== ====== ====== ======= =======
<CAPTION>
The components of total income tax expense are classified as follows:
<S> <C> <C> <C> <C> <C>
Income taxes charged
to operating expenses $793 $6,085 $5,995 $14,060 $32,653
Other income taxes (72) (178) (1,068) (262) 71
------ ------ ------ ------- -------
Total income tax
expense $721 $5,907 $4,927 $13,798 $32,724
====== ====== ====== ======= =======
</TABLE>
F-25
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
<TABLE>
<CAPTION>
Three Months Ended For the Years Ended
March 31, 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 $ 317 $ (193) $ 32 $ 9,066 $ 7,016
Energy adjustment clause (923) (971) 4,102 (1,549) 3,598
Expenses associated with
nuclear outages 2,060 - (4,633) - -
Demand-side management 261 (1,110) 1,557 (1,184) 466
Nuclear plant deferrals (802) (245) (2,258) 2,468 (1,802)
Bond redemptions (125) (126) (502) (572) 1,535
Other 97 (222) (268) (3,096) 1,151
------ ------- ------- ------- -------
Deferred income taxes, net $ 885 $(2,867) $(1,970) $ 5,133 $11,964
====== ======= ======= ======= =======
</TABLE>
F-26
<PAGE>
Western Massachusetts Electric Company
NOTES TO 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>
Three Months Ended For the Years Ended
March 31, 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 $(418) $4,905 $2,946 $18,526 $28,763
Tax effect of differences:
Depreciation 377 1,059 2,280 2,173 1,740
Amortization of regulatory
assets 479 - 1,029 1,665 3,347
Investment tax credit
amortization 367 (367) (1,468) (1,715) (1,708)
State income taxes, net of
federal benefit 124 736 776 2,577 4,144
Adjustment for prior years'
taxes - - - (7,702) (825)
Bad debt 123 (59) (38) 69 135
Dividends received reduction (43) (122) (378) (481) (520)
Other, net (288) (245) (220) (1,314) (2,352)
----- ------ ------ ------- -------
Total income tax expense $721 $5,907 $4,927 $13,798 $32,724
===== ====== ====== ======= =======
</TABLE>
F-27
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
8. LEASES
WMECO and CL&P 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. WMECO
and CL&P 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 WMECO and CL&P.
WMECO has also entered into lease agreements for the use of data
processing and office equipment, vehicles, nuclear control room
simulators and office space. The provisions of these lease agreements
generally provide for renewal options. The following rental payments
have been charged to expense:
Year Capital Leases Operating Leases
---- -------------- ----------------
1996 $ 3,598,000 $6,410,000
1995 12,553,000 6,398,000
1994 13,594,000 6,485,000
Interest included in capital lease rental payments was $1,858,000 in
1996, $1,954,000 in 1995, and $1,845,000 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-28
<PAGE>
Western Massachusetts Electric Company
NOTES TO 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:
Year Operating Leases
---- ----------------
(Thousands of Dollars)
1997 $ 4,500
1998 3,500
1999 3,200
2000 3,000
2001 2,700
After 2001 24,500
-------
Future minimum lease payments $41,400
=======
Certain operating lease payments related to NUSCO leases may be
accelerated from future years into 1997. See Note 11G, "The Rocky River
Realty Company - Obligations" for additional information.
F-29
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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
charged to utility plant, approximated $2.0 million in 1996, $2.7
million in 1995 and $1.0 million in 1994. The company's pension costs
for 1996, 1995 and 1994 included approximately $1.0 million, $0
million, and $0.8 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.
The components of net pension cost for WMECO are:
<TABLE>
<CAPTION>
For the Years Ended December 31
1996 1995 1994
---- ---- ----
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost $ 2,932 $ 1,645 $ 2,720
Interest cost 7,786 7,757 7,655
Return on plan assets (22,174) (29,798) 221
Net amortization 9,458 17,669 (11,635)
-------- -------- --------
Net pension income $ (1,998) $ (2,727) $ (1,039)
======== ======== ========
</TABLE>
F-30
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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 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 $85,094,000 and
$84,943,000, respectively $91,170 $90,154
======= =======
Projected benefit obligation $107,816 $107,527
Market value of plan assets 157,863 143,632
------- -------
Market value in excess of
projected benefit obligation 50,047 36,105
Unrecognized transition amount (1,963) (2,198)
Unrecognized prior service costs 1,213 (525)
Unrecognized net gain (46,486) (32,570)
-------- ---------
Prepaid pension asset $ 2,811 $ 812
======== =========
</TABLE>
F-31
<PAGE>
Western Massachusetts Electric Company
NOTES TO 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. WMECO's direct portion of SFAS
106 benefits, part of which were deferred or charged to utility plant,
approximated $3.8 million in 1996, $4.4 million in 1995, and $5.0
million in 1994.
During 1994, the company began funding 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.
F-32
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The components of health care and life insurance costs are:
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1996 1995 1994
---- ---- ----
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost $490 $490 $519
Interest cost 2,236 2,544 2,703
Return on plan assets (883) (718) 19
Amortization of unrecognized transition
obligation 1,641 1,641 1,641
Other amortization, net 353 473 76
------ ------- ------
Net health care and life insurance costs $3,837 $4,430 $4,958
====== ====== ======
</TABLE>
For calculating WMECO's 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 or return - 5.25 5.00 5.00
Health assets, net of tax
Life assets 8.75 8.50 8.50
</TABLE>
F-33
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
The following table represents the plan's funded status reconciled to the
Balance Sheets:
<TABLE>
<CAPTION>
At December 31,
---------------
1996 1995
---- ----
(Thousands of Dollars)
<S> <C> <C>
Accumulated postretirement benefit obligation of:
Retirees $ 24,614 $ 28,787
Fully eligible active employees 28 28
Active employees not eligible to retire 5,449 5,847
-------- --------
Total accumulated postretirement benefit obligation 30,091 34,662
Market value of plan assets 10,215 5,339
-------- --------
Accumulated postretirement benefit obligation in
excess of plan assets (19,876) (29,323)
Unrecognized transition amount 26,259 27,901
Unrecognized net gain (6,765) (1,399)
-------- --------
Accrued postretirement benefit liability $ (382) $ (2,821)
======== ========
</TABLE>
F-34
<PAGE>
Western Massachusetts Electric Company
NOTES TO 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%
Health care cost trend rate (a) 7.23 8.40
</TABLE>
(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 $1.8 million and the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for the year then ended by $0.2 million. The
trust holding the health plan assets is subject to federal income taxes at
a 39.6 percent tax rate.
WMECO is currently recovering SFAS 106 costs.
10. SALE OF CUSTOMER RECEIVABLES
In September 1996, WMECO entered into a five-year agreement to sell up to
$40 million of eligible billed and unbilled customer accounts receivable.
The eligible receivables are sold with limited recourse. The company has
retained collection responsibilities for receivables which have been sold
under the agreement. As collections reduce previously sold undivided
interests, new receivables would routinely be sold. The agreement provides
for a loss reserve determined by a formula which reflects credit exposure.
As of March 31, 1997, WMECO had sold approximately $15 million of its
accounts receivable under the agreement, which was accounted for as a
secured borrowing.
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
F-35
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
financial assets in exchange for consideration should be accounted for as a
sale or as a secured borrowing.
During May 1997, WMECO restructured its sales agreement to comply with the
requirements of SFAS 125. WMECO's sales of its receivables are now
accounted for as a sale. Consistent with the prior agreement, new undivided
interests in receivables may be sold, when collections reduce previously
sold undivided interests.
SFAS 125 required, in part, that WMECO establish a special-purpose, wholly
owned subsidiary, WMECO Receivables Corporation (WRC). WRC's sole purpose
is to purchase receivables from WMECO and, at times, resell undivided
ownership interests in those receivables to a third party purchaser. All
eligible receivables transferred to WRC are assets owned by WRC.
F-36
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
11. COMMITMENTS AND CONTINGENCIES
A. Restructuring
Although WMECO 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 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. The company has restructured
its nuclear organization and is currently implementing comprehensive
plans to restart the units.
Millstone 3 has been designated 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 work on the restart of Millstone 1 will be reduced until late in
1997 when the full work effort will be resumed.
Management believes that Millstone 3 will be ready for restart around
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 is ready for restart by that time. Management hopes that
Millstone 3 can begin operating by the end of 1997.
F-37
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
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. WMECO expensed approximately $33 million of
incremental nonfuel nuclear operation and maintenance costs (O&M) in
1996, including a reserve of $12 million against 1997 expenditures.
Management estimates WMECO will expense approximately $73 million of
nonfuel nuclear O&M costs in 1997.
Based on a recent review of the work efforts and budgets, management
believes that the overall 1997 nuclear spending levels - both nuclear
operations and maintenance (O&M) expenditures and associated support
services and capital expenditures - will be slightly higher than
previously estimated. 1997 nuclear O&M expenditures and related
support services are expected to increase, while 1997 capital
expenditures are expected to decrease. Management also believes that
it is possible that 1997 nuclear spending will increase somewhat as
the detailed work needed to restore the units to service progresses.
WMECO expensed approximately $17 million of non-fuel nuclear operation
and maintenance costs in the first quarter of 1997. An additional $5.3
million was expended in the first quarter of 1997 and charged against
the reserve established in 1996. The balance of the reserve at March
31, 1997 was $7 million.
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. A portion of the increased nuclear O&M
expenditures in 1997 will be reserved in the second quarter of 1997.
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 WMECO will ultimately
incur. Replacement power costs incurred by WMECO which are
attributable to the Millstone outages averaged approximately $6
million per month during the first quarter of 1997, and are projected
to average approximately $5 million per month for the remainder of
1997. Management believes the system has sufficient resources to fund
the restoration of the Millstone units to service under its present
timetable.
MY: The system companies rely on MY for approximately two percent of
their capacity. The MY nuclear generating plant has been limited to
operating at 90
F-38
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
percent of capacity since early 1996, pending the resolution
of issues related to investigations initiated by the NRC, and
on December 6, 1996, was taken off line to resolve
cable-separation and associated issues. The NRC has notified
MY that the NRC staff has placed the MY plant on its watch
list. Returning the plant to service would require NRC
approval. Management cannot predict if or when MY's plant will
be allowed to return to service. The owners of MY are
evaluating a range of options, including closure of the plant,
with respect to MY's future operations, and have curtailed
expenditures pending resolution of this evaluation.
Potential Litigation: The non-NU owners of Millstone 3 have
been paying their share of the monthly costs for Millstone 3
since the unit went out of service in March, 1996, but have
reserved their rights to contest whether the NU system
companies have any responsibility for the additional costs the
non-NU owners have borne as a result of the current outage. No
formal claims have been made, but management believes that it
is possible that some or all of the non-NU owners will assert
liability on the part of the NU system. CL&P and WMECO,
through NNECO as agent, operate Millstone 3 at cost, and
without profit, under a Sharing Agreement that obligates them
to utilize good utility operating practice and requires the
joint owners to share the risk of employee negligence and
other risks pro rata in accordance with their ownership
shares. The Sharing Agreement provides that CL&P and WMECO
would only be liable for damages to the non-NU owners for a
deliberate breach of the Sharing Agreement. At December 31,
1996, the costs related to this potential litigation were
estimated to be $2.5 million for incremental O&M costs and to
be between $8 million and $10 million for replacement power
costs. At March 31, 1997, the costs related to the potential
litigation were estimated to be $3 million for incremental O&M
costs and between $11 million and $13 million for replacement
power costs. These costs are likely to increase as long as
Millstone 3 remains out of service. NU will vigorously contest
such suits if they are brought.
C. Environmental Matters
WMECO 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.
WMECO 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
F-39
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
environmental requirements could also require extensive and
costly modifications to WMECO's existing generating units, and
transmission and distribution systems, and could raise
operating costs significantly. As a result, WMECO 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. WMECO 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.
WMECO 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 WMECO for its estimated environmental remediation
costs, excluding any possible insurance recoveries or
recoveries from third parties, amounted to approximately $1.4
million, which management has determined to be the most
probable amount within the range of $1.4 million to $5.9
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 $450 thousand increase to WMECO's environmental
reserves.
At March 31, 1997, WMECO's net liability recorded for its
estimated environmental remediation costs, excluding any
possible insurance recoveries or recoveries from third
parties, amounted to approximately $1.9 million, which
management has determined to be the most probable amount
within the range of $1.9 million to $4.2 million.
F-40
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
WMECO 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 WMECO'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 million per nuclear unit in any one year.
Based on its ownership interest in Millstone 1, 2, and 3,
WMECO's maximum liability including any additional potential
assessments, would be $39.8 million per incident. In addition,
through power purchase contracts with MY, VY and CY, WMECO
would be responsible for up to an additional $11.9 million per
incident. Payments for WMECO's ownership interest in nuclear
generating facilities would be limited to a maximum of $6.5
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. WMECO is subject to
retroactive assessments if losses exceed the accumulated funds
available to the insurer. The maximum potential assessment
against WMECO with respect to losses arising during the
current policy year is approximately $2.5 million under the
primary property insurance program. Based on the most recent
renewal, the maximum potential assessment against WMECO with
respect to losses arising during the current policy year is
approximately $2.7 million under the primary property
insurance program at March 31, 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. WMECO 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 $2.0 million
under the replacement power policies and $4.9 million under
the excess property damage, decontamination and
decommissioning policies. The cost of a nuclear incident could
exceed available insurance proceeds.
F-41
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
Insurance has been purchased aggregating $200 million on an
industry basis for coverage of worker claims. All
participating reactor operators insured under this coverage
are subject to retrospective assessments of $3.0 million per
reactor. The maximum potential assessment against WMECO with
respect to losses arising during the current policy period is
approximately $2.2 million.
E. Construction Program
The construction program is subject to periodic review and
revision by management. WMECO currently forecasts construction
expenditures of approximately $169 million for the years
1997-2001, including $37 million for 1997. In addition, the
company estimates that nuclear fuel requirements, including
nuclear fuel financed through the NBFT, will be approximately
$54.1 million for the years 1997-2001, including $2.4 million
for 1997. See Note 8, "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 $37 million to $31 million.
F. Long-Term Contractual Arrangements
Yankee Companies: WMECO along with CL&P and PSNH, relies 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 purchased power expense
and recovered through the company's rates. WMECO's total cost
of purchases under these contracts with the Yankee companies
excluding YAEC, amounted to $28.3 million in 1996, $28.9
million in 1995, and $28.8 million in 1994. See Note 1E,
"Summary of Significant Accounting Policies-Investments and
Jointly Owned Electric Utility Plant," and Note 2, "Nuclear
Decommissioning" for more information on the Yankee companies.
Nonutility Generators (NUG): WMECO, along with CL&P and PSNH,
has entered into various arrangements for the purchase of
capacity and energy from NUGs. These arrangements have terms
form 15 to 25 years, currently expiring in the years 2008
through 2013, and requires WMECO to purchase energy at
specified prices or formula rates. For the 12 months ended
December 31, 1996, approximately 13
F-42
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
percent of system electricity requirements were met by NUGs.
WMECO's total cost of purchases under these arrangements
amounted to $29.5 million in 1996, $28.6 million in 1995, and
$27.5 million in 1994. These costs are eventually recovered
through the company's rates.
Hydro-Quebec: Along with other New England utilities, WMECO,
CL&P, PSNH and HWP have entered into agreements to support
transmission and terminal facilities to import electricity
from the Hydro-Quebec system in Canada. WMECO 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 the WMECO'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>
MY and VY $10.4 $ 8.9 $10.5 $10.4 $ 9.5
Nonutility generators 33.0 35.0 37.0 39.0 42.0
Hydro-Quebec 3.9 3.8 3.7 3.6 3.5
</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 approximately $38 million are 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 NUSCO as lessee. The leases provide for the
acceleration of rent equal to RRR's note obligations when RRR
repurchases the notes. The operating companies, primarily
CL&P, WMECO and PSNH may be billed by NUSCO for their
proportionate share of the accelerated lease obligations. NU
has guaranteed the notes.
F-43
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
In April 1997, the holders of approximately $38 million of
RRR's notes elected to have RRR repurchase the notes at par.
On July 1, 1997, RRR received a commitment from an alternative
purchaser to purchase approximately $12 million of the notes
that RRR had been required to repurchase. RRR repurchased the
remaining $26 million of the notes on July 14, 1997.
Management does not expect the resolution of this matter to
have a material adverse impact on its financial condition or
liquidity.
F-44
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
12. 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 trust were
adjusted to market by approximately $8.4 million as of December 31,
1996 and by approximately $4.5 million as of December 31, 1995, with a
corresponding offset 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 WMECO's
fixed-rate securities is based upon the quoted market price for those
issues or similar issues. Adjustable rate securities are assumed to
have a fair value equal to their carrying value.
The carrying amount of WMECO'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 $ 20,000 $ 15,200
Preferred stock subject to mandatory redemption 21,000 18,404
Long-term debt - First Mortgage Bonds 259,500 260,440
Other long-term debt 90,855 90,855
</TABLE>
F-45
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
<TABLE>
<CAPTION>
Carrying Fair
At December 31, 1995 Amount Value
- -------------------- ------ -----
(Thousands of Dollars)
<S> <C> <C>
Preferred stock not subject to mandatory redemption $ 53,500 $ 53,700
Preferred stock subject to mandatory redemption 24,000 25,085
Long-term debt - First Mortgage Bonds 259,500 265,280
Other long-term debt 88,980 88,980
</TABLE>
The fair values shown above have been reported to meet the
disclosure requirements and do not purport to represent the amounts at
which those obligations would be settled.
F-46
<PAGE>
Western Massachusetts Electric Company
NOTES TO FINANCIAL STATEMENTS
-----------------------------
(Information Subsequent to December 31, 1996 is Unaudited)
STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited)
- --------------------------------------------------
<TABLE>
<CAPTION>
Quarter Ended (a)
-----------------
1996 March 31 June 30 Sept. 30 Dec. 31
- ---- -------- ------- -------- -------
<S> <C> <C> <C> <C>
Operating Revenues................................ $114,797 $102,602 $99,866 $104,072
======== ======== ======= ========
Operating Income (Loss)........................... $13,692 $9,377 $4,327 $(1,373)
======= ====== ====== ========
Net Income (Loss)................................. $8,109 $4,016 $(396) $(7,807)
====== ====== ====== ========
1995
- ----
Operating Revenues................................ $106,684 $100,593 $107,960 $105,197
======== ======== ======== ========
Operating Income ................................. $18,085 $8,977 $19,799 $16,203
======= ====== ======= =======
Net Income ....................................... $12,076 $3,289 $14,141 $9,627
======= ====== ======= ======
</TABLE>
(a) Reclassifications of prior data have been made to conform to the
current presentation.
F-47
