NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NORTH ATLANTIC ENERGY CORPORATION
1994 Form 10-K Annual Report
Table of Contents
PART I
Page
Item 1. Business. . . . . . . . . . . . . . . . . . . 1
The Northeast Utilities System . . . . . . . . . . 1
Public Utility Regulation. . . . . . . . . . . . . 2
Competition and Marketing. . . . . . . . . . . . . 2
The Economy . . . . . . . . . . . . . . . . . 3
Retail Marketing. . . . . . . . . . . . . . . 3
Wholesale Marketing . . . . . . . . . . . . . 5
Rates. . . . . . . . . . . . . . . . . . . . . . . 6
Connecticut Retail Rates. . . . . . . . . . . 6
New Hampshire Retail Rates. . . . . . . . . . 8
Massachusetts Retail Rates. . . . . . . . . . 11
Resource Plans . . . . . . . . . . . . . . . . . . 13
Construction. . . . . . . . . . . . . . . . . 13
Future Needs. . . . . . . . . . . . . . . . . 13
Financing Program. . . . . . . . . . . . . . . . . 14
1994 Financings . . . . . . . . . . . . . . . 14
1995 Financing Requirements . . . . . . . . . 15
1995 Financing Plans. . . . . . . . . . . . . 15
Financing Limitations . . . . . . . . . . . . 15
Electric Operations. . . . . . . . . . . . . . . . 18
Distribution and Load . . . . . . . . . . . . 18
Generation and Transmission . . . . . . . . . 21
Fossil Fuels. . . . . . . . . . . . . . . . . 21
Nuclear Generation. . . . . . . . . . . . . . 22
Non-Utility Businesses. . . . . . . . . . . . . . . 32
General . . . . . . . . . . . . . . . . . . . 32
Private Power Development . . . . . . . . . . 33
Energy Management Services. . . . . . . . . . 33
Regulatory and Environmental Matters . . . . . . . 34
Environmental Regulation. . . . . . . . . . . 34
Electric and Magnetic Fields. . . . . . . . . 41
FERC Hydro Project Licensing. . . . . . . . . 42
Employees. . . . . . . . . . . . . . . . . . . . . 42
Subsequent Events. . . . . . . . . . . . . . . . . 44
Item 2. Properties. . . . . . . . . . . . . . . . . . 46
Item 3. Legal Proceedings . . . . . . . . . . . . . . 51
Item 4. Submission of Matters to a Vote of Security
Holders . . . . . . . . . . . . . . . . . . . 54
PART II
Item 5. Market for Registrants' Common Equity and
Related Shareholder Matters . . . . . . . . . 55
Item 6. Selected Financial Data . . . . . . . . . . . 55
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations. . . . . . . . . . . . . . . . . 57
Item 8. Financial Statements and Supplementary Data . 57
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . 58
PART III
Item 10. Directors and Executive Officers of the
Registrants . . . . . . . . . . . . . . . . . 59
Item 11. Executive Compensation. . . . . . . . . . . . 63
Item 12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . 67
Item 13. Certain Relationships and Related
Transactions. . . . . . . . . . . . . . . . . 69
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K . . . . . . . . . . . 70
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations
or acronyms that are found throughout this report:
COMPANIES
NU. . . . . . . . . . . . . . Northeast Utilities
CL&P . . . . . . . . . . . . The Connecticut Light and Power Company
Charter Oak . . . . . . . . . Charter Oak Energy, Inc.
WMECO . . . . . . . . . . . . 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 or North Atlantic. . . North Atlantic Energy Service
Corporation
PSNH. . . . . . . . . . . . . Public Service Company of New Hampshire
RRR . . . . . . . . . . . . The Rocky River Realty Company
the System. . . . . . . . . . the Northeast Utilities System
CYAPC . . . . . . . . . . . . Connecticut Yankee Atomic Power Company
MYAPC . . . . . . . . . . . . Maine Yankee Atomic Power Company
VYNPC . . . . . . . . . . . . Vermont Yankee Nuclear Power
Corporation
YAEC. . . . . . . . . . . . . Yankee Atomic Electric Company
GENERATING UNITS
Millstone 1 . . . . . . . . . Millstone Unit No. 1, a 660-MW
nuclear electric 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.
REGULATORS
DOE . . . . . . . . . . . . . U.S. Department of Energy
DPU . . . . . . . . . . . . . Massachusetts Department of Public
Utilities
DPUC. . . . . . . . . . . . . Connecticut Department of Public
Utility Control
GLOSSARY OF TERMS
REGULATORS (Continued)
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
SEC . . . . . . . . . . . . . Securities and Exchange Commission
Other
1935 Act. . . . . . . . . . . Public Utility Holding Company Act of
1935
AFUDC . . . . . . . . . . . . Allowance for funds used during
construction
CC. . . . . . . . . . . . . . Conservation charge
DSM . . . . . . . . . . . . . Demand-Side Management
Energy Policy Act . . . . . . Energy Policy Act of 1992
FPPAC . . . . . . . . . . . . Fuel and purchased power adjustment
clause (PSNH)
GUAC. . . . . . . . . . . . . Generation utilization adjustment
clause (CL&P)
IRM . . . . . . . . . . . . . Integrated resource management
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
ROE . . . . . . . . . . . . . Return on equity
NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NORTH ATLANTIC ENERGY CORPORATION
PART I
Item 1. Business
THE NORTHEAST UTILITIES SYSTEM
Northeast Utilities (NU) is the parent company of the Northeast Utilities
system (the System). It is not itself an operating company. The System
furnishes retail electric service in Connecticut, New Hampshire and western
Massachusetts through four of NU's wholly-owned subsidiaries (The Connecticut
Light and Power Company [CL&P], Public Service Company of New Hampshire [PSNH],
Western Massachusetts Electric Company [WMECO] and Holyoke Water Power Company
[HWP]). In addition to their retail electric service, CL&P, PSNH, WMECO and HWP
(including its wholly-owned subsidiary, Holyoke Power and Electric Company
[HPE]) (the System companies) together furnish firm wholesale electric service
to eight municipal electric systems and investor-owned utilities. The System
companies also supply other wholesale electric services to various
municipalities and other utilities. NU 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.
North Atlantic Energy Corporation (NAEC) is a special purpose subsidiary of
NU, which sells its share of the capacity and output of the Seabrook nuclear
generating facility (Seabrook) in Seabrook, New Hampshire, to PSNH under two
life-of-unit, full cost recovery contracts. NU's subsidiary North Atlantic
Energy Service Corporation (North Atlantic or NAESCO) has operational
responsibility for Seabrook.
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 or the Service Company) provides centralized
accounting, administrative, data processing, engineering, financial, legal,
operational, planning, purchasing and other services to the System companies.
Northeast Nuclear Energy Company (NNECO) acts as agent for the System companies
and other New England utilities in operating the Millstone nuclear generating
facilities in Connecticut. North Atlantic acts as agent for the System
companies and other New England utilities in operating Seabrook. Three other
subsidiaries construct, acquire or lease some of the property and facilities
used by the System companies.
NU has two other principal subsidiaries, Charter Oak Energy, Inc. (Charter Oak)
and HEC Inc. (HEC), which have non-utility businesses. Directly and through
subsidiaries, Charter Oak develops and invests in cogeneration, small power
production and other forms of non-utility generation and in exempt wholesale
generators ("EWGs")(collectively, "NUGs") and foreign utility companies
("FUCOs") as permitted under the Energy Policy Act of 1992 (Energy Policy Act).
HEC provides energy management services for commercial, industrial and
institutional electric customers. See "Nonutility Businesses."
A reorganization of NU entailing realignment into two core business groups
became effective on January 1, 1994. The first group, the energy resources
group, is devoted to energy resource acquisition and wholesale marketing and
focuses on nuclear, fossil and hydroelectric generation and wholesale power
marketing. The other group, the retail business group, oversees all customer
service, transmission and distribution operations and retail marketing in
Connecticut, New Hampshire and Massachusetts. These two core business groups
are served by various support functions known collectively as the corporate
center. In connection with NU's reorganization, the System is undergoing a
corporate reengineering process to assist in identifying opportunities to become
more competitive while improving customer service and maintaining a high level
of operational performance.
PUBLIC UTILITY REGULATION
NU is a registered electric utility holding company under the Public Utility
Holding Company Act of 1935 (1935 Act). Accordingly, the Securities and
Exchange Commission (SEC) has jurisdiction over NU and its subsidiaries with
respect to, among other things, securities issues, sales and acquisitions of
securities and utility assets, intercompany loans, services performed by and for
associated companies, accounts and records, involvement in non-utility
operations and dividends. The 1935 Act limits the System, with certain
exceptions, to the business of being an electric utility in the Northeastern
region of the country.
The System companies are subject to the Federal Power Act as administered by
the Federal Energy Regulatory Commission (FERC). The Energy Policy Act amended
this act to authorize FERC to order wholesale transmission wheeling services and
under certain circumstances to require electric utilities to enlarge
transmission capacity necessary to provide such services. FERC's authority to
order wheeling does not extend to retail wheeling, and FERC may not issue a
wheeling order that is inconsistent with state laws governing the retail
marketing areas of electric utilities.
In addition, the Nuclear Regulatory Commission (NRC) has broad jurisdiction
over the System's nuclear units and each of the System companies is subject to
broad regulation by its respective state and/or local regulatory authorities
with jurisdiction over the service areas in which each company operates. The
System incurs substantial capital expenditures and operating expenses to
identify and comply with environmental, energy, licensing and other regulatory
requirements, including those described herein, and it expects to incur
additional costs to satisfy further requirements in these and other areas of
regulation. See generally "Rates," "Electric Operations" and "Regulatory and
Environmental Matters."
COMPETITION AND MARKETING
Competitive forces within the electric utility industry are continuing to
increase due to a variety of influences, including legislative and regulatory
actions, technological advances and changes in consumer demands. In response,
the System has developed, and is continuing to develop, a number of initiatives
to retain and continue to serve its existing customers and to expand its retail
and wholesale customer base. The System also benefits from a diverse retail
base. The System has no significant dependence on any one retail customer or
industry.
THE ECONOMY
In 1994, the System experienced its most significant retail sales growth in
six years, due in large part to the economic recovery in New England.
Employment levels have risen, particularly in New Hampshire, unemployment rates
have fallen, and personal income has increased in all three states comprising
the System's retail service territory. The System's 1994 retail sales, which
comprise 77 percent of all kilowatt-hour sales, rose by a total of 2.9 percent
or 867 million kilowatt-hours over 1993. Retail sales growth was consistent
across all major customer classes, with residential sales rising by 2.8 percent,
commercial sales by 3.2 percent and industrial sales by 2.6 percent. Retail
sales growth was strongest for CL&P, which recorded an increase of 3.4 percent,
and weakest for WMECO, which experienced a 1.4 percent increase. At PSNH,
retail sales rose by 2.0 percent. Overall, weather had little effect on sales
volume, with mild weather after mid-August offsetting unusually cold weather in
January and hot weather in late June and July.
In 1995, the System expects little retail sales growth from 1994, primarily
because of the effects of higher interest rates on the regional economy and
further cutbacks in defense-related industries in Connecticut. Over the longer
term, retail sales growth is expected to be strongest in New Hampshire, which by
some measures has the fastest-growing economy in New England. In 1994, many
businesses announced plans to expand in New Hampshire. The System estimates
that PSNH will have compounded annual sales growth of 1.9 percent from 1994
through 1999, compared with 1.4 percent for CL&P and 0.9 percent for WMECO.
Wholesale sales, which comprised the remaining 23 percent of all sales,
rose 0.8 percent or 75 million kilowatt-hours in 1994, due to aggressive
marketing efforts and the opening of new wholesale markets as a result of
increased wholesale competition, including the addition of Madison, Maine as a
wholesale customer.
RETAIL MARKETING
Retail sales growth and the System's success in lowering operating costs
were the primary reasons for the improvement in NU's financial performance in
1994. Because the System has surplus generating capacity, additional demand can
be easily met from existing generation. As a result, the additional costs of
serving expanding load--principally the cost of additional fuel--are far less
than the revenues received from the additional kilowatt-hour sales.
The System companies continue to operate predominantly in state-approved
franchise territories under traditional cost-of-service regulation. Retail
wheeling, under which a retail customer would be permitted to select an
electricity supplier other than its local electric utility and require the local
electric utility to transmit the power to the customer's site, is not required
in any of the System's jurisdictions. In 1994, Connecticut regulators reviewed
the desirability of retail wheeling and determined that it was not in the best
interest of the state until new generating capacity is needed, which the System
projects to be in 2009. The Connecticut Department of Public Utility Control
(DPUC) is presently conducting a generic proceeding studying the restructuring
of the electric industry and competition in order to develop findings and
recommendations to be presented to policymakers at the legislative level. A
decision in this proceeding is expected in mid-1995.
In New Hampshire, several bills related to retail wheeling have been
introduced in the legislature. The chairman of the New Hampshire Public
Utilities Commission (NHPUC) has set up a roundtable discussion with
legislators, utilities and large customers on how to deal with a more
competitive market. In addition, a new entity, Freedom Electric Power Company
(FEPCO), has filed with the NHPUC for permission to do business as an electric
utility to serve selected large PSNH customers. PSNH and other New Hampshire
utilities are opposing FEPCO's petition before the NHPUC.
There also have been several bills introduced in Massachusetts that involve
the potential for retail wheeling, electric utility industry restructuring and
regulatory reform. To date, none of these bills have been enacted. On February
10, 1995, the Massachusetts Department of Public Utilities (DPU) initiated an
investigation into various ways in which the electric utility industry in
Massachusetts could be restructured. The DPU has asked interested parties to
comment on numerous topics such as competition and customer choice by March 31,
1995. It is not known when the DPU will issue an order in this proceeding.
While retail wheeling is not required in the System's retail service
territory, competitive forces nonetheless are influencing retail pricing. These
include competition from alternate fuels such as natural gas, competition from
customer-owned generation and regional competition for business retention and
expansion. The System's retail business group is continuing to work with
customers to address their concerns. Since the fall of 1991, the System
companies have reached approximately 230 special rate agreements with customers
to increase or retain their electricity purchases from the System, including
124 CL&P customers, 54 PSNH customers and 44 WMECO customers through the end of
1994. These agreements include 135 agreements to retain existing customers and
87 agreements for new customers and account for approximately four percent of
System 1994 retail revenues.
In general, these special rate agreements have terms of approximately five
years. Most of CL&P's agreements have been entered pursuant to general rate
riders approved by the DPUC. Most of PSNH's special contracts require
individual approval from the NHPUC. The DPU requires individual approval of
some special contracts, but in 1994 the DPU also authorized WMECO to reduce
rates by five percent for all customers whose demand exceeds one megawatt (MW)
as long as those customers agree to give WMECO at least five years' notice
before generating their own power or purchasing it from an alternative supplier.
As of December 31, 1994, ten WMECO customers had signed up for this service
extension discount.
Many of the special rate agreements were reached individually on a
customer-by-customer basis. However, three significant groups of customers also
entered agreements with certain of the System companies over the past two years.
In 1993, HWP entered ten-year contracts with all of its approximately 40 retail
industrial customers, which accounted for approximately $7 million of revenue in
1994. PSNH entered into long-term contracts with approximately 30 sawmill
operators and nine ski resorts in 1994.
Negotiated retail rate reductions for System customers under rate
agreements in effect for 1994 amounted to approximately $20 million, including
$11 million for CL&P, $3 million for PSNH, $4 million for WMECO and $2 million
for HWP. Management believes that the aggregate amount of retail rate
reductions will increase in 1995, but that such agreements will continue to
provide significant benefits to the System including the preservation of
approximately four percent of retail revenues.
Special rate agreements represent only a portion of the System's response
to the new competitive forces in the energy marketplace. The System spent
approximately $46 million in 1994 on demand side management (DSM) programs.
Over 60 percent of DSM program costs were targeted to the commercial and
industrial sectors. These programs help customers improve the efficiency of
their electric lighting, manufacturing, and heating, ventilating and air
conditioning systems, making them more competitive in their own markets, which
in turn enables them to be more viable employers in the System's service
territories. DSM program costs are recovered from customers through various
cost recovery adjustment mechanisms. For further information on DSM programs,
see "Rates - Connecticut Retail Rates - Demand Side Management" and "Rates -
Massachusetts Retail Rates - Demand Side Management." System companies also are
increasingly working with customers to improve reliability and power quality
within commercial and industrial facilities.
Many of the System's programs for residential customers are targeted at
improving the efficiency of lighting and electric space heating, as well as the
energy efficiency of new homes. Residential space heating represents
approximately five percent of the System's retail electric sales, and suppliers
of alternative fuels, such as natural gas, have actively recruited residential
customers to convert their heating systems from electric heat. In 1994, an
increase in the number of CL&P's space heating customers offset decreases in the
numbers of WMECO's and PSNH's space heating customers.
WHOLESALE MARKETING
The System acts as both a buyer and a seller of electricity in the highly
competitive wholesale electricity market in the Northeastern United States
(Northeast). Many of the sales contracts signed by the System companies in the
late 1980's have expired or will expire in the mid-1990's, and much of the
revenue produced by such contracts has not been replaced through new wholesale
power arrangements. In 1994, wholesale sales, including firm wholesale service
and other bulk supply transactions, accounted for approximately $331 million, or
approximately 9.2 percent, of System revenues, down from approximately $383
million in 1993, due in large part to the loss of one major customer and the
increased competitiveness of the wholesale market. Unless prices on the
wholesale market improve, revenues are expected to fall further in 1995 before
stabilizing in late 1996 and 1997. Wholesale sales are made primarily to
investor-owned utilities and municipal systems or cooperative electric systems
in the Northeast. The System will be increasing its efforts to increase
wholesale sales through intensified marketing efforts. The System's power
marketing efforts benefit from the interconnection of its transmission system
with all of the major utilities in New England, as well as with three of the
largest electric utilities in New York state.
The System's 1994 firm wholesale sales were approximately 1.3 million
megawatt-hours. In 1994, firm wholesale electric service accounted for
approximately 2.5 percent of the System's revenues (approximately 1.4 percent of
CL&P's operating revenue, 6 percent of PSNH's operating revenue and a negligible
amount of WMECO's operating revenue).
In 1994, the System companies commenced service under six long-term sales
contracts with municipal electric systems, including five in Massachusetts and
one in Maine. These power sales contracts have terms which range from five to
ten years. The related revenues, which amounted to approximately $4 million in
1994, are expected to increase over the coming years. The System also sold an
average of approximately 400 MW of power during 1994 in short-term sales to four
utilities in New York State. Those sales ranged in duration from a week to six
months and accounted for approximately $54 million in System revenues in 1994.
The System owns approximately one-half of the 2,000 MW of surplus capacity
in New England. This surplus and the resulting competition for business has
caused the System to renegotiate some of its arrangements with its existing
wholesale customers. For example, in 1994 CL&P began serving the City of
Chicopee, Massachusetts under a new ten-year arrangement. Furthermore, CL&P and
the Town of Wallingford, Connecticut signed a contract for service of
Wallingford's approximate 110 MW load for a ten-year period beginning in 1995.
The new arrangement was coordinated through the Connecticut Municipal Electric
Energy Cooperative, an organization that assists municipalities with their
energy needs, and supersedes CL&P's current firm wholesale contract with
Wallingford. In these cases, due to wholesale competition, the customers were
able to secure prices lower than those that would have been paid under
traditional cost-of-service ratemaking. Similarly, long-term agreements were
renegotiated before 1994 with the New Hampshire Electric Cooperative and several
other municipal and small investor-owned electric systems in Connecticut, New
Hampshire and Massachusetts.
The System's transmission system is an open access wholesale transmission
system: other parties, either utilities or independent power producers, can use
NU's transmission system to move power from a seller to a wholesale buyer at
FERC-approved rates, provided adequate capacity across those lines is available
and service reliability is not endangered. In 1994, the System companies
collected approximately $42 million in transmission revenues for transmission of
power sales emanating from either the System or from other generating plants.
See "Electric Operations - Generation and Transmission" for further information
on bulk supply transactions and for information on pending FERC proceedings
relating to transmission service. All of the wholesale electric transactions of
CL&P, PSNH, WMECO, NAEC and HWP are subject to the jurisdiction of the FERC.
For a discussion of certain FERC-regulated sales of power by CL&P, PSNH,
WMECO and HWP to other utilities, see "Electric Operations - Distribution and
Load." For a discussion of sales of power by NAEC to PSNH, see "Rates -
Seabrook Power Contract."
RATES
CONNECTICUT RETAIL RATES
GENERAL
CL&P's retail electric rate schedules are subject to the jurisdiction of
the DPUC. Connecticut law provides that increased rates may not be put into
effect without the prior approval of the DPUC. Connecticut law authorizes the
DPUC to order a rate reduction before holding a full-scale rate proceeding if it
finds that (i) a utility's earnings exceed authorized levels by one percentage
point or more for six consecutive months, (ii) tax law changes significantly
increase the utility's profits, or (iii) the utility may be collecting rates
that are more than just and reasonable. The law requires the DPUC to give
notice to the utility and any customers affected by the interim decrease. The
utility would be afforded a hearing. If final rates set after a full rate
proceeding or court appeal are higher, customers would be surcharged to make up
the difference.
The DPUC issued a decision in CL&P's most recent rate case in June 1993
(1993 Decision) approving a multi-year rate plan that provides for annual retail
rate increases of $46.0 million, or 2.01 percent, in July 1993, $47.1 million,
or 2.04 percent, in July 1994 and $48.2 million, or 2.06 percent, in July 1995.
The rate increases were implemented as scheduled in 1993 and 1994. For more
information regarding the 1993 Decision, see "Legal Proceedings."
CL&P ADJUSTMENT CLAUSES
CL&P has a fossil fuel and purchased power adjustment clause pursuant to
which CL&P, subject to periodic review by the DPUC, recovers or refunds
substantially all prudently incurred expenses and credits applicable to its
retail electric rates on a current basis.
CL&P's current retail rates also assume that the nuclear units in which
CL&P has entitlements will operate at a 72 percent composite capacity factor. A
generation utilization adjustment clause (GUAC) levels the effect on rates of
fuel costs incurred or avoided due to variations in nuclear generation above and
below that performance level. Because nuclear fuel is less expensive than any
other fuel utilized by the System, when actual nuclear performance is above the
specified level, net fuel costs are lower than the costs reflected in base
rates, and when nuclear performance is below the specified level, net fuel costs
are higher than the costs reflected in base rates. At the end of each
twelve-month period ending July 31, these net variations from the costs
reflected in base rates are, with DPUC approval, generally refunded to or
collected from customers over the subsequent twelve-month period beginning
September 1.
On January 5, 1994, the DPUC issued a decision ordering CL&P not to include
a GUAC amount in customers' bills through August 1994. The DPUC found that CL&P
overrecovered its fuel costs during the 1992-1993 GUAC period and offset the
amount of the overrecovery against the unrecovered GUAC balance. The effect of
the order was a disallowance of $7.9 million. On March 4, 1994, CL&P appealed
this decision to Hartford Superior Court and expects a decision in the spring of
1995.
In the most recent GUAC period, which ended July 31, 1994, the actual level
of nuclear generating performance was 68.2 percent, resulting in a GUAC deferral
of $23.7 million to be collected from customers beginning in September 1994. On
December 30, 1994, the DPUC ordered CL&P to collect from customers over the
ensuing eight months only $15.9 million of the $23.7 million GUAC deferral
accrued during the 1993-1994 GUAC year. The DPUC disallowed $7.8 million of the
deferral, finding that CL&P had overrecovered that amount through base rate fuel
recoveries. The DPUC further stated that it would follow a similar course in
the future. CL&P has also appealed this order.
For the GUAC year ended July 31, 1995, CL&P expects to defer in excess of
$50 million of GUAC fuel costs for projected nuclear performance below 72
percent. As of December 31, 1994, CL&P has reserved $13 million against this
amount based on the methodology applied by the DPUC in previous GUAC decisions.
The DPUC has conducted several reviews to examine the prudence of certain
costs, including purchased power costs, incurred in connection with outages at
various nuclear units located in Connecticut, which occurred during the period
October 1990 - February 1992. Three of these prudence reviews are either on
appeal or still pending at the DPUC. Approximately $92 million of costs are at
issue in these remaining cases, some or all of which may be disallowed.
Management believes its actions with respect to these outages have been prudent
and does not expect the outcome of the appeals to result in material
disallowances. For further information on these prudence reviews, see "Nuclear
Performance" in the notes to NU's and CL&P's financial statements.
DEMAND SIDE MANAGEMENT
CL&P participates in a collaborative process for the development and
implementation of DSM programs for its residential, commercial and industrial
customers. CL&P is allowed to recover conservation costs in excess of costs
reflected in base rates over periods ranging from 3.85 to 10 years.
In June 1994, the DPUC issued an order approving a reduction in the
amortization period from eight years to 3.85 years for CL&P's 1994 DSM
expenditures, which will allow CL&P to recover its total 1994 program budget of
$40 million over 3.85 years beginning in 1994.
On October 31, 1994, CL&P filed an application with the DPUC regarding
CL&P's 1995 DSM expenditures, program designs, performance incentive mechanism
and lost fixed-cost recovery. CL&P proposed a budget level of $36.7 million for
1995 DSM expenditures and an amortization period for new expenditures of 3.93
years. The DPUC began hearings on the proposed budget and programs during
November 1994. CL&P's unrecovered DSM costs at December 31, 1994, excluding
carrying costs, which are collected currently, were approximately $116 million.
NEW HAMPSHIRE RETAIL RATES
RATE AGREEMENT AND FPPAC
PSNH's 1989 Rate Agreement with the State of New Hampshire provides for
seven base rate increases of 5.5 percent per year beginning in 1990 and a
comprehensive fuel and purchased power adjustment clause (FPPAC). The first
five base rate increases went into effect as scheduled and the remaining two
base rate increases will be put in effect on June 1, 1995 and June 1, 1996,
concurrently with semi-annual adjustments in the FPPAC. Political and economic
pressures, caused by historically high retail electric rates in New Hampshire,
may inhibit additional rate increases, including FPPAC increases, above 5.5
percent per year during the next two years, may lead to challenges to the Rate
Agreement in the future and may limit rate recoveries after the period for the
seven 5.5 percent increases has ended. In accordance with the schedule for rate
increases under the Rate Agreement, PSNH increased its average retail electric
rates by about 5.5 percent in June 1994.
The FPPAC provides for the recovery or refund by PSNH, for the ten-year
period beginning on May 16, 1991, of the difference between its actual prudent
energy and purchased power costs and the estimated amounts of such costs
included in base rates established by the Rate Agreement. The FPPAC amount is
calculated for a six-month period based on forecasted data and is reconciled to
actual data in subsequent FPPAC billing periods.
For the period December 1, 1993 through May 31, 1994, the NHPUC approved an
increase in the FPPAC rate which resulted in a 1.8% increase in overall base
rates. For the period June 1, 1994 through November 30, 1994, the NHPUC
approved an increase in the FPPAC rate consistent with an overall increase in
base rates of 5.5% For the period December 1, 1994 through May 31, 1995, the
NHPUC approved a continuation of the current FPPAC rate. This rate treatment
allowed PSNH to limit overall rate increases in 1994 to a level that did not
exceed 5.5%, while maintaining an FPPAC rate level sufficient to collect the
Seabrook refueling costs over four periods through rates by the end of November
30, 1995. The FPPAC rate is not expected to increase in 1995.
The costs associated with purchases by PSNH from certain NUGs at prices
over the level assumed in rates and a portion of the payments to New Hampshire
Electric Cooperative, Inc. (NHEC) for PSNH's buyback of NHEC's Seabrook
entitlement are deferred and recovered through the FPPAC over ten years. As of
December 31, 1994, NUG and NHEC deferrals totaled approximately $174 and $20.3
million, respectively.
Under the Rate Agreement, PSNH has an obligation to use its best efforts to
renegotiate burdensome purchase power arrangements with 13 specified NUGs that
were selling their output to PSNH under long term rate orders. In general, PSNH
has been attempting to exchange present cash payments for relief from high-cost
purchased power obligations to the NUGs, with such payments and an associated
return being recoverable from customers over a future amortization period. For
more information regarding the Rate Agreement, see "PSNH Rate Agreement" in the
notes to NU's and PSNH's financial statements.
On April 19, 1994, the NHPUC approved new purchase power agreements with
five hydroelectric NUGs. These agreements were effective retroactive to January
1993. Management anticipates that the initial decrease in payments to these
NUGs during a year with normal water flow will average approximately 14 percent
or $1.4 million per year. PSNH will flow the savings resulting from these new
agreements through the FPPAC to its customers. The first of these new power
purchase agreements will expire in 2022. The NHPUC deferred action on whether
PSNH had exercised its best effort to renegotiate the agreements.
In addition, PSNH has been involved in negotiations with eight wood-fired
NUGs. On September 23, 1994, the NHPUC approved settlement agreements with two
wood-fired NUGs covering approximately 20 MW of capacity. Pursuant to the
settlement agreements, PSNH paid the owners approximately $40 million in
exchange for the cancellation of the rate orders under which these NUGs sold
their entire output at rates in excess of PSNH's replacement power costs. These
NUGs also agreed not to compete with PSNH or other NU subsidiaries. Under New
Hampshire legislation passed in May 1994, PSNH and the remaining six wood-fired
NUGs were directed to continue negotiations concerning their power sales
arrangements. Absent successful negotiations, the parties were directed to
enter into a mediation process to be completed by November 14, 1994. The
legislation required the parties to attempt to agree on a settlement under which
the payments PSNH made for the NUGs' power would be lowered but the plants would
continue to operate. At a January 4, 1995 status hearing, the NHPUC directed
further mediation to take place with a representative from the State of New
Hampshire assisting the parties. Only one agreement emerged from the mediation
process, which calls for a payment of $52 million in return for a substantial
reduction in the rates charged to PSNH. This agreement was filed with the NHPUC
in February 1995.
The Rate Agreement also provides for the recovery by PSNH through rates of
a regulatory asset, which is the aggregate value placed by PSNH's reorganization
plan on PSNH's assets in excess of the net book value of its non-Seabrook assets
and the value assigned to Seabrook. The unrecovered balance of the regulatory
asset at December 31, 1994 was approximately $679 million. In accordance with
the Rate Agreement, approximately $204 million of the remaining regulatory asset
is scheduled to be amortized and recovered through rates by 1998, and the
remaining amount, approximately $475 million, is being amortized and recovered
through rates by 2011. PSNH earns a return each year on the unamortized portion
of the asset. For more information regarding PSNH's recovery of this regulatory
asset after 1997, see "Regulatory Asset-PSNH" in the notes to NU's financial
statements and "Regulatory Asset" in the notes to PSNH's financial statements.
SEABROOK POWER CONTRACT
PSNH and NAEC entered into the Seabrook Power Contract (Contract) in June
1992. Under the terms of the Contract, PSNH is obligated to purchase NAEC's
initial 35.56942% ownership share of the capacity and output of Seabrook 1 for
the term of Seabrook's NRC operating license and to pay NAEC's "cost of service"
during this period, whether or not Seabrook 1 continues to operate. NAEC's cost
of service includes all of its prudently incurred Seabrook 1-related costs,
including maintenance and operation expenses, cost of fuel, depreciation of
NAEC's recoverable investment in Seabrook 1 and a phased-in return on that
investment. The payments by PSNH to NAEC under the Contract constitute
purchased power costs for purposes of the FPPAC and are recovered from customers
under the Rate Agreement. Decommissioning costs are separately collected by
PSNH in its base rates. See "Rates - New Hampshire Retail Rates - Rate
Agreement and FPPAC" for information relating to the Rate Agreement. At
December 31, 1994, NAEC's net utility plant investment in Seabrook 1 was
approximately $718 million.
If Seabrook 1 were retired prior to the expiration of its NRC operating
license term, NAEC would continue to be entitled under the Contract to recover
its remaining Seabrook investment and a return on that investment and its other
Seabrook-related costs for 39 years, less the period during which Seabrook 1 has
operated.
The Contract provides that NAEC's return on its "allowed investment" in
Seabrook 1 (its investment in working capital, fuel, capital additions after the
date of commercial operation and a portion of the initial investment) is
calculated based on NAEC's actual capitalization over the term of the Contract,
its actual debt and preferred equity costs, and a common equity cost of 12.53
percent for the first ten years of the Contract, and thereafter at an equity
rate of return to be fixed in a filing with the FERC. The portion of the
initial investment which is included in the allowed investment has increased
annually since May 1991 and will reach 100 percent by 1997. As of December 31,
1994, 70 percent of the initial investment was included in rates.
NAEC is entitled to earn a deferred return on the portion of the initial
investment not yet phased into rates. The deferred return on the excluded
portion of the initial investment, together with a return on it, will be
recovered between 1997 and 2001. At December 31, 1994, the amount of this
deferred return was $131.5 million. For additional information regarding the
Contract and a similar contract, which involves NAEC's acquisition of Vermont
Electric Generation and Transmission Cooperative, Inc.'s ownership interest in
Seabrook, see "Seabrook Power Contract" in the notes to PSNH's financial
statements.
MASSACHUSETTS RETAIL RATES
GENERAL
WMECO's retail electric rate schedules are subject to the jurisdiction of
the DPU. The rates charged under HWP's contracts with industrial customers are
not subject to the ratemaking jurisdiction of any state or federal regulatory
agency.
On May 26, 1994, the DPU approved a settlement offer from WMECO and the
Massachusetts Attorney General that, among other things, provided that: (1) all
pending WMECO generating unit performance review proceedings regarding unit
outages from mid-1987 through mid-1993 would be terminated without findings; (2)
WMECO's customers' overall bills will be reduced by approximately $13.3 million
over the 20-month period June 1, 1994 to January 31, 1996; (3) WMECO will not
file for increased base rates effective before February 1, 1996; (4) WMECO will
amortize post-retirement benefits other than pensions costs over a three-year
period starting July 1, 1994; and (5) WMECO will offer a five percent rate
reduction to its largest customers who agree not to self-generate or take
electricity from another provider for five years. The settlement did not have a
significant adverse impact on WMECO's 1994 earnings.
DEMAND SIDE MANAGEMENT
In 1992, the DPU established a conservation charge (CC) to be included in
WMECO'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. On January 21, 1994 the DPU
approved a settlement offer from WMECO, the Massachusetts Attorney General, the
Massachusetts Division of Energy Resources (DOER), the Conservation Law
Foundation (CLF) and the Massachusetts Public Interest Research Group (MASSPIRG)
pre-approving DSM funding levels for 1994 and 1995 of $14.2 million and $15.8
million, respectively. The settlement also provides for cost recovery
adjustments and an incentive mechanism if certain implementation objectives are
met.
In a subsequent proceeding, the DPU established a CC for each rate class at
least through 1994 (and ordered deferred recovery of conservation-related costs
in connection with two rate classes) and examined the level of conservation
savings delivered by WMECO programs in prior years (and disallowed certain
claimed conservation savings). On January 11, 1995, the DPU initiated hearings
to set CCs for 1995, review the claimed level of conservation savings delivered
and review the mechanism for determining lost fixed-cost recovery. Recently, in
proceedings involving two other utilities, the DPU changed its policy to limit
recovery of lost revenues due to implementation of conservation measures to a
fixed period. If such a policy is implemented for WMECO, WMECO could lose
several millions of dollars of revenues starting in 1996 and possibly as early
as 1995. Further hearings for WMECO's docket are scheduled for March 1995.
Management cannot predict when the DPU will issue a decision in this case.
WMECO 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 quarterly adjustments in WMECO'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 the operation of the Northeast Utilities Generation and
Transmission Agreement (NUG&T). The NUG&T is the FERC-approved contract among
the System operating companies, other than PSNH, that provides for the sharing
among the companies on a system-wide basis costs of generation and transmission
and serves as the basis for planning and operating the System's bulk power
supply system on a unified basis.
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 if a utility fails to meet the fuel procurement and use
performance goals set for that utility. Fuel clause revenues collected in
Massachusetts are subject to potential refund, pending the DPU's examination of
the actual performance of WMECO'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. Accordingly, the DPU has established goals, as discussed above, for the
three Millstone units and for the three regional nuclear operating units (the
Yankee plants) in which WMECO has ownership interests.
Subsequent to the May 26, 1994 settlement between WMECO and the DPU, the
DPU initiated a review of WMECO's 1993-1994 generating unit performance.
Hearings have not begun in that proceeding and it is not known when the DPU may
issue a decision.
RESOURCE PLANS
CONSTRUCTION
The System's construction program expenditures, including allowance for
funds used during construction (AFUDC), in the period 1995 through 1999 are
estimated to be as follows:
1995 1996 1997 1998 1999
(Millions)
CL&P $148 $136 $144 $145 $145
PSNH 51 36 32 39 39
WMECO 36 28 29 39 39
NAEC 5 8 7 6 6
OTHER 14 10 10 10 10
---- ---- ---- ---- ----
TOTAL $254 $218 $222 $239 $239
==== ==== ==== ==== ====
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, improved reliability or other causes.
The construction program's main focus is maintaining and upgrading the existing
transmission and distribution system, as well as 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. The System does not foresee the
need for any new major generating facilities at least until 2009.
The System's long-term plans rely, in part, on certain DSM programs. These
System company sponsored measures, including installations to date, are
projected to lower the System summer peak load in 2009 by over 650 MW. See
"Rates - Connecticut Retail Rates - Demand Side Management" and "Rates -
Massachusetts Retail Rates - Demand Side Management" for information about rate
treatment of DSM costs.
In addition, System companies have long-term arrangements to purchase the
output from certain NUGs under federal and state laws, regulations and orders
mandating such purchases. NUGs supplied 680 MW of firm capacity in 1994. This
is the maximum amount that the System companies expect to purchase from NUGs for
the foreseeable future. See "New Hampshire Retail Rates - Rate Agreement and
FPPAC" for information concerning PSNH's efforts to renegotiate its agreements
with thirteen NUGs.
The System's long-term resource plan also considers the economic viability
of continuing the operation of certain of the System's fossil fuel generating
units beyond their current book retirement dates and possibly repowering certain
of the System's older fossil plants. Continued operation of existing fossil
fuel units past their book retirement dates (and replacing certain critically
located peaking units if they fail) is expected to provide approximately 1900 MW
of resources by 2009 that would otherwise have been retired. In addition,
repowering of some of the System's retired generating plants could provide the
System with approximately 900 MW of capacity. The capacity could be brought on
line in various increments timed with the year of need.
The System's need for new resources may be affected by unscheduled
retirements of its existing generating units, regulatory approval of the
continued operation of fossil fuel units and nuclear units past scheduled
retirement dates and deactivation of plants resulting from environmental
compliance or licensing decisions. For information regarding the agreement
concerning NOX emissions at the Merrimack units, see "Regulatory and
Environmental Matters - Environmental Regulation - Air Quality Requirements."
See "Electric Operations - Nuclear Generation - Nuclear Plant Licensing and NRC
Regulation" and - "Nuclear Performance" for further information on the NRC rule
on nuclear plant operating license renewal, and information on the expiration
dates of the operating licenses of the nuclear plants in which the System
companies have interests. Before the System can make any decisions about
whether license extensions for any of its nuclear units are feasible, detailed
technical and economic studies will be needed.
The System's long-term resource plan also anticipates that the System's
nuclear units will continue to run through the scheduled terms of their
respective operating licenses. For information regarding the early retirement
of one of the System's nuclear units, see "Electric Operations - Nuclear
Generation - Nuclear Performance" and - "Decommissioning."
FINANCING PROGRAM
1994 FINANCINGS
In 1994, CL&P and WMECO issued $535 and $90 million, respectively, of first
mortgage bonds. In virtually all cases, new issues of first mortgage bonds were
of smaller principal amounts than the issues that were retired with the proceeds
of such issuances, with cash derived from operations making up the balance of
funds needed to effect the retirements. This was done as part of NU's overall
effort to reduce the System companies' debt levels. Total debt, including
short-term and capitalized leased obligations, was $4.54 billion as of December
31, 1994, compared with $4.88 billion as of December 31, 1993 and $5.21 billion
as of December 31, 1992. For more information regarding 1994 financings, see
Notes to Consolidated Statements of Capitalization of NU and "Long-Term Debt" in
the notes to CL&P's, PSNH's, WMECO's and NAEC's financial statements.
1995 FINANCING REQUIREMENTS
In addition to financing the construction requirements described under
"Resource Plans - Construction," the System companies are obligated to meet $1.3
billion of long-term debt maturities and cash sinking fund requirements and
$124.9 million of preferred stock cash sinking fund requirements in 1995 through
1999. In 1995, long-term debt maturity and cash sinking fund requirements will
be $175.8 million, consisting of $11.9 million of cash sinking fund requirements
to be met by CL&P, $94 million of cash sinking fund requirements to be met by
PSNH, $35.8 million of long-term debt maturities and cash sinking fund
requirements to be met by WMECO, $20 million of cash sinking fund requirements
to be met by NAEC and $14.1 million of cash sinking fund requirements to be met
by other subsidiaries.
The System's aggregate capital requirements for 1995, exclusive of
requirements under the Niantic Bay Fuel Trust (NBFT), are as follows:
Total
CL&P PSNH WMECO NAEC Other System
(Millions of Dollars)
Construction
(including AFUDC)..... $148 $51 $36 $ 5 $14 $254
Nuclear Fuel
(excluding AFUDC).. 47 1 11 9 - 68
Maturities.............. - - 35 - - 35
Cash Sinking Funds.. 12 94 1 20 14 141
---- ---- --- --- --- ----
Total........... $207 $146 $83 $34 $28 $498
==== ==== === === === ====
For further information on NBFT and the System's financing of its nuclear fuel
requirements, see "Leases" in the notes to NU's, CL&P's and WMECO's financial
statements.
1995 FINANCING PLANS
The System companies currently expect to finance their 1995 requirements
through internal cash flow and short-term debt. This estimate excludes the
nuclear fuel requirements financed through the NBFT. In addition to financing
their 1995 requirements, the System companies intend, if market conditions
permit, to continue to refinance a portion of their outstanding long-term debt
and preferred stock, if that can be done at a lower effective cost. On January
23, 1995, CL&P issued, through an affiliate, $100 million of 9.3 percent Monthly
Income Preferred Securities, to help finance the retirement of approximately
$125 million of preferred stock.
FINANCING LIMITATIONS
The amounts of short-term borrowings that may be incurred by NU, CL&P,
PSNH, WMECO, HWP, NAEC, NNECO, The Rocky River Realty Company (RRR), The
Quinnehtuk Company (Quinnehtuk) (RRR and Quinnehtuk are real estate
subsidiaries) and HEC are subject to periodic approval by the SEC under the 1935
Act.
The following table shows the amount of short-term borrowings authorized by
the SEC for each company as of January 1, 1995 and the amounts of outstanding
short-term debt of those companies at the end of 1994.
Maximum Authorized Short-Term Debt
Short-Term Debt Outstanding at 12/31/94*
(Millions)
NU.................. $ 150 $ 104
CL&P ............... 325 179
PSNH ............... 175 -
WMECO............... 60 -
HWP................. 5 -
NAEC................ 50 -
NNECO............... 50 6
RRR................. 22 17
Quinnehtuk.......... 8 5
HEC................. 11 2
-----
Total $ 313
=====
-----------------
* This column includes borrowings of various System companies from NU and
other System companies through the Northeast Utilities System Money Pool (Money
Pool). Total System short term indebtedness to unaffiliated lenders was $190
million at December 31, 1994.
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, CL&P, PSNH nor
WMECO may dispose of voting stock of CL&P, PSNH or WMECO other than to NU or
another System company, except that CL&P may sell voting stock for cash to
third persons if so ordered by a regulatory agency so long as the amount sold is
not more than 19 percent of CL&P's voting stock after the sale. The
restrictions also generally prohibit NU from pledging voting stock of CL&P,
PSNH or WMECO or granting liens on its other assets in amounts greater than
five percent of the total common equity of NU. As of March 1, 1995, no NU debt
was secured by liens on NU assets. Finally, NU may not declare or make
distributions on its capital stock, acquire its capital stock (or rights
thereto), or permit a System company to do the same, at times when there is an
Event of Default under the supplemental indentures under which the amortizing
notes were issued.
The charters of CL&P and WMECO contain preferred stock provisions
restricting the amount of short term or other unsecured borrowings those
companies may incur. As of December 31, 1994, CL&P's charter would permit CL&P
to incur an additional $450.3 million of unsecured debt and WMECO's charter
would permit it to incur an additional $145.5 million of unsecured debt.
In connection with NU's acquisition of PSNH, certain financial conditions
intended to prevent NU from relying on CL&P resources if the PSNH acquisition
strains NU's financial condition were imposed by the DPUC. The principal
conditions provide for a DPUC review if CL&P's common equity falls to 36 percent
or below, require NU to obtain DPUC approval to secure NU financings with CL&P
stock or assets, and obligate NU to use its best efforts to sell CL&P preferred
or common stock to the public if NU cannot meet CL&P's need for equity capital.
At December 31, 1994, CL&P's common equity ratio was 42.0 percent.
While not directly restricting the amount of short-term debt that CL&P,
WMECO, RRR, NNECO and NU may incur, credit agreements to which CL&P, WMECO,
HWP, RRR, NNECO and NU are parties provide that the lenders are not required to
make additional loans, or that the maturity of indebtedness can be accelerated,
if NU (on a consolidated basis) does not meet a common equity ratio that
requires, in effect, that the NU consolidated common equity (as defined) be at
least 27 percent for three consecutive quarters. At December 31, 1994, NU's
common equity ratio was 33.4 percent. Credit agreements to which PSNH is a
party forbid its incurrence of additional debt unless it is able to
demonstrate, on a pro forma basis for the prior quarter and going forward, that
its equity ratio (as defined) will be at least 23 percent of total
capitalization (as defined) through June 30, 1995 and 25 percent thereafter. In
addition, PSNH must demonstrate that its ratio of operating income to interest
expense will be at least 1.75 to 1 at the end of each fiscal quarter for the
remaining term of the agreement. At December 31, 1994, PSNH's common equity
ratio was 32.7 percent and its operating income to interest expense ratio for
the twelve-month period was 2.69 to 1.
See "Short-Term Debt" in the notes to NU's, CL&P's, PSNH's and WMECO's
financial statements for information about credit lines available to System
companies.
The indentures securing the outstanding first mortgage bonds of CL&P,
PSNH, WMECO and NAEC provide that additional bonds may not be issued, except
for certain refunding purposes, unless earnings (as defined in each indenture,
and before income taxes, and, in the case of PSNH, without deducting the
amortization of PSNH's regulatory asset) are at least twice the pro forma
annual interest charges on outstanding bonds and certain prior lien obligations
and the bonds to be issued.
The preferred stock provisions of CL&P's, PSNH's and WMECO's charters also
prohibit the issuance of additional preferred stock (except for refinancing
purposes) unless income before interest charges (as defined and after income
taxes and depreciation) is at least 1.5 times the pro forma annual interest
charges on indebtedness and the annual dividend requirements on preferred stock
that will be outstanding after the additional stock is issued.
NU is dependent on the earnings of, and dividends received from, its
subsidiaries to meet its own financial requirements, including the payment of
dividends on NU common shares. At the current indicated annual dividend of
$1.76 per share, NU's aggregate annual dividends on common shares outstanding at
December 31, 1994, including unallocated shares held by the ESOP trust, would be
approximately $236.2 million. Dividends are payable on common shares only if,
and in the amounts, declared by the NU Board of Trustees.
SEC rules under the 1935 Act require that dividends on NU's shares be
based on the amounts of dividends received from subsidiaries, not on the
undistributed retained earnings of subsidiaries. The SEC's order approving
NU's acquisition of PSNH under the 1935 Act approved NU's request for a waiver
of this requirement through June 1997. PSNH and NAEC were effectively
prohibited from paying dividends to NU through May 1993. Through the remainder
of 1993 and 1994, PSNH did not pay dividends, to allow it to build up the common
equity portion of its capitalization and to fund the buyout of certain NUGs
operating in New Hampshire. See "Rates - New Hampshire Retail Rates - Rate
Agreement and FPPAC." NAEC paid dividends of $5 million in each of the third
and fourth quarters of 1994. If PSNH does not fund its pro rata share of NU's
dividend requirements, NU expects to fund that portion of its dividend
requirements with the proceeds of borrowings or the issuance of additional
common shares under the dividend reinvestment plan.
The supplemental indentures under which CL&P's and WMECO's first mortgage
bonds and the indenture under which PSNH's first mortgage bonds have been issued
limit the amount of cash dividends and other distributions these subsidiaries
can make to NU out of their retained earnings. As of December 31, 1994, CL&P
had $225.6 million, WMECO had $90.1 million and PSNH had $125.0 million of
unrestricted retained earnings. PSNH's preferred stock provisions also limit
the amount of cash dividends and other distributions PSNH can make to NU if
after taking the dividend or other distribution into account, PSNH's common
stock equity is less than 25 percent of total capitalization. The indenture
under which NAEC's Series A Bonds have been issued also limits the amount of
cash dividends or distributions NAEC can make to NU to retained earnings plus
$10 million. At December 31, 1994, $69.2 million was available to be paid under
this provision.
PSNH's credit agreements prohibit PSNH from declaring or paying any cash
dividends or distributions on any of its capital stock, except for dividends on
the preferred stock, unless minimum interest coverage and common equity ratio
tests are satisfied. At December 31, 1994, $162 million was available to be paid
under these provisions.
Certain subsidiaries of NU established the Money Pool to provide a more
effective use of the cash resources of the System, and to reduce outside short
term borrowings. The Service Company 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 cost. Funds may be
withdrawn or repaid to the Money Pool at any time without prior notice.
ELECTRIC OPERATIONS
DISTRIBUTION AND LOAD
The System companies own and operate a fully-integrated electric utility
business. The System operating companies' retail electric service territories
cover approximately 11,335 square miles (4,400 in CL&P's service area, 5,445 in
PSNH's service area and 1,490 in WMECO's service area) and have an estimated
total population of approximately 4.0 million (2.5 million in Connecticut,
959,000 in New Hampshire and 582,000 in Massachusetts). The companies furnish
retail electric service in 149, 198 and 59 cities and towns in Connecticut, New
Hampshire and Massachusetts, respectively. In December 1994, CL&P furnished
retail electric service to approximately 1.1 million customers in Connecticut,
PSNH provided retail electric service to approximately 400,000 customers in New
Hampshire and WMECO served approximately 194,000 retail electric customers in
Massachusetts. HWP serves 46 retail customers in Holyoke, Massachusetts.
The following table shows the sources of 1994 electric revenues based on
categories of customers:
CL&P PSNH WMECO NAEC Total System
Residential........... 41% 35% 38% - 40%
Commercial............ 34 28 31 - 33
Industrial ........... 14 18 19 - 16
Wholesale* ........... 9 16 9 100% 9
Other ................ 2 3 3 - 2
---- ---- ---- ---- ----
Total ................ 100% 100% 100% 100% 100%
* Includes capacity sales.
NAEC's 1994 electric revenues were derived entirely from sales to PSNH
under the Seabrook Power Contract. See "Rates - Seabrook Power Contract" for
a discussion of the contract.
Through December 31, 1994, the all-time maximum demand on the System was
6339 MW, which occurred on July 21, 1994. The System was also selling
approximately 896 MW of capacity to other utilities at that time. At the time
of the peak, the System's generating capacity, including capacity purchases, was
8948 MW.
System energy requirements were met in 1993 and 1994 as set forth below:
Source 1994 1993
Nuclear .................................... 54% 62%
Oil ........................................ 7 7
Coal ....................................... 8 10
Hydroelectric .............................. 4 3
Natural gas ................................ 3 2
NUGs ....................................... 14 14
Purchased power............................. 10 2
----- ---
100% 100%
The actual changes in kilowatt-hour sales for the last two years and the
forecasted sales growth estimates for the 10-year period 1994 through 2004, in
each case exclusive of bulk power sales, for the System, CL&P, PSNH and WMECO
are set forth below:
1994 over 1993 over Forecast 1994-2004
1993 (under) 1992 Compound Rate of Growth
System......... 2.50% 10.9%(1) 1.2%
CL&P........... 3.66% (0.3)% 1.1%
PSNH........... 1.56% 1.0% 1.5%
WMECO....... 1.47% 0.1% 1.2%
(1) The percent increase in System 1993 sales over 1992 sales is due to the
inclusion of PSNH sales beginning in June 1992.
In 1990, FERC required the reclassification of bulk power sales from
"purchased power" to "sales for resale" for 1990 and later reporting years.
Bulk power sales are not included in the development of any long-term forecasted
growth rates. The actual changes in kilowatt-hour sales for the last two years,
adjusted for bulk power sales (by adding back the bulk power sales), for the
System, CL&P, PSNH and WMECO are set forth below:
1994 over (under) 1993 1993 over (under) 1992
System ................... 2.37% 11.8%
CL&P ..................... 3.33% 1.2%
PSNH ..................... (1.35)% (9.3)%
WMECO .................... 5.58% 13.5%
For a discussion of trends in bulk power sales, see "Competition and Marketing."
The System's total kilowatt-hour sales grew 2.5% in 1994 because of
economic growth. The growth was broad-based and was not dominated by any
particular industry or sector. Partially offsetting the gains in the economy
were continued curtailments in the defense and insurance industries, which
particularly affected the CL&P service area. Such curtailments should continue
into 1995, which, combined with the efforts of the Federal Reserve to slow the
national recovery, have the potential to further thwart New England's recovery.
Moreover, where energy costs are a significant part of operating expenses,
business customers may turn to self-generation, switch fuel sources or relocate
to other states and countries, which have aggressive programs to attract new
businesses. For more information on the effect of competition on sales growth
rates, see "Competition and Marketing."
In spite of further defense and insurance curtailments moderate growth is
forecasted to resume over the next ten years. The System forecasts a 1.2%
growth rate of sales over this period. This growth rate is significantly below
historic rates because of anticipated labor force constraints and, in part,
because of forecasted savings from System sponsored DSM programs that are
designed to minimize operating expenses for System customers and postpone the
need for new capacity on the System. The forecasted ten-year growth rate of
System sales would be approximately 0.5% higher if the System did not pursue DSM
programs at the forecasted levels. See "Rates - Connecticut Retail Rates" and
"Rates - Massachusetts Retail Rates" for information about rate treatment of DSM
costs.
With the System's generating capacity of 8,241 MW as of January 1, 1995
(including the net of capacity sales to and purchases from other utilities, and
approximately 688 MW of capacity purchased from NUGs under existing contracts),
the System expects to meet reliably its projected annual peak load growth of 1.2
percent until at least the year 2009.
The availability of new resources and reduced demand for electricity have
combined to place the System and most other New England electric utilities in a
surplus capacity situation. Taking into account projected load growth for the
System and committed capacity sales, but not taking into account future
potential capacity sales to other utilities or purchases from other utilities
that are not subject to firm commitments, the System's installed reserve is
expected to be approximately 1,700 MW in the summer of 1995. For further
information on the effect of competition on sales of surplus capacity, see
"Competition and Marketing."
The System companies operate and dispatch their generation as provided in
the New England Power Pool (NEPOOL) Agreement. In 1994, the peak demand on the
NEPOOL system was 20,519 MW in July, which was 949 MW above the 1993 peak load
of 19,570 MW in July of that year. NEPOOL has projected that there will be a
decrease in demand in 1995 and estimates that the summer 1995 peak load could
reach 20,425 MW. NEPOOL projects that sufficient capacity will be available to
meet this anticipated demand.
GENERATION AND TRANSMISSION
The System companies and most other New England utilities with electric
generating facilities are parties to the NEPOOL Agreement. Under the NEPOOL
Agreement, planning and operation of the region's generation and transmission
facilities are coordinated. 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 northeastern United States 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.
The System companies, except PSNH and NAEC, pool their electric production
costs and the costs of their principal transmission facilities under the
Northeast Utilities Generation and Transmission Agreement (NUG&T). In addition,
a ten-year agreement, expiring in June 2002, between PSNH and CL&P, WMECO and
HWP provides for a sharing of the capability responsibility savings and energy
expense savings resulting from a single system dispatch.
In January 1992, FERC issued a decision approving NU's acquisition of PSNH,
provided that the combined system accord transmission access to other utilities
and non-utility generators that need to use the NU-PSNH transmission system to
buy or sell electricity. FERC noted that NU system customers should remain
harmless from the granting of such access. In accordance with the January 1992
decision, in April and August 1992, NU made compliance filings with FERC,
including transmission tariffs implementing such conditions. FERC has made all
tariffs effective as of the merger date based on interim rates and terms of
service established by FERC pursuant to summary determinations (without
hearing). NU filed for rehearing of FERC's compliance tariff order in an effort
to reinstate the originally proposed rates. FERC has not yet acted on NU's
rehearing petition. For information regarding the appeal of FERC's approval of
NU's acquisition of PSNH, see "Legal Proceedings."
The terms on which wheeling transactions are to be effected in New England
have stimulated a series of negotiations among utilities, regulators, power
brokers and marketers and non-utility generators, directed at the possible
development of a regional transmission group within New England. Any
arrangement would require widespread support by the parties and be subject to
approval by FERC.
FOSSIL FUELS
The System's residual oil-fired generation stations used approximately
six million barrels of oil in 1994. The System obtained the majority of its oil
requirements in 1994 through contracts with two large, independent oil
companies. Those contracts allow for some spot purchases when market conditions
warrant, but spot purchases represented less than 10 percent of the System's
fuel oil purchases in 1994. The contracts expire annually or biennially. The
System currently does not anticipate any difficulties in obtaining necessary
fuel oil supplies on economic terms.
The System converted CL&P's Devon Units 7 and 8 into oil and gas dual-fuel
generating units in July 1994. The System now has five generating stations,
aggregating approximately 800 MW, which can burn either residual oil or natural
gas as economics, environmental concerns or other factors dictate. CL&P, PSNH
and WMECO all have contracts with the local gas distribution companies where the
dual-fuel generating units are located, under which natural gas is made
available by those companies on an interruptible basis. In addition, gas for
the Devon units is being purchased directly from producers and brokers on an
interruptible basis and transported through the interstate pipeline system and
the local gas distribution company. The System expects that interruptible
natural gas will continue to be available for its dual-fuel electric generating
units on economic terms and will continue to supplement fuel oil requirements.
See "Derivative Financial Instruments" in the notes to NU's and CL&P's
financial statements for information about CL&P's oil and natural gas swap
agreements to hedge against fuel price risk on certain long-term fixed-price
energy contracts.
The System companies obtain their coal through long-term supply contracts
and spot market purchases. The System companies currently have an adequate
supply of coal. Because of changes in federal and state air quality
requirements, the System expects to use lower sulfur coal in its plants in the
future. See "Regulatory and Environmental Matters - Environmental Regulation -
Air Quality Requirements."
NUCLEAR GENERATION
GENERAL
The System companies have interests in seven operating nuclear units:
Millstone 1, 2 and 3, Seabrook 1 and three other units, Connecticut Yankee (CY),
Maine Yankee (MY), and Vermont Yankee (VY), owned by regional nuclear generating
companies (the Yankee companies). System companies operate the three Millstone
units and Seabrook 1 and have operational responsibility for CY. The System
companies also have interests in Yankee Rowe owned by the Yankee Atomic Electric
Company (YAEC), which was permanently removed from service in 1992.
CL&P and WMECO own 100 percent of Millstone 1 and 2 as tenants in common.
Their respective ownership interests are 81 percent and 19 percent.
CL&P, PSNH and WMECO have agreements with other New England utilities
covering their joint ownership as tenants in common of Millstone 3. CL&P's
ownership interest in the unit is 52.93 percent, PSNH's ownership interest in
the unit is 2.85 percent and WMECO's interest is 12.24 percent. NAEC and CL&P
have 35.98 percent and 4.06 percent ownership interests, respectively, in
Seabrook. The Millstone 3 and Seabrook joint ownership agreements provide for
pro rata sharing by the owners of each unit of the construction and operating
costs, the electrical output and the associated transmission costs.
CL&P and NAEC have been affected at times by the inability of certain other
Seabrook joint owners to fund their share of Seabrook costs. Great Bay Power
Corporation (GBPC), a former subsidiary of Eastern Utilities Associates and
owner of 12.13 percent of Seabrook, began bankruptcy proceedings in February
1991. On November 11, 1994, a final plan of reorganization of GBPC was
confirmed by the United States Bankruptcy Court. Under the plan of
reorganization's financing agreement, on November 22, 1994 a group of investors
purchased 60 percent of the reorganized GBPC's common stock for an investment of
$35 million and repaid CL&P $7.3 million for advances which CL&P made to cover
GBPC's shortfalls in funding its share of operating costs of Seabrook during the
bankruptcy.
CL&P, PSNH, WMECO and other New England electric utilities are the
stockholders of the Yankee companies. Each Yankee company owns a single nuclear
generating unit. The stockholder-sponsors of a Yankee company are responsible
for proportional shares of the operating costs of the 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 non-stockholder electric utilities have
contractual rights to some of the output of particular units. The Yankee
companies and CL&P's, PSNH's and WMECO's stock ownership percentages in the
Yankee companies are set forth below:
CL&P PSNH WMECO System
Connecticut Yankee Atomic
Power Company (CYAPC) ...... 34.5% 5.0% 9.5% 49.0%
Maine Yankee Atomic Power
Company (MYAPC) ............ 12.0% 5.0% 3.0% 20.0%
Vermont Yankee Nuclear
Power Corporation (VYNPC)... 9.5% 4.0% 2.5% 16.0%
Yankee Atomic Electric
Company (YAEC) ............ 24.5% 7.0% 7.0% 38.5%
CL&P, PSNH and WMECO are obligated to provide their percentages of any
additional equity capital necessary for the Yankee companies, but do not expect
to contribute additional equity capital in the future. CL&P, PSNH and WMECO
believe that the Yankee companies, excluding YAEC, 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
each Yankee company would attempt to finance these expenditures, if they are
needed, have not been determined, CL&P, PSNH and WMECO could be asked to provide
direct or indirect financial support for one or more Yankee companies.
NUCLEAR PLANT LICENSING AND NRC REGULATION
The operators of Millstone 1, 2 and 3, CY, MY, VY and Seabrook 1 hold full
power operating licenses from the NRC. As holders of licenses to operate
nuclear reactors, CL&P, WMECO, 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.
In addition, activities related to nuclear plant operation are routinely
inspected by the NRC for compliance with NRC regulations. The NRC has authority
to enforce its regulations through various mechanisms which include the issuance
of notices of violation (NOV) and civil monetary penalties. Several regulatory
enforcement actions, with associated civil monetary penalties aggregating
$357,500, were taken by the NRC in 1994 for certain violations which occurred at
Millstone Station. However, approximately $270,000 of such amounts related to
violations that occurred prior to 1994.
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. One such issue that has received considerable attention
from the NRC in the last several years concerns the ability and willingness of
nuclear plant workers to raise nuclear safety concerns without fear of
retaliation for doing so. The NRC has identified the Millstone Station in
particular as a site where workers have expressed concern with their ability to
raise nuclear safety issues to company supervisors and managers. Management is
aware of the NRC's concerns in this area, and is taking steps to ensure that the
environment at Millstone is one where workers feel free to raise issues without
fear of retaliation.
NUCLEAR PLANT PERFORMANCE
Capacity factor is a ratio that compares a unit's actual generating output
for a period with the unit's maximum potential output. The average capacity
factor for operating nuclear units in the United States was 73.2 percent for
January through September 1994, and 67.5 percent for the five nuclear units
operated by the System in 1994, compared with 80.8 percent for 1993. The lower
1994 capacity factor was primarily due to extended refueling and maintenance
outages at Millstone 1, Millstone 2 and Seabrook and unexpected technical and
operating difficulties at Millstone 2, Seabrook and CY.
The System anticipates total expenditures in 1995 of approximately $477.5
million for operations and maintenance and $82.2 million in capital improvements
for the five nuclear plants that it operates. The Performance Enhancement
Program (PEP), initiated in 1992 by the System's nuclear organization, was
designed in response to a declining performance trend noted in the early 1990's.
Seven PEP action plans were completed in 1994. The System companies spent
$25.2 million on PEP in 1994 and have budgeted $21.7 million (included in the
1995 operations and maintenance annual budget) for 1995 PEP action plans. The
remaining nine action plans are expected to be completed by the end of 1997.
When the nuclear units in which they have interests are out of service,
CL&P, PSNH and WMECO need to generate and/or purchase replacement power.
Recovery of replacement power costs is permitted, subject to prudence reviews,
through the GUAC for CL&P, through FPPAC for PSNH and through a retail fuel
adjustment clause for WMECO. For the status of regulatory and legal proceedings
related to recovery of replacement power costs for the 1990-1993 period, see
"Rates - Connecticut Retail Rates," "Rates - New Hampshire Retail Rates" and
"Rates - Massachusetts Retail Rates."
MILLSTONE UNITS
For the twelve months ended December 31, 1994, the three Millstone units'
composite capacity factor was 66.4 percent, compared with a composite capacity
factor of 79.3 percent for the twelve months ended December 31, 1993 and 53.1
percent for the same period in 1992.
Millstone 1, a 660 MW boiling water reactor, has a license expiration date
of October 6, 2010. In 1994, Millstone 1 operated at a 58.3 percent capacity
factor. The unit began a 71 day planned refueling and maintenance outage on
January 15, 1994. Millstone 1 returned to service on May 20, 1994, for an
outage duration of 125 days. The delay in completing the outage on schedule was
primarily attributable to unanticipated work associated with the service water
systems, certain system valves and surveillance testing. The next refueling
outage is scheduled for October 1995.
Millstone 2, a 870 MW pressurized water reactor, has a license expiration
date of July 31, 2015. In 1994 Millstone 2 operated at a 48.2 percent capacity
factor. The unit began a planned 63-day refueling and maintenance outage on
October 1, 1994. Subsequent events have added substantially to the duration of
the refueling outage and at present, the unit is not expected return to service
before mid-April 1995. Earlier in 1994, Millstone 2 experienced a 57-day
unplanned maintenance outage which ended on June 18, 1994 and a second unplanned
outage to repair the reactor coolant pump oil collection system from July 27,
1994 to September 3, 1994. The recovery of replacement power operation and
maintenance costs incurred during these outages are subject to prudence reviews
in both Connecticut and Massachusetts.
A recent report issued by the NRC for the Millstone Station noted
significant weaknesses in Millstone 2's operations and maintenance.
Subsequently, a senior NRC official expressed disappointment with the continued
weaknesses in Millstone 2's performance. The primary cause of the NRC's
disappointment with Millstone 2's performance appears to be that, despite
significant management attention and action over a period of years, the NRC does
not believe it has seen enough objective evidence of improvement in reducing
procedural noncompliance and other human errors. Management has acknowledged
the basis for the NRC's concern with Millstone 2 and has been devoting increased
attention to resolving these issues. Management and the NRC expect to continue
to closely monitor performance at Millstone 2.
Millstone 3, a 1154 MW pressurized water reactor, has a license expiration
date of November 25, 2025. In 1994, Millstone 3 operated at a 94 percent
capacity factor. The unit had no planned refueling and maintenance outages in
1994. Millstone 3 experienced one unplanned outage in 1994 which lasted from
September 8, 1994 to September 22, 1994. The next refueling outage is scheduled
to begin on April 14, 1995, with a planned duration of 54 days.
SEABROOK
Seabrook 1, a 1148 MW pressurized water reactor, has a license expiration
date of October 17, 2026. The Seabrook operating license expires 40 years from
the date of issuance of authorization to load fuel, which was about three and a
half years before Seabrook's full power operating license was issued. The
System will determine at the appropriate time whether to seek recapture of this
period from the NRC and thus add an additional three and a half years to the
operating term for Seabrook. In 1994, Seabrook operated at a capacity factor of
61.6 percent. The unit began a scheduled refueling and maintenance outage on
April 9, 1994. The unexpected discovery of reactor coolant pump locking cups
and a bolt in the reactor vessel contributed substantially to the duration of
the outage. The unit returned to service on August 1, 1994 for an outage
duration of 114 days. Seabrook experienced one unplanned outage in 1994 which
lasted from January 26 to February 17, 1994 when a main steam isolation valve
closed during quarterly surveillance testing. The next refueling outage is
scheduled for November 1995.
YANKEE UNITS
CONNECTICUT YANKEE
CY, a 582 MW pressurized water reactor, has a license expiration date of
June 29, 2007. In 1994 CY operated at a capacity factor of 75.4 percent. CY
experienced two unplanned outages with durations greater than two weeks in 1994.
The first such outage began in February 1994 and lasted 44 days in order to
repair and replace service water piping. On July 11, 1994 the unit began a
second forced outage to upgrade the oil collection system for the reactor
coolant pumps. The unit returned to service on August 17, 1994. CY began a
planned refueling and maintenance outage on January 28, 1995, with a scheduled
duration of 51 days.
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. At the appropriate time, 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 1994, MY operated at a
capacity factor of 85.9 percent. The current refueling outage began in January
1995.
VERMONT YANKEE
VY, a 514 MW boiling water reactor, has a license expiration date of March
21, 2012. In 1994, VY operated at a capacity factor of 94.4 percent. The
current refueling outage began on March 17, 1995.
YANKEE ROWE
In February 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 CL&P, PSNH and WMECO and YAEC permit YAEC to recover from each
its proportional share of the Yankee Rowe shutdown and decommissioning costs.
For more information regarding recovery of decommissioning costs for Yankee
Rowe, see "Electric Operations - Nuclear Generation - Decommissioning."
NUCLEAR INSURANCE
The NRC's nuclear property insurance rule requires nuclear plant licensees
to obtain a minimum of $1.06 billion in insurance coverage. The rule requires
that, although such policies may provide traditional property coverage, proceeds
from the policy following an accident in which estimated stabilization and
decontamination expenses exceed $100 million will first be applied to pay such
expenses. The insurance carried by the licensees of the Millstone units,
Seabrook 1, CY, MY and VY meets the requirements of this rule. YAEC has
obtained an exemption for the Yankee Rowe plant from the $1.06 billion
requirement and currently carries $25 million of insurance that otherwise meets
the requirements of the rule. For more information regarding nuclear insurance,
see "Nuclear Insurance Contingencies" in the notes of NU's, CL&P's, PSNH's,
WMECO's and NAEC's 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 System companies have maintained diversified sources of supply for
these materials and services, relying on no single source of supply for any one
component of the fuel cycle. The majority of the System companies' uranium
enrichment services requirements are provided under a long term contract with
the U.S. Enrichment Corporation, a wholly-owned government corporation. The
majority of Seabrook 1's uranium enrichment services requirements, however, are
furnished by a Russian trading company. 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 Policy Act, the U.S. commercial nuclear power
industry is required to pay to the DOE, via a special assessment for the costs
of the decontamination and decommissioning of uranium enrichment plants owned by
the U.S. government, no more than $150 million for 15 years beginning in 1993.
Each domestic nuclear utility will make a payment based on its pro rata share of
all enrichment services received by the U.S. commercial nuclear power industry
from the U.S. Government through October 1992. Each year, the U. S. Department
of Energy (DOE) will adjust the annual assessment using the Consumer Price
Index. The Energy Policy Act provides that the assessments are to be treated as
reasonable and necessary current costs of fuel, which costs shall be fully
recoverable in rates in all jurisdictions. The System's total share of the
estimated assessment was approximately $51 million. Management believes that
the DOE assessments against CL&P, WMECO, PSNH and NAEC will be recoverable in
future rates. Accordingly, each of these companies has recognized these costs
as a regulatory asset, with a corresponding obligation on its balance sheet.
Costs associated with nuclear plant operations include amounts for disposal
of nuclear waste, including spent fuel, and for the ultimate decommissioning of
the plants. The System companies include in their nuclear fuel expense spent
fuel disposal costs accepted by the DPUC, the NHPUC and the DPU in rate case or
fuel adjustment decisions. Spent fuel disposal costs are also reflected in
FERC-approved wholesale charges. Such provisions include amortization and
recovery in rates of previously unrecovered disposal costs of accumulated spent
nuclear fuel.
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 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, the NHPUC and the
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. In late 1993 and 1994, DOE indicated that it was not likely to meet its
statutory and contractual obligations to accept spent fuel in 1998.
In June 1994, the DPUC joined with the Connecticut and Massachusetts
Attorneys General and a number of states in a lawsuit filed in federal court
against the DOE, seeking a declaratory judgment that the DOE has a statutory
obligation to take high-level nuclear waste from utilities in 1998 and to
establish judicially administered milestones to enforce that obligation. The
State of New Hampshire, among others, subsequently joined in this lawsuit. NU
and its affiliates did not join a companion lawsuit filed by fourteen utilities
seeking similar relief. Nuclear utilities and state regulators are presently
considering additional steps which they might take to ensure that the DOE is
able to meet its obligations with regard to nuclear waste disposal as soon as
possible.
Until the federal government begins accepting nuclear waste for disposal,
operating nuclear generating plants will need to retain high-level wastes and
spent fuel on-site or make some other provisions for their storage. With the
addition of new storage racks or through fuel consolidation, storage facilities
for Millstone 3 and CY are expected to be adequate for the projected life of the
units. 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 2000. Fuel consolidation, which has been licensed for Millstone 2, could
provide adequate storage capability for the projected lives of Millstone 1 and
2. In addition, other licensed technologies, such as dry storage casks or
on-site transfers, are being considered to accommodate spent fuel storage
requirements. With the addition of new racks, Seabrook 1 is expected to have
spent fuel storage capacity until at least 2010.
MY's present storage capacity of the spent fuel pool at the unit will be
reached in 1999, and after 1996 the available capacity of the pool will not
accommodate a full-core removal. After consideration of available technologies,
MYAPC elected to provide additional capacity by replacing the fuel racks in the
spent fuel pool at the unit. On March 15, 1994, the NRC authorized this plan.
MYAPC believes that the replacement of the fuel racks will provide 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 effective February
1992, YAEC is planning to construct 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. See "Electric Operations - Nuclear Generation
- Decommissioning" for further information on the closing and decommissioning of
Yankee Rowe.
LOW-LEVEL RADIOACTIVE WASTE
In accordance with the provisions of the federal Low-Level Radioactive
Waste Policy Act of 1980, as amended (the Waste Policy Act), on December 31,
1992 the disposal site at Beatty, Nevada closed, and the Richland, Washington
facility closed to disposal of low-level radioactive wastes (LLRW) from outside
its compact region. On July 1, 1994, the Barnwell, South Carolina LLRW facility
ceased accepting LLRW for disposal from states situated outside its compact
region. The NU System is currently implementing plans for the temporary on-site
storage of LLRW generated at its nuclear facilities. The costs associated with
temporary on-site storage of LLRW are not material. The System has plans that
will allow for the storage of LLRW until a permanent disposal facility becomes
available. The System can manage its Connecticut LLRW by volume reduction,
storage or shipment at least through 1999. In addition, an NRC policy
memorandum provides additional guidance on interim LLRW storage by removing any
time limitations on the on-site storage of LLRW and by allowing for modification
and expansion of storage facilities without prior NRC approval. The Millstone
units and CY incurred approximately $6.8 million in off-site disposal costs in
1994.
The Connecticut Hazardous Waste Management Service (the Service), a state
quasi-public corporation, is charged with coordinating the establishment of a
facility for disposal of LLRW originating in Connecticut. On February 1, 1993,
the Connecticut legislature approved a site selection plan under which
communities are urged to volunteer a site for a facility in return for financial
and other incentives. The volunteer process is being continued through 1996.
The Service's activities in this regard are funded by assessments on
Connecticut's LLRW generators. Due to the change to a volunteer process, there
was no assessment for the 1994-1995 fiscal year and the state projects no
assessment for the 1995-1996 and 1996-1997 fiscal years. Management cannot
predict whether and when a disposal site will be designated in Connecticut. The
Service currently projects that a disposal site will be designated by 2002.
Since January 1, 1989, the State of New Hampshire has been barred from
shipping Seabrook LLRW to the operating disposal facilities in South Carolina,
Nevada and Washington for failure to meet the milestones required by the Waste
Policy Act. Seabrook 1 has never shipped LLRW but has capacity to store at
least five years' worth of the LLRW generated on-site, with the capability to
expand this on-site capacity if necessary. The Seabrook station accrued
approximately $2.0 million in off-site disposal costs in 1994. New Hampshire is
pursuing options for out-of-state disposal of LLRW generated at Seabrook.
MY has been storing its LLRW on-site since January 1993. VY and MY each
has on-site storage capacity for at least five years' production of LLRW from
its respective plants. Maine and Vermont are in the process of implementing an
agreement with Texas to provide access to a LLRW facility that is to be
developed in that state.
DECOMMISSIONING
Based upon the System's most recent comprehensive site-specific updates of
the decommissioning costs for each of the three Millstone units and for
Seabrook, the recommended decommissioning method continues to be immediate and
complete dismantlement of those units at their retirement. The table below sets
forth the estimated Millstone and Seabrook decommissioning costs for the System
companies. The estimates are based on the latest site studies, escalated to
December 31, 1994 dollars, and include costs allocable to NAEC's share of
Seabrook acquired from VEG&T.
CL&P PSNH WMECO NAEC System
(Millions)
Millstone 1 $332.8 $ - $ 78.1 $ - $ 410.9
Millstone 2 267.3 - 62.7 - 330.0
Millstone 3 237.5 12.8 54.9 - 305.2
Seabrook 1* 15.5 - - 137.3 52.8
------ ----- ------ ------ --------
Total $853.1 $12.8 $195.7 $137.3 $1,198.9
====== ===== ====== ====== ========
---------------
* The Seabrook decommissioning estimate currently is under review by the New
Hampshire Nuclear Decommissioning Finance Committee (NDFC).
As of December 31, 1994, the balances (at market) in certain external
decommissioning trust funds, as discussed more fully below, were as follows:
CL&P PSNH WMECO NAEC System
(Millions)
Millstone 1 $ 81.5 $ - $ 27.4 $ - $108.9
Millstone 2 52.1 - 18.5 - 70.6
Millstone 3 37.2 1.8 10.2 - 49.2
Seabrook 1 1.2 - - 10.3 11.5
------ ---- ------ ----- ------
Total $172.0 $1.8 $ 56.1 $10.3 $240.2
====== ==== ===== ===== ======
Pursuant to Connecticut law, CL&P has periodically filed plans with the
DPUC for financing the decommissioning of the three Millstone units. In 1986,
the DPUC approved the establishment of separate external trusts for the
currently tax-deductible portions of decommissioning expense accruals for
Millstone 1 and 2 and for all expense accruals for Millstone 3. In its 1993
CL&P multi-year rate case decision, the DPUC allowed CL&P's full decommissioning
estimate for the three Millstone units to be collected from customers. This
estimate includes an approximately 16 percent contingency factor for each unit.
The estimated aggregate System cost of decommissioning the Millstone units is
approximately $1.05 billion in December 1994 dollars.
WMECO has established independent trusts to hold all decommissioning
expense collections from customers. In its 1990 WMECO multi-year rate case
decision, the DPU allowed WMECO's decommissioning estimate for the three
Millstone units ($840 million in December 1990 dollars) to be collected from
customers. Due to the settlement in the 1992 WMECO rate case, the aggregate
decommissioning estimate for the three Millstone units remains unchanged.
The decommissioning cost estimates for the Millstone 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. CL&P, PSNH and WMECO attempt to recover sufficient amounts
through their allowed rates to cover their 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 System companies.
Although allowances for decommissioning have increased significantly in recent
years, collections from customers in future years will need to increase to
offset the effects of any insufficient rate recoveries in previous years.
New Hampshire enacted a law in 1981 requiring the creation of a
state-managed fund to finance decommissioning of any units in that state. In
1992, the NDFC established approximately $323 million (in 1991 dollars) as the
decommissioning cost estimate for immediate and complete dismantlement of
Seabrook 1 upon its retirement. North Atlantic prepared a revised
decommissioning estimate in 1994. The revised estimate is currently under
review by the NDFC. Public hearings were held in the fourth quarter of 1994.
Approval of the estimate is expected in late April, 1995. On the basis of North
Atlantic's 1994 revised estimate, the total System decommissioning cost for
Seabrook 1 is $152.8 million in December 1994 dollars.
The NHPUC is authorized to permit the utilities subject to its jurisdiction
that own an interest in Seabrook 1 to recover from their customers on a
per-kilowatt hour basis amounts paid into the decommissioning fund over a period
of years. NAEC's costs for decommissioning are billed by it to PSNH and
recovered by PSNH under the Rate Agreement. Under the Rate Agreement, PSNH is
entitled to a base rate increase to recover increased decommissioning costs.
See "Rates - New Hampshire Retail Rates" for further information on the Rate
Agreement.
YAEC, MYAPC, VYNPC and CYAPC are all collecting revenues for
decommissioning from their power purchasers. The table below sets forth the
estimated decommissioning costs of the Yankee units for the System companies.
The estimates are based on the latest site studies, escalated to December 31,
1994 dollars. For information on the equity ownership of the System companies
in each of the Yankee units, see "Electric Operations - Nuclear Generation -
General."
CL&P PSNH WMECO System
(Millions)
VY $ 31.3 $13.2 $ 8.2 $ 52.7
Yankee Rowe* 100.0 28.6 28.6 157.2
CY 124.9 18.1 34.4 177.4
MY 40.6 16.9 10.1 67.6
------ ----- ----- -----
Total $298.8 $76.8 $81.3 $454.9
====== ===== ===== ======
---------------
* The costs shown include all decommissioning costs as well as other closing
costs associated with the early retirement of Yankee Rowe.
As of December 31, 1994, the balances (at market) in the external
decommissioning trust funds for the Yankee Units were as follows:
CL&P PSNH WMECO System
(Millions)
VY $ 10.8 $ 4.5 $ 2.8 $ 18.1
Yankee Rowe 26.4 7.6 7.6 41.6
CY 51.6 7.5 14.2 73.3
MY 13.0 5.4 3.3 21.7
------ ----- ----- -----
Total $101.8 $25.0 $27.9 $154.7
====== ===== ===== ======
In October 1994, YAEC submitted a decommissioning cost estimate as part of
its decommissioning plan with the NRC. Following the receipt of NRC approval,
this estimate will be filed with FERC. The estimate increased the system's
ownership share of decommissioning YAEC's nuclear facility by approximately $36
million in January 1, 1994 dollars. At December 31, 1994, the estimated
remaining costs amounted to $408.2 million, of which the System's share was
approximately $157.1 million. Management expects that CL&P, PSNH and WMECO will
continue to be allowed to recover such FERC approved costs from their customers.
YAEC has begun component removal activities related to the decommissioning
of its nuclear facility. Based on the revised decommissioning estimate and the
remaining decommissioning costs in 1994 dollars, approximately nine percent of
such removal activities has been completed. Management believes that, although
Yankee Rowe was shut down eight years before the end of the unit's operating
license, CL&P, PSNH and WMECO will recover their investments in YAEC, along with
any other associated costs.
CYAPC accrues decommissioning costs on the basis of immediate dismantlement
at retirement. The most current estimated decommissioning cost, based on a 1992
study, is approximately $362.0 million in year-end 1994 dollars. In May 1993,
FERC approved a settlement agreement in a CYAPC rate proceeding allowing a
revised decommissioning estimate of $294.2 million (in July 1992 dollars) to be
recovered in rates beginning on June 1, 1993. This amount will increase by a
stated amount each year for inflation.
MYAPC estimates the cost of decommissioning MY at $338.3 million in
December 31, 1994 dollars based on a study completed in July 1993. VYNPC
estimates the cost of decommissioning VY at $329.6 million in December 31, 1994
dollars based on a study completed in March 1994.
For further information regarding the decommissioning of the System nuclear
units, see "Nuclear Decommissioning" in the notes to NU's, CL&P's, PSNH's,
WMECO's and NAEC's financial statements.
NON-UTILITY BUSINESSES
GENERAL
In addition to its core electric utility businesses in Connecticut, New
Hampshire and Massachusetts, in recent years the System has begun a
diversification of its business activities into two energy-related fields:
private power development and energy management services.
PRIVATE POWER DEVELOPMENT
In 1988, NU organized a subsidiary corporation, Charter Oak, through which
the System participates as a developer and investor in domestic and
international private power projects. With the passage of the Energy Policy
Act, Charter Oak can invest in EWG and FUCO power projects anywhere in the
world. Management currently does not permit Charter Oak to invest in facilities
which are located within the System service territory or to sell its electric
output to any of the System electric utility companies.
Charter Oak has made strategic alliances with several experienced
developers to pursue development opportunities nationwide and internationally.
Charter Oak owns, through a wholly-owned special purpose subsidiary, a ten
percent equity interest in a 220 MW natural gas-fired combined cycle
cogeneration QF in Texas. Charter Oak also owns 56 MW of the 1,875 MW Teesside
natural gas-fired cogeneration facility in the United Kingdom.
Charter Oak is pursuing other project development opportunities in both the
domestic and international markets with a combined capacity over 1,000 MW.
Charter Oak is currently participating in the development stage of projects in
Texas, the West Coast, Latin America and the Pacific Rim. Specifically, Charter
Oak is engaged in constructing a 114 MW natural gas-fired project located in the
Republic of Argentina (Argentina) and plans to begin construction of a 20 MW
wind project in Costa Rica in the spring of 1995. Charter Oak's share of these
projects is 38 MW and 13 MW, respectively.
Although Charter Oak has no full-time employees, nine NUSCO employees are
dedicated to Charter Oak activities on a full-time basis. Other NUSCO employees
provide services as required. NU's total investment in Charter Oak was
approximately $31.0 million as of December 31, 1994. NU currently is committed
to invest an additional $15 million in Charter Oak to fund completion of the
natural gas-fired project in Argentina.
ENERGY MANAGEMENT SERVICES
In 1990, NU organized a subsidiary corporation, HEC, to acquire
substantially all of the assets and personnel of an existing, non-affiliated
energy management services company. In general, the energy management services
that HEC provides are performed for customers pursuant to contracts to reduce
the customers' energy costs and/or conserve energy and other resources. HEC
also provides demand side management consulting services to utilities. HEC's
energy management and consulting services are directed primarily to the
commercial, industrial and institutional markets and utilities in New England
and New York. NU's initial equity investment in HEC was approximately $4
million and NU has made additional capital contributions of approximately
$300,000 through December 31, 1994.
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 or 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) provides that every "point source"
discharger of pollutants into navigable waters must obtain a National Pollutant
Discharge Elimination System (NPDES) permit from the U.S. Environmental
Protection Agency (EPA) or state environmental agency specifying the allowable
quantity and characteristics of its effluent. The System's steam-electric
generating plants 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.
The CWA requires EPA and state permitting authorities to approve the
cooling water intake structure design and thermal discharge of steam-electric
generating plants. All System steam-electric plants have received these
approvals. In the renewed discharge permit for the three Millstone nuclear
units, issued in 1992, the Connecticut Department of Environmental Protection
(CDEP) included a condition requiring a feasibility study of various structural
or operational modifications of the cooling water intake system to reduce the
entrainment of winter flounder larvae. On January 14, 1994, CDEP approved the
Millstone feasibility report submitted to it in 1993 and required that Millstone
station continue efforts to schedule refueling outages to coincide with the
period of high winter flounder larvae abundance and that the station continue to
monitor the Niantic River winter flounder population in accordance with existing
NPDES permit conditions.
Merrimack Station's NPDES permit requires site work to isolate adjacent
wetlands from the station's waste water system. Plans have been approved by the
New Hampshire Department of Environmental Services (NHDES), and PSNH is now
preparing a permit application to begin construction.
The Merrimack permit also requires PSNH to perform further biological
studies because significant numbers of migratory fish are being restored to
lower reaches of the Merrimack River. These studies are in progress and will be
completed in 1995. If they indicate that Merrimack Station's once-through
cooling system interferes with the establishment of a balanced aquatic
community, PSNH could be required to construct a partially enclosed cooling
water system for Merrimack station. The amount of capital expenditures relating
to the foregoing cannot be determined at this time. However, if such
expenditures were required, they would likely be substantial and a reduction of
Merrimack station's net generation capability could result.
The ultimate cost impact of the CWA and state water quality regulations on
the System 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 System's generating facilities.
In response to several major oil spills in recent years, Congress passed
the Oil Pollution Act of 1990 (OPA 90). OPA 90 sets out the requirements for
facility response plans and periodic inspections of spill response equipment at
facilities that can cause substantial harm or significant and substantial harm
to the environment by discharging oil or hazardous substances into the navigable
waters of the United States and adjoining shorelines. Pursuant to OPA 90, EPA
has authority to regulate nontransportation-related fixed onshore facilities and
the Coast Guard has the authority to regulate transportation-related onshore
facilities.
Response plans were filed for all System facilities believed to be subject
to this requirement. The Coast Guard has completed its final review process and
issued its approval of these plans. The EPA has issued its approval of all
facility plans except PSNH's Schiller Station, where the EPA has authorized
continued operation pending its final plan approval.
OPA 90 includes limits on the liability that may be imposed on persons
deemed responsible for release of oil. The limits do not apply to oil spills
caused by negligence or violation of laws or regulations. OPA 90 also does not
preempt state laws regarding liability for oil spills. In general, the laws of
the states in which the System owns facilities and through which the System
transports oil could be interpreted to impose strict liability for the cost of
remediating releases of oil and for damages caused by releases. The System and
its principal oil transporter currently carry a total of $890 million in
insurance coverage for oil spills.
AIR QUALITY REQUIREMENTS
The Clean Air Act Amendments of 1990 (CAAA) made extensive revisions and
additions to the federal Clean Air Act and imposed many stringent new
requirements on air emissions sources. The CAAA contains provisions further
regulating emissions of sulfur dioxide (SO2) and nitrogen oxides (NOX) for the
purpose of controlling acid rain, toxic air pollutants and other pollutants,
requiring installation of continuous emissions monitors (CEMs) and expanding
permitting provisions.
Existing and additional federal and state air quality regulations could
hinder or possibly preclude the construction of new, or modification of
existing, fossil units in the System's service area, could raise the capital and
operating cost of existing units, and may affect the operations of the System's
work centers and other facilities. 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. The CAAA identifies NOX emissions as a precursor of
ambient ozone for the northeastern region of the United States, which currently
exceeds ambient air quality standard for ozone. Pursuant to the CAAA,
Connecticut, New Hampshire and Massachusetts must implement plans to address
ozone nonattainment. All three states have issued final regulations to
implement Phase I (RACT) reduction requirements. The System has developed
compliance strategies and estimates of costs. The capital cost to comply with
Phase I requirements will cost the System a total of approximately $41 million:
$10 million for CL&P, $27 million for PSNH, $1 million for WMECO and $3 million
for HWP. Compliance will be achieved using currently available technology and
combustion efficiency improvements. Compliance costs for Phase II, effective in
1999, are expected to result in an additional cost of $10 to $15 million. These
Phase II costs take into consideration capital expenditures during Phase I and
expanded capital costs for available technology.
In December 1993, PSNH reached a revised agreement regarding NOX emissions
with various environmental groups and the New Hampshire Business and Industrial
Association. The agreement was submitted to the New Hampshire Air Resources
Division (NHARD) in the form of proposed regulations.
The agreement provides for aggressive unit specific NOX emission rate limits for
PSNH's generating facilities, effective May 31, 1995. The agreement no longer
requires a PSNH commitment to retire or repower Merrimack Unit 2 by May 15,
1999. More stringent emission rate limits equivalent to the range of 0.1 to 0.4
pounds of NOX per million Btu, however, are required for the unit by that date.
On May 20, 1994, NHARD promulgated the New Hampshire NOX reduction rule. The
System will comply with the requirements of this rule by installing controls on
the units. The additional requirements for Merrimack Unit 2 for 1999 will be
attained through increased catalytic reduction of NOX at an additional estimated
cost of $5 to 7 million.
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 are required to reduce their emissions beginning January 1,
1995. The only System units subject to the Phase I reduction requirements are
PSNH's Merrimack Units 1 and 2. All Phase I units will be allocated SO2
allowances for the period 1995-1999. These allowances are freely tradable. One
allowance entitles a source to emit one ton of SO2 in a year. No unit may emit
more SO2 in a particular year than the amount for which it has allowances.
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. The System expects that its allocated
allowances will substantially exceed its expected SO2 emissions for 2000 and
subsequent years. Current estimates indicate the System will have approximately
25,000 tradeable SO2 allowances available annually at a market value of
approximately $150 per allowance. On July 20, 1994 the DPUC issued an order
that, with some restrictions, allows CL&P to retain for its shareholders 15
percent of the net proceeds from the sale of SO2 allowances.
New Hampshire and Massachusetts have each instituted acid rain control laws
that limit SO2 emissions. The System expects to meet the new SO2 limitations by
using natural gas and lower sulfur coal in its plants. The System could incur
additional costs for the lower sulfur fuels it may burn to meet the requirements
of this legislation.
Under the existing fuel adjustment clauses in Connecticut, New Hampshire
and Massachusetts, the System would be able to recover the additional fuel costs
of compliance with the CAAA and state laws from its customers. Management does
not believe that the acid rain provisions of the CAAA will have a significant
impact on the 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 (acid rain) requirements for NOX
limitations will not have a significant impact on System costs due to the more
stringent state NOX limitations 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 that new or modified fossil fuel-fired electric generating units 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 imposes new stringent discharge
limitations on hazardous air pollutants. EPA is required to study toxic
emissions and mercury emissions from power plants. Pending completion of these
studies, power plants are exempt from the hazardous air pollutant requirements.
Should EPA or Congress determine that power plant emissions must be controlled
to the same extent as emissions from other sources under Title III, the System
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 but lower than 8,500 ppm to an unaffiliated company to
dispose of using a chemical treatment process. Electrical capacitors that
contain PCB fluid are sent offsite 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 on removal of
asbestos, including measures to protect the health of workers and the general
public and to properly dispose of asbestos wastes. Asbestos costs for the
System are typically several million dollars annually. These costs are already
included in capital and operation and maintenance budgets.
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.
CL&P is expecting that EPA and DEP will approve clean closure for CL&P's
Montville and Middletown Stations' former surface impoundments. For the Norwalk
Harbor and Devon sites, CL&P has applied for post-closure permits and is
awaiting approval from EPA and DEP. The System estimates that it will incur
approximately $2 million in total costs of 30-year maintenance monitoring, and
closure of the container storage areas for these sites in the future, but the
ultimate amount will depend on EPA's final disposition.
Underground Storage Tanks. Federal and state regulations regulate
underground tanks storing petroleum products or hazardous substances. To reduce
its environmental and financial liabilities, the System has been permanently
removing all non-essential underground vehicle fueling tanks. Costs for this
program are not substantial.
Hazardous Waste Liability. As many other industrial companies have done in
the past, System companies have 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. In recent years it has been determined that deposited or buried
wastes, under certain circumstances, could cause groundwater contamination or
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. At December 31, 1994, the liability
recorded by the System 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 $11 million.
The costs for these known sites could rise to as much as $16 million 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 clean up 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 one Superfund site in Kentucky and
three 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 Financial Accounting Standards Board standards 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.
The System is no longer involved with the Beacon Heights, Connecticut
Superfund site, at which a coalition of major parties had attempted to join
"Northeast Utilities (Connecticut Light and Power)" as defendants. In January
1994, the Beacon Heights Coalition filed a response with the federal district
court indicating that it would not continue to pursue NU (CL&P) as a defendant
in this litigation. Accordingly, it is not likely that CL&P will incur any
cleanup costs for this site.
EPA has issued a notice of potential liability to NNECO and CYAPC as
potentially responsible parties (PRPs) at the Maxey Flats nuclear waste disposal
site in Fleming County, Kentucky. The System had sent a substantial volume of
LLRW from Millstone 1, Millstone 2 and CY to this site. PRPs that are 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 have reached a tentative settlement with
EPA embodied in a consent decree. NUSCO, on behalf of NNECO and CYAPC, signed
the consent decree in March 1995. The System has recorded a liability for
future remediation costs for this site based on its best estimate of its share
of ultimate remediation costs under the tentative agreement. To date, the costs
have not been material with respect to System earnings or financial position.
PSNH has committed approximately $280,000 as its share of the costs to
clean up Superfund sites at municipal landfills in Dover and North Hampton, New
Hampshire. Some additional costs may be incurred at these sites and at the
Somersworth site but they are not expected to be significant.
As discussed below, 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.
In 1987, Connecticut Department of Environmental Protection (CDEP)
published a list of 567 hazardous waste disposal sites in Connecticut. The
System owns two sites on this list, which are also listed on the EPA's list of
hazardous waste sites. The System has spent approximately $600,000 to date
completing investigations at these sites. Both sites were formerly used by CL&P
predecessor companies for the manufacture of coal gas (also known as town gas
sites) from the late 1800s to the 1950s. This process resulted in the
production of coal tar residues, which, when not sold for roofing or road
construction, were frequently deposited on or near the production facilities.
Site investigations are being carried out to gain an understanding of the
environmental and health risks of these sites. The need for site remediation is
being evaluated. The level of cleanup will be established in cooperation with
CDEP, which is currently developing cleanup standards and guidelines for soil
and groundwater.
One of the sites is a 25.8 acre site located in the south end of Stamford,
Connecticut. Site investigations have located coal tar deposits covering
approximately 5.5 acres and having a volume of approximately 45,000 cubic yards.
A final risk assessment report for the site was completed in January 1994.
Several remedial options are currently being evaluated to clean up the site.
These options include institutional controls, excavation and limited removal of
contamination, which would reduce the potential environmental and health risks
and secure the site. The estimated costs of remediation and institutional
controls range from $5 to $13 million.
The second site is a 3.5 acre former coal gasification facility that
currently serves as an active substation in Rockville, Connecticut. Site
investigations have located creosote and other polyaromatic hydrocarbon
contaminants which will require remediation. Several options are being
evaluated to process surface soils and degrade subsurface contamination to
remediate the site. Levels of cleanup will be coordinated with the CDEP.
As part of the 1989 divestiture of CL&P's gas business, site investigations
were performed for properties that were transferred to Yankee Gas Services
Company (Yankee Gas). CL&P agreed to accept liability for required cleanup for
the three sites it retained. These three sites include Stamford and Rockville
(discussed above) and Torrington, Connecticut. At the Torrington site,
investigations have been completed and the cost of any remediation, if
necessary, is not expected to be material. CL&P and Yankee Gas also share a
site in Winsted, Connecticut and any liability for required cleanup there. CL&P
and Yankee Gas will share the costs of cleanup of sites formerly used in CL&P's
gas business but not currently owned by either of them.
PSNH contacted NHDES in December 1993 concerning possible coal tar
contamination in Laconia, New Hampshire in Lake Opechee and the Winnipesaukee
River near an area where PSNH formerly owned and operated a coal gasification
plant which was sold in 1945. PSNH completed a site investigation in December
1994. Results indicate that off-site coal tar/creosote contamination is present
in the adjacent water bodies. The cost of remediation at this site is estimated
at $1.8 million. A second coal gasification facility formerly owned and
operated by a predecessor company to PSNH is located in Keene, New Hampshire.
The NHDES has been notified of the presence of coal tar contamination and
further site investigations are planned in 1995. Other New Hampshire sites
include a municipal landfill in Peterborough and the inactive Dover Point site
owned by PSNH in Dover, New Hampshire. PSNH's liability at the landfill is not
expected to be significant and its liability at the Dover Point site cannot be
estimated at this time.
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. Except for
the Holyoke site, the System does not expect that its share of the remaining
remediation costs for most of these sites will be material. 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 west 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 (SNS) - 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 indicated they may require the removal of tar deposits from
the vicinity of the SNS spawning habitat. To date, HWP has spent approximately
$400,000 for river studies and construction costs for an oil containment boom to
prevent leaching hydrocarbons from entering the Hadley Falls tailrace and the
Connecticut River. The estimated costs for remediation of this site range from
$2 to $3 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. If the System, regulatory agencies or courts determine that remedial
actions must be taken in relation to past disposal practices on property owned
or used for disposal by the System in the past, the System could incur
substantial costs.
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 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. Based on this information
management does not believe that a causal relationship has been established or
that significant capital expenditures are appropriate to minimize
unsubstantiated risks. NU is closely monitoring research and government policy
developments.
The System supports further research into the subject and is participating
in the funding of the National EMF Research and Public Information Dissemination
Program and other industry-sponsored studies. 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.
The Connecticut Interagency EMF Task Force (Task Force) provided a report
to the state legislature in January 1995. The Task Force advocates a policy of
"voluntary exposure control," which involves providing people with information
to enable them to make individual decisions about EMF exposure. Neither the
Task Force, nor any Connecticut state agency, has recommended changes to the
existing electrical supply system. The Connecticut Siting Council previously
adopted a set of EMF "best management practices," which are now considered in
the justification, siting and design of new transmission lines and substations.
The Siting Council also opened a generic docket in 1994 to conduct a life-cycle
cost analysis of overhead and underground transmission lines, which was mandated
by PA-176. This Act was adopted by the General Assembly in part due to public
EMF concerns.
EMF has become increasingly important as a factor in facility siting
decisions in many states. Several bills involving EMF were introduced in
Massachusetts in 1994, with no action taken. These bills were similar to ones
introduced in previous years, on which no action was taken.
CL&P has been the focus of media reports charging that EMF associated with
a CL&P substation and related distribution lines in Guilford, Connecticut, are
linked with various cancers and other illnesses in several nearby residents.
See Item 3, Legal Proceedings, for information about two suits brought by
plaintiffs who now live or formerly lived near that substation.
FERC HYDRO PROJECT LICENSING
Federal Power Act licenses may be issued for hydroelectric projects for
terms of up to 50 years as determined by FERC. Upon the expiration of a
license, any hydroelectric project so licensed is subject to reissuance by FERC
to the existing licensee or to others upon payment to the licensee of the lesser
of fair value or the net investment in the project plus severance damages less
certain amounts earned by the licensee in excess of a reasonable rate of return.
The System companies hold FERC licenses for thirteen hydroelectric projects
located in Connecticut, Massachusetts and New Hampshire. Four of the System
licenses expired on December 31, 1993 (WMECO's Gardners Falls Project and PSNH's
Ayers Island, Smith and Gorham Projects). On August 1, 1994, FERC issued new
30-year licenses to PSNH for the continued operation of the Smith and Gorham
Projects. Although rehearing requests on these new licenses are pending with
FERC, it is anticipated that it will be economic for PSNH to continue operation
of these projects. FERC has issued annual licenses allowing the Gardners Falls
and Ayers Island Projects to continue operations pending completion of the
relicensing process. It is not known whether FERC will require any substantial
changes in the operation or design of these two projects if and when it issues
new licenses.
The license for HWP's Holyoke Project expires in late 1999. The
relicensing process for this project began in 1994.
At the time of relicensing and for certain matters during the term of an
existing license, FERC can direct changes in hydro project operation,
maintenance and design to accommodate environmental, recreational, or
navigational needs. At present, the U.S. Fish and Wildlife Service is
considering a petition to place the Atlantic Salmon on the endangered species
list. If such designation is granted, System hydroelectric projects along the
Connecticut River, the Merrimack River and their tributaries may be required to
make operational and/or design changes to mitigate any adverse effects on the
Atlantic Salmon. The System cannot estimate the cost of such mitigation actions
at this time.
FERC recently 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 at an appropriate time.
EMPLOYEES
As of December 31, 1994, the System companies had approximately 9,395 full
and part time employees on their payrolls, of which approximately 2,601 were
employed by CL&P, approximately 1,390 by PSNH, approximately 619 by WMECO,
approximately 112 by HWP, approximately 1,312 by NNECO, approximately 2,456 by
NUSCO and approximately 905 by North Atlantic. NU, NAEC and Charter Oak have no
employees. Approximately 2,325 employees of CL&P, PSNH, WMECO, North Atlantic
and HWP are covered by union agreements, which expire between October 1994 and
May 1996. The two union agreements that expired on October 1, 1994 cover 370
employees of WMECO and HWP and are currently under negotiation. Management
cannot predict the timing or terms of these new contracts.
SUBSEQUENT EVENTS
COMPETITION AND MARKETING - RETAIL MARKETING
On March 23, 1995, the Energy and Technology Committee of the Connecticut
General Assembly passed a bill that would create a task force to study
restructuring of the electric industry in Connecticut. If enacted, the bill
would require a preliminary report to the committee by February 1, 1996, and a
final report by January 1, 1997. The bill now goes to the state Senate and
House of Representatives where CL&P will be proposing changes.
RATES
CONNECTICUT RETAIL RATES
On March 22, 1995, the System introduced its plan, entitled "Path to a
Competitive Future," for the future of the electric industry and related
regulation in Connecticut in a filing submitted to the DPUC in its investigation
into the potential restructuring of the electric utility industry initiated
earlier this year. The plan is a comprehensive four-phase approach to enhancing
CL&P's customer satisfaction and market efficiency in Connecticut. It calls for
several significant changes in electricity pricing, in the ability to introduce
new products and services, in methods of rate-setting, and in the composition of
NEPOOL. The two-year first phase began in early 1995. The second and third
phases, which involve the transition to a more efficient market, would each last
an estimated four to six years. The final stage--a fully competitive market for
electricity--could begin once all issues relating to traditional utility
regulation have been thoroughly addressed and relevant transition costs have
been recovered from customers. Other similar approaches, tailored to the
specific needs of their service territories, are to be introduced this spring by
NU's other operating company subsidiaries, PSNH and WMECO, in ongoing
restructuring proceedings in New Hampshire and Massachusetts, respectively.
NEW HAMPSHIRE RETAIL RATES
On March 17, 1995 a status conference was held with the NHPUC relating to
PSNH's negotiations with the wood-fired NUGs. The parties reported that an
agreement in principle had been reached with all but one of the owners of the
wood-fired NUGs. It is expected that settlement agreements and purchase power
contracts with the settling owners will be drafted, executed and filed with the
NHPUC as soon as possible. The NHPUC will consider approval of the settlements
in proceedings to begin in the late Spring of 1995. Negotiations are continuing
with the nonsettling owner, who owns two plants.
FINANCING PROGRAM - FINANCING LIMITATIONS
The amount, in millions, of short-term debt outstanding as of March 20,
1995 was $91.5 for NU, $88.3 for CL&P, $0 for PSNH, $14.3 for WMECO, $0 for HWP,
$0 for NAEC, $0 for NNECO, $17.2 for RRR, $4.5 for Quinnehtuk and $2.2 for HEC,
or a total of $218.
ELECTRIC OPERATIONS - NUCLEAR GENERATION
NUCLEAR PLANT PERFORMANCE
The average capacity factor for the operating nuclear units in the United
States for calendar 1994 was 72.5 percent.
MILLSTONE UNITS
Management's ongoing evaluation of the current Millstone 2 extended
refueling and maintenance outage, which has been under way since October 1,
1994, has concluded that based on currently available information, the unit is
now expected to resume operations in May 1995, following an NRC assessment of
the unit's readiness to restart.
CONNECTICUT YANKEE
The CY planned refueling and maintenance outage which began on January 28,
1995 has been extended for approximately two weeks due to overall work progress
and emergent work. The plant is expected to return to service in early April
1995.
MAINE YANKEE
MY, like other pressurized water reactors, has been experiencing
degradation of its steam generator tubes, principally in the form of
circumferential cracking which, until early 1995, was believed to be limited to
a relatively small number of steam generator tubes. In the past the detection
of defects has resulted in the plugging of those tubes to prevent their
subsequent use. During the refueling and maintenance shutdown that commenced in
early February 1995, MYAPC detected an increased rate of degradation of MY's
steam generator tubes, in excess of the number expected, and is currently
evaluating several courses of action to address the matter. This circumstance
is likely to adversely affect the operation of MY and may result in substantial
cost to MYAPC. MYAPC cannot now predict what course of action it will choose or
to what extent the operation of MY will be affected. See "Nuclear Generation-
General" for information about the ownership interests of CL&P, PSNH and WMECO
in MYAPC.
Item 2. Properties
The physical properties of the System are owned or leased by subsidiaries
of NU. CL&P's principal plants and other properties are located either on land
which is owned in fee or on land, as to which CL&P owns perpetual occupancy
rights adequate to exclude all parties except possibly state and federal
governments, which has been reclaimed and filled pursuant to permits issued by
the United States Army Corps of Engineers. The principal properties of PSNH are
held by it in fee. In addition, PSNH leases space in an office building under a
30-year lease expiring in 2002. WMECO's principal plants and a major portion of
its other properties are owned in fee, although one hydroelectric plant is
leased. NAEC owns a 35.98 percent interest in Seabrook 1 and approximately 719
acres of exclusion area land located around the unit. In addition, CL&P, PSNH,
and WMECO have certain substation equipment, data processing equipment, nuclear
fuel, nuclear control room simulators, vehicles, and office space that are
leased. With few exceptions, the System companies' lines are located on or
under streets or highways, or on properties either owned or leased, or in which
the company has appropriate rights, easements, or permits from the owners.
CL&P's properties are subject to the lien of its first mortgage indenture.
PSNH's properties are subject to the lien of its first mortgage indenture. In
addition, PSNH's outstanding term loan and revolving credit agreement borrowings
are secured by a second lien, junior to the lien of the first mortgage
indenture, on PSNH property located in New Hampshire. WMECO's properties are
subject to the lien of its first mortgage indenture. NAEC's First Mortgage Bonds
are secured by a lien on the Seabrook 1 interest described above, and all rights
of NAEC under the Seabrook Power Contract. In addition, CL&P's and WMECO's
interests in Millstone 1 are subject to second liens for the benefit of lenders
under agreements related to 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 owning company.
The System companies' and NAEC's properties are well maintained and are in
good operating condition.
Transmission and Distribution System
At December 31, 1994, the System companies owned 103 transmission and 429
distribution substations that had an aggregate transformer capacity of
25,001,996 kilovoltamperes (kVa) and 9,145,129 kVa, respectively; 3,054 circuit
miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV,
and 194 cable miles of underground transmission lines ranging from 69 kV to 138
kV; 32,507 pole miles of overhead and 1,893 conduit bank miles of underground
distribution lines; and 384,367 line transformers in service with an aggregate
capacity of 15,625,000 kVa.
Electric Generating Plants
As of December 31, 1994, the electric generating plants of the System
companies and NAEC, and the System companies' entitlements in the generating
plants of the three operating Yankee regional nuclear generating companies were
as follows (See "Item 1. Business - Electric Operations, Nuclear Generation" for
information on ownership and operating results for the year.):
Claimed
Plant name Year Capability*
Owner (location) Type Installed (kilowatts)
----- ---------- ---- --------- -----------
CL&P Millstone(Waterford,CT)
Unit 1 Nuclear 1970 524,637
Unit 2 Nuclear 1975 708,345
Unit 3 Nuclear 1986 606,453
Seabrook (Seabrook,NH) Nuclear 1990 46,688
CT Yankee (Haddam,CT) Nuclear 1968 201,204
ME Yankee (Wiscasset,ME) Nuclear 1972 94,832
VT Yankee (Vernon,VT) Nuclear 1972 44,570
---------
Total Nuclear-Steam Plants (7 units) 2,226,729
Total Fossil-Steam Plants (9 units) 1954-73 1,803,000
Total Hydro-Conventional (25 units) 1903-55 98,930
Total Hydro-Pumped Storage (7 units) 1928-73 905,150
Total Internal Combustion (16 units) 1966-86 413,200
---------
Total CL&P Generating Plant (64 units) 5,447,009
=========
PSNH Millstone(Waterford,CT)
Unit 3 Nuclear 1986 32,624
CT Yankee (Haddam,CT) Nuclear 1968 29,160
ME Yankee (Wiscasset,ME) Nuclear 1972 39,514
VT Yankee (Vernon,VT) Nuclear 1972 18,737
---------
Total Nuclear-Steam Plants (4 units) 120,035
Total Fossil-Steam Plants (7 units) 1952-78 1,004,065
Total Hydro-Conventional (20 units) 1917-83 67,510
Total Internal Combustion (5 units) 1968-70 107,050
---------
Total PSNH Generating Plant (36 units) 1,298,660
=========
Claimed
Plant name Year Capability*
Owner (location) Type Installed (kilowatts)
----- ---------- ---- --------- -----------
WMECO Millstone(Waterford,CT)
Unit 1 Nuclear 1970 123,063
Unit 2 Nuclear 1975 166,155
Unit 3 Nuclear 1986 140,216
CT Yankee (Haddam,CT) Nuclear 1968 55,404
ME Yankee (Wiscasset,ME) Nuclear 1972 23,708
VT Yankee (Vernon,VT) Nuclear 1972 11,741
---------
Total Nuclear-Steam Plants (6 units) 520,287
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 63,500
---------
Total WMECO Generating Plant (41 units) 1,006,897
=========
NAEC Seabrook (Seabrook,NH) Nuclear 1990 413,793
=========
HWP Mt. Tom (Holyoke,MA) Fossil-Steam 1960 147,000
Total Hydro-Conventional (15 units) 1905-83 43,560
---------
Total HWP Generating Plant (16 units) 190,560
=========
NU Millstone(Waterford,CT)
SYSTEM Unit 1 Nuclear 1970 647,700
Unit 2 Nuclear 1975 874,500
Unit 3 Nuclear 1986 779,293
Seabrook (Seabrook,NH) Nuclear 1990 460,481
CT Yankee (Haddam,CT) Nuclear 1968 285,768
ME Yankee (Wiscasset,ME) Nuclear 1972 158,054
VT Yankee (Vernon,VT) Nuclear 1972 75,048
---------
Total Nuclear-Steam Plants (7 units) 3,280,844
Total Fossil-Steam Plants (18 units) 1952-78 3,061,065
Total Hydro-Conventional (87 units) 1903-83 320,910**
Total Hydro-Pumped Storage (7 units) 1928-73 1,110,350
Total Internal Combustion (24 units) 1966-86 583,750
---------
Total NU SYSTEM Generating Plant
Including Regional Yankees (143 units) 8,356,919
=========
Excluding Regional Yankees (140 units) 7,838,049
=========
*Claimed capability represents winter ratings as of December 31, 1994.
**Total Hydro-Conventional capability includes the Cobble Mtn.
plant's 33,960 kW which is leased from the City of Springfield, MA.
Franchises
NU's operating subsidiaries hold numerous franchises in the territories
served by them.
CL&P. Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits and
consents of public authority and others prescribed by statute, CL&P has, subject
to certain exceptions not deemed material, valid franchises free from burdensome
restrictions to sell electricity in the respective areas in which it is now
supplying such service.
In addition to the right to sell electricity as set forth above, the
franchises of CL&P include, among others, rights and powers to manufacture,
generate, purchase, transmit and distribute electricity, to sell electricity at
wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on public highways and grounds, all subject to such
consents and approvals of public authority and others as may be required by law.
The franchises of CL&P include the power of eminent domain.
PSNH. Subject to the power of alteration, amendment or repeal by the
General Court (legislature) of the State of New Hampshire and subject to certain
approvals, permits and consents of public authority and others prescribed by
statute, PSNH has, subject to certain exceptions not deemed material, valid
franchises free from burdensome restrictions to sell electricity in the
respective areas in which it is now supplying such service.
In addition to the right to sell electricity as set forth above, the
franchises of PSNH include, among others, rights and powers to manufacture,
generate, purchase, transmit and distribute electricity, to sell electricity at
wholesale to other utility companies and municipalities and to erect and
maintain certain facilities on certain public highways and grounds, all subject
to such consents and approvals of public authority and others as may be required
by law. The franchises of PSNH include the power of eminent domain.
NNECO. Subject to the power of alteration, amendment or repeal by the
General Assembly of Connecticut and subject to certain approvals, permits and
consents of public authority and others prescribed by statute, NNECO has a valid
franchise free from burdensome restrictions to sell electricity to utility
companies doing an electric business in Connecticut and other states.
In addition to the right to sell electricity as set forth above, the
franchise of NNECO includes, among others, rights and powers to manufacture,
generate and transmit electricity, and to erect and maintain facilities on
certain public highways and grounds, all subject to such consents and approvals
of public authority and others as may be required by law.
WMECO. WMECO is authorized by its charter to conduct its electric business
in the territories served by it, and has locations in the public highways for
transmission and distribution lines. Such locations are granted pursuant to the
laws of Massachusetts by the Department of Public Works of Massachusetts or
local municipal authorities and are of unlimited duration, but the rights
thereby granted are not vested. Such locations are for specific lines only,
and, for extensions of lines in public highways, further similar locations must
be obtained from the Department of Public Works of Massachusetts or the local
municipal authorities. In addition, WMECO has been granted easements for its
lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority.
HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly
owned subsidiary HP&E, are authorized by their charters to conduct their
businesses in the territories served by them. HWP's electric business is
subject to the restriction that sales be made by written contract in amounts of
not less than 100 horsepower, except for municipal customers in the counties of
Hampden or Hampshire, Massachusetts and except for customers who occupy property
in which HWP has a financial interest, by ownership or purchase money mortgage.
HWP also has certain dam and canal and related rights, all subject to such
consents and approvals of public authorities and others as may be required by
law. The two companies have locations in the public highways for their
transmission and distribution lines. Such locations are granted pursuant to the
laws of Massachusetts by the Department of Public Works of Massachusetts or
local municipal authorities and are of unlimited duration, but the rights
thereby granted are not vested. Such locations are for specific lines only and,
for extensions of lines in public highways, further similar locations must be
obtained from the Department of Public Works of Massachusetts or the local
municipal authorities. The two companies have no other utility franchises.
NAEC. NAEC is authorized by the NHPUC to own and operate its interest in
Seabrook 1.
Item 3 - Legal Proceedings
1. Litigation Relating to Electric and Magnetic Fields
In December 1991, NU and CL&P were sued in Connecticut Superior Court by
Melissa Bullock, a nineteen-year old woman, and her mother, Suzanne Bullock,
both residents of 28 Meadow Street in Guilford, Connecticut. The plaintiffs
allege that they have lived in close proximity to CL&P's Meadow Street
substation and distribution lines since 1979. The suit claims that Melissa
Bullock suffers from a form of brain cancer and related physical and
psychological injuries, which were "brought on as a result of exposure in her
home to electromagnetic radiation generated by the defendants." Suzanne Bullock
claims various physical and psychological injuries, and a diminution in the
value of her property. The various counts against NU and CL&P include
allegations of negligence, product liability, nuisance, unfair trade practices
and strict liability. The suit seeks monetary damages, both compensatory and
punitive, in as-yet unspecified amounts, as well as an injunction to cease
emission of "dangerous levels" of electric and magnetic fields (EMF) into the
plaintiffs' home.
The plaintiffs are represented in part by counsel with a nationwide
emphasis on similar litigation, and management considers this lawsuit to be a
test case. The case is presently in the pre-trial discovery process. Trial is
not anticipated until 1996 at the earliest.
In January 1992, a related lawsuit by two other plaintiffs also alleging
cancer from EMF emanating from CL&P's Meadow Street substation and distribution
lines was served on CL&P and NU. The plaintiffs are represented by the same
counsel as the Bullocks, and the claims are nearly identical to the Bullocks'
suit. This case is also in the pretrial discovery process; a trial date is not
yet known.
Management believes that the allegations that EMF caused or contributed to
the plaintiffs' illnesses are not supported by current scientific studies. NU
and CL&P intend to defend the lawsuits vigorously. For information on EMF
studies and state and federal initiatives, see "Item 1. Business - Regulatory
and Environmental Matters - Electric and Magnetic Fields."
2. Massachusetts Municipal Wholesale Electric Company / 30th Amendment to
NEPOOL Agreement Settlement
NU's operating subsidiaries, CL&P, PSNH, WMECO, HWP and HP&E (collectively,
the Company) and a number of other utilities that are members of NEPOOL, as
defendants, are involved in two pending actions relating to pool planning and
future transmission service issues under the NEPOOL Agreement. An action in
Suffolk Superior Court in Massachusetts was brought by a number of the
Massachusetts electric municipal systems and the Massachusetts Municipal
Wholesale Electric Company requesting damages and injunctive relief. FERC
subsequently commenced an action when the Company and 26 other participants
filed an amendment to the NEPOOL Agreement with FERC that concerns many of the
issues raised in the Massachusetts litigation.
On February 10, 1995, FERC issued an order accepting a withdrawal of the
amendment to the NEPOOL Agreement. The withdrawal was part of a settlement
agreement signed by substantially all of the parties and intervenors, which will
also result in the withdrawal by the settling plaintiffs of their Superior Court
complaint after the FERC action is terminated and no longer subject to appeal.
The 30-day period in which to appeal from the FERC order expired without the
filing of requests for rehearing, and the order has become final.
3. Southeastern Connecticut Regional Resources Recovery Authority (SCRRRA) -
Application of the Municipal Rate
This matter involves three separate disputes over the rates that apply to
CL&P's purchases of the generation of the SCRRRA project in Preston,
Connecticut.
Municipal Rate Litigation: In 1990, CL&P initiated a challenge
--------------------------
district court to the DPUC's approval of an electricity purchase contract for
the SCRRRA project under Connecticut's so-called "municipal rate law." Under
this law, CL&P would be required to purchase a portion of the electricity from
the resource recovery facility at a rate equal to the retail rate that CL&P
charges municipalities for electricity ("municipal rate"), which is
significantly higher than CL&P's avoided costs. The district court subsequently
ordered the parties to seek FERC's resolution of this matter. On January 11,
1995, FERC ruled that a state cannot require an electric utility to enter into a
contract paying a qualifying facility more than the utility's avoided costs.
The FERC decision is subject to rehearing and can be appealed to the United
States Court of Appeals. In early February 1995, several petitions for
rehearing were filed. Should CL&P ultimately prevail, the benefits to CL&P
customers would be approximately $13 million.
Non-Participant Towns: CL&P also contested SCRRRA's claim that CL&P must
---------------------
pay the municipal rate for the portion of the project's electricity that is
derived from the trash of towns that are not long-term participants in the
project. On April 20, 1994, the DPUC granted SCRRRA's request that the
municipal rate be made applicable to the non-participant's portion of
electricity.
On June 9, 1994, CL&P filed an appeal of the DPUC's ruling in the Hartford
Superior Court. A total of approximately $3.5 million is in dispute for the
years 1992 through 1994. The rate CL&P would be required to pay would also be
substantially higher in later years if the DPUC's ruling is upheld. On February
6, 1995, the Superior Court granted the SCRRRA's motion to stay this proceeding
until FERC issues a final decision on the municipal rate law. This case could
be moot once the FERC decision is final.
Excess Capacity: CL&P also contested SCRRRA's claim that CL&P must
---------------
purchase at the applicable contract rates (each of which is higher than CL&P's
current avoided costs) any excess of the project's generation above 13.85 MW per
hour. On May 3, 1994, the Connecticut Appellate Court affirmed a Superior
Court's ruling that the DPUC should decide this issue. CL&P has answered
interrogatories issued by the DPUC and further DPUC proceedings on this dispute
are expected. The amount in dispute for the period 1992 through August 1994 is
approximately $470,000. However, assuming SCRRRA were permitted to charge the
municipal rate for an assumed project generation of 14.5 MW per hour (i.e., 5%
greater than 13.85 MW), the amount in dispute could be as much as $4.5 million
(cumulative present value) for the remaining term of the contract with SCRRRA.
This dispute will not be resolved by the FERC decision on the municipal rate
statute because each of the contract rates is greater than CL&P's current
avoided costs.
On June 20, 1994, the Connecticut General Assembly overrode Governor
Weicker's veto of a bill that purportedly resolves the non-participant towns and
excess capacity disputes against CL&P. CL&P has a number of options in response
to this legislation including challenging its constitutionality in either
federal or state court. The law took effect on October 1, 1994, but has not yet
been applied against CL&P in either of these proceedings.
4. CL&P's 1992-1993 Retail Rate Case
In June 1993, the DPUC issued a decision approving a multi-year rate plan
for CL&P. Two appeals have been filed from the 1993 Decision, one by CL&P and
the other by the Connecticut Office of Consumer Counsel (OCC) and the City of
Hartford (City). The two appeals were consolidated. On May 9, 1994, the City's
appeal was dismissed by the Hartford Superior Court on jurisdictional grounds,
and the City appealed that dismissal to the Connecticut Appellate Court. The
Supreme Court of Connecticut transferred the jurisdictional issue to itself on
August 2, 1994. Oral argument is expected to be scheduled in the spring of
1995, and a decision is expected by September 1995.
5. Connecticut Indian Land Claims
Numerous lawsuits asserting land claims in Connecticut have been filed in
either state and federal court or threatened by a group called the Golden Hill
Paugussett Tribe of Indians (the Paugussetts). These actions could impact the
title to certain NU system real estate in the eight affected Connecticut towns.
Title to the properties of thousands of other owners, including homeowners, has
been similarly threatened. However, the only case to specifically name CL&P as
a defendant, a class action suit affecting approximately 1,500 property owners
in Southbury, was dismissed by the trial court, and the dismissal was
subsequently upheld on appeal by the Connecticut Supreme Court on the grounds
that the plaintiff lacked standing to act on behalf of the Paugussetts. The
outcome of the present or potential litigation either by the Paugussetts or by
other groups claiming to be "Indian tribes" cannot be predicted at this time.
However, a number of possible defenses exist to Indian land claims in
Connecticut, and the Paugussetts' success on the merits appears unlikely.
6. FERC - PSNH Acquisition Case
In 1992, FERC's approval of NU's acquisition of PSNH was appealed to the
United States Court of Appeals for the First Circuit. The Court affirmed the
decision approving the merger but ordered FERC to address whether, if FERC had
applied a more stringent "public interest standard" to the Seabrook power
contract, any modifications would have been necessary. Purporting to apply this
standard, FERC reaffirmed certain modifications to the contract, interpreting
the standard liberally to allow it to intervene in contracts on behalf of
non-parties to the contract. NU requested rehearing, arguing that FERC had not
applied the appropriate standard, which request was denied by FERC on July 8,
1994. On September 6, 1994, NU filed a Petition for Review with the First
Circuit Court of Appeals concerning FERC's application of a "public interest
standard" to the Seabrook Power Contract, which Petition is expected to be heard
April 3, 1995.
7. Other Legal Proceedings
The following sections of Item 1 "Business" discuss additional legal
proceedings: "Rates" for information about CL&P's rate and fuel clause
adjustment clause proceedings and the Seabrook Power Contract; "Electric
Operations -- Generation and Transmission" for information about proceedings
relating to power transmission issues; "Electric Operations -- Nuclear
Generation" for information related to Seabrook joint owners, high-level and
low-level radioactive waste disposal, decommissioning matters and NRC
regulation; "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; and "FINANCIAL CONDITION -- Property Taxes" in the
NU 1994 Annual Report for information about proceedings involving utility
property tax appeal matters.
Item 4. Submission of Matters to a Vote of Security Holders
No Event that would be described in response to this item occurred
with respect to NU, CL&P, WMECO, PSNH or NAEC.
PART II
Item 5. Market for the Registrants' Common Equity and Related
Shareholder Matters
NU. The common shares of NU are listed on the New York Stock Exchange.
The ticker symbol is "NU," although it is frequently presented as "Noeast Util"
in various financial publications. The high and low sales prices for the past
two years, by quarters, are shown below.
Year Quarter High Low
---- ------- ---- ---
1994 First $25 3/4 23
Second 24 7/8 21 1/4
Third 24 5/8 20 3/8
Fourth 23 3/8 21 1/4
1993 First $28 7/8 $25 1/2
Second 28 3/4 25 1/4
Third 28 1/8 26 1/4
Fourth 27 3/8 22
As of January 31, 1995, there were 137,978 common shareholders of record
of NU. As of the same date, there were a total of 134,210,261 common shares
issued, including approximately 9.1 million shares held in an ESOP trust.
NU declared and paid quarterly dividends of $0.44 in 1994 and $0.44 in
1993. On January 24, 1995, the Board of Trustees declared a dividend of $0.44
per share, payable on March 31, 1995 to holders of record on March 1, 1995. The
declaration of future dividends may vary depending on capital requirements and
income as well as financial and other conditions existing at the time.
Information with respect to dividend restrictions for NU and its
subsidiaries is contained in Item 1. Business under the caption "Financing
Program--Financing Limitations" and in Note (b) to the "Consolidated Statements
of Common Shareholders' Equity" on page 32 of NU's 1994 Annual Report to
Shareholders, which information is incorporated herein by reference.
CL&P, PSNH, WMECO, and NAEC. The information required by this item is not
applicable because the common stock of CL&P, PSNH, WMECO, and NAEC is held
solely by NU.
Item 6. Selected Financial Data
NU. Reference is made to information under the heading "Selected
Consolidated Financial Data" contained on pages 48 and 49 of NU's 1994
Annual Report to Shareholders, which information is incorporated herein by
reference.
CL&P. Reference is made to information under the heading "Selected
Financial Data" contained on page 40 of CL&P's 1994 Annual Report, which
information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected
Financial Data" contained on pages 37 and 38 of PSNH's 1994 Annual Report, which
information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected
Financial Data" contained on page 33 of WMECO's 1994 Annual Report, which
information is incorporated herein by reference.
NAEC. Reference is made to information under the heading "Selected
Financial Data" contained on page 21 of NAEC's 1994 Annual Report, which
information is incorporated herein by reference.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
NU. Reference is made to information under the heading "Management's
Discussion and Analysis" contained on pages 16 through 23 in NU's 1994 Annual
Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 32 through 39 in CL&P's 1994 Annual Report, which information
is incorporated herein by reference.
PSNH. Reference is made to information under the heading
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" contained on pages 29 through 35 in PSNH's 1994
Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 27 through 32 in WMECO's 1994 Annual Report, which
information is incorporated herein by reference.
NAEC. Reference is made to information under the heading "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained on pages 18 through 20 in NAEC's 1994 Annual Report, which information
is incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data
NU. Reference is made to information under the headings "Company Report,"
"Report of Independent Public Accountants," "Consolidated Statements of Income,"
"Consolidated Statements of Cash Flows," "Consolidated Statements of Income
Taxes," "Consolidated Balance Sheets," "Consolidated Statements of
Capitalization," "Consolidated Statements of Common Shareholders' Equity,"
"Notes to Consolidated Financial Statements," and "Consolidated Statements of
Quarterly Financial Data" contained on pages 24 through 47 in NU's 1994 Annual
Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the headings "Consolidated
Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements
of Cash Flows," "Consolidated Statements of Common Stockholder's Equity," "Notes
to Consolidated Financial Statements," "Report of Independent Public
Accountants," and "Statements of Quarterly Financial Data" contained on pages 1
through 31 and page 40 in CL&P's 1994 Annual Report, which information is
incorporated herein by reference.
PSNH. Reference is made to information under the headings "Balance
Sheets," "Statements of Income," "Statements of Cash Flows," Statements of
Common Equity," "Notes to Financial Statements," "Report of Independent Public
Accountants," "Independent Auditors' Report," and "Statements of Quarterly
Financial Data" contained on pages 1 through 28 and page 39 in PSNH's 1994
Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Balance
Sheets," "Statements of Income," "Statements of Cash Flows," "Statements of
Common Stockholder's Equity," "Notes to Financial Statements," "Report of
Independent Public Accountants," and "Statements of Quarterly Financial Data"
contained on pages 1 through 26 and page 33 in WMECO's 1994 Annual Report, which
information is incorporated herein by reference.
NAEC. Reference is made to information under the headings "Balance Sheet,"
"Statement of Income," "Statement of Cash Flows," "Statement of Common
Stockholder's Equity," "Notes to Financial Statements," "Report of Independent
Public Accountants," and "Statement of Quarterly Financial Data" contained on
pages 1 through 17 and page 21 in NAEC's 1994 Annual Report which information is
incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
No event that would be described in response to this item has occurred with
respect to NU, CL&P, PSNH, WMECO, or NAEC.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
NU.
In addition to the information provided below concerning the executive
officers of NU, incorporated herein by reference are pages 1 through 13 of the
definitive proxy statement for solicitation of proxies by NU's Board of
Trustees, dated April 3, 1995 and filed with the Commission pursuant to Rule
14a-6 under the Securities Exchange Act of 1934 (the Act).
First First
Positions Elected Elected
Name Held an Officer a Trustee
--------------------- --------- ---------- ---------
William B. Ellis CHB, T 06/15/76 04/26/77
Bernard M. Fox P, CEO, T 05/01/83 05/20/86
CL&P.
First First
Positions Elected Elected
Name Held an Officer a Director
--------------------- --------- ---------- ----------
Robert G. Abair D - 01/01/89
Robert E. Busch EVP, CFO, D 06/01/87 06/01/87
William B. Ellis CH, D 06/15/76 06/15/76
Bernard M. Fox VC, 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
John B. Keane VP, T, D 08/01/92 08/01/92
Francis L. Kinney SVP 04/24/74 -
Hugh C. MacKenzie P, D 07/01/88 06/06/90
John W. Noyes 07/01/87 -
John F. Opeka D - 06/10/85
PSNH.
First First
Positions Elected Elected
Name Held an Officer a Director
------------------- --------- ---------- ----------
Robert E. Busch EVP, CFO 06/05/92
John C. Collins D - 10/19/92
William B. Ellis CH, D 06/05/92 06/05/92
William T. Frain, Jr. P, COO, D 03/18/71 02/01/94
Bernard M. Fox VC, CEO, D 06/05/92 06/05/92
Cheryl W. Grise D 02/06/95
Gerald Letendre D - 10/19/92
Hugh C. MacKenzie D - 02/01/94
Jane E. Newman D - 10/19/92
John W. Noyes VP, CONT 06/05/92 -
Robert P. Wax VP, SEC, GC, D 08/01/92 02/01/93
WMECO.
First First
Positions Elected Elected
Name Held an Officer a Director
------------------- --------- ---------- ----------
Robert G. Abair VP, CAD, D 09/06/88 01/01/89
Robert E. Busch EVP, CFO, D 06/01/87 06/01/87
William B. Ellis CH, D 06/15/76 06/15/76
Bernard M. Fox VC, 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
John B. Keane VP, TR, D 08/01/92 08/01/92
Francis L. Kinney SVP 04/24/74 -
Hugh C. MacKenzie P, D 07/01/88 06/06/90
John W. Noyes VP, CONT 04/01/92 -
John F. Opeka D - 06/10/85
NAEC.
First First
Positions Elected Elected
Name Held an Officer a Director
--------------------- --------- ---------- ----------
Robert E. Busch P, CFO, D 10/21/91 10/16/91
William B. Ellis CH, D 10/21/91 10/16/91
Ted C. Feigenbaum SVP, D 10/21/91 10/16/91
Bernard M. Fox VC, CEO, D 10/21/91 10/16/91
William T. Frain, Jr. D - 02/01/94
Cheryl W. Grise SVP, D 10/21/91 01/01/94
Francis L. Kinney SVP 10/21/91 -
John B. Keane VP, TR, D 08/01/92 08/01/92
Hugh C. MacKenzie D - 01/01/94
John W. Noyes VP, CONT 10/21/91 -
John F. Opeka EVP, D 10/21/91 10/16/91
KEY: CAO - Chief Administrative Office EVP - Executive Vice President
CEO - Chief Executive Officer GC - General Counsel
CFO - Chief Financial Officer P - President
CH - Chairman SEC - Secretary
CHB - Chairman of the Board SVP - Senior Vice President
COO - Chief Operating Officer T - Trustee
CONT - Controller TR - Treasurer
D - Director VC - Vice Chairman
VP - Vice President
Name Age Business Experience During Past 5 Years
----------------- --- ---------------------------------------
Robert G. Abair (1) 56 Elected Vice President and Chief Administrative
Officer of WMECO in 1988.
Robert E. Busch (2) 48 Elected President and Chief Financial Officer
of NAEC in 1994; elected Executive Vice
President and Chief Financial Officer of NU,
CL&P, PSNH, and WMECO in 1992; previously
Executive Vice President and Chief Financial
Officer of NAEC since 1992; Senior Vice
President and Chief Financial Officer of NU,
CL&P and WMECO since 1990.
John C. Collins (3) 50 Chief Executive Officer, The Hitchcock Clinic,
Dartmouth - Hitchcock Medical Center since
1977.
William B. Ellis (4) 54 Elected Chairman of the Board of NU in 1993;
elected Chairman of CL&P, NAEC, PSNH and WMECO
in 1993; previously Chairman of the Board and
Chief Executive Officer of NU and Chairman and
Chief Executive Officer of CL&P and WMECO since
1987, NAEC since 1991 and PSNH since 1992.
Ted C. Feigenbaum (5) 44 Elected Senior Vice President of NAEC in 1991;
previously Senior Vice President and Chief
Nuclear Officer of PSNH June, 1992 to August,
1992; previously President and Chief Executive
Officer - New Hampshire Yankee Division of PSNH
October, 1990 to June, 1992 and Chief Nuclear
Production Officer of PSNH January, 1990 to
June, 1992; Senior Vice President and Chief
Operating Officer - New Hampshire Yankee
Division of PSNH (1989-1990).
Bernard M. Fox (6) 52 Elected Vice Chairman of CL&P and WMECO, and
Vice Chairman and Chief Executive Officer of
NAEC, in 1994; previously Chief Executive
Officer of NU, CL&P, PSNH, WMECO and NAEC in
1993; previously President and Chief Operating
Officer of NU, CL&P and WMECO in 1990 and NAEC
since 1991; Vice Chairman of PSNH since 1992;
previously President and Chief Operating and
Financial Officer of NU, CL&P and WMECO since
1987.
William T. Frain, Jr.(7) 53 Elected President and Chief Operating Officer
of PSNH in 1994; previously Senior Vice
President of PSNH since 1992; previously
Treasurer of PSNH since 1991 and Vice President
of PSNH since 1982.
Cheryl W. Grise 42 Elected Senior Vice President-Human Resources
and Administrative Services of CL&P, WMECO and
NAEC in 1994; previously Vice President-Human
Resources of NAEC since 1992 and of CL&P and
WMECO since 1991.
John B. Keane (8) 48 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, PSNH, WMECO and NAEC
since February 1, 1993; previously 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; previously
Associate General Counsel of NUSCO since 1985.
Francis L. Kinney (9) 62 Elected Senior Vice President-Governmental
Affairs of CL&P, WMECO and NAEC in 1994;
previously Vice President-Public Affairs of
NAEC since 1992 and of CL&P and WMECO since
1978.
Gerald Letendre 53 President, Diamond Casting & Machine Co., Inc.
since 1972.
Hugh C. MacKenzie (10) 52 Elected President of CL&P and WMECO in 1994;
previously Senior Vice President-Customer
Service Operations of CL&P and WMECO since
1990.
Jane E. Newman (11) 49 President, Coastal Broadcasting Corporation
since 1992; previously Assistant to the
President of the United States for Management
and Administration from 1989 to 1991.
John W. Noyes 47 Elected Vice President and Controller of NU,
CL&P, PSNH, WMECO and NAEC in 1992; previously
Vice President of CL&P and WMECO since 1987.
John F. Opeka (12) 54 Elected Executive Vice President - Nuclear of
NAEC in 1991 and of NUSCO in 1986, previously
Executive Vice President - Nuclear of CL&P and
WMECO from 1986 to 1993.
Robert P. Wax 46 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; previously Associate
General Counsel of NUSCO since 1985.
(1) Trustee of Easthampton Savings Bank.
(2) Director Connecticut Yankee Atomic Power Company.
(3) Director of Fleet Bank - New Hampshire.
(4) Director of Nuclear Electric Insurance Limited, Connecticut Mutual Life
Insurance Company, The Hartford Steam Boiler Inspection and Insurance
Company and Radian Corporation (a subsidiary of Hartford Steam Boiler) and
the Greater Hartford Chamber of Commerce; Chairman of the Board of the
Capitol Region Growth Council, Inc.; Director Emeritus of Connecticut
Yankee Atomic Power Company; Member of The National Museum of Natural
History of The Smithsonian Institution and the Science Advisory Board of
The Nature Conservancy.
(5) Director of Maine Yankee Atomic Power Company.
(6) Director of The Institute of Living, The Institute of Nuclear Power
Operations, The Connecticut Business and Industry Association, Mount
Holyoke College, Shawmut National Corp., CIGNA Corporation, Connecticut
Yankee Atomic Power Company and The Dexter Corporation.
(7) Director of Connecticut Yankee Atomic Power Company, the Business and
Industry Association of New Hampshire, the Greater Manchester Chamber of
Commerce; Trustee of Optima Health, Inc.
(8) Director of Maine Yankee Atomic Power Company, Vermont Yankee Nuclear
Power Corporation, Yankee Atomic Electric Company and Connecticut Yankee
Atomic Power Company.
(9) Director of Mid-Conn Bank.
(10) Director of Connecticut Yankee Atomic Power Company.
(11) Director of Perini Corporation, NYNEX Telecommunications and Consumers
Water Company.
(12) Director of Connecticut Yankee Atomic Power Company and Yankee Atomic
Electric Company.
There are no family relationships between any director or executive
officer and any other director or executive officer of NU, CL&P, PSNH, WMECO or
NAEC.
ITEM 11. EXECUTIVE COMPENSATION
NU.
Incorporated herein by reference are pages 8 through 13 of the definitive proxy
statement for solicitation of proxies by NU's Board of Trustees, dated April
3, 1995 and filed with the Commission pursuant to Rule 14a-6 under the Act.
SUMMARY COMPENSATION TABLE
The following table presents the cash and non-cash compensation received by
the five highest-paid executive officers of Northeast Utilities, in accordance
with rules of the SEC:
<TABLE>
<CAPTION> Annual Compensation Long Term Compensation
------------------------------ ------------------------------
Awards Payouts
--------------------- --------
Name and Year Salary Bonus ($) Other Restricted Options/ Long All Other
Principal ($) (Note 1) Annual Stock Stock Term Compensa-
Position Compen- Award(s) Apprecia- Incentive tion ($)
sation ($) tion Program (Note 2)
($) Rights(#) Payouts
($)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
---------------- ------- ------- ---------- ------- ---------- --------- -------- ---------
Bernard M. Fox 1994 544,459 (Note 3) None None None 115,771 4,500
(Note 4) 1993 478,775 180,780 None None None 61,155 7,033
(Note 5) 1992 424,517 54,340 None None None 19,493 6,860
--------------------------------------------------------------------------------------------------------
William B. Ellis 1994 457,769 (Note 3) None None None 185,003 4,500
(Note 4) 1993 521,250 160,693 None None None 87,363 None
(Note 5) 1992 522,212 97,029 None None None 30,707 None
--------------------------------------------------------------------------------------------------------
Robert E. Busch 1994 346,122 (Note 3) None None None 44,073 4,500
(Note 5) 1993 255,915 78,673 None None None 32,337 7,072
1992 236,654 27,934 None None None 10,040 6,866
--------------------------------------------------------------------------------------------------------
John F. Opeka 1994 283,069 (Note 3) None None None 54,556 4,500
(Note 5) 1993 277,304 58,259 None None None 40,014 6,875
1992 268,958 19,644 None None None 14,017 6,813
--------------------------------------------------------------------------------------------------------
Hugh C. MacKenzie 1994 245,832 (Note 3) None None None 40,449 4,500
(Note 5) 1993 192,502 51,765 None None None 28,000 5,775
1992 178,818 22,045 None None None 7,196 5,322
--------------------------------------------------------------------------------------------------------
</TABLE>
Notes:
1. Awards under the 1992 short-term program of the Northeast Utilities
Executive Incentive Plan (EIP) were paid in 1993 in the form of
unrestricted stock. Awards under the 1993 short-term EIP program were paid
in 1994 in the form of cash. In accordance with the requirements of the
SEC, these awards are included as "bonus" in the years earned.
2. "All Other Compensation" consists of employer matching contributions
under the 401(k) Plan, generally available to all eligible employees.
3. Awards under the short-term program of the EIP have typically been
made by the Committee on Organization, Compensation and Board Affairs in
April each year. Based on preliminary estimates of corporate performance,
and assuming that the individual performance levels of Messrs. Busch, Opeka
and MacKenzie approximate those of other system officers, it is estimated
that the five executive officers listed in the table above would receive
the following awards: Mr. Fox - $303,000; Mr. Ellis - $127,000;
Mr. Busch - $165,000; Mr. Opeka - $81,000; and Mr. MacKenzie - $108,000.
4. Mr. Fox served as President and Chief Operating Officer until July 1,
1993, when he became President and Chief Executive Officer. Mr. Ellis
served as Chairman of the Board and Chief Executive Officer until July 1,
1993, when he became Chairman of the Board.
5. The titles for these executive officers are listed by company in
"Item 10. Directors and Executive Officers of the Registrants."
PENSION BENEFITS
The following table shows the estimated annual retirement benefits payable
to an executive officer of Northeast Utilities 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 makes up for benefits lost through application of
certain tax code limitations on the benefits that may be provided under the
Retirement Plan, and is available to all officers. The "target benefit" further
supplements these benefits and is available to officers at the Senior Vice
President level and higher who are selected by the Board of Trustees to
participate in the target benefit and who remain in the employ of 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 above is currently eligible for a target benefit.
If an executive officer were not eligible for a target benefit at the time of
retirement, a lower level of retirement benefits would be paid.
The benefits presented are based on a straight life annuity beginning at
age 65 and do not take into account any reduction for joint and survivorship
annuity payments.
FINAL YEARS OF CREDITED SERVICE
AVERAGE
COMPENSATION
15 20 25 30 35
$200,000 $72,000 $96,000 $120,000 $120,000 $120,000
250,000 90,000 120,000 150,000 150,000 150,000
300,000 108,000 144,000 180,000 180,000 180,000
350,000 126,000 168,000 210,000 210,000 210,000
400,000 144,000 192,000 240,000 240,000 240,000
450,000 162,000 216,000 270,000 270,000 270,000
500,000 180,000 240,000 300,000 300,000 300,000
600,000 216,000 288,000 360,000 360,000 360,000
700,000 252,000 336,000 420,000 420,000 420,000
800,000 288,000 384,000 480,000 480,000 480,000
900,000 324,000 432,000 540,000 540,000 540,000
1,000,000 360,000 480,000 600,000 600,000 600,000
1,100,000 396,000 528,000 660,000 660,000 660,000
1,200,000 432,000 576,000 720,000 720,000 720,000
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 above, 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 Northeast Utilities and its subsidiaries under long term
disability plans and policies.
As of December 31, 1994, the five executive officers named in the Summary
Compensation Table above had the following years of credited service for
retirement compensation purposes: Mr. Fox - 30, Mr. Ellis - 18, Mr. Busch -
21, Mr. Opeka - 24, and Mr. MacKenzie - 29. Assuming that retirement were to
occur at age 65 for these officers, retirement would occur with 43, 29, 38, 35
and 41 years of credited service, respectively.
In 1992 Northeast Utilities entered into agreements with Messrs. Ellis and
Fox to provide for an orderly Chief Executive Officer succession. The agreement
with Mr. Ellis calls for him to work with the Board and Mr. Fox to effect the
orderly transition of his responsibilities to Mr. Fox. In accordance with the
agreement, Mr. Ellis stepped down as Chief Executive Officer as of July 1, 1993.
The agreement anticipates his retirement as of August 1, 1995.
The agreement provides that, upon his retirement, Mr. Ellis will be
entitled to receive from Northeast Utilities and its subsidiaries a target
benefit under the Supplemental Plan. His target benefit will be based on the
greater of his actual final average compensation or an amount determined as if
his salary had increased each year since 1991 at a rate equal to the average
rate of the increases of all other target benefit participants and as if he had
received incentive awards each year based on this modified salary, but with the
same performance as the Chief Executive Officer at the time. The agreement also
provides specified death and disability benefits for the period before Mr.
Ellis's 1995 retirement.
The agreement with Mr. Fox states that if he is terminated as Chief
Executive Officer without cause, he will be entitled to specified severance pay
and benefits. Those benefits consist primarily of (i) two years' base pay,
medical, dental and life insurance benefits, (ii) 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
(iii) a target benefit under the Supplemental Plan, notwithstanding that he
might not have reached age 60 on the termination date and notwithstanding other
forfeiture provisions of that plan. The agreement also provides specified death
and disability benefits. The agreement terminates two years after Northeast
Utilities gives Mr. Fox a notice of termination, but no earlier than the date he
becomes 55.
The agreements do not address the officers' normal compensation and
benefits, which are to be determined by the Committee and the Board in
accordance with their customary practices.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
NU.
Incorporated herein by reference are pages 6 through 13 of the definitive
proxy statement for solicitation of proxies by NU's Board of Trustees, dated
April 3, 1995 and filed with the Commission pursuant to Rule 14a-6 under the
Act.
CL&P, PSNH, WMECO AND NAEC.
NU owns 100% of the outstanding common stock of registrants CL&P, PSNH,
WMECO and NAEC. As of February 28, 1995, the Directors of CL&P, PSNH, WMECO and
NAEC, beneficially owned the number of shares of each class of equity securities
of NU listed below. No equity securities of CL&P, PSNH, WMECO or NAEC are owned
by the Directors and Executive Officers of their respective companies.
CL&P, PSNH, WMECO, and NAEC DIRECTORS AND NAMED EXECUTIVE OFFICERS
------------------------------------------------------------------
Amount and
Nature of
Title Of Name of Beneficial Percent of
Class Beneficial Owner Ownership (1) Class (2)
-------- ---------------------- ----------- ----------
NU Common Robert G. Abair(3) 5,323 shares
NU Common Robert E. Busch(4) 7,301 shares
NU Common John C. Collins (5)(6) 25 shares
NU Common William B. Ellis (7) 10,360 shares
NU Common Ted C. Feigenbaum(8) 299 shares
NU Common Bernard M. Fox (9) 19,911 shares
NU Common William T. Frain, Jr. 1,108 shares
NU Common Cheryl W. Grise 2,291 shares
NU Common John B. Keane (4) 1,374 shares
NU Common Francis L. Kinney (10) 2,415 shares
NU Common Gerald Letendre (5) 0 shares
NU Common Hugh C. MacKenzie(11)(12) 5,902 shares
NU Common Jane E. Newman (5) 0 shares
NU Common John W. Noyes 3,272 shares
NU Common John F. Opeka (4)(11)(13) 18,271 shares
NU Common Robert P. Wax (5) 1,963 shares
Amount beneficially owned by Directors and Executive Officers
as a group - CL&P 77,528 shares
- PSNH 70,404 shares
- WMECO 77,528 shares
- NAEC 72,504 shares
(1) Unless otherwise noted, each Director and Executive Officer of
CL&P, PSNH, WMECO and NAEC has sole voting and investment power with
respect to the listed shares. The numbers in parentheses reflect the
number of shares owned by each Director and Executive Officer under the
Northeast Utilities Service Company Supplemental Retirement and Savings
Plan (401(k) Plan), as to which the Officer has no investment power.
(2) As of February 28, 1995 there were 134,210,358 common shares of
NU outstanding. The percentage of such shares beneficially owned by
any Director or Executive Officer, or by all Directors and Executive
Officers of CL&P, PSNH, WMECO and NAEC as a group, does not exceed one
percent.
(3) Mr. Abair is a Director of CL&P and WMECO only.
(4) Messrs. Busch, Keane and Opeka are Directors of CL&P, WMECO and
NAEC only.
(5) Messrs. Collins, Letendre and Wax and Ms. Newman are Directors of
PSNH only.
(6) Mr. Collins shares voting and investment power with his wife for
25 shares.
(7) Mr. Ellis shares voting and investment power with his wife for
1,208 shares.
(8) Mr. Feigenbaum is a Director and an Executive Officer of NAEC
only.
(9) Mr. Fox shares voting and investment power with his wife for
3,031 of these shares. In addition, Mr. Fox's wife has sole voting and
investment power for 140 shares, as to which Mr. Fox disclaims
beneficial ownership.
(10) Mr. Kinney shares voting and investment power with his wife for
525 shares.
(11) Messrs. MacKenzie and Opeka are not officers of PSNH, but in
their capacity as officers (with their stated titles) of NUSCO, an
affiliate of PSNH, they perform policy-making functions for PSNH.
(12) Mr. MacKenzie shares voting and investment power with his wife
for 1,361 shares.
(13) Mr. Opeka shares voting and investment power with his wife for
1,718 shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
NU.
Incorporated herein by reference is page 15 of the definitive proxy statement
for solicitation of proxies by NU's Board of Trustees, dated April 3, 1995 and
filed with the Commission pursuant to Rule 14a-6 under the Act.
CL&P, PSNH, WMECO AND NAEC.
No relationships or transactions that would be described in response to this
item exist now or existed during 1994 with respect to CL&P, PSNH, WMECO and
NAEC.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K
(a) 1. Financial Statements:
The Report of Independent Public Accountants and
financial statements of NU, CL&P, PSNH, WMECO, and NAEC
are hereby incorporated by reference and made a part of
this report (see "Item 8. Financial Statements and
Supplementary Data").
Report of Independent Public Accountants
on Schedules S-1
Consent of Independent Public Accountants S-2
2. Schedules:
Financial Statement Schedules for NU
(Parent), NU and Subsidiaries, CL&P
and Subsidiaries, PSNH and WMECO are
listed in the Index to Financial
Statement Schedules S-3
3. Exhibits Index E-1
(b) Reports on Form 8-K:
During the fourth quarter of 1994, the companies
filed Form 8-Ks dated December 31, 1994 disclosing
the following:
o The primary reasons for lower composite nuclear
capacity factors in 1994.
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
NORTHEAST UTILITIES
-------------------
(Registrant)
Date: March 23, 1995 By /s/William B. Ellis
-------------- ---------------------------
William B. Ellis
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates
indicated.
Date Title Signature
---- ----- ---------
March 23, 1995 Trustee and Chairman /s/William B. Ellis
-------------- of the Board -------------------------
William B. Ellis
March 23, 1995 Trustee, President /s/Bernard M. Fox
-------------- and Chief Executive -------------------------
Officer Bernard M. Fox
March 23, 1995 Executive Vice /s/Robert E. Busch
-------------- President and Chief -------------------------
Financial Officer Robert E. Busch
March 23, 1995 Vice President and /s/John B. Keane
-------------- Treasurer -------------------------
John B. Keane
March 23, 1995 Vice President and /s/John W. Noyes
-------------- Controller -------------------------
John W. Noyes
NORTHEAST UTILITIES
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 23, 1995 Trustee /s/Cotton Mather Cleveland
-------------- ---------------------------
Cotton Mather Cleveland
March 23, 1995 Trustee /s/George David
-------------- ---------------------------
George David
March 23, 1995 Trustee /s/Donald J. Donahue
-------------- ---------------------------
Donald J. Donahue
March 23, 1995 Trustee /s/Eugene D. Jones
-------------- ---------------------------
Eugene D. Jones
March 23, 1995 Trustee /s/Gaynor N. Kelley
-------------- ---------------------------
Gaynor N. Kelley
March 23, 1995 Trustee /s/Elizabeth T. Kennan
-------------- ---------------------------
Elizabeth T. Kennan
March 23, 1995 Trustee /s/Denham C. Lunt, Jr.
-------------- ---------------------------
Denham C. Lunt, Jr.
March 23, 1995 Trustee /s/William J. Pape II
-------------- ---------------------------
William J. Pape II
March 23, 1995 Trustee /s/Robert E. Patricelli
-------------- ---------------------------
Robert E. Patricelli
NORTHEAST UTILITIES
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 23, 1995 Trustee /s/Norman C. Rasmussen
-------------- ---------------------------
Norman C. Rasmussen
March 23, 1995 Trustee /s/John F. Swope
-------------- ---------------------------
John F. Swope
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY
---------------------------------------
(Registrant)
Date: March 23, 1995 By /s/William B. Ellis
-------------- ---------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 23, 1995 Chairman and Director /s/William B. Ellis
-------------- --------------------------
William B. Ellis
March 23, 1995 Vice Chairman and /s/Bernard M. Fox
-------------- Director --------------------------
Bernard M. Fox
March 23, 1995 President and Director /s/Hugh C. MacKenzie
-------------- --------------------------
Hugh C. MacKenzie
March 23, 1995 Executive Vice /s/Robert E. Busch
-------------- President, Chief --------------------------
Financial Officer Robert E. Busch
and Director
March 23, 1995 Vice President and /s/John W. Noyes
-------------- Controller --------------------------
John W. Noyes
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 23, 1995 Director /s/Robert G. Abair
-------------- --------------------------
Robert G. Abair
March 23, 1995 Director /s/William T. Frain, Jr.
-------------- --------------------------
William T. Frain, Jr.
March 23, 1995 Director /s/Cheryl W. Grise
-------------- --------------------------
Cheryl W. Grise
March 23, 1995 Director /s/John B. Keane
-------------- --------------------------
John B. Keane
March 23, 1995 Director /s/John F. Opeka
-------------- --------------------------
John F. Opeka
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
---------------------------------------
(Registrant)
Date: March 23, 1995 By /s/William B. Ellis
-------------- -------------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 23, 1995 Chairman and Director /s/William B. Ellis
-------------- --------------------------
William B. Ellis
March 23, 1995 Vice Chairman, Chief /s/Bernard M. Fox
-------------- Executive Officer and --------------------------
Director Bernard M. Fox
March 23, 1995 President, Chief /s/William T. Frain, Jr.
-------------- Operating Officer --------------------------
and Director William T. Frain, Jr.
March 23, 1995 Executive Vice
-------------- President and /s/Robert E. Busch
Chief Financial --------------------------
Officer Robert E. Busch
March 23, 1995 Vice President and /s/John W. Noyes
-------------- Controller --------------------------
John W. Noyes
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 23, 1995 Director /s/John C. Collins
-------------- --------------------------
John C. Collins
March 23, 1995 Director /s/Cheryl W. Grise
-------------- --------------------------
Cheryl W. Grise
Director
-------------- --------------------------
Gerald Letendre
March 23, 1995 Director /s/Hugh C. MacKenzie
-------------- --------------------------
Hugh C. MacKenzie
March 23, 1995 Director /s/Jane E. Newman
-------------- --------------------------
Jane E. Newman
March 23, 1995 Director /s/Robert P. Wax
-------------- --------------------------
Robert P. Wax
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
--------------------------------------
(Registrant)
Date: March 23, 1995 By /s/William B. Ellis
-------------- --------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 23, 1995 Chairman and Director /s/William B. Ellis
-------------- --------------------------
William B. Ellis
March 23, 1995 Vice Chairman and /s/Bernard M. Fox
-------------- Director --------------------------
Bernard M. Fox
March 23, 1995 President and Director /s/Hugh C. MacKenzie
-------------- --------------------------
Hugh C. MacKenzie
March 23, 1995 Executive Vice /s/Robert E. Busch
-------------- President, Chief --------------------------
Financial Officer Robert E. Busch
and Director
March 23, 1995 Vice President and /s/John W. Noyes
-------------- Controller --------------------------
John W. Noyes
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 23, 1995 Director /s/Robert G. Abair
-------------- --------------------------
Robert G. Abair
March 23, 1995 Director /s/William T. Frain, Jr.
-------------- --------------------------
William T. Frain, Jr.
March 23, 1995 Director /s/Cheryl W. Grise
-------------- --------------------------
Cheryl W. Grise
March 23, 1995 Director /s/John B. Keane
-------------- --------------------------
John B. Keane
March 23, 1995 Director /s/John F. Opeka
-------------- --------------------------
John F. Opeka
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
NORTH ATLANTIC ENERGY CORPORATION
---------------------------------
(Registrant)
Date: March 23, 1995 By /s/William B. Ellis
-------------- ---------------------
William B. Ellis
Chairman
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 23, 1995 Chairman and Director /s/William B. Ellis
-------------- --------------------------
William B. Ellis
March 23, 1995 Vice Chairman, Chief /s/Bernard M. Fox
-------------- Executive Officer and --------------------------
Director Bernard M. Fox
March 23, 1995 President, Chief /s/Robert E. Busch
-------------- Financial Officer --------------------------
and Director Robert E. Busch
March 23, 1995 Vice President and /s/John W. Noyes
-------------- Controller --------------------------
John W. Noyes
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES (CONT'D)
Date Title Signature
---- ----- ---------
March 23, 1995 /s/Ted C. Feigenbaum
-------------- Director --------------------------
Ted C. Feigenbaum
March 23, 1995 Director /s/William T. Frain, Jr.
-------------- --------------------------
William T. Frain, Jr.
March 23, 1995 Director /s/Cheryl W. Grise
-------------- --------------------------
Cheryl W. Grise
March 23, 1995 Director /s/John B. Keane
-------------- --------------------------
John B. Keane
March 23, 1995 Director /s/Hugh C. MacKenzie
-------------- --------------------------
Hugh C. MacKenzie
March 23, 1995 Director /s/John F. Opeka
-------------- --------------------------
John F. Opeka
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
We have audited in accordance with generally accepted auditing
standards, the financial statements included in Northeast Utilities'
annual report to shareholders and The Connecticut Light and Power
Company's, Western Massachusetts Electric Company's, North Atlantic
Energy Corporation's, and Public Service Company of New Hampshire's
annual reports, incorporated by reference in this Form 10-K, and have
issued our reports thereon dated February 17, 1995. Our reports on the
financial statements include an explanatory paragraph with respect to the
change in methods of accounting for property taxes, postretirement
benefits other than pensions, and employee stock ownership
plans, if applicable to each company, as described in notes to the
related company's financial statements. Our audits were made for the
purpose of forming an opinion on each company's statements taken as a
whole. The schedules listed in the accompanying index are presented for
purposes of complying with the Securities and Exchange Commission's rules
and are not part of each company's basic financial statements. These
schedules have been subjected to the auditing procedures applied in the
audits of each company's basic financial statements and, in our opinion,
fairly state in all material respects the financial data required to be
set forth therein in relation to each company's basic financial
statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our reports in this Form 10-K, into previously filed
Registration Statement No. 33-55279 of The Connecticut Light and Power Company,
No. 33-56537 of CL&P Capital, LP, No. 33-51185 of Western Massachusetts Electric
Company, and No. 33-34622, No. 33-44814, and No. 33-40156 of Northeast
Utilities.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
March 10, 1995
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page
-------- ----
I. Financial Information of Registrant:
Northeast Utilities (Parent) Balance
Sheets 1994 and 1993 S-4
Northeast Utilities (Parent) Statements
of Income 1994, 1993, and 1992 S-5
Northeast Utilities (Parent) Statements
of Cash Flows 1994, 1993, and 1992 S-6
II. Valuation and Qualifying Accounts and Reserves
1994, 1993, and 1992:
Northeast Utilities and Subsidiaries S-7 -- S-9
The Connecticut Light and Power Company
and Subsidiaries S-10 -- S-12
Public Service Company of New Hampshire S-13 -- S-16
Western Massachusetts Electric Company S-17 -- S-19
All other schedules of the companies' for which provision is made in
the applicable regulations of the Securities and Exchange Commission are
not required under the related instructions or are not applicable, and
therefore have been omitted.
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 1994 AND 1993
(Thousands of Dollars)
<TABLE>
<CAPTION>
1994 1993
---------- ----------
<S> <C> <C>
ASSETS
------
Other Property and Investments:
Investments in subsidiary companies, at
equity............................................... $2,625,228 $2,505,950
Investments in transmission companies, at equity...... 26,106 26,535
Other, at cost........................................ 636 1,710
----------- -----------
2,651,970 2,534,195
----------- -----------
Current Assets:
Cash.................................................. 42 72
Notes receivable from affiliated companies............ 1,975 19,625
Taxes receivable...................................... - 485
Receivables from affiliated companies................. 2,598 32,638
Prepayments........................................... 228 73
----------- -----------
4,843 52,893
----------- -----------
Deferred Charges:
Accumulated deferred income taxes..................... 7,749 5,859
Unamortized debt expense.............................. 31 45
Other................................................. 26 42
----------- -----------
7,806 5,946
----------- -----------
Total Assets..................................... $2,664,619 $2,593,034
=========== ===========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common Shareholders' Equity:
Common shares, $5 par value--Authorized
225,000,000 shares; 134,210,226 shares issued and
124,962,981 shares outstanding in 1994 and
134,207,025 shares issued and
124,326,836 outstanding in 1993..................... $ 671,051 $ 671,035
Capital surplus, paid in.............................. 904,371 901,740
Deferred benefit plan--employee stock ownership plan.. (213,324) (228,205)
Retained earnings..................................... 946,988 879,518
----------- -----------
Total common shareholders' equity................... 2,309,086 2,224,088
Long-term debt........................................ 224,000 236,000
----------- -----------
Total capitalization................................ 2,533,086 2,460,088
----------- -----------
Current Liabilities:
Notes payable to banks................................ 104,000 72,500
Long-term debt and preferred stock--current portion... 12,000 9,000
Accounts payable...................................... 962 5,048
Accounts payable to affiliated companies.............. 2,944 42,459
Accrued taxes......................................... 7,454 -
Accrued interest...................................... 3,623 3,311
Other................................................. 17 13
----------- -----------
131,000 132,331
----------- -----------
Other Deferred Credits.................................. 533 615
----------- -----------
Total Capitalization and Liabilities $2,664,619 $2,593,034
=========== ===========
</TABLE>
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
(Thousands of Dollars Except Share Information)
<TABLE>
<CAPTION>
1994 1993 1992
------------- ------------- -------------
<S> <C> <C> <C>
Operating Revenues............... $ - $ - $ -
------------- ------------- -------------
Operating Expenses:
Other.......................... 13,114 2,677 (22,915)
Federal income taxes........... (10,736) (7,564) 12,736
------------- ------------- -------------
Total operating expenses...... 2,378 (4,887) (10,179)
------------- ------------- -------------
Operating Income (Loss).......... (2,378) 4,887 10,179
------------- ------------- -------------
Other Income:
Equity in earnings of
subsidiaries.................. 309,769 263,725 238,624
Equity in earnings of
transmission companies........ 3,418 3,736 4,141
Other, net..................... 679 1,302 6,439
------------- ------------- -------------
Other income, net............ 313,866 268,763 249,204
------------- ------------- -------------
Income before interest
charges..................... 311,488 273,650 259,383
------------- ------------- -------------
Interest Charges................. 24,614 23,697 3,329
------------- ------------- -------------
Net Income ...................... 286,874 249,953 256,054
Tax benefit of Employee Stock
Ownership Plan dividends........ - - 7,348
------------- ------------- -------------
Earnings For Common Shares....... $ 286,874 $ 249,953 $ 263,402
============= ============= =============
Earnings Per Common Share........ $ 2.30 $ 2.02 $ 2.02
============= ============= =============
Common Shares Outstanding
(average)....................... 124,678,192 123,947,631 130,403,488
============= ============= =============
</TABLE>
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1994, 1993, 1992
(Thousands of Dollars)
<TABLE>
<CAPTION>
1994 1993 1992
-------------- -------------- --------------
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net income $ 286,874 $ 249,953 $ 256,054
Adjustments to reconcile to net cash
from operating activities:
Equity in earnings of subsidiary companies (309,769) (263,725) (238,624)
Cash dividends received from subsidiary companies 201,403 191,297 196,267
Deferred income taxes (1,890) (3,199) 7,382
Other sources of cash 3,007 197 19,244
Other uses of cash (169) (3,915) (5,943)
Changes in working capital:
Receivables and accrued utility revenues 30,525 (25,012) 34,621
Accounts payable (43,601) 27,066 (4,528)
Other working capital (excludes cash) 7,615 (3,010) (4,203)
-------------- -------------- --------------
Net cash flows from operating activities 173,995 169,652 260,270
-------------- -------------- --------------
Cash Flows From Financing Activities:
Issuance of common shares 14,551 22,252 271,128
Issuance of long-term debt - - 75,000
Net increase in short-term debt 31,500 2,000 70,500
Reacquisitions and retirements of long-term debt (9,000) (5,000) -
Cash dividends on common shares (219,317) (218,179) (229,074)
-------------- -------------- --------------
Net cash flows (used for) from financing activities (182,266) (198,927) 187,554
-------------- -------------- --------------
Investment Activities:
NU System Money Pool 17,650 32,975 130,400
Investment in subsidiaries (10,912) (4,853) (592,715)
Other investment activities, net 1,503 1,152 (83)
-------------- -------------- --------------
Net cash flows used for investments 8,241 29,274 (462,398)
-------------- -------------- --------------
Net increase (decrease) in cash for the period (30) (1) (14,574)
Cash - beginning of period 72 73 14,647
-------------- -------------- --------------
Cash - end of period $ 42 $ 72 $ 73
============== ============== ==============
Supplemental Cash Flow Information
Cash paid during the year for:
Interest, net of amounts capitalized
during construction $ 24,235 $ 23,808 $ (11,419)
============== ============== ==============
Income taxes (refund) $ (16,786) $ - $ (4,277)
============== ============== ==============
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
<CAPTION>
-----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 14,629 $ 23,194 $ - $ 20,997 (a) $ 16,826
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 15,719 $ 8,437 $ - $ 6,433 (c) $ 17,723
========= ========= ========= ========= =========
Medical insurance (d) $ 8,657 $ (2,365)(e)$ - $ - $ 6,292
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Reflects change in medical insurance programs.
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
<CAPTION>
---------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 13,255 $ 21,118 $ - $ 19,744 (a) $ 14,629
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 14,059 $ 9,231 $ - $ 7,571 (c) $ 15,719
========= ========= ========= ========= =========
Medical insurance (d) $ 9,430 $ 42,442 $ - $ 43,215 (e) $ 8,657
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Principally payments for various employee medical expenses and expenses in connection therewith.
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
<CAPTION>
------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 11,607 $ 20,005 $ 2,826 (a)$ 21,183 (b)$ 13,255
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (c) $ 9,465 $ 8,275 $ 3,138 (a)$ 6,819 (d)$ 14,059
========= ========= ========= ========= =========
Medical insurance (e) $ 6,869 $ 39,693 $ 1,150 (a)$ 38,282 (f)$ 9,430
========= ========= ========= ========= =========
(a) Acquired as part of Northeast Utilities acquisition of Public Service Company of New Hampshire on
June 5, 1992.
(b) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of
accounts previously charged off.
(c) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(d) Principally payments for various injuries and damages and expenses in connection therewith.
(e) Provided to cover claims for employee medical insurance.
(f) Principally payments for various employee medical expenses and expenses in connection
</TABLE>
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
<CAPTION>
------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
-----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 10,816 $ 17,177 $ - $ 15,215 (a) $ 12,778
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 9,653 $ 6,052 $ - $ 5,197 (c) $ 10,508
========= ========= ========= ========= =========
Medical insurance (d) $ 2,367 $ (667)(e)$ - $ - $ 1,700
========= ========= ========= ========= =========
(a) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of
accounts previously charged off.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Reflects change in medical insurance programs.
</TABLE>
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
<CAPTION>
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 8,358 $ 16,366 $ - $ 13,908 (a) $ 10,816
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 8,359 $ 7,115 $ - $ 5,821 (c) $ 9,653
========= ========= ========= ========= =========
Medical insurance (d) $ 3,496 $ 19,846 $ - $ 20,975 (e) $ 2,367
========= ========= ========= ========= =========
(a) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of
accounts previously charged off.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Principally payments for various employee medical expenses and expenses in connection
therewith.
</TABLE>
<TABLE>
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
<CAPTION>
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 9,560 $ 14,837 $ - $ 16,039 (a)$ 8,358
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 7,369 $ 6,600 $ - $ 5,610 (c)$ 8,359
========= ========= ========= ========= =========
Medical insurance (d) $ 3,429 $ 19,770 $ - $ 19,703 (e)$ 3,496
========= ========= ========= ========= =========
(a) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of
accounts previously charged off.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Principally payments for various employee medical expenses and expenses in connection
therewith.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
<CAPTION>
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
-----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,816 $ 2,999 $ - $ 2,800 (a) $ 2,015
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages $ 2,045 $ 600 $ - $ 371 (b) $ 2,274
========= ========= ========= ========= =========
Medical insurance $ 1,915 $ (915)(c)$ - $ - $ 1,000
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for various injuries and damages and expenses in connection therewith.
(c) Reflects change in medical insurance programs.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
<CAPTION>
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,780 $ 1,771 $ - $ 2,735 (a) $ 1,816
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages $ 2,770 $ 192 $ - $ 917 (b) $ 2,045
========= ========= ========= ========= =========
Medical insurance $ 1,650 $ 265 $ - $ - $ 1,915
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Principally payments for various injuries and damages and expenses in connection therewith.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE PERIOD JANUARY 1, 1992 THROUGH JUNE 4, 1992
(Thousands of Dollars)
<CAPTION>
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,834 $ 1,581 $ - $ 1,589 (a)$ 2,826
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages $ 1,615 $ 1,618 $ - $ 95 (b)$ 3,138
========= ========= ========= ========= =========
Medical insurance $ 1,050 $ 100 $ - $ - $ 1,150
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Nonoperating reserve transferred to operating.
</TABLE>
<TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE PERIOD JUNE 5, 1992 THROUGH DECEMBER 31, 1992
(Thousands of Dollars)
<CAPTION>
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period(a)expenses describe describe of period
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,826 $ 1,617 $ - $ 1,663 (b)$ 2,780
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages $ 3,138 $ (277)$ - $ 91 (c)$ 2,770
========= ========= ========= ========= =========
Medical insurance $ 1,150 $ 500 $ - $ - $ 1,650
========= ========= ========= ========= =========
(a) Public Service Company of New Hampshire was acquired by Northeast Utilities on June 5, 1992.
(b) Amounts written off, net of recoveries.
(c) Nonoperating reserve transferred to operating.
</TABLE>
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
<CAPTION>
------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
-----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,997 $ 3,017 $ - $ 2,982 (a) $ 2,032
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 2,760 $ 1,551 $ - $ 617 (c) $ 3,694
========= ========= ========= ========= =========
Medical insurance (d) $ 467 $ (117)(e)$ - $ - $ 350
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Reflects change in medical insurance programs.
</TABLE>
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
<CAPTION>
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,117 $ 2,812 $ - $ 2,932 (a) $ 1,997
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 1,612 $ 1,750 $ - $ 602 (c) $ 2,760
========= ========= ========= ========= =========
Medical insurance (d) $ 741 $ 4,017 $ - $ 4,291 (e) $ 467
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
(e) Principally payments for various employee medical expenses and expenses in connection
therewith.
</TABLE>
<TABLE>
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
<CAPTION>
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,977 $ 3,303 $ - $ 3,163 (a)$ 2,117
========= ========= ========= ========= =========
RESERVES NOT APPLIED AGAINST ASSETS:
Injuries and damages (b) $ 1,496 $ 1,200 $ - $ 1,084 (c)$ 1,612
========= ========= ========= ========= =========
Medical insurance (d) $ 667 $ 3,916 $ - $ 3,842 (e)$ 741
========= ========= ========= ========= =========
(a) Amounts written off, net of recoveries.
(b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to
others, and property damage.
(c) Principally payments for various injuries and damages and expenses in connection therewith.
(d) Provided to cover claims for employee medical insurance.
</TABLE>
EXHIBIT INDEX
Each document described below is incorporated by reference to the files of
the Securities and Exchange Commission, unless the reference to the document is
marked as follows:
* - Filed with the 1994 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into
the 1994 Annual Reports on Form 10-K for CL&P, PSNH, WMECO and NAEC.
# - Filed with the 1994 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into
the 1994 Annual Report on Form 10-K for CL&P.
@ - Filed with the 1994 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into
the 1994 Annual Report on Form 10-K for PSNH.
** - Filed with the 1994 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into
the 1994 Annual Report on Form 10-K for WMECO.
## - Filed with the 1994 Annual Report on Form 10-K for NU and herein
incorporated by reference from the 1994 Form 10-K, File No. 1-5324 into the
1994 Annual Report on Form 10-K for NAEC.
Exhibit
Number Description
3 Articles of Incorporation and By-Laws
3.1 Northeast Utilities
3.1.1 Declaration of Trust of NU, as amended through May 24,
1988. (Exhibit
3.1.1, 1988 NU Form 10-K, File No. 1-5324)
3.2 The Connecticut Light and Power Company
3.2.1 Certificate of Incorporation of CL&P,restated to March 22,
1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-
5324)
3.2.2 By-laws of CL&P, as amended to March 1, 1982. (Exhibit
3.2.2, 1993 NU
Form 10-K, File No. 1-5324)
3.3 Public Service Company of New Hampshire
3.3.1 Articles of Incorporation, as amended to May 16, 1991.
(Exhibit 3.3.1,
1993 NU Form 10-K, File No. 1-5324)
3.3.2 By-laws of PSNH, as amended to November 1, 1993.
(Exhibit 3.3.2,
1993 NU Form 10-K, File No. 1-5324)
3.4 Western Massachusetts Electric Company
** 3.4.1 Articles of Organization of WMECO, restated to
February 23, 1995.
** 3.4.2 By-laws of WMECO, as amended to February 13, 1995.
3.5 North Atlantic Energy Corporation
3.5.1 Articles of Incorporation of NAEC dated September 20,
1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324)
3.5.2 Articles of Amendment dated October 16, 1991 and June 2,
1992 to Articles of Incorporation of NAEC. (Exhibit 3.5.2,
1993 NU Form 10-K, File No. 1-5324)
3.5.3 By-laws of NAEC, as amended to November 8, 1993. (Exhibit
3.5.3, 1993 NU Form 10-K, File No. 1-5324)
4 Instruments defining the rights of security holders, including
indentures
4.1 Northeast Utilities
4.1.1 Indenture dated as of December 1, 1991 between Northeast
Utilities and IBJ Schroder Bank & Trust Company, with
respect to the issuance of Debt Securities. (Exhibit
4.1.1, 1991 NU Form 10-K, File No. 1-5324)
4.1.2 First Supplemental Indenture dated as of December 1, 1991
between Northeast Utilities and IBJ Schroder Bank & Trust
Company, with respect to the issuance of Series A Notes.
(Exhibit 4.1.2, 1991 NU Form 10-K, File No. 1-5324)
4.1.3 Second Supplemental Indenture dated as of March 1, 1992
between Northeast Utilities and IBJ Schroder Bank & Trust
Company with respect to the issuance of 8.38% Amortizing
Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324)
4.1.4 Warrant Agreement dated as of June 5, 1992 between
Northeast Utilities and the Service Company. (Exhibit
4.1.4, 1992 NU Form 10-K, File No. 1-5324)
4.1.4.1 Additional Warrant Agent Agreement dated as of
June 5, 1992 between Northeast Utilities and
State Street Bank and Trust Company. (Exhibit
4.1.4.1, 1992 NU Form 10-K, File No. 1-5324)
4.1.4.2 Exchange and Disbursing Agent Agreement dated
as of June 5, 1992 among Northeast Utilities,
Public Service Company of New Hampshire and
State Street Bank and Trust Company. (Exhibit
4.1.4.2, 1992 NU Form 10-K, File No. 1-5324)
4.1.5 Credit Agreements among CL&P, NU, WMECO, NUSCO (as Agent)
and 19 Commercial Banks dated December 3, 1992 (364 Day and
Three-Year Facilities). (Exhibit C.2.38, 1992 NU Form U5S,
File No. 30-246)
4.1.6 Credit Agreements among CL&P, WMECO, NU, Holyoke Water
Power Company, RRR, NNECO and NUSCO (as Agent) dated
December 3, 1992 (364 Day and Three-Year Facilities).
(Exhibit C.2.39, 1992 NU Form U5S, File No. 30-246)
4.2 The Connecticut Light and Power Company
4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, Trustee, dated as of May 1, 1921.
(Composite including all twenty-four amendments to May 1,
1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-5324)
Supplemental Indentures to the Composite May 1, 1921
Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, dated as of:
4.2.2 April 1, 1967. (Exhibit 4.16, File No. 2-60806)
4.2.3 January 1, 1968. (Exhibit 4.18, File No. 2-60806)
4.2.4 December 1, 1969. (Exhibit 4.20, File No. 2-60806)
4.2.5 June 30, 1982. (Exhibit 4.33, File No. 2-79235)
4.2.6 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form
10-K, File No. 1-5324)
4.2.7 April 1, 1992. (Exhibit 4.30, File No. 33-59430)
4.2.8 July 1, 1992. (Exhibit 4.31, File No. 33-59430)
4.2.9 October 1, 1992. (Exhibit 4.32, File No. 33-59430)
4.2.10 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.11 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.12 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K,
File No. 1-5324)
4.2.13 February 1, 1994. 1(Exhibit 4.2.15, 1993 NU Form 10-K,
File No. 1-5324)
4.2.14 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K,
File No. 1-5324)
# 4.2.15 June 1, 1994.
# 4.2.16 October 1, 1994.
4.2.17 Financing Agreement between Industrial Development Authority
of the State of New Hampshire and CL&P (Pollution Control
Bonds) dated as of December 1, 1986. (Exhibit C.1.47, 1986
NU Form U5S, File No. 30-246)
4.2.18 Financing Agreement between Industrial Development Authority
of the State of New Hampshire and CL&P Pollution Control
Bonds) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU
Form U5S, File No. 30-246)
4.2.19 Financing Agreement between Industrial
Development Authority of the State of New
Hampshire and CL&P (Pollution Control
Bonds) dated as of December 1, 1989.
(Exhibit C.1.39, 1989 NU Form U5S, File No.
30-246)
4.2.20 Loan and Trust Agreement among Business Finance Authority
of the State of New Hampshire and CL&P (Pollution Control
Bonds) dated as of December 1, 1992. (Exhibit C.2.33, 1992
NU Form U5S, File No. 30-246)
4.2.21 Series A (Tax Exempt Refunding) PCRB Loan Agreement between
Connecticut Development Authority and CL&P (Pollution
Control Bonds) dated as of September 1, 1993. (Exhibit
4.2.21, 1993 NU Form 10-K, File No. 1-5324)
4.2.22 Series B (Tax Exempt Refunding) PCRB Loan Agreement between
Connecticut Development Authority and CL&P (Pollution
Control Bonds) dated as of September 1, 1993. (Exhibit
4.2.22, 1993 NU Form 10-K, File No. 1-5324)
4.2.23 Series A (Tax Exempt Refunding) PCRB Letter of Credit and
Reimbursement Agreement (Pollution Control Bonds) dated as
of September 1, 1993. (Exhibit 4.2.23, 1993 NU Form 10-K,
File No. 1-5324)
4.2.24 Series B (Tax Exempt Refunding) PCRB Letter of Credit and
Reimbursement Agreement (Pollution Control Bonds) dated as
of September 1, 1993. (Exhibit 4.2.24, 1993 NU Form 10-K,
File No. 1-5324)
4.2.25 Amended and Restated Limited Partnership Agreement (CL&P
Capital, L.P.) among CL&P, NUSCO, and the persons who
became limited partners of CL&P Capital, L.P. in
accordance with the provisions thereof dated as of
January 23, 1995(MIPS). (Exhibit A.1 (Execution Copy),
File No. 70-8451)
4.2.26 Indenture between CL&P and Bankers Trust Company, Trustee
(Series A Subordinated Debentures), dated as of January
1, 1995 (MIPS). (Exhibit B.1 (Execution Copy), File No.
70-8451)
4.2.27 Payment and Guaranty Agreement of CL&P dated as of
January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy),
File No. 70-8451)
4.3 Public Service Company of New Hampshire
4.3.1 First Mortgage Indenture dated as of August 15, 1978
between PSNH and First Fidelity Bank, National Association,
New Jersey, Trustee, (Composite including all amendments
to May 16, 1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File
No. 1-5324)
4.3.1.1 Tenth Supplemental Indenture dated as of May 1,
1991 between PSNH and First Fidelity Bank,
National Association. (Exhibit 4.1, PSNH
Current Report on Form 8-K dated February 10,
1992, File No. 1-6392).
4.3.2 Revolving Credit Agreement dated as May 1, 1991. (Exhibit
4.12, PSNH Current Report on Form 8-K dated February 10,
1992, File No. 1-6392)
4.3.3 Term Credit Agreement dated as of May 1, 1991. (Exhibit
4.11, PSNH Current Report on Form 8-K dated February 10,
1992, File No. 1-6392)
4.3.4 Series A (Tax Exempt New Issue) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.5 Series B (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.6 Series C (Tax Exempt Refunding) PCRB Loan and Trust
Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH
Current Report on Form 8-K dated February 10, 1992, File
No. 1-6392)
4.3.7 Series D (Taxable New Issue) PCRB Loan and Trust Agreement
dated as of May 1, 1991. (Exhibit 4.5, PSNH Current Report
on Form 8-K dated February 10, 1992, File No. 1-6392)
4.3.7.1 First Supplement to Series D (Tax Exempt
Refunding Issue) PCRB Loan and Trust Agreement
dated as of December 1, 1992. (Exhibit
4.4.5.1, 1992 NU Form 10-K, File No. 1-5324)
4.3.8 Series E (Taxable New Issue) PCRB Loan and Trust Agreement
dated as of May 1, 1991. (Exhibit 4.6, PSNH Current Report
on Form 8-K dated February 10, 1992, File No. 1-6392)
4.3.8.1 First Supplement to Series E (Tax Exempt
Refunding Issue) PCRB Loan and Trust Agreement
dated as of December 1, 1993. (Exhibit
4.3.8.1, 1993 NU Form 10-K, File No. 1-5324)
4.3.9 Series D (May 1, 1991 Taxable New Issue and December 1,
1992 Tax Exempt Refunding Issue) PCRB Letter of Credit and
Reimbursement Agreement dated as of October 1, 1992.
(Exhibit 4.3.9, 1993 NU Form 10-K, File No. 1-5324)
4.3.9.1 Amended and Restated Letter of Credit dated
December 17, 1992. (Exhibit 4.3.9.1, 1993 NU
Form 10-K, File No. 1-5324)
4.3.10 Series E (May 1, 1991 Taxable New Issue and December 1,
1993 Tax Exempt Refunding Issue) PCRB Letter of Credit and
Reimbursement Agreement dated as of May 1, 1991. (Exhibit
4.8, PSNH Current Report on Form 8-K dated February 10,
1992, File No. 1-6392)
4.3.10.1 Amended and Restated Letter of Credit dated
December 15, 1993. (Exhibit 4.3.10.1, 1993 NU
Form 10-K, File No. 1-5324)
4.4 Western Massachusetts Electric Company
4.4.1 First Mortgage Indenture and Deed of Trust between WMECO
and Old Colony Trust Company, Trustee, dated as of August
1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K, File No. 1-
5324)
Supplemental Indentures thereto dated as of:
4.4.2 March 1, 1967. (Exhibit 2.5, File No. 2-68808)
4.4.3 March 1, 1968. (Exhibit 2.6, File No. 2-68808)
4.4.4 September 1, 1990. (Exhibit 4.3.15, 1990 NU Form 10-K,
File No. 1-5324.)
4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772)
4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File
No. 1-5324)
4.4.7 March 1, 1994. (Exhibit 4.4.11, 1993 NU Form 10-K, File
No. 1-5324)
4.4.8 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File
No. 1-5324)
4.4.9 Series A (Tax Exempt Refunding) PCRB Loan Agreement between
Connecticut Development Authority and WMECO (Pollution
Control Bonds) dated as of September 1, 1993. (Exhibit
4.4.13, 1993 NU Form 10-K, File No. 1-5324)
4.4.10 Series A (Tax Exempt Refunding) PCRB Letter of Credit and
Reimbursement Agreement (Pollution Control Bonds) dated as
of September 1, 1993. (Exhibit 4.4.14, 1993 NU Form 10-K,
File No. 1-5324)
4.5 North Atlantic Energy Corporation
4.5.1 First Mortgage Indenture and Deed of Trust between NAEC and
United States Trust Company of New York, Trustee, dated as
of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form 10-K, File
No. 1-5324)
4.5.2 Note Indenture dated as of May 15, 1991. (Exhibit 4.10,
PSNH Current Report on Form 8-K dated February 10, 1992,
File No. 1-6392)
4.5.3 First Supplemental Indenture dated as of June 5, 1992
between NAEC, PSNH and United States Trust Company of New
York, Trustee. (Exhibit 4.6.3, 1992 NU Form 10-K, File No.
1-5324)
10 Material Contracts
#@** 10.1 Stockholder Agreement dated as of July 1, 1964 among the
stockholders of Connecticut Yankee Atomic Power Company (CYAPC).
#@** 10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and
each of CL&P, HELCO, PSNH and WMECO.
#@** 10.2.1 Form of Additional Power Contract dated as of April 30,
1984, between CYAPC and each of CL&P, PSNH and WMECO.
10.2.2 Form of 1987 Supplementary Power Contract dated as
of April 1, 1987, between CYAPC and each
(Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-5324)
#@** 10.3 Capital Funds Agreement dated as of September 1, 1964 between
CYAPC and CL&P, HELCO, PSNH and WMECO.
10.4 Stockholder Agreement dated December 10, 1958 between Yankee
Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO.
(Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)
10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power
Contract between YAEC and each of CL&P, PSNH and WMECO, including
a composite restatement of original Power Contract dated June 30,
1959 and Amendment No. 1 dated April 1, 1975 and Amendment No. 2
dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No.
1-5324.)
10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6,
1988, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.5.4 Form of Amendment No. 7 to Power Contract, dated February
1, 1992, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324)
10.6 Stockholder Agreement dated as of May 20, 1968 among stockholders
of MYAPC. (Exhibit 4.15, File No. 2-30018)
10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC and
each of CL&P, HELCO, PSNH and WMECO. (Exhibit 4.14, File No.
2-30018)
10.7.1 Form of Amendment No. 1 to Power Contract dated as of March
1, 1983 between MYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324)
10.7.2 Form of Amendment No. 2 to Power Contract dated as of
January 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-
5324)
#@** 10.7.3 Form of Amendment No. 3 to Power Contract dated as of
October 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO.
10.7.4 Form of Additional Power Contract dated as of February 1,
1984 between MYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
10.8 Capital Funds Agreement dated as of May 20, 1968 between Maine
Yankee Atomic Power Company (MYAPC) and CL&P, PSNH, HELCO and
WMECO. (Exhibit 4.13, File No. 2-30018)
#@** 10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of
August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.
10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of
VYNPC. (Exhibit 4.16, File No. 2-30285)
10.10 Form of Power Contract dated as of February 1, 1968 between
VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit
4.18, File No. 2-30018)
10.10.1 Form of Amendment to Power Contract dated as of June
1, 1972 between VYNPC and each of CL&P, HELCO, PSNH
and WMECO. (Exhibit 5.22, File No. 2-47038)
10.10.2 Form of Second Amendment to Power Contract dated as
of April 15, 1983 between VYNPC and each of CL&P,
PSNH and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K,
File No. 1-5324)
#@** 10.10.3 Form of Third Amendment to Power Contract dated as of
April 24, 1985 between VYNPC and each of CL&P, PSNH
and WMECO.
10.10.4 Form of Fourth Amendment to Power Contract dated as
of June 1, 1985 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.4, 1986 NU Form 10-K, File
No. 5324)
10.10.5 Form of Fifth Amendment to Power Contract dated as of
May 6, 1988 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.5, 1990 NU Form 10-K, File
No. 1-5324)
10.10.6 Form of Sixth Amendment to Power Contract dated as of
May 6, 1988 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No.
1-5324)
10.10.7 Form of Seventh Amendment to Power Contract dated as
of June 15, 1989 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File
No. 1-5324)
10.10.8 Form of Eighth Amendment to Power Contract dated as
of December 1, 1989 between VYNPC and each of CL&P,
PSNH and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K,
File No. 1-5324)
10.10.9 Form of Additional Power Contract dated as of
February 1, 1984 between VYNPC and each of CL&P, PSNH
and WMECO. (Exhibit 10.10.9, 1993 NU Form 10-K, File
No. 1-5324)
10.11 Capital Funds Agreement dated as of February 1, 1968 between
Vermont Yankee Nuclear Power Corporation (VYNPC) and CL&P,
HELCO, PSNH and WMECO. (Exhibit 4.16, File No. 2-30018)
10.11.1 Form of First Amendment to Capital Funds Agreement
dated as of March 12, 1968 between VYNPC and CL&P,
HELCO, PSNH and WMECO. (Exhibit 4.17, File
No. 2-30018)
10.11.2 Form of Second Amendment to Capital Funds Agreement
dated as of September 1, 1993 between VYNPC and CL&P,
HELCO, PSNH and WMECO. (Exhibit 10.11.2, 1993 NU
Form 10-K, File No. 1-5324)
#** 10.12 Amended and Restated Millstone Plant Agreement dated as of
December 1, 1984 by and among CL&P, WMECO and Northeast
Nuclear Energy Company (NNECO).
10.13 Sharing Agreement dated as of September 1, 1973 with respect
to 1979 Connecticut nuclear generating unit (Millstone 3).
(Exhibit 6.43, File No. 2-50142)
10.13.1 Amendment dated August 1, 1974 to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 5.45, File
No. 2-52392)
10.13.2 Amendment dated December 15, 1975 to Sharing
Agreement - 1979 Connecticut Nuclear Unit. (Exhibit
7.47, File No. 2-60806)
10.13.3 Amendment dated April 1, 1986 to Sharing Agreement -
1979 Connecticut Nuclear Unit. (Exhibit 10.17.3,
1990 NU Form 10-K, File No. 1-5324)
10.14 Agreement dated July 19, 1990, among NAESCO and Seabrook
Joint owners with respect to operation of Seabrook.
(Exhibit 10.53, 1990 NU Form 10-K, File No. 1-5324)
10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH
dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form
10-K, File No. 1-5324)
10.16 Form of Seabrook Power Contract between PSNH and NAEC, as
amended and restated. (Exhibit 10.45, NU 1992 Form 10-K,
File No. 1-5324)
* 10.17 Agreement (composite) for joint ownership, construction and
operation of New Hampshire nuclear, as amended through the
November 1, 1990 twenty-third amendment.
10.17.1 Memorandum of Understanding dated November 7, 1988
between PSNH and Massachusetts Municipal Wholesale
Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K,
File No. 1-6392)
10.17.2 Agreement of Settlement among Joint Owners dated as
of January 13, 1989. (Exhibit 10.13.21, 1988 NU Form
10-K, File No. 1-5324)
10.17.2.1 Supplement to Settlement Agreement, dated as of
February 7, 1989, between PSNH and Central
Maine Power Company. (Exhibit 10.18.1, PSNH
1989 Form 10-K, File No. 1-6392)
10.18 Amended and Restated Agreement for Seabrook Project
Disbursing Agent dated as of November 1, 1990. (Exhibit
10.4.7, File No. 33-35312)
10.18.1 Form of First Amendment to Exhibit 10.18. (Exhibit
10.4.8, File No. 33-35312)
10.18.2 Form (Composite) of Second Amendment to Exhibit
10.18. (Exhibit 10.18.2, 1993 NU Form 10-K, File No.
1-5324)
10.19 Agreement dated November 1, 1974 for Joint Ownership,
Construction and Operation of William F. Wyman Unit No. 4
among PSNH, Central Maine Power Company and other utilities.
(Exhibit 5.16 , File No. 2-52900)
10.19.1 Amendment to Exhibit 10.19 dated June 30, 1975.
(Exhibit 5.48, File No. 2-55458)
10.19.2 Amendment to Exhibit 10.19 dated as of August 16,
1976. (Exhibit 5.19, File No. 2-58251)
10.19.3 Amendment to Exhibit 10.19 dated as of December 31,
1978. (Exhibit 5.10.3, File No. 2-64294)
10.20 Form of Service Contract dated as of July 1, 1966 between
each of NU, CL&P and WMECO and the Service Company. (Exhibit
10.20, 1993 NU Form 10-K, File No. 1-5324)
10.20.1 Service Contract dated as of June 5, 1992 between
PSNH and the Service Company. (Exhibit 10.12.4, 1992
NU Form 10-K, File No. 1-5324)
10.20.2 Service Contract dated as of June 5, 1992 between
NAEC and the Service Company. (Exhibit 10.12.5, 1992
NU Form 10-K, File No. 1-5324)
10.20.3 Form of Annual Renewal of Service Contract. (Exhibit
10.20.3, 1993 NU Form 10-K, File No. 1-5324)
10.21 Memorandum of Understanding between CL&P, HELCO, Holyoke
Power and Electric Company (HP&E), Holyoke Water Power
Company (HWP) and WMECO dated as of June 1, 1970 with
respect to pooling of generation and transmission. (Exhibit
13.32, File No. 2-38177)
10.21.1 Amendment to Memorandum of Understanding between
CL&P, HELCO, HP&E, HWP and WMECO dated as of February
2, 1982 with respect to pooling of generation and
transmission. (Exhibit 10.21.1, 1993 NU Form 10-K,
File No. 1-5324)
**#10.21.2 Amendment to Memorandum of Understanding between
CL&P, HELCO, HP&E, HWP and WMECO dated as of January
1, 1984 with respect to pooling of generation and
transmission.
10.22 New England Power Pool Agreement effective as of November 1,
1971, as amended to November 1, 1988. (Exhibit 10.15, 1988
NU Form 10-K, File No. 1-5324.)
10.22.1 Twenty-sixth Amendment to Exhibit 10.22 dated as of
March 15, 1989. (Exhibit 10.15.1, 1990 NU Form 10-K,
File No. 1-5324)
10.22.2 Twenty-seventh Amendment to Exhibit 10.22 dated as of
October 1, 1990. (Exhibit 10.15.2, 1991 NU Form
10-K, File No. 1-5324)
10.22.3 Twenty-eighth Amendment to Exhibit 10.22 dated as of
September 15, 1992. (Exhibit 10.18.3, 1992 NU Form
10-K, File No. 1-5324)
10.22.4 Twenty-ninth Amendment to Exhibit 10.22 dated as of
May 1, 1993. (Exhibit 10.22.4, 1993 NU Form 10-K,
File No. 1-5324)
10.23 Agreements among New England Utilities with respect to the
Hydro-Quebec interconnection projects. (See Exhibits 10(u)
and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988,
respectively, Form 10-K of New England Electric System,
File No. 1-3446.)
10.24 Trust Agreement dated February 11, 1992, between State
Street Bank and Trust Company of Connecticut, as Trustor,
and Bankers Trust Company, as Trustee, and CL&P and WMECO,
with respect to NBFT. (Exhibit 10.23, 1991 NU Form 10-K,
File No. 1-5324)
10.24.1 Nuclear Fuel Lease Agreement dated as of February 11,
1992, between Bankers Trust Company, Trustee, as
Lessor, and CL&P and WMECO, as Lessees. (Exhibit
10.23.1, 1991 NU Form 10-K, File No. 1-5324)
#@**10.25 Simulator Financing Lease Agreement, dated as of February 1,
1985, by and between ComPlan and NNECO.
#@**10.26 Simulator Financing Lease Agreement, dated as of May 2,
1985, by and between The Prudential Insurance Company of
America and NNECO.
10.27 Lease dated as of April 14, 1992 between The Rocky River
Realty Company (RRR) and Northeast Utilities Service Company
(NUSCO) with respect to the Berlin, Connecticut headquarters
(office lease). (Exhibit 10.29, 1992 NU Form 10-K, File
No. 1-5324)
10.27.1 Lease dated as of April 14, 1992 between RRR and
NUSCO with respect to the Berlin, Connecticut
headquarters (project lease). (Exhibit 10.29.1,
1992 NU Form 10-K, File No. 1-5324)
10.28 Millstone Technical Building Note Agreement dated as of
December 21, 1993 between, by and between The Prudential
Insurance Company of America and NNECO. (Exhibit 10.28, 1993 NU
Form 10-K, File No. 1-5324)
10.29 Lease and Agreement, dated as of December 15, 1988, by and
between WMECO and Bank of New England, N.A., with BNE Realty
Leasing Corporation of North Carolina. (Exhibit 10.63, 1988
NU Form 10-K, File No. 1-5324.)
10.30 Note Agreement dated April 14, 1992, by and between The
Rocky River Realty Company (RRR) and Purchasers named
therein (Connecticut General Life Insurance Company, Life
Insurance Company of North America, INA Life Insurance
Company of New York, Life Insurance Company of Georgia),
with respect to RRR's sale of $15 million of guaranteed
senior secured notes due 2007 and $28 million of guaranteed
senior secured notes due 2017. (Exhibit 10.52, 1992 NU Form
10-K, File No. 1-5324)
10.30.1 Note Guaranty dated April 14, 1992 by Northeast
Utilities pursuant to Note Agreement dated April 14,
1992 between RRR and Note Purchasers, for the benefit
of The Connecticut National Bank as Trustee, the
Purchasers and the owners of the notes. (Exhibit
10.52.1, 1992 NU Form 10-K, File No. 1-5324)
10.30.2 Assignment of Leases, Rents and Profits, Security
Agreement and Negative Pledge, dated as of April 14,
1992 among RRR, NUSCO and The Connecticut National
Bank as Trustee, securing notes sold by RRR pursuant
to April 14, 1992 Note Agreement. (Exhibit 10.52.2,
1992 NU Form 10-K, File No. 1-5324)
10.31 Master Trust Agreement dated as of September 2, 1986 between
CL&P and WMECO and Colonial Bank as Trustee, with respect to
reserve funds for Millstone 1 decommissioning costs.
(Exhibit 10.80, 1986 NU Form 10-K, File No. 1-5324)
10.31.1 Notice of Appointment of Mellon Bank, N.A. as
Successor Trustee, dated November 20, 1990, and
Acceptance of Appointment. (Exhibit 10.41.1, 1992 NU
Form 10-K, File No. 1-5324)
10.32 Master Trust Agreement dated as of September 2, 1986 between
CL&P and WMECO and Colonial Bank as Trustee, with respect to
reserve funds for Millstone 2 decommissioning costs.
(Exhibit 10.81, 1986 NU Form 10-K, File No. 1-5324)
10.32.1 Notice of Appointment of Mellon Bank, N.A. as
Successor Trustee, dated November 20, 1990, and
Acceptance of Appointment. (Exhibit 10.42.1, 1992 NU
Form 10-K, File No. 1-5324)
10.33 Master Trust Agreement dated as of April 23, 1986 between
CL&P and WMECO and Colonial Bank as Trustee, with respect to
reserve funds for Millstone 3 decommissioning costs.
(Exhibit 10.82, 1986 NU Form 10-K, File No. 1-5324)
10.33.1 Notice of Appointment of Mellon Bank, N.A. as
Successor Trustee, dated November 20, 1990, and
Acceptance of Appointment. (Exhibit 10.43.1, 1992 NU
Form 10-K, File No. 1-5324)
10.34 NU Executive Incentive Plan, effective as of January 1,
1991. (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)
10.35 Supplemental Executive Retirement Plan for Officers of NU
System Companies, Amended and Restated effective as of
January 1, 1992. (Exhibit 10.45.1, NU Form 10-Q for the
Quarter Ended June 30, 1992, File No. 1-5324)
10.35.1 Amendment 1 to Exhibit 10.35, effective as of August
1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File
No. 1-5324)
10.35.2 Amendment 2 to Exhibit 10.35, effective as of
January 1, 1994. (Exhibit 10.35.2, 1993 NU Form
10-K, File No. 1-5324)
10.36 Loan Agreement dated as of December 2, 1991, by and between
NU and Mellon Bank, N.A., as Trustee, with respect to NU's
loan of $175 million to an ESOP Trust. (Exhibit 10.46, NU
1991 Form 10-K, File No. 1-5324)
10.36.1 First Amendment to Exhibit 10.36 dated February 7,
1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No.
1-5324)
10.36.2 Loan Agreement dated as of March 19, 1992 by and
between NU and Mellon Bank, N.A., as Trustee, with
respect to NU's loan of $75 million to the ESOP
Trust. (Exhibit 10.49.1, 1992 NU Form 10-K, File No.
1-5324)
10.36.3 Second Amendment to Exhibit 10.36 dated April 9,
1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No.
1-5324)
10.37 Management Succession Agreement. (Exhibit 10.47, NU Form
10-Q for the Quarter Ended June 30, 1992, File No. 1-5324)
10.38 Employment Agreement. (Exhibit 10.48, NU Form 10-Q for the
Quarter Ended June 30, 1992, File No. 1-5324)
13 Annual Report to Security Holders (Each of the Annual Reports is filed
only with the Form 10-K of that respective registrant.)
* 13.1 Portions of the Annual Report to Shareholders of NU (pages
16 - 50) that have been incorporated by reference into this
Form 10-K.
13.2 Annual Report of CL&P.
13.3 Annual Report of WMECO.
13.4 Annual Report of PSNH.
13.5 Annual Report of NAEC.
21 Subsidiaries of the Registrant (Exhibit 22, 1992 NU Form 10-K, File
1-5324)
27 Financial Data Schedules (Each Financial Data Schedule is filed only with
the Form 10-K of that respective registrant.)
27.1 Financial Data Schedule of NU.
27.2 Financial Data Schedule of CL&P.
27.3 Financial Data Schedule of WMECO.
THE COMMONWEALTH OF MASSACHUSETTS
FEDERAL ID
MICHAEL JOSEPH CONNOLLY
Secretary of State NO. 04-1961130
ONE ASHBURTON PLACE, BOSTON, MASS, 02108
RESTATED ARTICLES OF ORGANIZATION
General Laws, Chapter 164, Section 8C
This certificate must be submitted to the Secretary of the Commonwealth
within sixty days after the date of the vote of stockholders adopting the
restated articles of organization. The fee for filing this certificate is
prescribed by General Laws, Chapter 156B, Section 114. Make check payable to
The Commonwealth of Massachusetts.
We, Hugh C. MacKenzie, President
Mark A. Joyse, Assistant Clerk of
WESTERN MASSACHUSETTS ELECTRIC COMPANY
located at, 174 Brush Hill Avenue, West Springfield, Massachusetts 01089 do
hereby certify that the following restatement of the articles of organization of
the corporation was duly adopted by unanimous consent on , 1995, by vote of
1,072,471 shares of common out of 1,072,471 shares outstanding,
(Class of Stock)
being all of each class of stock outstanding and entitled to vote thereon
1. The name by which the corporation shall be known is:
WESTERN MASSACHUSETTS ELECTRIC COMPANY
2. The purpose for which the corporation is formed are as follows:
See attached RIDER 2A, pages 1-2
3. The total number of shares and the par value, if any, of each class of
stock which the corporate is authorized to issue is as follows:
WITHOUT PAR VALUE WITH PAR VALUE
CLASS OF STOCK NUMBER OF SHARES NUMBER OF SHARES PAR VALUE
7.72% Preferred Stock, 200,000 $100
Series B
Preferred 7.60% Class A, 1,200,000 $ 25
Preferred Stock, 1987 Series
Dutch Auction Rate Transferable
Securities Class A, 2,140,000 $ 25
Preferred Stock, 1988 Series
Common 1,072,471 $ 25
*4. If more than one class is authorized, a description of each of the
difference classes of stock with, if any, the preferences, voting powers,
qualifications, special or relative rights or privileges as to each class
thereof and any series now established:
See attached RIDER 4A, pages 1-28
*5. The restrictions, if any, imposed by the articles or organization upon the
transfer of shares of stock of any class are as follows: None
*6. Other lawful provisions, if any, for the conduct and regulation of the
business and affairs of the corporation, for its voluntary dissolution, or
for limiting, defining, or regulating the powers of the corporation, or of
its directors or stockholders, or of any class of stockholders:
See attached RIDER 6A, page 1
*If there are no such provisions, state "None".
WESTERN MASSACHUSETTS ELECTRIC COMPANY
RESTATED ARTILCES OF ORGANIZATION RIDER 2A
To make, purchase, transmit, distribute, and sell electricity. To
generate, by means of water power, steam power, atomic energy, or other means,
electricity within or without the Commonwealth of Massachusetts; to purchase
from others electricity generated within or without the said Commonwealth; and
to sell or distribute and sell electricity within or without the said
Commonwealth. To supply electricity in bulk within or without the said
Commonwealth. To transmit, within or without the said Commonwealth, electricity
for itself and for others. To manufacture, by such means as may be necessary or
desirable for the purpose, steam, and to sell or distribute and sell steam
within or without the said Commonwealth. To construct, operate, and maintain,
within or without the said Commonwealth, works and structures, including,
without limitation, dams, reservoirs, canals, power houses, water conduits,
cables, transmission lines, substations and other facilities used or useful for
the purpose of generating and transmitting electricity and for incidental
beneficial uses, including recreational and water supply purposes. To hold,
purchase, convey, sell, mortgage or lease, within or without the said
Commonwealth, real or personal property, including without limiting the
generality of the foregoing the right to hold property as a tenant-in-common
with others. To purchase, hold, display, lease, sell or otherwise obtain
receipts from, and to install and service within the Commonwealth, merchandise,
equipment, utensils, and chattels of any description incidental or auxiliary to
the use of electricity distributed to its consumers, or necessary or expedient
in the protection or management of its property used in its business. To carry
on and conduct from time to time all activities to which its utility properties
may be usefully applied, subject to all requisite regulatory approvals. To loan
its funds or invest its funds in the stocks, bonds, certificates of
participation, or other securities of any domestic or foreign corporation,
association, or trust, subject to all requisite regulatory approvals. To
guarantee the performance of any contract or obligation of domestic or foreign
corporations, associations, or trusts, any obligation of which or any interest
in which is held by this corporation or in the affairs of which this corporation
has an interest, subject to all requisite regulatory approvals. To indemnify,
to the extent permitted by law, its officers and directors, past or present,
against all liability and expenses incurred in connection with the defense or
disposition of any action, suit or proceeding, actual or threatened, whether
civil or criminal, in which they may be involved by reason of being or having
been directors or officers. To do every act and thing necessary, convenient, or
proper for the accomplishment of any of the purposes herein enumerated, or
incidental to any of the powers herein stated. It is expressly intended that no
specific enumeration in the foregoing clauses shall restrict in any way any
general language, that none of the purposes set forth in any of the above
clauses shall be limited or restricted in any way by the terms of any other
clause, that each purpose may be pursued independently of any other purpose from
time to time and whenever deemed desirable, and that the corporation shall have
and possess all the rights, privileges, and powers now or hereafter conferred by
the laws of the Commonwealth of Massachusetts upon electric companies organized
under such laws.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
RESTATED ARTILCES OF ORGANIZATION RIDER 4A
CAPITAL STOCK PROVISIONS
PART ONE
AMOUNT AND CLASSES OF AUTHORIZED STOCK
The Company's capital stock includes a class of capital stock
designated "Common Stock," a class of capital stock designated "Preferred
Stock," and a class of capital stock designated "Class A Preferred Stock." The
authorized number of shares of Common Stock is 1,072,471 shares of the par value
of $25 per share. The authorized number of shares of Preferred Stock is 200,000
shares of the par value of $100 per share. The authorized number of shares of
Class A Preferred Stock is 3,340,000 shares of the par value of $25 per share.
The Preferred Stock and the Class A Preferred Stock are hereinafter for
convenience of reference sometimes collectively referred to as the "Senior
Stock," and either class may hereinafter individually be referred to as "Senior
Stock." Shares of Preferred Stock and shares of Class A Preferred Stock shall
rank on a parity in respect of dividends or payment in case of liquidation, and,
to the extent not fixed and determined by these Articles of Organization or the
Company's By-laws or otherwise by law, shall have the same rights, preferences
and powers. The general terms, limitations and relative rights and preferences
of each share of Preferred Stock and each share of Class A Preferred Stock shall
be determined in accordance with the following
Sections:
Section 1. Issuance of Senior Stock
Shares of Preferred Stock may be issued from time to time in one or more
series on such terms and for such consideration as may be determined by the
Board of Directors. Shares of Class A Preferred Stock may be issued from time
to time in one or more series on such terms and for such consideration as may be
determined by the Board of Directors. The variations in the relative rights and
preferences as between the different series of either class of Senior Stock, the
series designation, dividend rate, redemption prices, and any other terms or
limitations shall be determined by the Board of Directors to the extent not
fixed and determined by law or by these Articles of Organization or the
Company's By-laws.
Section 2. Dividends
A. The holders of either class of the Senior Stock shall receive,
but only when and as declared by the Board of Directors, cumulative
dividends at the rate provided for the particular series and payable on
such dividend payment dates in each year as said Board may determine, such
dividends to be payable to holders of record on such dates as may be fixed
by said Board but not more than 45 days before each dividend date,
provided, however, that dividends shall not be declared and set apart for
payment, or paid, on Senior Stock of any one class and series, for any
dividend period, unless dividends have been or are contemporaneously
declared and set apart for payment, or paid, on Senior Stock of all series
for all dividend periods terminating on the same or an earlier date.
B. Dividends on each share of Senior Stock shall be cumulative from
the date of issue thereof or from such earlier date as the Board of
Directors may determine therefor. Unless full cumulative dividends to the
last preceding dividend date shall have been paid or set apart for payment
on all outstanding shares of Senior Stock, no dividend shall be paid on any
junior stock. The term "junior stock" means Common Stock or any other
stock of the Company subordinate to the Senior Stock in respect of
dividends or payments in liquidation.
C. So long as any shares of Senior Stock are outstanding, the
Company shall not declare any dividends or make any other distributions in
respect of outstanding shares of any junior stock of the Company, other
than dividends or distributions in shares of junior stock, or purchase or
otherwise acquire for value any outstanding shares of junior stock (the
declaration of any such dividend or the making of any such distribution,
purchase or acquisition being herein called a "junior stock payment") in
contravention of the following:
(1) If and so long as the junior stock equity (hereinafter
defined), adjusted to reflect the proposed junior stock payment, at the end
of the calendar month immediately preceding the calendar month in which the
proposed junior stock payment is to be made is less than 20% of total
capitalization (hereinafter defined) at that date, as so adjusted, the
Company shall not make such junior stock payment in an amount which,
together with all other junior stock payments made within the year ending
with and including the date on which the proposed junior stock payment is
to be made, exceeds 50% of the net income of the Company available for
dividends on junior stock for the 12 full calendar months immediately
preceding the calendar month in which such junior stock payment is made,
except in an amount not exceeding the aggregate of junior stock payments
which under the restrictions set forth above in this paragraph (1) could
have been, and have not been, made.
(2) If and so long as the junior stock equity, adjusted to
reflect the proposed junior stock payment, at the end of the calendar month
immediately preceding the calendar month in which the proposed junior stock
payment is to be made, is less than 25% but not less than 20% of the total
capitalization at that date, as so adjusted, the Company shall not make
such junior stock payment in an amount which, together with all other
junior stock payments made within the year ending with and including the
date on which the proposed junior stock payment is to be made, exceeds 75%
of the net income of the Company available for dividends on the junior
stock for the 12 full calendar months immediately preceding the calendar
month in which such junior stock payment is made, except in an amount not
exceeding the aggregate of junior stock payments which under the
restrictions set forth above in this paragraph (2) could have been, and
have not been, made.
D. The term "junior stock equity" means the aggregate of the part
value of or stated capital represented by, the outstanding shares of junior
stock, all earned surplus, capital or paid-in surplus, and any premiums on
the junior stock then carried on the books of the Company, less:
(1) the excess, if any, of the aggregate amount payable on
involuntary liquidation of the Company upon all outstanding shares of
Senior Stock over the sum of (i) the aggregate par or stated value of such
shares and (ii) any premiums thereon;
(2) any amounts on the books of the Company known, or estimated
if not known, to represent the excess, if any, of recorded value over
original cost of used or useful utility plant; and
(3) any intangible items set forth on the asset side of the
balance sheet of the Company as a result of accounting convention, such as
unamortized debt discount and expense; provided, however, that no
deductions shall be required to be made in respect of items referred to in
clauses (2) and (3) of this subsection D in cases in which such items are
being amortized or are provided for, or are being provided for, by
reserves.
E. The term "total capitalization" means the aggregate of:
(1) the principal amount of all outstanding indebtedness of the
Company maturing more than 12 months after the date of issue thereof; and
(2) the par value or stated capital represented by, and any
premiums carried on the books of the Company in respect of, the outstanding
shares of all classes of the capital stock of the Company, earned surplus,
and capital or paid-in surplus, less any amounts required to be deducted
pursuant to clauses (2) and (3) of subsection D of this Section 2 in the
determination of junior stock equity.
Section 3. Redemption or Purchase of Senior Stock
A. All or any part of any series of Senior Stock may by vote of
the Board of Directors be called for redemption at any time at the
redemption price provided for the particular series and in the manner
hereinbelow provided. Subject to the provisions of subsection B of this
Section 3, all or any part of any series of Senior Stock may be called for
redemption without calling all or any part of any other series of Senior
Stock. If less than all of any series of Senior Stock is so called, the
Transfer Agent shall determine by lot or in some other manner approved by
the Board of Directors the shares of such series of Senior Stock to be
called.
B. No call for redemption of less than all shares of Senior Stock
outstanding shall be made if the Company shall be in arrears in respect of
payment of dividends on any shares of Senior Stock outstanding.
C. The sums payable in respect of any shares of Senior Stock so
called shall be payable at the office of an incorporated bank or trust
company in good standing. Notice of such call stating the redemption date
shall be mailed not less than 30 days before the redemption date to each
holder of record of shares of Senior Stock so called at his address as it
appears upon the books of the Company.
D. The Company shall, before the redemption date, deposit with
said bank or trust company all sums payable with respect to shares of
Senior Stock so called. After such mailing and deposit the holders of
shares of Senior Stock so called for redemption shall cease to have any
right to future dividends or other rights or privileges as stockholders
in respect of such shares and shall be entitled to look for payment on and
after the redemption date only to the sums so deposited with said bank or
trust company for their respective amounts. Shares so redeemed may be
reissued but only subject to the limitations imposed upon the issue of
Senior Stock.
E. The Company may at any time purchase all or any of the
then outstanding shares of Senior Stock of any class and series upon the
best terms reasonably obtainable, but not exceeding the then current
redemption price of such shares, except that no such purchase shall be made
if the Company shall be in arrears in respect of payment of dividends on
any shares of Senior Stock outstanding or if there shall exist an event of
default as defined in Section 5 hereof.
Section 4. Amounts Payable on Liquidation
A. The holders of any series of Senior Stock shall receive upon
any voluntary liquidation, dissolution or winding up of the Company the
then current redemption price of the particular series and if such action
is involuntary $100 per share in the case of the Preferred Stock and $25
per share in the case of the Class A Preferred Stock, plus in each case all
dividends accrued and unpaid to the date of such payment, before any
payment in liquidation is made on any junior stock.
B. If the net assets of the Company available for distribution on
liquidation to the holders of Senior Stock shall be insufficient to pay
said amounts in full, then such net assets shall be distributed among the
holders of Senior Stock, who shall receive a common percentage of the full
respective preferential amounts.
Section 5. Voting Powers
A. Except as provided in these Articles of Organization or in the
Company's By-laws or as provided by law, the holders of Senior Stock shall
have no voting power or right to notice of any meeting.
B. Whenever the holders of the Senior Stock shall have the
right to vote or consent to an action as provided in these Articles of
Organization or the Company's By-laws or as provided by law, both classes of
Senior Stock shall (except as provided below) vote together as a single
class, each outstanding share of Preferred Stock entitled to vote and each
outstanding share of Class A Preferred Stock entitled to vote having such
voting rights as are proportionate to the ratio of (i) the par value
represented by such share to (ii) the par value represented by all shares
of Senior Stock then outstanding. Whenever only one class of the Senior
Stock shall have the right to vote or consent to an action as provided in
these Articles of Organization or the Company's By-laws or as provided by
law, or whenever each class of the Senior Stock shall be entitled or be
required to vote as a separate class on a matter, each outstanding share
of such class entitled to vote shall be entitled to one vote on each such
matter.
C. Whenever dividends on any share of Senior Stock shall be in
arrears in an amount equal to or exceeding four quarterly dividend
payments, or whenever there shall have occurred some default in the
observance of any of the provisions of this Article, or some default on
which action has been taken by debentureholders, bondholders or the trustee
of any deed of trust or mortgage of the Company, or whenever the Company
shall have been declared bankrupt or a receiver of its property shall have
been appointed (any of said conditions being herein called an "event of
default"), then the holders of Senior Stock shall be given notice of all
stockholders' meetings and shall have the right voting together as a class
to elect the smallest number of directors necessary to constitute a
majority of the Board of Directors of the Company and the exclusive right
voting together as a class to amend the by-laws to make such appropriate
increase in the number of directorships as may be required to effect such
election. When all arrears of dividends shall have been paid and such
event of default shall have been terminated, all the rights and powers of
the holders of Senior Stock to receive notice and to vote shall cease,
subject to being again revived on any subsequent event of default.
D. Whenever the right to elect directors shall have accrued to the
holders of Senior Stock the Company shall call a meeting of stockholders
for the election of directors and, if necessary, the amendment of the
by-laws to permit the holders of Senior Stock to exercise their rights
pursuant to subsection C of this Section 5, such meeting to be held not
less than 45 days and not more than 90 days after the accrual of such
rights. When such rights shall cease, the Company shall, within seven days
from the delivery to the Company of a written request therefor by any
stockholder, cause a meeting of the stockholders to be held within 30 days
from the delivery of such request for the purpose of electing a new Board
of Directors. Forthwith, upon the election of such new Board of Directors,
the directors in office immediately prior to such election (other than
persons elected directors in such election) shall be deemed removed from
office without further action by the Company.
Section 6. Action Requiring Certain Consent of Senior
Stockholders
A. So long as any Senior Stock is outstanding, the Company,
without the affirmative vote or written consent of at least a majority in
interest of the Senior Stock then outstanding voting or giving consent
together as a class shall not:
(1) Issue or assume any unsecured notes, unsecured debentures
or other securities representing unsecured debt (other than for the purpose
of refunding or renewing outstanding unsecured securities issued or assumed
by the Company resulting in equal or longer maturities or redeeming or
otherwise retiring all outstanding shares of Senior Stock) if immediately
after such issue or assumption (a) the total outstanding principal amount
of all unsecured notes, unsecured debentures or other securities
representing unsecured debt of the Company will thereby exceed 20% of the
aggregate of all outstanding secured debt of the Company and the capital
stock, premiums thereon, and surplus of the Company, as stated on its
books, or (b) the total outstanding principal amount of all unsecured debt
of the Company of maturities of less than 10 years will thereby exceed 10%
of the aggregate of all outstanding secured debt of the Company and the
capital stock, premiums thereon, and surplus of the Company, as stated on
its books. For the purposes of this subsection A, the payment due upon the
maturity of unsecured debt having an original single stated maturity of 10
years or more shall not be regarded as unsecured debt with a maturity of
less than 10 years until within three years of the maturity thereof, and
none of the payments due upon any unsecured serial debt having an original
stated maturity for the final serial payment of 10 years or more shall be
regarded as unsecured debt of a maturity of less than 10 years until within
three years of the maturity of the final serial payment.
(2) Issue, sell or otherwise dispose of any shares of the then
authorized but unissued Senior Stock or any other stock ranking on a parity
with or having a priority over Senior Stock in respect of dividends or of
payments in liquidation, or reissue, sell or otherwise dispose of any
reacquired shares of Senior Stock or such other stock, other than to
refinance an equal par value or stated value of Senior Stock or of stock
ranking on a parity with or having priority over Senior Stock in respect of
dividends or of payments in liquidation, if:
(a) For a period of 12 consecutive calendar months within
15 calendar months immediately preceding the calendar month in which any
such shares shall be issued, the Income before Interest Charges of the
Company for said period available for the payment of interest determined in
accordance with the systems of accounts then prescribed for the Company by
the Department of Public Utilities of the Commonwealth of Massachusetts (or
by such other official body as may then have authority to prescribe such
systems of accounts) but in any event after deducting depreciation charges
and taxes (including income taxes) and including, in any case in which such
stock is to be issued, sold or otherwise disposed of in connection with the
acquisition of any property, the Income before Interest Charges of the
property to be so acquired, computed as nearly as practicable in the manner
specified above, shall not have been at least one and one-half (1 1/2)
times the sum of (i) the interest charges for one year on all indebtedness
which shall then be outstanding (excluding interest charges on any
indebtedness, proposed to be retired in connection with the issue, sale or
other disposition of such shares), and (ii) an amount equal to all annual
dividend requirements on all outstanding shares of Senior Stock and all
other stock, if any, ranking on a parity with or having priority over
Senior Stock in respect of dividends or of payments in liquidation,
including the shares proposed to be issued, but not including any shares
proposed to be retired in connection with such issue, sale or other
disposition; or if
(b) Such issue, sale or disposition would bring the
aggregate of the amount payable in connection with an involuntary
liquidation of the Company with respect to all shares of Senior Stock and
all shares of stock, if any, ranking on a parity with or having priority
over Senior Stock in respect of dividends or of payments in liquidation to
an amount in excess of the sum of the junior stock equity. If for the
purposes of meeting the requirements of this clause (b), it shall have been
necessary to take into consideration any earned surplus of the Company, the
Company shall not thereafter pay any dividends on or make any distributions
in respect of, or make any payment for the purchase or other acquisition
of, junior stock which would result in reducing the junior stock equity to
an amount less than the amount payable on involuntary liquidation of the
Company in respect of Senior Stock and all shares ranking on a parity with
or having a priority over Senior Stock in respect of dividends or of
payments in liquidation at the time outstanding.
If during the period for which Income before Interest Charges is to be
determined for the purpose set forth in this paragraph (2), the amount, if any,
required to be expended by the Company during such period for property
additions pursuant to a renewal and replacement fund or similar fund
established under any indenture of mortgage or deed of trust of the Company
shall exceed the amount deducted during such period in the determination of
such Income before Interest Charges on account of depreciation and
amortization of electric plan acquisition adjustments, such excess shall
also be deducted in determining such Income before Interest Charges.
B. So long as any Senior Stock is outstanding, the Company,
without the affirmative vote or written consent of at least two-thirds in
interest of the Senior Stock then outstanding voting or giving consent
together as a class shall not authorize any shares of any class of stock
having a priority over the Senior Stock in respect of dividends or of
payments in liquidation or issue any shares of any such prior ranking stock
more than 12 months after the date of the vote or consent authorizing such
prior ranking stock.
C. The provisions of this Article of these Articles of Organization may
be changed only by the affirmative vote or written consent of at least
two-thirds in interest of the issued and outstanding shares of each class of
capital stock of the Company voting or giving their consent in each case
separately as a class; provided, however, that if any such change or proposed
change would affect only one class of Senior Stock, then such change may be
effected only by the affirmative vote or written consent of at least two-thirds
in interest of the issued and outstanding shares of Common Stock and at least
two-thirds in interest of the issued and outstanding shares of the class of
Senior Stock that is affected, voting or giving their consent in each case
separately as a class; and provided further, however, the holders of Senior
Stock shall not be entitled to vote on an increase in the number of
authorized shares of Preferred Stock or Class A Preferred Stock. In no
event shall any reduction of the dividend rate or of the amounts payable
upon redemption or liquidation with respect to any share of Senior Stock be
made without the consent of the holder thereof, and no such reduction in
respect of the shares of any particular series of Senior Stock shall be
made without the consent of all the holders of shares of such series.
D. No share of Senior Stock shall be deemed to be "outstanding"
within the meaning of this Section 6 or of Section 7 if, at or prior to the
time when the approval herein or therein referred to would otherwise be
required, provision shall be made for its redemption, including a deposit
complying with the requirements of subsection D of Section 3.
Section 7. Merger, Consolidation or Sale of All Assets
Except with the affirmative vote or written consent of a majority in
interest of Senior Stock then outstanding voting or giving consent together as a
class, the Company shall not merge or consolidate with or into any other
corporation or sell or otherwise dispose of all or substantially all of its
assets (except by mortgage or pledge) unless such merger, consolidation,
sale or other disposition, or the issuance or assumption of securities in
the effectuation thereof shall have been ordered, approved or permitted
under the Public Utility Holding Company Act of 1935.
Section 8. No Preemptive Right
Except as otherwise expressly provided by law, the holders of Senior
Stock shall have no preemptive right to subscribe to any further issue of
additional shares of Senior Stock or of any other class of stock now or
hereafter authorized, nor for any future issue of bonds, debentures, notes
or other evidence of indebtedness or other security convertible into stock.
If it is expressly required by law that, notwithstanding the provisions of
the preceding sentence, any such further or future issue be offered
proportionately to the stockholders, the holders of Preferred Stock only
shall be entitled to subscribe for new or additional Preferred Stock, the
holders of Class A Preferred Stock only shall be entitled to subscribe for
new or additional Class A Preferred Stock and the holders of Common Stock
only shall be entitled to subscribe for new or additional Common Stock; and
notice of such increase as required by law need be given and the new shares
need be offered proportionately only to the stockholders who are so
entitled to subscribe.
Section 9. Immunity of Directors, Officers and Agents
No director, officer or agent of the Company shall be held personally
responsible for any action taken in good faith though subsequently adjudged
to be in violation of this Article.
Section 10. Transfer Agent
The Company shall always have at least one transfer agent for Senior
Stock, which shall be an incorporated bank or trust company of good
standing.
PART TWO
PROVISIONS WITH RESPECT TO THE SERIES OF PREFERRED STOCK
1. 7.72% Preferred Stock, Series B
-------------------------------
There shall be a series of Preferred Stock designated "7.72%
Preferred Stock, Series B," and consisting of 200,000 shares with an
aggregate par value of $20,000,000 and a par value per share of $100. The
dividend rate and redemption prices as to said 7.72% Preferred Stock,
Series B, shall be as follows:
(a) Dividends on said 7.72% Preferred Stock, Series B, shall be
at the rate of 7.72% per share per annum, and no more, and shall be
cumulative from October 1, 1971. Said dividends, when declared, shall be
payable on the first days of January, April, July and October in each year.
(b) Redemption Prices of said 7.72% Preferred Stock, Series B,
shall be $109.30 per share if redeemed on or before October 1, 1976,
$107.37 per share if redeemed after October 1, 1976 and on or before
October 1, 1981, $105.44 per share if redeemed after October 1, 1981 and on
or before October 1, 1986, and $103.51 per share if redeemed after October
1, 1986, plus in all cases that portion of the quarterly dividend accrued
thereon to the redemption date and all unpaid dividends thereon, if any,
provided, however, that none of the 7.72% Preferred Stock, Series B shall
be redeemed prior to October 1, 1976, if such redemption is for the purpose
of or in anticipation of refunding such 7.72% Preferred Stock, Series B
through the use, directly or indirectly, of finds borrowed by the Company
or of the proceeds of the issue by the Company of shares of any stock
ranking prior to or on a parity with the 7.72% Preferred Stock, Series B as
to dividends or assets, if such borrowed funds or such shares have an
effective interest cost or effective dividend cost to the Company (computed
in accordance with generally accepted financial principles), as the case
may be, of less than 7.69% per annum.
4. Adjustable Rate Preferred Stock, Series D
There shall be a series of Preferred Stock designated "Adjustable
Rate Preferred Stock, Series D", and consisting of 350,000 shares with an
aggregate par value of $35,000,000 and a par value per share of $100. The
dividend rate provisions, redemption prices and sinking fund provisions as
to said Adjustable Rate Preferred Stock, Series D, shall be as follows:
(a)The dividend per share on said Adjustable Rate Preferred
Stock, Series D, shall be (1) at the rate of 12% per annum per share for
the Initial Dividend Payment Period (as herein defined) (2) at the rate of
forty-one hundredth (40/100th) of one percentage point above the Applicable
Rate (as herein defined), from time to time in effect, for each subsequent
quarterly Dividend Period (as herein defined); provided, however, the
dividend rate for any Dividend Period (including the Initial Dividend
Payment Period) shall not be at a rate of less than 8% per annum per share
or greater than 13% per annum per share. Dividends shall be cumulative
from the date of issuance. Except as provided below in this paragraph,
the "Applicable Rate" for any Dividend Period shall be the highest of (i)
the Treasury Bill Rate, (ii) the Ten Year Constant Maturity Rate and (iii)
the Twenty Year Constant Maturity Rate (each as hereinafter defined) for
such Dividend Period. If the Company determines in good faith that for any
reason one or more of such rates cannot be determined for a particular
Dividend Period, then the Applicable Rate for such Dividend Period shall be
the higher of whichever of such rates can be so determined. If the Company
determines in good faith that none of such rates can be determined for a
particular Dividend Period, then the Applicable Rate in effect for the
preceding Dividend Period shall be continued for such Dividend Period.
Except as provided below in this paragraph, the "Treasury Bill
Rate" for each Dividend Period shall be the arithmetic average of the two
most recent weekly per annum market discount rates (or the one weekly per
annum market discount rate, if only one such rate shall be published during
the relevant Calendar Period (as defined below)) for three-month U.S.
Treasury bills, as published weekly by the Federal Reserve Board or its
successor agency during the Calendar Period immediately prior to the ten
calendar days immediately preceding the Dividend Payment Date for the
dividend period immediately prior to the Dividend Period for which the
dividend rate on the Adjustable Rate Preferred Stock, Series D is being
determined. If the Federal Reserve Board or its successor agency does not
publish such a weekly per annum market discount rate during such Calendar
Period, then the Treasury Bill Rate for such Dividend Period shall be the
arithmetic average of the two most recent weekly per annum market discount
rates (or the one weekly per annum market discount rate, if one such rate
shall be published during the relevant Calendar Period) for three-month
U.S. Treasury bills, as published weekly during such Calendar Period by any
Federal Reserve Bank or by any U.S. Government department or agency
selected by the Company. If a per annum market discount rate for
three-month U.S. Treasury bills shall not be published by the Federal
Reserve Board or its successor agency or by any Federal Reserve Bank or by
any U.S. Government department or agency during such Calendar Period, then
the Treasury Bill Rate for such Dividend Period shall be the arithmetic
average of the two most recent weekly per annum market discount rates (or
the one weekly per annum market discount rate, if one such rate shall be
published during the relevant Calendar Period) for all of the U.S. Treasury
bills then having maturities of not less than 80 nor more than 100 days, as
published during such Calendar Period by the Federal Reserve Board or its
successor agency or, if the Federal Reserve Board or its successor agency
shall not publish such rates, by any Federal Reserve Bank or by any U.S.
Government department or agency selected by the Company. If the Company
determines in good faith that for any reason no such U.S. Treasury bill
rates are published as provided above during such Calendar Period, then the
Treasury Bill Rate for such Dividend Period shall be the arithmetic average
of the per annum market discount rates based upon the closing bids during
such Calendar Period for each of the issues of marketable non-interest
bearing U.S. Treasury securities with a maturity of not less than 80 nor
more than 100 days from the date of each such quotation, as quoted daily
for each business day in New York City (or less frequently if daily
quotations shall not be generally available) to the Company by at least
three recognized U.S. Government securities dealers selected by the
Company. If the Company determines in good faith that for any reason the
Company cannot determine the Treasury Bill Rate for any Dividend Period as
provided above in this paragraph, the Treasury Bill Rate for such Dividend
Period shall be the arithmetic average of the per annum market discount
rates based upon the closing bids during the related Calendar Period for
each of the issues of marketable interest-bearing U.S. Treasury securities
with a maturity of not less than 80 nor more than 100 days from the date of
each such quotation, as quoted daily for each business day in New York City
(or less frequently if daily quotations shall not be generally available)
to the Company by at least three recognized U.S. Government securities
dealers selected by the Company.
Except as provided below in this paragraph, the "Ten Year
Constant Maturity Rate" for each Dividend Period shall be the arithmetic
average of the two most recent weekly per annum Ten Year Average Yields (or
the one weekly per annum Ten Year Average Yield, if only one such Yield
shall be published during the relevant Calendar Period as provided below),
as published weekly by the Federal Reserve Board or its successor agency
during the Calendar Period immediately prior to the ten calendar days
immediately preceding the Dividend Payment Date prior to the Dividend
Period for which the dividend rate on the Adjustable Rate Preferred Stock,
Series D is being determined. If the Federal Reserve Board or its
successor agency does not publish such a weekly per annum Ten Year Average
Yield during such Calendar Period, then the Ten Year Constant Maturity Rate
for such Dividend Period shall be the arithmetic average of the two most
recent weekly per annum Ten Year Average Yields (or the one weekly per
annum Ten Year Average Yield, if only one such Yield shall be published
during such Calendar Period), as published weekly during such Calendar
Period by any Federal Reserve Bank or by any U.S. Government department or
agency selected by the Company. If a per annum Ten Year Average Yield
shall not be published by the Federal Reserve Board or its successor agency
or by any Federal Reserve Bank or by any U.S. Government department or
agency during such Calendar Period, then the Ten Year Constant Maturity
Rate for such Dividend Period shall be the arithmetic average of the two
most recent weekly per annum average yields to maturity (or the one
weekly average yield to maturity, if only one such yield shall be
published during such Calendar Period) for all of the actively traded
marketable U.S. Treasury fixed interest rate securities (other than Special
Securities (as defined below)) then having maturities of not less than
eight nor more than twelve years, as published during such Calendar Period
by the Federal Reserve Board or its successor agency or, if the Federal
Reserve Board or its successor agency shall not publish such yields, by any
Federal Reserve Bank or by any U.S. Government department or agency
selected by the Company. If the Company determines in good faith that for
any reason the Company cannot determine the Ten Year Constant Maturity Rate
for any Dividend Period as provided above in this paragraph, then the Ten
Year Constant Maturity Rate for such Dividend Period shall be the
arithmetic average of the per annum average yields to maturity based upon
the closing bids during such Calendar Period for each of the issues of
actively traded marketable U.S. Treasury fixed interest rate securities
(other than Special Securities) with a final maturity date not less than
eight nor more than twelve years from the date of each such quotation, as
quoted daily for each business day in New York City (or less frequently if
daily quotations shall not be generally available) to the Company by at
least three recognized U.S. Government securities dealers selected by the
Company.
Except as provided below in this paragraph, the "Twenty Year
Constant Maturity Rate" for each Dividend Period shall be the arithmetic
average of the two most recent weekly per annum Twenty Year Average Yields
(or the one weekly per annum Twenty Year Average Yield, if only one such
Yield shall be published during the relevant Calendar Period), as published
weekly by the Federal Reserve Board or its successor agency during the
Calendar Period immediately prior to the ten calendar days immediately
preceding the Dividend Payment Date prior to the Dividend Period for which
the dividend rate on the Adjustable Rate Preferred Stock, Series D is being
determined. If the Federal Reserve Board or its successor agency does not
publish such a weekly per annum Twenty Year Average Yield during such
Calendar Period, then the Twenty Year Constant Maturity Rate for such
Dividend Period shall be the arithmetic average of the two most recent
weekly per annum Twenty Year Average Yields (or the one weekly per annum
Twenty Year Average Yield, if only one such Yield shall be published during
such Calendar Period), as published weekly during such Calendar Period by
any Federal Reserve Bank or by any U.S. Government department or agency
selected by the Company. If a per annum Twenty Year Average Yield shall
not be published by the Federal Reserve Board or its successor agency or by
any Federal Reserve Bank or by any U.S. Government department or agency
during such Calendar Period, then the Twenty Year Constant Maturity Rate
for such Dividend Period shall be the arithmetic average of the two most
recent weekly per annum average yields to maturity (or the one weekly
average yield to maturity, if only one such yield shall be published during
such Calendar Period) for all of the actively traded marketable U.S.
Treasury fixed interest rate securities (other than Special Securities)
then having maturities of not less than eighteen nor more than twenty-two
years, as published during such Calendar Period by the Federal Reserve
Board or its successor agency or, if the Federal Reserve Board or its
successor agency shall not publish such yields, by any Federal Reserve Bank
or by any U.S. Government department or agency selected by the Company. If
the Company determines in good faith that for any reason the Company cannot
determine the Twenty Year Constant Maturity Rate for any Dividend Period as
provided above in this paragraph, then the Twenty Year Constant Maturity
Rate for such Dividend Period shall be the arithmetic average of the per
annum average yields to maturity based upon the closing bids during such
Calendar Period for each of the issues of actively traded marketable U.S.
Treasury fixed interest rate securities (other than Special Securities)
with a final maturity date not less than eighteen nor more than twenty-two
years from the date of each such quotation, as quoted daily for each
business day in New York City (or less frequently if daily quotations shall
not be generally available) to the Company by at least three recognized
U.S. Government securities dealers selected by the Company.
The Treasury Bill Rate, the Ten Year Constant Maturity Rate and
the Twenty Year Constant Maturity Rate shall each be rounded to the nearest
five one-hundredths of a percentage point.
The "Initial Dividend Payment Period" shall be that period
beginning on April 19, 1983 (the date of issuance) and continuing through
and including June 30, 1983. The initial dividend payment date shall be
July 1, 1983.
A "Dividend Period" shall mean the three month period beginning
April 1, July 1, October 1, and January 1 in each year. A "Dividend
Payment Date" shall mean the first day of April, July, October, and January
in each year, commencing October 1, 1983.
The amount of dividends per share payable for each Dividend
Period shall be computed by dividing the dividend rate for such Dividend
Period by four and applying such rate against the par value per share of
the Adjustable Rate Preferred Stock, Series D. The amount of dividends
payable for the Initial Dividend Period or any period shorter than a full
quarterly Dividend Period shall be computed on the basis of 30-day months,
a 360-day year and the actual number of days elapsed in such period.
The dividend rate with respect to each Dividend Period will be
calculated as promptly as practicable by the Company according to the
appropriate method described herein. The mathematical accuracy of each
such calculation will be confirmed in writing by independent accountants of
recognized standing. The Company will cause each dividend rate to be
published in a newspaper of general circulation in New York City prior to
the commencement of the new Dividend Period to which it applies and will
cause notice of such dividend rate to be enclosed with the dividend payment
checks next mailed to the holders of the Adjustable Rate Preferred Stock,
Series D.
As used herein, the term "Calendar Period" means a period of
fourteen calendar days; the term "Special Securities" means securities
which can, at the option of the holder, be surrendered at face value in
payment of any Federal estate tax or which provide tax benefits to the
holder and are priced to reflect such tax benefits or which were originally
issued at a deep or substantial discount; the term "Ten Year Average Yield"
means the average yield to maturity for actively traded marketable U.S.
Treasury fixed interest rate securities (adjusted to constant maturities of
ten years); and the term "Twenty Year Average Yield" means the average
yield to maturity for actively traded marketable U.S. Treasury fixed
interest rate securities (adjusted to constant maturities of twenty years).
(b)The redemption prices of the Adjustable Rate Preferred Stock,
Series D, shall be $112.00 per share if redeemed on or before April 1,
1988, $103.00 per share if redeemed after April 1, 1988 but on or before
April 1, 1993, or $100.00 per share if redeemed after April 1, 1993. In
each case the redemption price will also include accrued dividends to the
date of redemption. None of the Adjustable Rate Preferred Stock, Series D
shall be redeemed prior to April 1, 1988 if such redemption is for the
purpose of or in anticipation of refunding the Adjustable Rate Preferred
Stock, Series D through the use, directly or indirectly, of borrowed funds
or of the proceeds of the issue by the Company of shares of any stock
ranking prior to or on a parity with the Adjustable Rate Preferred Stock,
Series D as to dividends or assets, if such borrowed funds or such shares
have an effective interest cost or effective dividend cost (computed in
accordance with generally accepted financial principles), as the case may
be, of less than 12.36 % per annum per share.
(c) As and for a sinking fund for the Adjustable Rate
Preferred Stock, Series D, commencing on April 1, 1988 and on or before
each April 1 in each year thereafter so long as any shares of the
Adjustable Rate Preferred Stock, Series D remain outstanding, the Company
shall, to the extent of any funds of the Company legally available therefor
and except as otherwise restricted by the Company's Statement of Preferred
Stock Provisions, redeem 17,500 shares of Adjustable Rate Preferred Stock,
Series D (or such lesser number of such shares as remain outstanding) at
$100 per share plus accrued dividends to the date of redemption; provided,
however, that if in any year the Company does not redeem the full number of
shares of Adjustable Rate Preferred Stock, Series D required to be redeemed
pursuant to this sinking fund, the deficiency shall be made good on the
next April 1 on which the Company has funds legally available for, and is
otherwise permitted to effect, the redemption of shares of Adjustable Rate
Preferred Stock, Series D, pursuant to this sinking fund. The number of
shares of Adjustable Rate Preferred Stock, Series D, redeemed on any April
1 shall be reduced by the number of such shares purchased and cancelled by
the Company during the preceding twelve-month period or redeemed during
such period pursuant to subsection (b) hereof. Any shares so redeemed or
purchased or cancelled may be given the status of authorized but unissued
shares of Preferred Stock, but none of such shares shall be reissued as
shares of Adjustable Rate Preferred Stock, Series D. The Company shall
have the option, which shall be noncumulative, to redeem on April 1, 1988
and on each April 1 thereafter up to an additional 17,500 shares of
Adjustable Rate Preferred Stock, Series D, at the sinking fund redemption
price. No such optional sinking fund shall operate to reduce the number of
shares of the Adjustable Rate Preferred Stock, Series D, required to be
redeemed pursuant to the mandatory sinking fund provisions hereinabove set
forth. In the event that the Company shall at any time fail to make a full
mandatory sinking fund payment on any sinking fund payment date, the
Company shall not pay any dividends or make any other distributions in
respect of outstanding shares of any junior stock (as that term is defined
in Subsection A of Section of Article XVI of the by-laws of the Company) of
the Company, other than dividends or distributions in shares of junior
stock, or purchase or otherwise acquire for value any outstanding shares of
junior stock, until all such payments have been made.
2. 7.60% Class A Preferred Stock, 1987 Series
------------------------------------------
There shall be a series of Preferred Stock designated "7.60% Class A
Preferred Stock, 1987 Series," and consisting of 1,200,000 shares with an
aggregate par value of $30,000,000 and a par value per share of $25. The
dividend rate and redemption prices as to said 7.60% Class A Preferred
Stock, 1987 Series, shall be as follows:
(a) Dividends on said 7.60% Class A Preferred Stock, 1987 Series,
shall be at the rate of 7.60% per share per annum, and no more, and shall
be cumulative from the date of issuance. Said dividends, when declared,
shall be payable on the first days of February, May, August and November in
each year, commencing May 1, 1987.
(b) For each of the twelve month periods commencing February 1,
1987, the redemption prices of said 7.60% Class A Preferred Stock, 1987
Series, shall be the amount per share set forth below:
Twelve Twelve
Months Redemption Months Redemption
Beginning Price Beginning Price
February 1 Per Share February 1 Per Share
1987 $26.90 2000 $25.26
1988 26.90 2001 25.13
1989 26.90 2002 25.00
1990 26.90 2003 25.00
1991 26.90 2004 25.00
1992 26.27 2005 25.00
1993 26.14 2006 25.00
1994 26.02 2007 25.00
1995 25.89 2008 25.00
1996 25.76 2009 25.00
1997 25.64 2010 25.00
1998 25.51 2011 25.00
1999 25.38
plus in all cases that portion of the quarterly dividend accrued thereon
to the redemption date and all unpaid dividends thereon, if any; provided,
however, that none of the 7.60% Class A Preferred Stock, 1987 Series, shall
be redeemed prior to February 1, 1992, if such redemption is for the
purpose of or in anticipation of refunding such 7.60% Class A Preferred
Stock, 1987 Series, through the use, directly or indirectly, of funds
borrowed by the Company or of the proceeds of the issue by the Company of
shares of any stock ranking prior to or on a parity with the 7.60% Class A
Preferred Stock, 1987 Series, as to dividends or assets, if such borrowed
funds or such shares have an effective interest cost or effective dividend
cost to the Company (computed in accordance with generally accepted
financial principles), as the case may be, of less than 7.69% per annum.
(c) As and for a sinking fund for said 7.60% Class A Preferred
Stock, 1987 Series, commencing on February 1, 1992, and on each February
1 in each year thereafter so long as any shares of the 7.60% Class A
Preferred Stock, 1987 Series, remain outstanding, the Company shall, to the
extent of any funds of the Company legally available therefor and except as
otherwise restricted by the Company's Statement of Preferred Stock
Provisions, redeem 60,000 shares of 7.60% Class A Preferred Stock, 1987
Series (or such lesser number of such shares as remain outstanding) at $25
per share plus accrued dividends to the date of redemption; provided,
however, that if in any year the Company does not redeem the full number of
shares of 7.60% Class A Preferred Stock, 1987 Series, required to be
redeemed pursuant to this sinking fund, the deficiency shall be made good
on the next succeeding February 1 on which the Company has funds legally
available for, and is otherwise permitted to effect, the redemption of
shares of 7.60% Class A Preferred Stock, 1987 Series, pursuant to this
sinking fund. At the option of the Company, the number of shares of 7.60%
Class A Preferred Stock, 1987 Series, redeemed on any February 1 may be
reduced by the number of such shares purchased and canceled by the Company
during the preceding twelve-month period or redeemed during such period
pursuant to subsection (b) hereof. Any shares so redeemed or purchased and
canceled may be given the status of authorized but unissued shares of
Senior Stock, but none of such shares shall be reissued as shares of 7.60%
Class A Preferred Stock, 1987 Series. The Company shall have the option,
which shall be noncumulative, to redeem on February 1, 1992 and on each
February 1 thereafter up to an additional 60,000 shares of 7.60% Class A
Preferred Stock, 1987 Series, at the sinking fund redemption price. No
such optional sinking fund shall operate to reduce the number of shares of
the 7.60% Class A Preferred Stock, 1987 Series, required to be redeemed
pursuant to the mandatory sinking fund provisions hereinabove set forth.
In the event that the Company shall at any time fail to make a full
mandatory sinking fund payment on any sinking fund payment date, the
Company shall not pay any dividends or make any other distributions in
respect of outstanding shares of any junior stock (as that term is defined
in this Article and the By-laws of the Company)of the Company, other than
dividends or distributions in shares of junior stock, or purchase or otherwise
acquire for value any outstanding shares of junior stock, until all such
payments have been made.
3. Dutch Auction Rate Transferable Securities Class A Preferred
------------------------------------------------------------
Stock, 1988 Series
------------------
There shall be a series of Class A Preferred Stock designated "Dutch
Auction Rate Transferable Securities Class A Preferred Stock, 1988
Series" (the "1988 DARTS") consisting of 2,140,000 shares with an
aggregate par value of $53,500,000 and a par value per share of $25. The
provisions governing the issue and sale of the 1988 DARTS in Units,
certification, dividend rights, redemption, reacquisition, auction
procedures, and other preferences, qualifications and special or relative
rights or privileges with respect to the 1988 DARTS shall be as follows:
(1) Units
The 1988 DARTS shall be issued and sold by the Company only in units
of 4,000 shares per unit ("Units"). No partial Units shall be issued and
sold by the Company, and no fractional shares of the 1988 DARTS shall be
issued and sold, no transfer of the 1988 DARTS in less than whole Units
shall be made, nor shall any transfer in less than whole Units be
registered on the transfer books of the Company or be effective for any
purpose.
(2) Certification
Except as otherwise provided by law, all outstanding DARTS shall be
represented by a certificate or certificates registered in the name of a
nominee of the Securities Depository (as defined in Section (6)(a)(xxi)
below), and no person acquiring Units shall be entitled to receive a
certificate representing the 1988 DARTS. The nominee of the Securities
Depository shall be the sole holder of record of the 1988 DARTS. Each
purchaser of Units will receive dividends, distributions and notices
according to the procedures of the Securities Depository and, if such
purchaser is not a member of the Securities Depository, of such purchaser's
Agent Member (as defined in Section (6)(a)(ii) below).
(3) Dividend Rights
(a) Dividends on the 1988 DARTS shall be paid, when, as and if
declared by the Board of Directors of the Company out of funds legally
available therefor, at the rate per annum determined as set forth below in
subsection (c) of this Section (3) and no more (the "Applicable Rate"),
payable on the respective dates set forth below.
(b) Dividends on the 1988 DARTS shall accrue from the date of
original issuance and shall be payable commencing on May 3, 1988, and on
each succeeding seventh Tuesday thereafter, except that if any of such
Tuesday, the Monday preceding such Tuesday, or the Wednesday following such
Tuesday is not a Business Day (as defined below), then (i) the dividend
payment date shall be the first Business Day after such Tuesday that is
immediately followed by a Business Day and is preceded by a Business Day
that is the preceding Monday or a day after such Monday, or (ii) if the
Securities Depository shall make available to its participants and members,
in funds immediately available in New York City on dividend payment dates,
the amount due as dividends on such dividend payment dates (and the
Securities Depository shall have so advised the Trust Company (as defined
in Section (6)(a)(xxx) below)), then the dividend payment date shall be the
first Business Day on or after such Tuesday that is preceded by a Business
Day that is the preceding Monday or a day after such Monday. "Business
Day" means a day on which the New York Stock Exchange is open for trading
and which is not a day on which banks in New York City are authorized by
law to close. Each dividend payment date determined as provided above is
referred to herein as the "Dividend Payment Date." Although any particular
Dividend Payment Date may not occur on the originally scheduled Tuesday
because of the exceptions discussed above, the next succeeding Dividend
Payment Date shall be, subject to such exceptions, the seventh Tuesday
following the originally designated Tuesday Dividend Payment Date for the
prior Dividend Period. As used herein, Dividend Period means the period
commencing on a Dividend Payment Date for DARTS and ending on the day next
preceding the next Dividend Payment Date. Notwithstanding the foregoing,
in the event of a change in law altering the minimum holding period
(currently found in Section 246(c) of the Internal Revenue Code of 1986, as
amended (the "Code")) required for taxpayers to be entitled to the
dividends received deduction on preferred stock held by non-affiliated
corporations (currently found in Section 243(a) of the Code), the Company
shall adjust the period of time between Dividend Payment Dates so as to
adjust uniformly the number of days (such number of days without giving
effect to the exceptions referred to above being hereinafter referred to as
"Dividend Period Days") in Dividend Periods commencing after the date of
such change in law to equal or exceed the then current minimum holding
period; provided that the number of Dividend Period Days shall not exceed
by more than nine days the length of such then current minimum holding
period and shall be evenly divisible by seven, and the maximum number of
Dividend Period Days in no event shall exceed 98 days. Upon any such
change in the number of Dividend Period Days as a result of a change in
law, the Company shall give notice of such change to all Existing Holders
of Units.
(c) The dividend rate on shares of the 1988 DARTS during the period
from and after the date of original issuance to the Initial Dividend
Payment Date (the "Initial Dividend Period") shall be 6.375 percent per
annum. Commencing on the Initial Dividend Payment Date, the dividend rate
on shares of the 1988 DARTS for each subsequent Dividend Period shall be at
a rate per annum that results from the implementation of the Auction
procedures set forth in Section (6) below.
The amount of dividends per Unit for the 1988 DARTS payable for each
Dividend Period shall be computed by multiplying the dividend rate for such
series for each Dividend Period determined in accordance with subsection
(c) above by a fraction the numerator of which shall be the number of days
in such Dividend Period (calculated by counting the first day thereof but
excluding the last day thereof) such Unit was outstanding and the
denominator of which shall be 360, and multiplying the amount so obtained
by $100,000 per Unit.
(d) Prior to each Dividend Payment Date, the Company shall pay to the
Trust Company sufficient funds for the payment of declared dividends.
(e) For the purpose of determining whether and when holders of the
Senior Stock are entitled to the rights to elect certain directors of the
Company, described under Section 5C of this Article and the Company's By-laws,
dividends on the DARTS shall be deemed to be in arrears "in an amount equal
to or exceeding four quarterly dividend payments," if, at the time
dividends are in arrears for four quarterly dividend payments for Senior
Stock having quarterly dividend payments, dividends on the 1988 DARTS are
in arrears for each Dividend Period beginning on or after the first day of
the first of the four quarterly dividend periods as to which dividends on
the Senior Stock having quarterly dividends are in arrears.
(4) Redemption Provisions
(a) At the option of the Company, the Units may be redeemed out of
funds legally available therefor in whole on any Dividend Payment Date at a
redemption price of $25 per share of the 1988 DARTS ($100,000 per Unit)
plus accrued and unpaid dividends (whether or not earned or declared) to
the redemption date. Only whole Units may be redeemed. See Section (5)
below for restrictions on the reissue of Units after redemption.
(b) In accordance with Section 3 of this Article and the Company's
By-laws, notice of redemption shall be mailed to each record holder of Units and
to the Trust Company not less than 30 days prior to the date fixed for
redemption thereof. Each notice of redemption shall include a statement setting
forth: (i) the redemption date, (ii) the number of Units to be redeemed, (iii)
the redemption price, (iv) the place or places where Units
are to be surrendered for payment of the redemption price, and (v) that
dividends of the Units to be redeemed will cease to accrue on such
redemption date. No defect in the notice of redemption or in the mailing
thereof shall affect the validity of the redemption proceedings, except as
required by applicable law.
(c) If less than all of the outstanding Units are to be redeemed,
the number of Units to be redeemed shall be determined by the Company and
communicated to the Trust Company. In accordance with section 3A of this
Article and the Company's By-laws, the Trust Company shall give notice to the
Securities Depository and the Securities Depository will determine by lot under
its usual operating procedures the number of Units, if any, to be redeemed from
the account of the Agent Member of each Existing Holder. An Agent Member may
determine to redeem Units from some Existing Holders without redeeming Units
from the accounts of other Existing Holders.
(5) Reacquisition
Except in an Auction (as defined in Section (6)(a)(iii) below), the
Company shall have the right, in accordance with Section 3E of this Article and
the Company's By-laws, and where permitted by applicable law, to purchase or
otherwise acquire Units upon the best terms reasonably obtainable, but not
exceeding the then current redemption price of such Units, except that no
such purchase shall be made if the Company shall be in arrears in respect
to payment of dividends on any shares of Senior Stock outstanding or if
there shall exist an event of default as defined in Section 5 of this Article
and the Company's By-laws. Notwithstanding the provisions of this Article and
the Company's By-laws, Units that have been redeemed, purchased or otherwise
acquired by the Company shall not be reissued as 1988 DARTS and shall either be
restored to authorized but unissued shares of the Company's Class A Preferred
Stock or canceled at the Company's option.
(6) Auction Procedures
(a) Certain Definitions
As used in these provisions establishing and designating the Dutch
Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series, the
following terms shall have the following meanings, unless the context otherwise
requires:
(i) "Affiliate" shall mean any Person known to the Trust
Company to be controlled by, in control of, or under common control with
the Company.
(ii) "Agent Member" shall mean the member of the Securities
Depository that will act on behalf of a Bidder and is identified as such in
such Bidder's Purchaser's Letter.
(iii) "Auction" shall mean the periodic operation of the
procedures set forth herein.
(iv) "Auction Date" shall mean the Business Day next
preceding a Dividend Payment Date.
(v) "Available Units" shall have the meaning specified in
paragraph (d)(i)(A) below.
(vi) "Bid" shall have the meaning specified in paragraph
(b)(i) below.
(vii) "Bidder" shall have the meaning specified in paragraph
(b)(i) below.
(viii) "Board of Directors" shall mean the Board of Directors of
the Company.
(ix) "Broker-Dealer" shall mean any broker-dealer, or other
entity permitted by law to perform the functions required of a
Broker-Dealer herein, that has been selected by the Company and has entered
into a Broker-Dealer Agreement with the Trust Company that remains
effective.
(x) "Broker-Dealer Agreement" shall mean an agreement between
the Trust Company and a Broker-Dealer pursuant to which such Broker-Dealer
agrees to follow the procedures specified herein.
(xi) "DARTS" or "1988 DARTS" shall mean the 2,140,000 shares of
Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988
Series, $25 Par Value, of the Company.
(xii) "Existing Holder," when used with respect to Units, shall
mean a Person who has signed a Purchaser's Letter and is listed as the
beneficial owner of such Units in the records of the Trust Company.
(xiii) "Hold Order" shall have the meaning specified in
paragraph (b)(i) below.
(xiv) "Maximum Applicable Rate," on any Auction Date, shall
mean the percentage of the 60-day "AA" Composite Commercial Paper Rate (as
defined below) in effect on such Auction Date, determined as set forth
below based on the prevailing rating of the DARTS in effect at the close of
business on the day preceding such Auction Date:
Prevailing Rating Percentage
AA/aa or Above........................... 110%
A/a...................................... 120%
BBB/baa.................................. 130%
BB/ba.................................... 175%
Below BB/ba.............................. 200%
For purposes of this definition, the "prevailing rating" of
the DARTS shall be (i) AA/aa or Above, if the DARTS have a rating of AA- or
better by Standard & Poor's Corporation or its successor ("S&P") and aa3 or
better by Moody's Investors Service, Inc. or its successor ("Moody's"), or
the equivalent of both of such ratings by such agencies or a substitute
rating agency or substitute rating agencies selected as provided below,
(ii) if not AA/aa or Above, then A/a, if the DARTS have a rating of A- or
better by S&P and a3 or better by Moody's or the equivalent of both of such
ratings by such agencies or a substitute rating agency or substitute rating
agencies selected as provided below, (iii) if not AA/aa or Above or A/a,
then BBB/Baa, if the DARTS have a rating of BBB- or better by S&P and baa3
or better by Moody's or the equivalent of both of such ratings by such
agencies or a substitute rating agency or substitute rating agencies
selected as provided below, and (iv) if not AA/aa or Above, A/a or BBB/baa,
then BB/ba, if the DARTS have a rating of BB- or better by S&P and Ba3 or
better by Moody's, or the equivalent of both of such ratings by such
agencies or a substitute rating agency or substitute rating agencies
selected as provided below, and (v) if not AA/aa or Above, A/a, BBB/baa or
BB/ba, then Below BB/ba. The Company shall take all reasonable action
necessary to enable S&P and Moody's to provide a rating for the DARTS. If
either S&P or Moody's shall not make such a rating available, or neither
S&P nor Moody's shall make such a rating available, Salomon Brothers Inc
and Morgan Stanley & Co. Incorporated, or their successors shall select a
nationally recognized securities rating agency or two nationally recognized
securities rating agencies to act as substitute rating agency or substitute
rating agencies, as the case may be.
(xv) "Minimum Applicable Rate," on any Auction Date, shall mean
59% of the 60-day "AA" Composite Commercial Paper Rate in effect on such
Auction Date.
(xvi) "Order" shall have the meaning specified in
paragraph(b)(i) below.
(xvii) "Outstanding" shall mean, as of any date, the DARTS
theretofore issued by the Company except, without duplication, (A) any
DARTS theretofore canceled or delivered to the Trust Company for
cancellation, or redeemed by the Company, or as to which a notice of
redemption shall have been given by the Company, (B) any DARTS as to which
the Company or any Affiliate thereof shall be an Existing Holder and (C)
any DARTS represented by any certificate in lieu of which a new
certificate has been executed and delivered by the Company.
(xviii) "Person" shall mean and include an individual, a
partnership, a corporation, a trust, an unincorporated association, a joint
venture or other entity or a government or any agency or political
subdivision thereof.
(xix) "Potential Holder" shall mean any Person, including any
Existing Holder, (A) who shall have executed and delivered or caused to be
delivered a Purchaser's Letter to the Trust Company and (B) who may be
interested in acquiring Units (or, in the case of an Existing Holder,
additional Units).
(xx) "Purchaser's Letter" shall mean a letter addressed to the
Company, the Trust Company, Broker-Dealer and other persons in which a
Person agrees, among other things, to offer to purchase, purchase, offer to
sell and/or sell Units as set forth herein.
(xxi) "Securities Depository" shall mean The Depository Trust
Company and its successors and assigns or any other securities depository
selected by the Company which agrees to follow the procedures required to
be followed by such securities depository in connection with the DARTS.
(xxii) "Sell Order" shall have the meaning specified in paragraph
(b)(i) below.
(xxiii) "60-day 'AA' Composite Commercial Paper Rate," on any
date, means (i) the interest equivalent of the 60-day rate on commercial
paper placed on behalf of issuers whose corporate bonds are rated "AA" by
S&P or the equivalent of such rating by S&P or another rating agency, as
such 60-day rate is made available on a discount basis or otherwise by the
Federal Reserve Bank of New York for the Business Day immediately preceding
such date, or (ii) in the event that the Federal Reserve Bank of New York
does not make available such a rate, then the interest equivalent of the
60-day rate on commercial paper placed on behalf of such issuers, as quoted
on a discount basis or otherwise by Morgan Stanley & Co. Incorporated or,
in lieu thereof, any affiliates or successor thereof (the "Commercial
Paper Dealer"), to the Trust Company for the close of business on the
Business Day immediately preceding such date. If the Commercial Paper
Dealer does not quote a rate required to determine the 60-day "AA"
Composite Commercial Rate, the 60-day "AA" Composite Commercial Paper Rate
shall be determined on the basis of the quotation or quotations furnished
by any Substitute Commercial Paper Dealer or Substitute Commercial Paper
Dealers selected by the Company to provide such rate. If the Company,
however, shall adjust the number of Dividend Period Days in the event of a
change in the dividends received deduction minimum holding period contained
in the Internal Revenue Code of 1986, as amended, with the result that (i)
the Dividend Period Days shall be fewer than 70 days, such rate shall be
the interest equivalent of the 60-day rate on such commercial paper, (ii)
the Dividend Period Days shall be 70 or more days but fewer than 85 days,
such rate shall be the arithmetic average of the interest equivalent of the
60-day and 90-day rates on such commercial paper, and (iii) the Dividend
Period Days shall be 85 or more days but 98 or fewer days, such rate shall
be the interest equivalent of the 90-day rate on such commercial paper.
For the purposes of such definition, "interest equivalent" means the
equivalent yield on a 360-day basis of a discount basis security to an
interest-bearing security and "Substitute Commercial Paper Dealer" shall
mean any commercial paper dealer that is a leading dealer in the
commercial paper market, provided that neither such dealer nor any of its
affiliates is a Commercial Paper Dealer.
(xxiv) "Submission Deadline" shall mean 12:30 P.M., New York City
time, on any Auction Date or such other time on any Auction Date by which
Broker-Dealers are required to submit Orders to the Trust Company as
specified by the Trust Company from time to time.
(xxv) "Submitted Bid" shall have the meaning specified
in paragraph (d)(i) below.
(xxvi) "Submitted Hold Order" shall have the meaning specified
in paragraph (d)(i) below.
(xxvii) "Submitted Order" shall have the meaning specified in
paragraph (d)(i) below.
(xxviii) "Submitted Sell Order" shall have the meaning specified
in paragraph (d)(i) below.
(xxvix) "Sufficient Clearing Bids" shall have the meaning
specified in paragraph (d)(i) below.
(xxx) "Trust Company" shall mean Bankers Trust Company and its
successor, and assigns or any other bank, trust company or other entity
selected by the Company which agrees to follow the Auction Procedures
described in this Section (6) for the purposes of determining the
Applicable Rate for the DARTS.
(xxxi) "Winning Bid Rate" shall have the meaning specified in
paragraph (d)(i) below.
(b) Orders by Existing Holders and Potential Holders
(i) On or prior to each Auction Date:
(A) each Existing Holder may submit to a Broker-Dealer
information as to:
(1) the number of Outstanding Units, if any, held by
such Existing Holder which such Existing Holder desires to continue to hold
without regard to the Applicable Rate for the next succeeding Dividend
Period;
(2) the number of Outstanding Units, if any, held by such
Existing Holder which such Existing Holder desires to continue to hold,
provided that the Applicable Rate for the next succeeding Dividend Period
shall not be less than the rate per annum specified by such Existing
Holder; and/or
(3) the number of Outstanding Units, if any, held by
such Existing Holder which such Existing Holder offers to sell without
regard to the Applicable Rate for the next succeeding Dividend Period; and
(B) Each Broker-Dealer, using a list of Potential Holders
that shall be maintained in good faith for the purpose of conducting a
competitive Auction shall contact Potential Holders, including Persons that
are not Existing Holders, on such list to determine the number of
Outstanding Units, if any, which each such Potential Holder offers to
purchase, provided that the Applicable Rate for the next succeeding
Dividend Period shall not be less than the rate per annum specified by such
Potential Holder.
For the purposes hereof, the communication to a Broker-Dealer of
information referred to in clause (A) or (B) of this paragraph (b)(i) is
hereinafter referred to as an "Order" and each Existing Holder and each
Potential Holder placing an Order is hereinafter referred to as a "Bidder";
and Order containing the information referred to in clause (A)(1) of this
paragraph (b)(i) is hereinafter referred to as a "Hold Order"; an Order
containing the information referred to in clause (A)(2) or (B) of this
paragraph (b)(i) is hereinafter referred to as a "Bid"; and an Order
containing the information referred to in clause (A)(3) of this paragraph
(b)(i) is hereinafter referred to as a "Sell Order."
(ii) (A) A Bid by an Existing Holder shall constitute an
irrevocable offer to sell:
(1) the number of Outstanding Units specified in such
Bid if the Applicable Rate determined on such Auction Date shall be less
than the rate specified therein; or
(2) such number or a lesser number of Outstanding
Units to be determined as set forth in paragraph (e)(i)(D) if the
Applicable Rate determined on such Auction Date shall be equal to the rate
specified therein; or
(3) a lesser number of Outstanding Units to be determined
as set forth in paragraph (e)(ii)(C) if such specified rate shall be higher
than Maximum Applicable Rate and Sufficient Clearing Bids do not exist.
(B) A Sell Order by an Existing Holder shall constitute an
irrevocable offer to sell:
(1) the number of Outstanding Units specified in such Sell
Order; or
(2) such number or a lesser number of Outstanding
Units to be determined as set forth in paragraph (e)(ii)(C) if Sufficient
Clearing Bids do not exist.
(C) A Bid by a Potential Holder shall constitute an irrevocable
offer to purchase:
(1) the number of Outstanding Units specified in such Bid
if the Applicable Rate determined on such Auction Date shall be higher than
the rate specified therein; or
(2) such number of a lesser number of Outstanding Units to
be determined as set forth in paragraph (e)(i)(E) if the Applicable Rate
determined on such Auction Date shall be equal to the rate specified
therein.
(c) Submission of Orders by Broker-Dealers to Trust Company
(i) Each Broker-Dealer shall submit in writing to the Trust Company
prior to the Submission Deadline on each Auction Date all Orders obtained by
such Broker-Dealer and specifying with respect to each Order:
(A) the name of the Bidder placing such Order;
(B) the aggregate number of Outstanding Units that are subject
of such Order;
(C) to the extent that such Bidder is an Existing Holder:
(1) the number of Outstanding Units, if any, subject to any
Hold Order placed by such Existing Holder;
(2) the number of Outstanding Units, if any, subject to
any Bid placed by such Existing Holder and the rate specified in such Bid;
and
(3) the number of Outstanding Units, if any, subject to
any Sell Order placed by such Existing Holder; and
(D) to the extent such Bidder is a Potential Holder, the rate
specified in such Potential Holder's Bid.
(ii) If any rate specified in any Bid contains more than three
figures to the right of the decimal point, the Trust Company shall round
such rate up to the next highest one-thousandth (.001) of 1%.
(iii) If an Order or Orders covering all of the Outstanding Units
held by an Existing Holder is not submitted to the Trust Company prior to
the Submission Deadline, the Trust Company shall deem a Hold Order to have
been submitted on behalf of such Existing Holder covering the number of
Outstanding Units held by such Existing Holder and not subject to Orders
submitted to the Trust Company.
(iv) If one or more Orders covering in the aggregate more than the
number of Outstanding Units held by an Existing Holder are submitted to the
Trust Company, such Orders shall be considered valid as follows and in the
following order or priority:
(A) any Hold Order submitted on behalf of such Existing
Holder shall be considered valid up to and including the number of
Outstanding Units held by such Existing Holder; provided that if more than
one Hold Order is submitted on behalf of such Existing Holder and the
number of Units subject to such Hold Orders exceeds the number of
Outstanding Units held by such Existing Holder, the number of Units subject
to such Hold Orders shall be reduced pro rata so that such Hold Orders
shall cover the number of Outstanding Units held by such Existing Holder;
(B) (1) any Bid shall be considered valid up to and including
the excess of the number of Outstanding Units held by such Existing Holder
over the number of Units subject to Hold Orders referred to in paragraph
(c)(iv)(A);
(2) subject to clause (1) above, if more than one Bid
with the same rate is submitted on behalf of such Existing Holder and the
number of Outstanding Units subject to such Bids is greater than such
excess, the number of Outstanding Units subject to such Bids shall be
reduced pro rata so that such Bids shall cover the number of Outstanding
Units equal to such excess; and
(3) subject to clause (1) above, if more than one Bid
with different rates is submitted on behalf of such Existing Holder, such
Bids shall be considered valid in the ascending order of their respective
rates and in any such event the number, if any, of such Outstanding shares
subject to Bids not valid under this clause (B) shall be treated as the
subject of a Bid by a Potential Holder; and (C) any Sell Order shall be
considered valid up to and including the excess of the number of
Outstanding Units held by such Existing Holder over the number of
Outstanding Units subject to Hold Orders referred to in paragraph
(c)(iv)(A) and Bids referred to in paragraph (c)(iv)(B).
(v) If more than one Bid is submitted on behalf of any Potential
Holder, each Bid submitted shall be a separate Bid with the rate and Units
therein specified.
(vi) If any rate specified in any Bid is lower than the Minimum
Applicable Rate for the Dividend Period to which such Bid relates, such Bid
shall be deemed to be a Bid specifying a rate equal to such Minimum
Applicable Rate.
(vii) Orders by Existing Holders and Potential Holders must specify
numbers of Units in whole Units. Any Order that specifies a number of
Units other than in whole shares will be invalid and will not be considered
a Submitted Order for purposes of an Auction.
(d) Determination of Sufficient Clearing Bids, Winning Bid Rate
and Applicable Rate
(i) Not earlier than the Submission Deadline on each
Auction Date, the Trust Company shall assemble all Orders submitted or
deemed submitted to it by the Broker-Dealers (each such Order as submitted
or deemed submitted by a Broker-Dealer being hereinafter referred to
individually as a "Submitted Hold Order" a "Submitted Bid" or a "Submitted
Sell Order," as the case may be, or as a "Submitted Order") and shall
determine:
(A) the excess of the total number of Outstanding Units over
the number of Outstanding Units that are the subject of Submitted Hold
Orders (such excess being hereinafter referred to as the "Available
Units");
(B) from the Submitted Orders, whether:
(1) the number of Outstanding Units that are the subject of Submitted
Bids by Potential Holders specifying one or more rates equal to or lower than
the Maximum Applicable Rate exceeds or is equal to the sum of:
(2) [a] the number of Outstanding Units that are the
subject of Submitted Bids by Existing Holders specifying one or more
rates higher than the Maximum Applicable Rate, and [b] the number of
Outstanding Units that are subject to Submitted Sell Orders (if such excess
of such equality exists (other than because the number of Outstanding Units
in clauses [a] and [b] above are each zero because all of the Outstanding
Units are the subject of Submitted Hold Orders), such Submitted Bids in
clause (1) above being hereinafter referred to collectively as "Sufficient
Clearing Bids"); and
(C) if Sufficient Clearing Bids exist, the lowest rate specified in
the Submitted Bids (the "Winning Bid Rate"), which if:
(1) each Submitted Bid from Existing Holders specifying the
Winning Bid Rate and all other Submitted Bids from Existing Holders
specifying lower rates were rejected, thus entitling such Existing Holders
to continue to hold the Units that are the subject of such Submitted Bids,
and
(2) each Submitted Bid from Potential Holders specifying the Winning
Bid Rate and all other Submitted Bids from Potential Holders specifying lower
rates were accepted, thus entitling the Potential Holders to purchase the Units
that are the subject of such Submitted Bids, would result in the number of
shares subject to all Submitted Bids specifying the Winning Bid Rate or a lower
rate being at least equal to the Available Units.
(ii) Promptly after the Trust Company has made the determinations
pursuant to paragraph (d)(i), the Trust Company shall advise the Company
of the Maximum Applicable Rate and the Minimum Applicable Rate and, based
on such determinations, the Applicable Rate for the next succeeding
Dividend Period as follows:
(A) if Sufficient Clearing Bids exist, that the Applicable
Rate for the next succeeding Dividend Period shall be equal to the Winning
Bid Rate so determined;
(B) if Sufficient Clearing Bids do not exist (other than
because all of the Outstanding Units are the subject of Submitted Hold
Orders), that the Applicable Rate for the next succeeding Dividend Period
shall be equal to the Maximum Applicable Rate; or
(C) if all the outstanding Units are the subject of Submitted Hold
Orders, that the Applicable Rate for the next succeeding Dividend Period shall
be equal to the Minimum Applicable Rate.
(e) Acceptance and Rejection of Submitted Bids and Submitted Sell
Orders and Allocation of Shares
Based on the determinations made pursuant to paragraph (d)(i), the
Submitted Bids and Submitted Sell Orders shall be accepted or rejected and the
Trust Company shall take such other action as set forth below:
(i) If Sufficient Clearing Bids have been made, subject to
the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Bids and
Submitted Sell Orders shall be accepted or rejected in the following order
or priority and all other Submitted bids shall be rejected:
(A) the Submitted Sell Orders of Existing Holders shall be
accepted and the Submitted Bid of each of the Existing Holders specifying
any rate that is higher than the Winning Bid Rate shall be rejected, thus
requiring each such Existing Holder to sell the Outstanding Units that are
the subject of such Submitted Bid;
(B) the Submitted Bid of each of the Existing Holders
specifying any rate that is lower than the Winning Bid Rate shall be
accepted, thus entitling each such Existing Holder to continue to hold the
Outstanding Units that are the subject of such Submitted Bid;
(C) the Submitted Bid of each of the Potential Holders
specifying any rate that is lower than the Winning Bid Rate shall be
accepted;
(D) the Submitted Bid of each of the Existing Holders
specifying a rate that is equal to the Winning Bid Rate shall be accepted,
thus entitling each such Existing Holder to continue to hold the
Outstanding Units that are the subject of such Submitted Bid, unless the
number of Outstanding Units subject to all such Submitted Bids shall be
greater than the number of Outstanding Units ("remaining shares") equal to
the excess of the Available Units over the number of Outstanding Units
subject to Submitted Bids described in paragraphs (e)(i)(B) and (e)(i)(C),
in which event the Submitted Bids of each such Existing Holder shall be
rejected, and each such Existing Holder shall be required to sell
Outstanding Units, but only in an amount equal to the difference between
(1) the number of Outstanding Units then held by such Existing Holder
subject to such Submitted Bid and (2) the number of Units obtained by
multiplying (x) the number of remaining shares by (y) a fraction the
numerator of which shall be the number of Outstanding Units held by such
Existing Holder subject to such Submitted Bid and the denominator of which
shall be the sum of the number of Outstanding Units subject to such
Submitted Bids made by all such Existing Holders that specified a rate
equal to the Winning Bid Rate; and
(E) the Submitted Bid of each of the Potential Holders
specifying a rate that is equal to the Winning Bid Rate shall be accepted
but only in an amount equal to the number of Outstanding Units obtained by
multiplying (x) the difference between the Available Units and the number
of Outstanding Units subject to the Submitted Bids described inparagraphs
(e)(i)(B), (e)(i)(C) and (e)(i)(D) by (y) a fraction the numerator of which
shall be the number of Outstanding shares of Units subject to such
Submitted Bid and the denominator of which shall be the sum of the number
of Outstanding Units subject to such Submitted Bids made by all such
Potential Holders that specified rates equal to the Winning Bid Rate.
(ii) If Sufficient Clearing Bids have been made (other than because
all of the Outstanding Units are subject to Submitted Hold Orders), subject to
the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Orders
shall be accepted or rejected as follows in the following order of priority
and all other Submitted Bids shall be rejected:
(A) the Submitted Bid of each Existing Holder specifying any
rate that is equal to or lower than the Maximum Applicable Rate shall be
accepted, thus entitling such Existing Holder to continue to hold the
Outstanding Units that are the subject of such Submitted Bid;
(B) the Submitted Bid of each Potential Holder specifying any
rate that is equal to or lower than the Maximum Applicable Rate shall be
accepted, thus requiring such Potential Holder to purchase the Outstanding
Units that are the subject of such Submitted Bid; and
(C) the Submitted Bids of each Existing Holder specifying any
rate that is higher than the Maximum Applicable Rate shall be rejected and
the Submitted Sell Orders of each Existing Holder shall be accepted, in
both cases only in an amount equal to the difference between (1) the number
of Outstanding Units then held by such Existing Holder subject to such
Submitted Bid or Submitted Sell Order and (2) the number of Units obtained
by multiplying (x) the difference between the Available Units and the
aggregate number of Outstanding Units subject to Submitted Bids described
in paragraphs (e)(ii)(A) and (e)(ii)(B) by (y) a fraction the numerator of
which shall be the number of Outstanding Units held by such Existing Holder
subject to such Submitted Bid or Submitted Sell Order and the denominator
of which shall be the number of Outstanding Units subject to all such
Submitted Bids and Submitted Sell Orders.
(iii) If, as a result of the procedures described in paragraph (e)(i)
or (e)(ii), any Existing Holder would be entitled or required to sell, or any
Potential Holder would be entitled or required to purchase, a fraction
of a Unit on any Auction Date, the Trust Company shall, in such manner as,
in its sole discretion, it shall determine, round up or down the number of
Units to be purchased or sold by any Existing Holder or Potential Holder on
such Auction Date so that the number of Outstanding shares purchased or
sold by each Existing Holder or Potential Holder on such Auction Date shall
be whole Units.
(iv) If, as a result of the procedures described in paragraph
(e)(i), any Potential Holder would be entitled or required to purchase less
than a whole Unit on any Auction Date, the Trust Company shall, in such
manner as, in its sole discretion, it shall determine, allocate Units for
purchase among Potential Holders so that only whole Units are purchased on
such Auction Date by any Potential Holder, even if such allocation results
in one or more of such Potential Holders not purchasing Units on such
Auction Date.
(v) Based on the results of each Auction, the Trust Company shall
determine the aggregate number of Outstanding Units to be purchased and the
aggregate number of Outstanding Units to be sold by Potential Holders and
Existing Holders on whose behalf each Broker-Dealer submitted Bids or Sell
Orders, and, with respect to each Broker-Dealer, to the extent that such
aggregate number of Outstanding Units to be purchased and such aggregate
number of Outstanding Units to be sold differ, determine to which other
Broker-Dealer or Broker-Dealers acting for one or more purchasers such
Broker-Dealer shall deliver, or from which other Broker-Dealer or Broker-Dealers
acting for one or more sellers such Broker-Dealer shall receive, as the case may
be, Outstanding Units.
(f) Miscellaneous
The Board of Directors may interpret the provisions of these Auction
Procedures to resolve any inconsistency or ambiguity, and may remedy any formal
defect or make any other change or modification which does not
adversely affect the rights of Existing Holders of Units. An Existing
Holder (A) may sell, transfer or otherwise dispose of Units only pursuant
to a Bid or Sell Order in accordance with the procedures described in this
paragraph or to or through a Broker-Dealer or to a Person that has
delivered a signed copy of a Purchaser's Letter to the Trust Company,
provided that in the case of all transfers other than pursuant to Auctions
such Existing Holder, its Broker-Dealer or its Agent Member advises the
Trust Company of such transfer and (B) shall have the ownership of the
Units held by it maintained in book entry form by the Securities Depository
in the account of its Agent Member, which in turn will maintain records of
such Existing Holder's beneficial ownership. Neither the Company nor any
Affiliate shall submit an Order, either directly or indirectly, in any
Auction. Except as otherwise provided by law, all of the Outstanding Units
shall be represented by a certificate registered in the name of the nominee
of the Securities Depository and no Person acquiring Units shall be
entitled to receive a certificate representing such Units.
(g) Headings of Subdivisions
The headings of the various subdivisions of these Auction Procedures
are for convenience of reference only and shall not affect the interpretation of
any of the provisions hereof.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
RESTATED ARTICLES OF ORGANIZATION RIDER 6A
Each meeting of the stockholders, annual or special, shall be held at such
hour of the day, and at such place within the United States, or at such other
place as shall then be permitted by law, as may be designated by the Board of
Directors, by the Chairman of the Board or by the President.
*We further certify that the foregoing restated articles of organization
effect no amendments to the articles of organization of the corporation as
heretofore amended, except amendments to the following articles: 3, 4 and 6
(*If there are no such amendments, state "None".)
Briefly describe amendments in space below:
Article 3 - Article 3 has been amended to eliminate the provisions with
respect to the 9.60% Preferred Stock, Series A, the 16% Preferred Stock, Series
C and the Adjustable Rate Preferred Stock, Series D. Each of these series has
been retired or redeemed in its entirety.
Article 4 - Article 4 has been amended to include the amount and classes of
authorized stock and to delete references to specific sections of the Company's
By-laws in favor of general references. These changes are ministerial only and
do not affect any of the rights or obligations of the holders of shares of any
class or series of the capital stock of the company. It also has been amended
to eliminate the provisions with respect to the 9.60% Preferred Stock, Series A,
the 16% Preferred Stock, Series C and the Adjustable Rate Preferred Stock,
Series D. Each of these series has been retired or redeemed in its entirety.
Article 6 - has been amended regarding the time and place for meetings of
stockholders.
IN WITNESS WHEREOF AND UNDER THE PENALTIES OF PERJURY, we have hereto
signed our names this 17th day of February in the year 1995
\s\ Hugh C. MacKenzie President
\s\ Mark A Joyse Assistant Clerk
THE COMMONWEALTH OF MASSACHUSETTS
RESTATED ARTICLES OF ORGANIZATION
(General Laws, Chapter 164, Section 8c)
I hereby approved the within restated articles of organization and, the
filing fee in the amount of $ 500.00 having been paid, said articles are deemed
to be filed with me this 23rd day of February, 1995.
/s/William Francis Galvin
Secretary of State
TO BE FILED IN BY CORPORATION
PHOTO COPY OF RESTATED ARTICLES OF ORGANIZATION TO BE SENT
TO: Robert L. Dewees, Jr.
Peabody & Brown
101 Federal Street
Boston, MA 02110-1832
BY-LAWS
WESTERN MASSACHUSETTS ELECTRIC COMPANY
Adopted
February 11, 1937
(Amended
February 18, 1942)
January 13, 1943
October 19, 1945
January 15, 1947
August 18, 1948
November 17, 1954
February 26, 1960
September 9, 1960
February 27, 1962
July 8, 1964
May 19, 1966
December 5, 1967
June 3, 1970
August 2, 1971
October 13, 1971
October 20, 1975
December 16, 1981
March 1, 1982
April 12, 1983
December 15, 1983
(effective
November 13, 1986)
February 11, 1987
February 24, 1988
April 11, 1994
February 13, 1995
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BY-LAWS
ARTICLE I
STOCKHOLDERS' MEETINGS
The annual meeting of the stockholders shall be held on the first Wednesday
of March in each year, and special meetings of the stockholders shall be held
whenever the Chairman of the Board, the President, or two Directors shall so
order, or whenever called in any other manner as provided by law.
Each meeting of the stockholders, annual or special, shall be held at such
hour of the day, and at such place within the United States, or at such other
place as shall then be permitted by law, as may be designated by the Board of
Directors, by the Chairman of the Board or by the President. Notice of the time
and place of every such meeting shall be given by the Clerk by mailing a notice
to each stockholder of record at his address as shown on the books of the
corporation not less than seven (7) days before the day named for the meeting.
No business shall be in order at a special meeting except such as shall have
been indicated in the notice of such meeting.
In the event of any failure to call and hold the annual meeting as herein
provided, a special meeting may be called and held in lieu of and for the
purposes of such annual meeting. Any election had or business done at such
substitute meeting shall be as valid and effectual as if had or done at a
meeting called as an annual meeting and duly held on said date.
A majority in interest of all the shares of stock of the corporation
outstanding present in person or by proxy shall constitute a quorum for the
transaction of business but less than a quorum may adjourn either sine die or to
a date certain.
No meeting of the stockholders shall be deemed to be invalid for want of
notice provided every stockholder waives notice thereof by a writing filed
either before or after such meeting with the records thereof.
ARTICLE II
OFFICERS
The officers of the corporation shall be a Chairman of the Board of
Directors, a President, an Executive Vice-president, one or more Vice-
presidents, a Treasurer, a Clerk, a Board of not less than five (5) nor
more than twenty-five (25) Directors, such other officers as the Board of
Directors may appoint, including, if the Directors see fit, a Secretary and
one or more Assistant Treasurers. The officers need not be stockholders.
No two of the following offices may be held by the same person: Chairman
of the Board of Directors, President, Executive Vice-president, and Vice-
president, and the Treasurer shall not be an Assistant Treasurer.
The business, property and affairs of the Company shall be managed by
a Board of not less than three nor more than sixteen Directors. Within
these limits, the number of positions on the Board of Directors for any
year shall be the number fixed by resolution of the shareholders or of the
Board of Directors, or, in the absence of such a resolution, shall be the
number of Directors elected at the preceding Annual Meeting of
Shareholders. The Directors so elected shall continue in office until
their successors have been elected and qualified.
ARTICLE III
ELECTION OF OFFICERS
The Directors, the clerk, and the Treasurer shall be elected by
ballot each year at the annual meeting of the stockholders. The Chairman
of the Board, the President, the Executive Vice-president, and each Vice-
president shall be elected annually by, and the Chairman of the Board and
the President shall be elected from, The Board of Directors. All such
other officers as the Directors may appoint, as provided in Article II,
shall be elected annually by the Board of Directors.
Any vacancy in the office of Chairman of the Board, President,
Executive Vice-president, Vice-president, Directors, Treasurer, Assistant
Treasurer, or Clerk arising from non-election, resignation, declination,
death, or any other cause, may be filled by the Board of Directors, except
that whenever the number of Directors shall be increased at any special
meeting of the stockholders the additional Directors so provided for shall
be elected by ballot by the stockholders at the same meeting. Said Board
may also elect an officer pro tempore to serve during the disability or
absence of any officer. Officers chosen to fill vacancies shall hold their
offices until new officers are duly chosen by the stockholders or
Directors, as the case may be.
ARTICLE IV
DIRECTORS
Meetings of the Board of Directors may be held at any time and place
at the call of the Chairman of the Board, the President, or any two
Directors. Notice of each meeting shall be given to each Director either
by notice mailed to him at least forty-eight (48) hours before the time of
such meeting, or by a telephone or telegraphic message sent to his place of
business or residence, or other form of notice actually given to him
twenty-four (24) hours before the time of such meetings. However, any
meeting of the Board and all business transacted thereat shall be legal and
valid without such notice if each member of the Board is present in person
or waives notice thereof by writing filed with the records of the meeting
or assents in writing to the recorded proceedings of the meeting.
One-third of the directors then in office shall constitute a quorum,
except that no quorum shall consist of less than two Directors. A number
less than a quorum may adjourn from time to time until a quorum is present.
In the event of such an adjournment, notice of the adjourned meeting shall
be given to all Directors.
The Board of Directors may at any time elect by ballot not less than
five (5) of their members who shall constitute an Executive committee of
the Board, and if such an Executive Committee is elected the Board of
Directors shall make regulations defining the powers and duties of such
Executive Committee and may delegate to it any or all of their powers in
management of the property, business and affairs of the corporation except
so far as is incompatible with these By-laws or with the laws of the
Commonwealth. A majority of the Executive Committee shall constitute a
quorum.
Such Executive Committee shall elect a Chairman and Secretary and
shall keep a record of its doings which at all reasonable times shall be
open to inspection by each member of the Board of Directors. The Chairman
of the Executive Committee shall submit its records to the Board of
Directors at each regular or special meeting of the Board for such action
as said Board may deem proper.
The Directors as a Board shall have the management of the property,
business and affairs of the corporation and they are hereby invested in
such management with all the powers which the corporation itself possesses
so far as such investing is not incompatible with the provisions of these
By-laws or the laws of the Commonwealth. However, so long as the holders
of the outstanding shares of the corporation's preferred stock voting as a
class have not exercised their right to elect a majority of the Board of
Directors of the corporation on the happening of any of the events of
default specified in the preferred stock provisions of these By-laws, any
right of the corporation to terminate, amend, rescind, waive, discharge, or
in any other way alter or change the obligations of the corporation under
any contract with Northeast Nuclear Energy Company covering the maintaining
of an inventory of nuclear core elements for Unit Nos. 1, 2 or 3 of the
Millstone Nuclear Power Station, including, without limitation, the Fuel
Supply Contract dated as of December 1, 1972, (as it is to be amended by a
Contract of Amendment to be dated as of October 1, 1975), by and among the
corporation, The Hartford Electric Light Company, and the Connecticut Light
and Power Company and Northeast Nuclear Energy Company, shall be reserved
to the common stockholders of the corporation.
They may appoint and remove at pleasure such subordinate officers and
employees as may see to them wise.
They may assign such powers and duties to any officers or subordinate
officers or employees as may not be inconsistent with Laws or these
By-laws.
They shall have access to the books, vouchers and funds of the
corporation in the custody of the Treasurer, shall determine upon the form
of the corporate seal and of the certificates of stock, shall fix the
salaries of the officers, and shall declare dividends from time to time as
they may deem for the best interests of the corporation.
They may make contributions to corporations, trusts, funds or
foundations organized and operated exclusively for charitable, scientific
or educational purposes, no part of the earnings of which inures to the
benefit of any private shareholder or individual, in such amounts as they
may deem reasonable up to but not exceeding in any fiscal year in the
aggregate one-half of one percent of the capital and surplus of the
corporation as at the close of the fiscal year last preceding the making of
any such contribution.
The Company shall indemnify each of its Directors and officers
(including persons who serve at its request as Directors, officers, or in
any other similar capacity of another organization in which it has any
interest as a shareholder, creditor or otherwise) against all liabilities
and expenses, including amounts paid in satisfaction of judgments, in
compromise or as fines and penalties, and counsel fees, reasonably incurred
by him in connection with the defense or disposition of any action, suit or
other proceeding, whether civil or criminal, in which he may be involved or
with which he may be threatened, while in office or thereafter, by reason
of his being or having been such a Director or officer, except with respect
to any matter as to which he shall have been adjudicated in such action,
suit or proceeding not to have acted in good faith in the reasonable belief
that his action was in the best interests of the corporation; provided,
however, that as to any matter disposed of by a compromise payment by such
Director or officer pursuant to a consent decree or otherwise, no
indemnification either for said payment or for any other expenses shall be
provided unless such compromise shall be approved as in the best interests
of the corporation, after notice that it involves such indemnification, (a)
by a disinterested majority of the Directors then in office; or (b) by a
majority of the disinterested Directors then in office, provided that there
has been obtained an opinion in writing of independent legal counsel to the
effect that such Director or officer appears to have acted in good faith in
the reasonable belief that his action was in the best interests of the
corporation; or (c) by the holders of majority of the outstanding stock at
the time entitled to vote for Directors, voting as a single class,
exclusive of any stock owned by an interested Director or officer. In
discharging his duty any such Director or officer, when acting in good
faith, may rely upon the books of account of the corporation or of such
other organization, reports made to the corporation or to such other
organization by any of its officers or employees or by counsel,
accountants, appraisers or other experts selected with reasonable care by
the Board of Directors or officers, or upon other records of the
corporation or of such other organization. Expenses incurred with respect
to any such action, suit or proceeding may be advanced by the corporation
prior to the final disposition of such action, suit or proceeding, upon
receipt of an undertaking by or on behalf of the recipient to repay such
amount unless it is ultimately determined that he is entitled to
indemnification. The right of indemnification hereby provided shall not be
exclusive of or affect any other right to which any Director or officer may
be entitled. As used in this paragraph, the terms "Director" and "officer"
include their respective heirs, executors and administrators, and an
"interested" Director or officer is one against whom in such capacity the
proceedings in question or another proceeding on the same or similar
grounds is then pending. Nothing contained in this Article shall be found,
in any action, suit or proceeding to be invalid or ineffective, the
validity and the effect of the remaining parts shall not be affected.
ARTICLE V
CHAIRMAN OF THE BOARD OF DIRECTORS
The Chairman of the Board of Directors shall preside at the meetings
of the Board and shall act in a general advisory capacity to the Board in
regard to all activities of the corporation, and shall have such other
powers and perform such other duties as may from time to time be determined
by the Board.
ARTICLE VI
THE PRESIDENT
The President shall preside at all meetings of the stockholders and
in the absence of the Chairman of the Board at all meetings of the Board of
Directors. The President shall be the chief executive officer of the
corporation and shall have full charge of its business and affairs and
shall perform all the duties of this office prescribed by law and all
powers and duties given him by the Board of Directors.
ARTICLE VII
EXECUTIVE VICE-PRESIDENT AND VICE-PRESIDENTS
The Executive Vice-president shall have such powers and perform such
duties as may be assigned to him by the Board of Directors or as may be
delegated to him by the President. In the absence or disability of the
President, or in case of an unfilled vacancy in that office, the Executive
Vice-president shall perform the duties and exercise the powers of the
President.
The Vice-president or Vice-presidents shall perform such duties of a
general or special nature as may be assigned to him or them by the Board of
Directors or as may be delegated to him or them by or through the
President. In case of the absence or disability of the Executive
Vice-president, a Vice-president shall perform all the duties and have all
the powers of the Executive Vice-president. If there are at any time two
or more Vice-presidents, the one to act in place of the Executive
Vice-president shall be selected by the Board of Directors, provided,
however, that prior to the making of such selection by said Board a
Vice-president to act as aforesaid may be appointed by the President, or if
he is unable to make such appointment or fails to do so, by the Chairman of
the Board, and the Vice-president so appointed shall continue to act as
aforesaid until another Vice-president has been appointed for that purpose
by the Board of Directors.
ARTICLE VIII
THE SECRETARY AND THE CLERK
The Secretary shall have such duties as may from time to time be
delegated to him by the Board of Directors.
The Clerk shall be a resident of Massachusetts. He shall be sworn,
and shall record all votes of the corporation in a book to be kept for the
purpose. He shall attend all meetings of stockholders, of the Board of
Directors, and of the Executive Committee. In the absence of the Clerk or
if at any such meeting he shall be otherwise engaged, an Assistant Clerk if
present shall record the votes taken at the meeting, and if no Assistant
Clerk shall be present, a Clerk pro tempore shall be chosen for that
purpose. The Clerk or any Assistant Clerk may furnish certified copies of
any portion of the records of the corporation under its corporate seal.
All Assistant Clerks shall be sworn.
ARTICLE IX
THE TREASURER
The Treasurer when required by the Directors shall give bond with
sureties acceptable to them for the faithful discharge of his duties and in
such sum as the Directors may determine, and the premium may, by vote of
the Board of Directors, be paid from the funds of the corporation.
He shall be the transfer agent of the stock of the corporation unless
a special transfer agent is appointed by the Directors, shall keep a record
of the names and residences of all the stockholders, shall have the custody
of the corporate seal and of all the moneys, funds and valuable papers and
documents of the corporation except his own bond which shall be in the
custody of the President.
He shall deposit all the funds of the corporation in such bank or
banks as the Directors shall designate to the credit of the corporation by
its corporate name, subject to the checks of the corporation signed by its
Treasurer or an Assistant Treasurer or such other officer or employee as
may be designated for that purpose by the vote of the Directors, but with
such requirements, if any, as to joint signatures and such other
limitations, if any, of the authority as aforesaid of any signing officer
or employee as the Directors may see fit to impose.
He shall issue notes and accept drafts on behalf of the corporation
only when authorized thereto by the Directors.
He shall keep accurate books of account of the corporation's
transactions which shall be the property of the corporation, which together
with all its property in his custody shall be subject at all times to
inspection and control of the Directors.
ARTICLE X
ASSISTANT TREASURER
Each Assistant Treasurer, if any, shall have such powers and duties
as may be given him by the Directors and shall give bond when required by
the Directors with sureties acceptable to them for the faithful discharge
of his duties in such sum as the Directors may determine, and the premiums
may, by vote of the Board of Directors, be paid by the corporation.
ARTICLE XI
SALES, LEASES, AND CONVEYANCES OF REAL ESTATE
The President and Treasurer may in their discretion, to the extent
authorized by law and by vote of the Directors or of the Executive
Committee, lease for any term of time and convey all of its real estate
including water power and release or modify easements and other rights in
real estate whether granted to or by the corporation; and all deeds,
conveyances and leases of real estate including water power and releases
and modifications of easements and of other rights in real estate of the
corporation, unless otherwise provided by vote of the corporation, shall be
made in the name of the corporation under its corporate seal, and be signed
by the President, the Executive Vice-president, or any Vice-president
thereto authorized by a vote of the Directors or of the Executive Committee
and may be acknowledged by any person signing as aforesaid.
ARTICLE XII
CERTIFICATES OF STOCK-TRANSFERS
Certificates of stock may be signed by the President or a
Vice-president and the Treasurer or an Assistant Treasurer. Such
certificates shall be in such form as the Directors may approve, and shall
also bear the seal of the corporation which shall be in the form
theretofore used by the corporation, or in a newer form adopted by the
Directors.
Shares of stock may be transferred by assignment thereof in writing,
accompanied by delivery of the certificates; but no such transfer of stock
shall affect the right of the corporation to pay any dividend thereon or to
treat the holder of record as the holder in fact until the transfer has
been recorded upon the books of the corporation or a new certificate has
been issued to the person to whom the stock has been transferred.
In case of the loss of a certificate, a duplicate may be issued on
such reasonable terms as the Directors shall prescribe.
ARTICLE XIII
CLOSING OF TRANSFER BOOKS
The transfer books of the corporation may be closed for not exceeding
fifteen (15) days next prior to any meeting of the stock-holders and at
such other times and for such reasonable periods as may be determined by
the Board of Directors.
ARTICLE XIV
FISCAL YEAR
The fiscal year of the corporation shall end on the thirty-first day
of December in each year.
ARTICLE XV
TRANSFER AGENT AND REGISTRAR
If the Board of Directors deem it advisable to have a transfer agent
other than the Treasurer, they may appoint any Bank or Trust Company to
that office. They may appoint the same or any other Bank or Trust Company
as Registrar of stock certificates if it appear desirable to have the stock
registered. They may terminate the authority of any Bank acting in either
capacity whenever it shall seem wise.
ARTICLE XVI
SENIOR STOCK PROVISIONS
The Company's capital stock includes a class of capital stock
designated "Common Stock," a class of capital stock designated "Preferred
Stock," and a class of capital stock designated "Class A Preferred Stock."
The authorized shares of Common Stock, Preferred Stock and Class A
Preferred Stock are the number of shares authorized in the Company's
articles of organization, as amended from time to time. The Preferred
Stock and the Class A Preferred Stock are hereinafter for convenience of
reference sometimes collectively referred to as the "Senior Stock," and
either class may hereinafter individually be referred to as "Senior Stock."
Shares of Preferred Stock and shares of Class A Preferred Stock shall rank
on a parity in respect of dividends or payment in case of liquidation, and,
to the extent not fixed and determined by these by-laws or the Company's
articles of organization or otherwise by law, shall have the same rights,
preferences and powers. The general terms, limitations and relative rights
and preferences of each share of Preferred Stock and each share of Class A
Preferred Stock shall be determined in accordance with the following
Sections:
Section 1. Issuance of Senior Stock
Shares of Preferred Stock may be issued from time to time in one or
more series on such terms and for such consideration as may be determined
by the Board of Directors. Shares of Class A Preferred Stock may be issued
from time to time in one or more series on such terms and for such
consideration as may be determined by the Board of Directors. The series
designation, dividend rate, redemption prices, and any other terms,
limitations and relative rights and preferences of each series of either
class of Senior Stock shall be determined by the Board of Directors to the
extent not fixed and determined by this Article or the Company's articles
of organization.
Section 2. Dividends
A. The holders of either class of the Senior Stock shall receive,
but only when and as declared by the Board of Directors, cumulative
dividends at the rate provided for the particular series and payable on
such dividend payment dates in each year as said Board may determine, such
dividends to be payable to holders of record on such dates as may be fixed
by said Board but not more than 45 days before each dividend date,
provided, however, that dividends shall not be declared and set apart for
payment, or paid, on Senior Stock of any one class and series, for any
dividend period, unless dividends have been or are contemporaneously
declared and set apart for payment, or paid, on Senior Stock of all series
for all dividend periods terminating on the same or an earlier date.
B. Dividends on each share of Senior Stock shall be cumulative from
the date of issue thereof or from such earlier date as the Board of
Directors may determine therefor. Unless full cumulative dividends to the
last preceding dividend date shall have been paid or set apart for payment
on all outstanding shares of Senior Stock, no dividend shall be paid on any
junior stock. The term "junior stock" means Common Stock or any other
stock of the Company subordinate to the Senior Stock in respect of
dividends or payments in liquidation.
C. So long as any shares of Senior Stock are outstanding, the
Company shall not declare any dividends or make any other distributions in
respect of outstanding shares of any junior stock of the Company, other
than dividends or distributions in shares of junior stock, or purchase or
otherwise acquire for value any outstanding shares of junior stock (the
declaration of any such dividend or the making of any such distribution,
purchase or acquisition being herein called a "junior stock payment") in
contravention of the following:
(1) If and so long as the junior stock equity (hereinafter
defined), adjusted to reflect the proposed junior stock payment, at the end
of the calendar month immediately preceding the calendar month in which the
proposed junior stock payment is to be made is less than 20% of total
capitalization (hereinafter defined) at that date, as so adjusted, the
Company shall not make such junior stock payment in an amount which,
together with all other junior stock payments made within the year ending
with and including the date on which the proposed junior stock payment is
to be made, exceeds 50% of the net income of the Company available for
dividends on junior stock for the 12 full calendar months immediately
preceding the calendar month in which such junior stock payment is made,
except in an amount not exceeding the aggregate of junior stock payments
which under the restrictions set forth above in this paragraph (1) could
have been, and have not been, made.
(2) If and so long as the junior stock equity, adjusted to
reflect the proposed junior stock payment, at the end of the calendar month
immediately preceding the calendar month in which the proposed junior stock
payment is to be made, is less than 25% but not less than 20% of the total
capitalization at that date, as so adjusted, the Company shall not make
such junior stock payment in an amount which, together with all other
junior stock payments made within the year ending with and including the
date on which the proposed junior stock payment is to be made, exceeds 75%
of the net income of the Company available for dividends on the junior
stock for the 12 full calendar months immediately preceding the calendar
month in which such junior stock payment is made, except in an amount not
exceeding the aggregate of junior stock payments which under the
restrictions set forth above in this paragraph (2) could have been, and
have not been, made.
D. The term "junior stock equity" means the aggregate of the part
value of or stated capital represented by, the outstanding shares of junior
stock, all earned surplus, capital or paid-in surplus, and any premiums on
the junior stock then carried on the books of the Company, less:
(1) the excess, if any, of the aggregate amount payable on
involuntary liquidation of the Company upon all outstanding shares of
Senior Stock over the sum of (i) the aggregate par or stated value of such
shares and (ii) any premiums thereon;
(2) any amounts on the books of the Company known, or estimated
if not known, to represent the excess, if any, of recorded value over
original cost of used or useful utility plant; and
(3) any intangible items set forth on the asset side of the
balance sheet of the Company as a result of accounting convention, such as
unamortized debt discount and expense; provided, however, that no
deductions shall be required to be made in respect of items referred to in
clauses (2) and (3) of this subsection D in cases in which such items are
being amortized or are provided for, or are being provided for, by
reserves.
E. The term "total capitalization" means the aggregate of:
(1) the principal amount of all outstanding indebtedness of the
Company maturing more than 12 months after the date of issue thereof; and
(2) the par value or stated capital represented by, and any
premiums carried on the books of the Company in respect of, the outstanding
shares of all classes of the capital stock of the Company, earned surplus,
and capital or paid-in surplus, less any amounts required to be deducted
pursuant to clauses (2) and (3) of subsection D of this Section 2 in the
determination of junior stock equity.
Section 3. Redemption or Purchase of Senior Stock
A. All or any part of any series of Senior Stock may by vote of
the Board of Directors be called for redemption at any time at the
redemption price provided for the particular series and in the manner
hereinbelow provided. Subject to the provisions of subsection B of this
Section 3, all or any part of any series of Senior Stock may be called for
redemption without calling all or any part of any other series of Senior
Stock. If less than all of any series of Senior Stock is so called, the
Transfer Agent shall determine by lot or in some other manner approved by
the Board of Directors the shares of such series of Senior Stock to be
called.
B. No call for redemption of less than all shares of Senior Stock
outstanding shall be made if the Company shall be in arrears in respect of
payment of dividends on any shares of Senior Stock outstanding.
C. The sums payable in respect of any shares of Senior Stock so
called shall be payable at the office of an incorporated bank or trust
company in good standing. Notice of such call stating the redemption date
shall be mailed not less than 30 days before the redemption date to each
holder of record of shares of Senior Stock so called at his address as it
appears upon the books of the Company.
D. The Company shall, before the redemption date, deposit with
said bank or trust company all sums payable with respect to shares of
Senior Stock so called. After such mailing and deposit the holders of
shares of Senior Stock so called for redemption shall cease to have any
right to future dividends or other rights or privileges as stockholders
in respect of such shares and shall be entitled to look for payment on and
after the redemption date only to the sums so deposited with said bank or
trust company for their respective amounts. Shares so redeemed may be
reissued but only subject to the limitations imposed upon the issue of
Senior Stock.
E. The Company may at any time purchase all or any of the
then outstanding shares of Senior Stock of any class and series upon the
best terms reasonably obtainable, but not exceeding the then current
redemption price of such shares, except that no such purchase shall be made
if the Company shall be in arrears in respect of payment of dividends on
any shares of Senior Stock outstanding or if there shall exist an event of
default as defined in Section 5 hereof.
Section 4. Amounts Payable on Liquidation
A. The holders of any series of Senior Stock shall receive upon
any voluntary liquidation, dissolution or winding up of the Company the
then current redemption price of the particular series and if such action
is involuntary $100 per share in the case of the Preferred Stock and $25
per share in the case of the Class A Preferred Stock, plus in each case all
dividends accrued and unpaid to the date of such payment, before any
payment in liquidation is made on any junior stock.
B. If the net assets of the Company available for distribution on
liquidation to the holders of Senior Stock shall be insufficient to pay
said amounts in full, then such net assets shall be distributed among the
holders of Senior Stock, who shall receive a common percentage of the full
respective preferential amounts.
Section 5. Voting Powers
A. Except as provided in this Article or in the Company's articles
of organization and as provided by law, the holders of Senior Stock shall
have no voting power or right to notice of any meeting.
B. Whenever the holders of the Senior Stock shall have the
right to vote or consent to an action as provided in these Articles or the
Company's articles of organization or as provided by law, both classes of
Senior Stock shall (except as provided below) vote together as a single
class, each outstanding share of Preferred Stock entitled to vote and each
outstanding share of Class A Preferred Stock entitled to vote having such
voting rights as are proportionate to the ratio of (i) the par value
represented by such share to (ii) the par value represented by all shares
of Senior Stock then outstanding. Whenever only one class of the Senior
Stock shall have the right to vote or consent to an action as provided in
these Articles or the Company's articles of organization or as provided by
law, or whenever each class of the Senior Stock shall be entitled or be
required to vote as a separate class on a matter, each outstanding share
of such class entitled to vote shall be entitled to one vote on each such
matter.
C. Whenever dividends on any share of Senior Stock shall be in
arrears in an amount equal to or exceeding four quarterly dividend
payments, or whenever there shall have occurred some default in the
observance of any of the provisions of this Article, or some default on
which action has been taken by debentureholders, bondholders or the trustee
of any deed of trust or mortgage of the Company, or whenever the Company
shall have been declared bankrupt or a receiver of its property shall have
been appointed (any of said conditions being herein called an "event of
default"), then the holders of Senior Stock shall be given notice of all
stockholders' meetings and shall have the right voting together as a class
to elect the smallest number of directors necessary to constitute a
majority of the Board of Directors of the Company and the exclusive right
voting together as a class to amend the by-laws to make such appropriate
increase in the number of directorships as may be required to effect such
election. When all arrears of dividends shall have been paid and such
event of default shall have been terminated, all the rights and powers of
the holders of Senior Stock to receive notice and to vote shall cease,
subject to being again revived on any subsequent event of default.
D. Whenever the right to elect directors shall have accrued to the
holders of Senior Stock the Company shall call a meeting of stockholders
for the election of directors and, if necessary, the amendment of the
by-laws to permit the holders of Senior Stock to exercise their rights
pursuant to subsection C of this Section 5, such meeting to be held not
less than 45 days and not more than 90 days after the accrual of such
rights. When such rights shall cease, the Company shall, within seven days
from the delivery to the Company of a written request therefor by any
stockholder, cause a meeting of the stockholders to be held within 30 days
from the delivery of such request for the purpose of electing a new Board
of Directors. Forthwith, upon the election of such new Board of Directors,
the directors in office immediately prior to such election (other than
persons elected directors in such election) shall be deemed removed from
office without further action by the Company.
Section 6. Action Requiring Certain Consent of Senior
Stockholders
A. So long as any Senior Stock is outstanding, the Company,
without the affirmative vote or written consent of at least a majority in
interest of the Senior Stock then outstanding voting or giving consent
together as a class shall not:
(1) Issue or assume any unsecured notes, unsecured debentures
or other securities representing unsecured debt (other than for the purpose
of refunding or renewing outstanding unsecured securities issued or assumed
by the Company resulting in equal or longer maturities or redeeming or
otherwise retiring all outstanding shares of Senior Stock) if immediately
after such issue or assumption (a) the total outstanding principal amount
of all unsecured notes, unsecured debentures or other securities
representing unsecured debt of the Company will thereby exceed 20% of the
aggregate of all outstanding secured debt of the Company and the capital
stock, premiums thereon, and surplus of the Company, as stated on its
books, or (b) the total outstanding principal amount of all unsecured debt
of the Company of maturities of less than 10 years will thereby exceed 10%
of the aggregate of all outstanding secured debt of the Company and the
capital stock, premiums thereon, and surplus of the Company, as stated on
its books. For the purposes of this subsection A, the payment due upon the
maturity of unsecured debt having an original single stated maturity of 10
years or more shall not be regarded as unsecured debt with a maturity of
less than 10 years until within three years of the maturity thereof, and
none of the payments due upon any unsecured serial debt having an original
stated maturity for the final serial payment of 10 years or more shall be
regarded as unsecured debt of a maturity of less than 10 years until within
three years of the maturity of the final serial payment.
(2) Issue, sell or otherwise dispose of any shares of the then
authorized but unissued Senior Stock or any other stock ranking on a parity
with or having a priority over Senior Stock in respect of dividends or of
payments in liquidation, or reissue, sell or otherwise dispose of any
reacquired shares of Senior Stock or such other stock, other than to
refinance an equal par value or stated value of Senior Stock or of stock
ranking on a parity with or having priority over Senior Stock in respect of
dividends or of payments in liquidation, if:
(a) For a period of 12 consecutive calendar months within
15 calendar months immediately preceding the calendar month in which any
such shares shall be issued, the Income before Interest Charges of the
Company for said period available for the payment of interest determined in
accordance with the systems of accounts then prescribed for the Company by
the Department of Public Utilities of the Commonwealth of Massachusetts (or
by such other official body as may then have authority to prescribe such
systems of accounts) but in any event after deducting depreciation charges
and taxes (including income taxes) and including, in any case in which such
stock is to be issued, sold or otherwise disposed of in connection with the
acquisition of any property, the Income before Interest Charges of the
property to be so acquired, computed as nearly as practicable in the manner
specified above, shall not have been at least one and one-half (1 1/2)
times the sum of (i) the interest charges for one year on all indebtedness
which shall then be outstanding (excluding interest charges on any
indebtedness, proposed to be retired in connection with the issue, sale or
other disposition of such shares), and (ii) an amount equal to all annual
dividend requirements on all outstanding shares of Senior Stock and all
other stock, if any, ranking on a parity with or having priority over
Senior Stock in respect of dividends or of payments in liquidation,
including the shares proposed to be issued, but not including any shares
proposed to be retired in connection with such issue, sale or other
disposition; or if
(b) Such issue, sale or disposition would bring the
aggregate of the amount payable in connection with an involuntary
liquidation of the Company with respect to all shares of Senior Stock and
all shares of stock, if any, ranking on a parity with or having priority
over Senior Stock in respect of dividends or of payments in liquidation to
an amount in excess of the sum of the junior stock equity. If for the
purposes of meeting the requirements of this clause (b), it shall have been
necessary to take into consideration any earned surplus of the Company, the
Company shall not thereafter pay any dividends on or make any distributions
in respect of, or make any payment for the purchase or other acquisition
of, junior stock which would result in reducing the junior stock equity to
an amount less than the amount payable on involuntary liquidation of the
Company in respect of Senior Stock and all shares ranking on a parity with
or having a priority over Senior Stock in respect of dividends or of
payments in liquidation at the time outstanding.
If during the period for which Income before Interest Charges is to be
determined for the purpose set forth in this paragraph (2), the amount, if
any, required to be expended by the Company during such period for property
additions pursuant to a renewal and replacement fund or similar fund
established under any indenture of mortgage or deed of trust of the Company
shall exceed the amount deducted during such period in the determination of
such Income before Interest Charges on account of depreciation and
amortization of electric plan acquisition adjustments, such excess shall
also be deducted in determining such Income before Interest Charges.
B. So long as any Senior Stock is outstanding, the Company,
without the affirmative vote or written consent of at least two-thirds in
interest of the Senior Stock then outstanding voting or giving consent
together as a class shall not authorize any shares of any class of stock
having a priority over the Senior Stock in respect of dividends or of
payments in liquidation or issue any shares of any such prior ranking stock
more than 12 months after the date of the vote or consent authorizing such
prior ranking stock.
C. The provisions of this Article may be changed only by the
affirmative vote or written consent of at least two-thirds in interest of
the issued and outstanding shares of each class of capital stock of the
Company voting or giving their consent in each case separately as a class;
provided, however, that if any such change or proposed change would affect
only one class of Senior Stock, then such change may be effected only by
the affirmative vote or written consent of at least two-thirds in interest
of the issued and outstanding shares of Common Stock and at least
two-thirds in interest of the issued and outstanding shares of the class of
Senior Stock that is affected, voting or giving their consent in each case
separately as a class; and provided further, however, the holders of
Senior Stock shall not be entitled to vote on an increase in the number of
authorized shares of Preferred Stock or Class A Preferred Stock. In no
event shall any reduction of the dividend rate or of the amounts payable
upon redemption or liquidation with respect to any share of Senior Stock be
made without the consent of the holder thereof, and no such reduction in
respect of the shares of any particular series of Senior Stock shall be
made without the consent of all the holders of shares of such series.
D. No share of Senior Stock shall be deemed to be "outstanding"
within the meaning of this Section 6 or of Section 7 if, at or prior to the
time when the approval herein or therein referred to would otherwise be
required, provision shall be made for its redemption, including a deposit
complying with the requirements of subsection D of Section 3.
Section 7. Merger, Consolidation or Sale of All Assets Except
with the affirmative vote or written consent of a majority in interest of
Senior Stock then outstanding voting or giving consent together as a class,
the Company shall not merge or consolidate with or into any other
corporation or sell or otherwise dispose of all or substantially all of its
assets (except by mortgage or pledge) unless such merger, consolidation,
sale or other disposition, or the issuance or assumption of securities in
the effectuation thereof shall have been ordered, approved or permitted
under the Public Utility Holding Company Act of 1935.
Section 8. No Preemptive Right
Except as otherwise expressly provided by law, the holders of Senior
Stock shall have no preemptive right to subscribe to any further issue of
additional shares of Senior Stock or of any other class of stock now or
hereafter authorized, nor for any future issue of bonds, debentures, notes
or other evidence of indebtedness or other security convertible into stock.
If it is expressly required by law that, notwithstanding the provisions of
the preceding sentence, any such further or future issue be offered
proportionately to the stockholders, the holders of Preferred Stock only
shall be entitled to subscribe for new or additional Preferred Stock, the
holders of Class A Preferred Stock only shall be entitled to subscribe for
new or additional Class A Preferred Stock and the holders of Common Stock
only shall be entitled to subscribe for new or additional Common Stock; and
notice of such increase as required by law need be given and the new shares
need be offered proportionately only to the stockholders who are so
entitled to subscribe.
Section 9. Immunity of Directors, Officers and Agents No
director, officer or agent of the Company shall be held personally
responsible for any action taken in good faith though subsequently adjudged
to be in violation of this Article.
Section 10. Transfer Agent
The Company shall always have at least one transfer agent for Senior
Stock, which shall be an incorporated bank or trust company of good
standing.
ARTICLE XVII
PROVISIONS WITH RESPECT TO THE SERIES OF PREFERRED STOCK
1. 7.72% Preferred Stock, Series B
There shall be a series of Preferred Stock designated "7.72%
Preferred Stock, Series B," and consisting of 200,000 shares with an
aggregate par value of $20,000,000 and a par value per share of $100. The
dividend rate and redemption prices as to said 7.72% Preferred Stock,
Series B, shall be as follows:
(a)Dividends on said 7.72% Preferred Stock, Series B, shall be
at the rate of 7.72% per share per annum, and no more, and shall be
cumulative from October 1, 1971. Said dividends, when declared, shall be
payable on the first days of January, April, July and October in each year.
(b)Redemption Prices of said 7.72% Preferred Stock, Series B,
shall be $109.30 per share if redeemed on or before October 1, 1976,
$107.37 per share if redeemed after October 1, 1976 and on or before
October 1, 1981, $105.44 per share if redeemed after October 1, 1981 and on
or before October 1, 1986, and $103.51 per share if redeemed after October
1, 1986, plus in all cases that portion of the quarterly dividend accrued
thereon to the redemption date and all unpaid dividends thereon, if any,
provided, however, that none of the 7.72% Preferred Stock, Series B shall
be redeemed prior to October 1, 1976, if such redemption is for the purpose
of or in anticipation of refunding such 7.72% Preferred Stock, Series B
through the use, directly or indirectly, of finds borrowed by the Company
or of the proceeds of the issue by the Company of shares of any stock
ranking prior to or on a parity with the 7.72% Preferred Stock, Series B as
to dividends or assets, if such borrowed funds or such shares have an
effective interest cost or effective dividend cost to the Company (computed
in accordance with generally accepted financial principles), as the case
may be, of less than 7.69% per annum.
2. 7.60% Class A Preferred Stock, 1987 Series
There shall be a series of Preferred Stock designated "7.60% Class A
Preferred Stock, 1987 Series," and consisting of 1,200,000 shares with an
aggregate par value of $30,000,000 and a par value per share of $25. The
dividend rate and redemption prices as to said 7.60% Class A Preferred
Stock, 1987 Series, shall be as follows:
(a) Dividends on said 7.60% Class A Preferred Stock, 1987 Series,
shall be at the rate of 7.60% per share per annum, and no more, and shall
be cumulative from the date of issuance. Said dividends, when declared,
shall be payable on the first days of February, May, August and November in
each year, commencing May 1, 1987.
(b) For each of the twelve month periods commencing February 1,
1987, the redemption prices of said 7.60% Class A Preferred Stock, 1987
Series, shall be the amount per share set forth below:
Twelve Twelve
Months Redemption Months Redemption
Beginning Price Beginning Price
February 1 Per Share February 1 Per Share
1987 $26.90 2000 $25.26
1988 26.90 2001 25.13
1989 26.90 2002 25.00
1990 26.90 2003 25.00
1991 26.90 2004 25.00
1992 26.27 2005 25.00
1993 26.14 2006 25.00
1994 26.02 2007 25.00
1995 25.89 2008 25.00
1996 25.76 2009 25.00
1997 25.64 2010 25.00
1998 25.51 2011 25.00
1999 25.38
plus in all cases that portion of the quarterly dividend accrued thereon
to the redemption date and all unpaid dividends thereon, if any; provided,
however, that none of the 7.60% Class A Preferred Stock, 1987 Series, shall
be redeemed prior to February 1, 1992, if such redemption is for the
purpose of or in anticipation of refunding such 7.60% Class A Preferred
Stock, 1987 Series, through the use, directly or indirectly, of funds
borrowed by the Company or of the proceeds of the issue by the Company of
shares of any stock ranking prior to or on a parity with the 7.60% Class A
Preferred Stock, 1987 Series, as to dividends or assets, if such borrowed
funds or such shares have an effective interest cost or effective dividend
cost to the Company (computed in accordance with generally accepted
financial principles), as the case may be, of less than 7.69% per annum.
(c) As and for a sinking fund for said 7.60% Class A Preferred
Stock, 1987 Series, commencing on February 1, 1992, and on each February
1 in each year thereafter so long as any shares of the 7.60% Class A
Preferred Stock, 1987 Series, remain outstanding, the Company shall, to the
extent of any funds of the Company legally available therefor and except as
otherwise restricted by the Company's Statement of Preferred Stock
Provisions, redeem 60,000 shares of 7.60% Class A Preferred Stock, 1987
Series (or such lesser number of such shares as remain outstanding) at $25
per share plus accrued dividends to the date of redemption; provided,
however, that if in any year the Company does not redeem the full number of
shares of 7.60% Class A Preferred Stock, 1987 Series, required to be
redeemed pursuant to this sinking fund, the deficiency shall be made good
on the next succeeding February 1 on which the Company has funds legally
available for, and is otherwise permitted to effect, the redemption of
shares of 7.60% Class A Preferred Stock, 1987 Series, pursuant to this
sinking fund. At the option of the Company, the number of shares of 7.60%
Class A Preferred Stock, 1987 Series, redeemed on any February 1 may be
reduced by the number of such shares purchased and canceled by the Company
during the preceding twelve-month period or redeemed during such period
pursuant to subsection (b) hereof. Any shares so redeemed or purchased and
canceled may be given the status of authorized but unissued shares of
Senior Stock, but none of such shares shall be reissued as shares of 7.60%
Class A Preferred Stock, 1987 Series. The Company shall have the option,
which shall be noncumulative, to redeem on February 1, 1992 and on each
February 1 thereafter up to an additional 60,000 shares of 7.60% Class A
Preferred Stock, 1987 Series, at the sinking fund redemption price. No
such optional sinking fund shall operate to reduce the number of shares of
the 7.60% Class A Preferred Stock, 1987 Series, required to be redeemed
pursuant to the mandatory sinking fund provisions hereinabove set forth.
In the event that the Company shall at any time fail to make a full
mandatory sinking fund payment on any sinking fund payment date, the
Company shall not pay any dividends or make any other distributions in
respect of outstanding shares of any junior stock (as that term is defined
in Subsection 2D of Section 2 of Article XVI of the by-laws of the Company)
of the Company, other than dividends or distributions in shares of junior
stock, or purchase or otherwise acquire for value any outstanding shares of
junior stock, until all such payments have been made.
3. Dutch Auction Rate Transferable Securities Class A Preferred
Stock, 1988 Series
There shall be a series of Class A Preferred Stock designated "Dutch
Auction Rate Transferable Securities Class A Preferred Stock, 1988
Series" (the "1988 DARTS") consisting of 2,140,000 shares with an
aggregate par value of $53,500,000 and a par value per share of $25. The
provisions governing the issue and sale of the 1988 DARTS in Units,
certification, dividend rights, redemption, reacquisition, auction
procedures, and other preferences, qualifications and special or relative
rights or privileges with respect to the 1988 DARTS shall be as follows:
(1) Units
The 1988 DARTS shall be issued and sold by the Company only in units
of 4,000 shares per unit ("Units"). No partial Units shall be issued and
sold by the Company, and no fractional shares of the 1988 DARTS shall be
issued and sold, no transfer of the 1988 DARTS in less than whole Units
shall be made, nor shall any transfer in less than whole Units be
registered on the transfer books of the Company or be effective for any
purpose.
(2) Certification
Except as otherwise provided by law, all outstanding DARTS shall be
represented by a certificate or certificates registered in the name of a
nominee of the Securities Depository (as defined in Section (6)(a)(xxi)
below), and no person acquiring Units shall be entitled to receive a
certificate representing the 1988 DARTS. The nominee of the Securities
Depository shall be the sole holder of record of the 1988 DARTS. Each
purchaser of Units will receive dividends, distributions and notices
according to the procedures of the Securities Depository and, if such
purchaser is not a member of the Securities Depository, of such purchaser's
Agent Member (as defined in Section (6)(a)(ii) below).
(3) Dividend Rights
(a) Dividends on the 1988 DARTS shall be paid, when, as and if
declared by the Board of Directors of the Company out of funds legally
available therefor, at the rate per annum determined as set forth below in
subsection (c) of this Section (3) and no more (the "Applicable Rate"),
payable on the respective dates set forth below.
(b) Dividends on the 1988 DARTS shall accrue from the date of
original issuance and shall be payable commencing on May 3, 1988, and on
each succeeding seventh Tuesday thereafter, except that if any of such
Tuesday, the Monday preceding such Tuesday, or the Wednesday following such
Tuesday is not a Business Day (as defined below), then (i) the dividend
payment date shall be the first Business Day after such Tuesday that is
immediately followed by a Business Day and is preceded by a Business Day
that is the preceding Monday or a day after such Monday, or (ii) if the
Securities Depository shall make available to its participants and members,
in funds immediately available in New York City on dividend payment dates,
the amount due as dividends on such dividend payment dates (and the
Securities Depository shall have so advised the Trust Company (as defined
in Section (6)(a)(xxx) below)), then the dividend payment date shall be the
first Business Day on or after such Tuesday that is preceded by a Business
Day that is the preceding Monday or a day after such Monday. "Business
Day" means a day on which the New York Stock Exchange is open for trading
and which is not a day on which banks in New York City are authorized by
law to close. Each dividend payment date determined as provided above is
referred to herein as the "Dividend Payment Date." Although any particular
Dividend Payment Date may not occur on the originally scheduled Tuesday
because of the exceptions discussed above, the next succeeding Dividend
Payment Date shall be, subject to such exceptions, the seventh Tuesday
following the originally designated Tuesday Dividend Payment Date for the
prior Dividend Period. As used herein, Dividend Period means the period
commencing on a Dividend Payment Date for DARTS and ending on the day next
preceding the next Dividend Payment Date. Notwithstanding the foregoing,
in the event of a change in law altering the minimum holding period
(currently found in Section 246(c) of the Internal Revenue Code of 1986, as
amended (the "Code")) required for taxpayers to be entitled to the
dividends received deduction on preferred stock held by non-affiliated
corporations (currently found in Section 243(a) of the Code), the Company
shall adjust the period of time between Dividend Payment Dates so as to
adjust uniformly the number of days (such number of days without giving
effect to the exceptions referred to above being hereinafter referred to as
"Dividend Period Days") in Dividend Periods commencing after the date of
such change in law to equal or exceed the then current minimum holding
period; provided that the number of Dividend Period Days shall not exceed
by more than nine days the length of such then current minimum holding
period and shall be evenly divisible by seven, and the maximum number of
Dividend Period Days in no event shall exceed 98 days. Upon any such
change in the number of Dividend Period Days as a result of a change in
law, the Company shall give notice of such change to all Existing Holders
of Units.
(c) The dividend rate on shares of the 1988 DARTS during the period
from and after the date of original issuance to the Initial Dividend
Payment Date (the "Initial Dividend Period") shall be 6.375 percent per
annum. Commencing on the Initial Dividend Payment Date, the dividend rate
on shares of the 1988 DARTS for each subsequent Dividend Period shall be at
a rate per annum that results from the implementation of the Auction
procedures set forth in Section (6) below.
The amount of dividends per Unit for the 1988 DARTS payable for each
Dividend Period shall be computed by multiplying the dividend rate for such
series for each Dividend Period determined in accordance with subsection
(c) above by a fraction the numerator of which shall be the number of days
in such Dividend Period (calculated by counting the first day thereof but
excluding the last day thereof) such Unit was outstanding and the
denominator of which shall be 360, and multiplying the amount so obtained
by $100,000 per Unit.
(d) Prior to each Dividend Payment Date, the Company shall pay to the
Trust Company sufficient funds for the payment of declared dividends.
(e) For the purpose of determining whether and when holders of the
Senior Stock are entitled to the rights to elect certain directors of the
Company, described under Article XVI, Section 5(c) of these By-laws,
dividends on the DARTS shall be deemed to be in arrears "in an amount equal
to or exceeding four quarterly dividend payments," if, at the time
dividends are in arrears for four quarterly dividend payments for Senior
Stock having quarterly dividend payments, dividends on the 1988 DARTS are
in arrears for each Dividend Period beginning on or after the first day of
the first of the four quarterly dividend periods as to which dividends on
the Senior Stock having quarterly dividends are in arrears.
(4) Redemption Provisions
(a) At the option of the Company, the Units may be redeemed out of
funds legally available therefor in whole on any Dividend Payment Date at a
redemption price of $25 per share of the 1988 DARTS ($100,000 per Unit)
plus accrued and unpaid dividends (whether or not earned or declared) to
the redemption date. Only whole Units may be redeemed. See Section (5)
below for restrictions on the reissue of Units after redemption.
(b) In accordance with Article XVI, Section 3 of these By-laws,
notice of redemption shall be mailed to each record holder of Units and to
the Trust Company not less than 30 days prior to the date fixed for
redemption thereof. Each notice of redemption shall include a statement
setting forth: (i) the redemption date, (ii) the number of Units to be
redeemed, (iii) the redemption price, (iv) the place or places where Units
are to be surrendered for payment of the redemption price, and (v) that
dividends of the Units to be redeemed will cease to accrue on such
redemption date. No defect in the notice of redemption or in the mailing
thereof shall affect the validity of the redemption proceedings, except as
required by applicable law.
(c) If less than all of the outstanding Units are to be redeemed,
the number of Units to be redeemed shall be determined by the Company and
communicated to the Trust Company. In accordance with Article XVI, Section
3A of these By-laws, the Trust Company shall give notice to the Securities
Depository and the Securities Depository will determine by lot under its
usual operating procedures the number of Units, if any, to be redeemed from
the account of the Agent Member of each Existing Holder. An Agent Member
may determine to redeem Units from some Existing Holders without redeeming
Units from the accounts of other Existing Holders.
(5) Reacquisition
Except in an Auction (as defined in Section (6)(a)(iii) below), the
Company shall have the right, in accordance with Article XVI, Section 3E of
these By-laws, and where permitted by applicable law, to purchase or
otherwise acquire Units upon the best terms reasonably obtainable, but not
exceeding the then current redemption price of such Units, except that no
such purchase shall be made if the Company shall be in arrears in respect
to payment of dividends on any shares of Senior Stock outstanding or if
there shall exist an event of default as defined in Article XVI, Section 5
of these By-laws. Notwithstanding the provisions of Article XVI, Section
3D of these By-laws, Units that have been redeemed, purchased or otherwise
acquired by the Company shall not be reissued as 1988 DARTS and shall
either be restored to authorized but unissued shares of the Company's Class
A Preferred Stock or canceled at the Company's option.
(6) Auction Procedures
(a) Certain Definitions. As used in this Section 6 of these
Provisions with Respect to the series of Senior Stock, the following terms
shall have the following meanings, unless the context otherwise requires:
(i) "Affiliate" shall mean any Person known to the Trust
Company to be controlled by, in control of, or under common control with
the Company.
(ii) "Agent Member" shall mean the member of the Securities
Depository that will act on behalf of a Bidder and is identified as such in
such Bidder's Purchaser's Letter.
(iii) "Auction" shall mean the periodic operation of the
procedures set forth herein.
(iv) "Auction Date" shall mean the Business Day next
preceding a Dividend Payment Date.
(v) "Available Units" shall have the meaning specified in
paragraph (d)(i)(A) below.
(vi) "Bid" shall have the meaning specified in paragraph
(b)(i) below.
(vii) "Bidder" shall have the meaning specified in paragraph
(b)(i) below.
(viii) "Board of Directors" shall mean the Board of Directors of
the Company.
(ix) "Broker-Dealer" shall mean any broker-dealer, or other
entity permitted by law to perform the functions required of a
Broker-Dealer herein, that has been selected by the Company and has entered
into a Broker-Dealer Agreement with the Trust Company that remains
effective.
(x) "Broker-Dealer Agreement" shall mean an agreement between
the Trust Company and a Broker-Dealer pursuant to which such Broker-Dealer
agrees to follow the procedures specified herein.
(xi) "DARTS" or "1988 DARTS" shall mean the 2,140,000 shares of
Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988
Series, $25 Par Value, of the Company.
(xii) "Existing Holder," when used with respect to Units, shall
mean a Person who has signed a Purchaser's Letter and is listed as the
beneficial owner of such Units in the records of the Trust Company.
(xiii) "Hold Order" shall have the meaning specified in
paragraph (b)(i) below.
(xiv) "Maximum Applicable Rate," on any Auction Date, shall
mean the percentage of the 60-day "AA" Composite Commercial Paper Rate (as
defined below) in effect on such Auction Date, determined as set forth
below based on the prevailing rating of the DARTS in effect at the close of
business on the day preceding such Auction Date:
Prevailing Rating Percentage
AA/aa or Above........................... 110%
A/a...................................... 120%
BBB/baa.................................. 130%
BB/ba.................................... 175%
Below BB/ba.............................. 200%
For purposes of this definition, the "prevailing rating" of
the DARTS shall be (i) AA/aa or Above, if the DARTS have a rating of AA- or
better by Standard & Poor's Corporation or its successor ("S&P") and aa3 or
better by Moody's Investors Service, Inc. or its successor ("Moody's"), or
the equivalent of both of such ratings by such agencies or a substitute
rating agency or substitute rating agencies selected as provided below,
(ii) if not AA/aa or Above, then A/a, if the DARTS have a rating of A- or
better by S&P and a3 or better by Moody's or the equivalent of both of such
ratings by such agencies or a substitute rating agency or substitute rating
agencies selected as provided below, (iii) if not AA/aa or Above or A/a,
then BBB/Baa, if the DARTS have a rating of BBB- or better by S&P and baa3
or better by Moody's or the equivalent of both of such ratings by such
agencies or a substitute rating agency or substitute rating agencies
selected as provided below, and (iv) if not AA/aa or Above, A/a or BBB/baa,
then BB/ba, if the DARTS have a rating of BB- or better by S&P and Ba3 or
better by Moody's, or the equivalent of both of such ratings by such
agencies or a substitute rating agency or substitute rating agencies
selected as provided below, and (v) if not AA/aa or Above, A/a, BBB/baa or
BB/ba, then Below BB/ba. The Company shall take all reasonable action
necessary to enable S&P and Moody's to provide a rating for the DARTS. If
either S&P or Moody's shall not make such a rating available, or neither
S&P nor Moody's shall make such a rating available, Salomon Brothers Inc
and Morgan Stanley & Co. Incorporated, or their successors shall select a
nationally recognized securities rating agency or two nationally recognized
securities rating agencies to act as substitute rating agency or substitute
rating agencies, as the case may be.
(xv) "Minimum Applicable Rate," on any Auction Date, shall mean
59% of the 60-day "AA" Composite Commercial Paper Rate in effect on such
Auction Date.
(xvi) "Order" shall have the meaning specified in
paragraph(b)(i) below.
(xvii) "Outstanding" shall mean, as of any date, the DARTS
theretofore issued by the Company except, without duplication, (A) any
DARTS theretofore canceled or delivered to the Trust Company for
cancellation, or redeemed by the Company, or as to which a notice of
redemption shall have been given by the Company, (B) any DARTS as to which
the Company or any Affiliate thereof shall be an Existing Holder and (C)
any DARTS represented by any certificate in lieu of which a new
certificate has been executed and delivered by the Company.
(xviii) "Person" shall mean and include an individual, a
partnership, a corporation, a trust, an unincorporated association, a joint
venture or other entity or a government or any agency or political
subdivision thereof.
(xix) "Potential Holder" shall mean any Person, including any
Existing Holder, (A) who shall have executed and delivered or caused to be
delivered a Purchaser's Letter to the Trust Company and (B) who may be
interested in acquiring Units (or, in the case of an Existing Holder,
additional Units).
(xx) "Purchaser's Letter" shall mean a letter addressed to the
Company, the Trust Company, Broker-Dealer and other persons in which a
Person agrees, among other things, to offer to purchase, purchase, offer to
sell and/or sell Units as set forth herein.
(xxi) "Securities Depository" shall mean The Depository Trust
Company and its successors and assigns or any other securities depository
selected by the Company which agrees to follow the procedures required to
be followed by such securities depository in connection with the DARTS.
(xxii) "Sell Order" shall have the meaning specified in paragraph
(b)(i) below.
(xxiii) "60-day 'AA' Composite Commercial Paper Rate," on any
date, means (i) the interest equivalent of the 60-day rate on commercial
paper placed on behalf of issuers whose corporate bonds are rated "AA" by
S&P or the equivalent of such rating by S&P or another rating agency, as
such 60-day rate is made available on a discount basis or otherwise by the
Federal Reserve Bank of New York for the Business Day immediately preceding
such date, or (ii) in the event that the Federal Reserve Bank of New York
does not make available such a rate, then the interest equivalent of the
60-day rate on commercial paper placed on behalf of such issuers, as quoted
on a discount basis or otherwise by Morgan Stanley & Co. Incorporated or,
in lieu thereof, any affiliates or successor thereof (the "Commercial
Paper Dealer"), to the Trust Company for the close of business on the
Business Day immediately preceding such date. If the Commercial Paper
Dealer does not quote a rate required to determine the 60-day "AA"
Composite Commercial Rate, the 60-day "AA" Composite Commercial Paper Rate
shall be determined on the basis of the quotation or quotations furnished
by any Substitute Commercial Paper Dealer or Substitute Commercial Paper
Dealers selected by the Company to provide such rate. If the Company,
however, shall adjust the number of Dividend Period Days in the event of a
change in the dividends received deduction minimum holding period contained
in the Internal Revenue Code of 1986, as amended, with the result that (i)
the Dividend Period Days shall be fewer than 70 days, such rate shall be
the interest equivalent of the 60-day rate on such commercial paper, (ii)
the Dividend Period Days shall be 70 or more days but fewer than 85 days,
such rate shall be the arithmetic average of the interest equivalent of the
60-day and 90-day rates on such commercial paper, and (iii) the Dividend
Period Days shall be 85 or more days but 98 or fewer days, such rate shall
be the interest equivalent of the 90-day rate on such commercial paper.
For the purposes of such definition, "interest equivalent" means the
equivalent yield on a 360-day basis of a discount basis security to an
interest-bearing security and "Substitute Commercial Paper Dealer" shall
mean any commercial paper dealer that is a leading dealer in the
commercial paper market, provided that neither such dealer nor any of its
affiliates is a Commercial Paper Dealer.
(xxiv) "Submission Deadline" shall mean 12:30 P.M., New York City
time, on any Auction Date or such other time on any Auction Date by which
Broker-Dealers are required to submit Orders to the Trust Company as
specified by the Trust Company from time to time.
(xxv) "Submitted Bid" shall have the meaning specified
inparagraph (d)(i) below.
(xxvi) "Submitted Hold Order" shall have the meaning specified
in paragraph (d)(i) below.
(xxvii) "Submitted Order" shall have the meaning specified in
paragraph (d)(i) below.
(xxviii) "Submitted Sell Order" shall have the meaning specified
in paragraph (d)(i) below.
(xxvix) "Sufficient Clearing Bids" shall have the meaning
specified in paragraph (d)(i) below.
(xxx) "Trust Company" shall mean Bankers Trust Company and its
successor, and assigns or any other bank, trust company or other entity
selected by the Company which agrees to follow the Auction Procedures
described in this Section (6) for the purposes of determining the
Applicable Rate for the DARTS.
(xxxi) "Winning Bid Rate" shall have the meaning specified in
paragraph (d)(i) below.
(b) Orders by Existing Holders and Potential Holders
(i) On or prior to each Auction Date:
(A) each Existing Holder may submit to a Broker-Dealer
information as to:
(1) the number of Outstanding Units, if any, held by
such Existing Holder which such Existing Holder desires to continue to hold
without regard to the Applicable Rate for the next succeeding Dividend
Period;
(2) the number of Outstanding Units, if any, held by such
Existing Holder which such Existing Holder desires to continue to hold,
provided that the Applicable Rate for the next succeeding Dividend Period
shall not be less than the rate per annum specified by such Existing
Holder; and/or (3) the number of Outstanding Units, if any, held by
such Existing Holder which such Existing Holder offers to sell without
regard to the Applicable Rate for the next succeeding Dividend Period; and
(B) Each Broker-Dealer, using a list of Potential Holders
that shall be maintained in good faith for the purpose of conducting a
competitive Auction shall contact Potential Holders, including Persons that
are not Existing Holders, on such list to determine the number of
Outstanding Units, if any, which each such Potential Holder offers to
purchase, provided that the Applicable Rate for the next succeeding
Dividend Period shall not be less than the rate per annum specified by such
Potential Holder.
For the purposes hereof, the communication to a Broker-Dealer of
information referred to in clause (A) or (B) of this paragraph (b)(i) is
hereinafter referred to as an "Order" and each Existing Holder and each
Potential Holder placing an Order is hereinafter referred to as a "Bidder";
and Order containing the information referred to in clause (A)(1) of this
paragraph (b)(i) is hereinafter referred to as a "Hold Order"; an Order
containing the information referred to in clause (A)(2) or (B) of this
paragraph (b)(i) is hereinafter referred to as a "Bid"; and an Order
containing the information referred to in clause (A)(3) of this paragraph
(b)(i) is hereinafter referred to as a "Sell Order."
(ii) (A) A Bid by an Existing Holder shall constitute an
irrevocable offer to sell:
(1) the number of Outstanding Units specified in such
Bid if the Applicable Rate determined on such Auction Date shall be less
than the rate specified therein; or
(2) such number or a lesser number of Outstanding
Units to be determined as set forth in paragraph (e)(i)(D) if the
Applicable Rate determined on such Auction Date shall be equal to the rate
specified therein; or
(3) a lesser number of Outstanding Units to be determined
as set forth in paragraph (e)(ii)(C) if such specified rate shall be higher
than Maximum Applicable Rate and Sufficient Clearing Bids do not exist.
(B) A Sell Order by an Existing Holder shall constitute an
irrevocable offer to sell:
(1) the number of Outstanding Units specified in such Sell
Order; or
(2) such number or a lesser number of Outstanding
Units to be determined as set forth in paragraph (e)(ii)(C) if Sufficient
Clearing Bids do not exist.
(C) A Bid by a Potential Holder shall constitute an irrevocable
offer to purchase:
(1) the number of Outstanding Units specified in such Bid
if the Applicable Rate determined on such Auction Date shall be higher than
the rate specified therein; or
(2) such number of a lesser number of Outstanding Units to
be determined as set forth in paragraph (e)(i)(E) if the Applicable Rate
determined on such Auction Date shall be equal to the rate specified
therein.
(c) Submission of Orders by Broker-Dealers to Trust Company (i) Each
Broker-Dealer shall submit in writing to the Trust Company prior to the
Submission Deadline on each Auction Date all Orders obtained by such
Broker-Dealer and specifying with respect to each Order:
(A) the name of the Bidder placing such Order;
(B) the aggregate number of Outstanding Units that are subject
of such Order;
(C) to the extent that such Bidder is an Existing Holder:
(1) the number of Outstanding Units, if any, subject to any
Hold Order placed by such Existing Holder;
(2) the number of Outstanding Units, if any, subject to
any Bid placed by such Existing Holder and the rate specified in such Bid;
and
(3) the number of Outstanding Units, if any, subject to
any Sell Order placed by such Existing Holder; and
(D) to the extent such Bidder is a Potential Holder, the rate
specified in such Potential Holder's Bid.
(ii) If any rate specified in any Bid contains more than three
figures to the right of the decimal point, the Trust Company shall round
such rate up to the next highest one-thousandth (.001) of 1%.
(iii) If an Order or Orders covering all of the Outstanding Units
held by an Existing Holder is not submitted to the Trust Company prior to
the Submission Deadline, the Trust Company shall deem a Hold Order to have
been submitted on behalf of such Existing Holder covering the number of
Outstanding Units held by such Existing Holder and not subject to Orders
submitted to the Trust Company.
(iv) If one or more Orders covering in the aggregate more than the
number of Outstanding Units held by an Existing Holder are submitted to the
Trust Company, such Orders shall be considered valid as follows and in the
following order or priority:
(A) any Hold Order submitted on behalf of such Existing
Holder shall be considered valid up to and including the number of
Outstanding Units held by such Existing Holder; provided that if more than
one Hold Order is submitted on behalf of such Existing Holder and the
number of Units subject to such Hold Orders exceeds the number of
Outstanding Units held by such Existing Holder, the number of Units subject
to such Hold Orders shall be reduced pro rata so that such Hold Orders
shall cover the number of Outstanding Units held by such Existing Holder;
(B) (1) any Bid shall be considered valid up to and including
the excess of the number of Outstanding Units held by such Existing Holder
over the number of Units subject to Hold Orders referred to in paragraph
(c)(iv)(A);
(2) subject to clause (1) above, if more than one Bid
with the same rate is submitted on behalf of such Existing Holder and the
number of Outstanding Units subject to such Bids is greater than such
excess, the number of Outstanding Units subject to such Bids shall be
reduced pro rata so that such Bids shall cover the number of Outstanding
Units equal to such excess; and
(3) subject to clause (1) above, if more than one Bid
with different rates is submitted on behalf of such Existing Holder, such
Bids shall be considered valid in the ascending order of their respective
rates and in any such event the number, if any, of such Outstanding shares
subject to Bids not valid under this clause (B) shall be treated as the
subject of a Bid by a Potential Holder; and (C) any Sell Order shall be
considered valid up to and including the excess of the number of
Outstanding Units held by such Existing Holder over the number of
Outstanding Units subject to Hold Orders referred to in paragraph
(c)(iv)(A) and Bids referred to in paragraph (c)(iv)(B).
(v) If more than one Bid is submitted on behalf of any Potential
Holder, each Bid submitted shall be a separate Bid with the rate and Units
therein specified.
(vi) If any rate specified in any Bid is lower than the Minimum
Applicable Rate for the Dividend Period to which such Bid relates, such Bid
shall be deemed to be a Bid specifying a rate equal to such Minimum
Applicable Rate.
(vii) Orders by Existing Holders and Potential Holders must specify
numbers of Units in whole Units. Any Order that specifies a number of
Units other than in whole shares will be invalid and will not be considered
a Submitted Order for purposes of an Auction.
(d) Determination of Sufficient Clearing Bids, Winning Bid Rate and
Applicable Rate (i) Not earlier than the Submission Deadline on each
Auction Date, the Trust Company shall assemble all Orders submitted or
deemed submitted to it by the Broker-Dealers (each such Order as submitted
or deemed submitted by a Broker-Dealer being hereinafter referred to
individually as a "Submitted Hold Order" a "Submitted Bid" or a "Submitted
Sell Order," as the case may be, or as a "Submitted Order") and shall
determine:
(A) the excess of the total number of Outstanding Units over
the number of Outstanding Units that are the subject of Submitted Hold
Orders (such excess being hereinafter referred to as the "Available
Units");
(B) from the Submitted Orders, whether:
(1) the number of Outstanding Units that are the
subject of Submitted Bids by Potential Holders specifying one or more rates
equal to or lower than the Maximum Applicable Rate exceeds or is equal to
the sum of:
(2) [a] the number of Outstanding Units that are the
subject of Submitted Bids by Existing Holders specifying one or more
rates higher than the Maximum Applicable Rate, and [b] the number of
Outstanding Units that are subject to Submitted Sell Orders (if such excess
of such equality exists (other than because the number of Outstanding Units
in clauses [a] and [b] above are each zero because all of the Outstanding
Units are the subject of Submitted Hold Orders), such Submitted Bids in
clause (1) above being hereinafter referred to collectively as "Sufficient
Clearing Bids"); and (C) if Sufficient Clearing Bids exist, the lowest
rate specified in the Submitted Bids (the "Winning Bid Rate"), which if:
(1) each Submitted Bid from Existing Holders specifying the
Winning Bid Rate and all other Submitted Bids from Existing Holders
specifying lower rates were rejected, thus entitling such Existing Holders
to continue to hold the Units that are the subject of such Submitted Bids,
and (2) each Submitted Bid from Potential Holders specifying the Winning
Bid Rate and all other Submitted Bids from Potential Holders specifying
lower rates were accepted, thus entitling the Potential Holders to purchase
the Units that are the subject of such Submitted Bids, would result in the
number of shares subject to all Submitted Bids specifying the Winning Bid
Rate or a lower rate being at least equal to the Available Units.
(ii) Promptly after the Trust Company has made the determinations
pursuant to paragraph (d)(i), the Trust Company shall advise the Company
of the Maximum Applicable Rate and the Minimum Applicable Rate and, based
on such determinations, the Applicable Rate for the next succeeding
Dividend Period as follows:
(A) if Sufficient Clearing Bids exist, that the Applicable
Rate for the next succeeding Dividend Period shall be equal to the Winning
Bid Rate so determined;
(B) if Sufficient Clearing Bids do not exist (other than
because all of the Outstanding Units are the subject of Submitted Hold
Orders), that the Applicable Rate for the next succeeding Dividend Period
shall be equal to the Maximum Applicable Rate; or (C) if all the
Outstanding Units are the subject of Submitted Hold Orders, that the
Applicable Rate for the next succeeding Dividend Period shall be equal to
the Minimum Applicable Rate.
(e) Acceptance and Rejection of Submitted Bids and Submitted Sell Orders
and Allocation of Shares Based on the determinations made pursuant to
paragraph (d)(i), the Submitted Bids and Submitted Sell Orders shall be
accepted or rejected and the Trust Company shall take such other action as
set forth below:
(i) If Sufficient Clearing Bids have been made, subject to
the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Bids and
Submitted Sell Orders shall be accepted or rejected in the following order
or priority and all other Submitted bids shall be rejected:
(A) the Submitted Sell Orders of Existing Holders shall be
accepted and the Submitted Bid of each of the Existing Holders specifying
any rate that is higher than the Winning Bid Rate shall be rejected, thus
requiring each such Existing Holder to sell the Outstanding Units that are
the subject of such Submitted Bid;
(B) the Submitted Bid of each of the Existing Holders
specifying any rate that is lower than the Winning Bid Rate shall be
accepted, thus entitling each such Existing Holder to continue to hold the
Outstanding Units that are the subject of such Submitted Bid;
(C) the Submitted Bid of each of the Potential Holders
specifying any rate that is lower than the Winning Bid Rate shall be
accepted;
(D) the Submitted Bid of each of the Existing Holders
specifying a rate that is equal to the Winning Bid Rate shall be accepted,
thus entitling each such Existing Holder to continue to hold the
Outstanding Units that are the subject of such Submitted Bid, unless the
number of Outstanding Units subject to all such Submitted Bids shallbe
greater than the number of Outstanding Units ("remaining shares") equal to
the excess of the Available Units over the number of Outstanding Units
subject to Submitted Bids described in paragraphs (e)(i)(B) and (e)(i)(C),
in which event the Submitted Bids of each such Existing Holder shall be
rejected, and each such Existing Holder shall be required to sell
Outstanding Units, but only in an amount equal to the difference between
(1) the number of Outstanding Units then held by such Existing Holder
subject to such Submitted Bid and (2) the number of Units obtained by
multiplying (x) the number of remaining shares by (y) a fraction the
numerator of which shall be the number of Outstanding Units held by such
Existing Holder subject to such Submitted Bid and the denominator of which
shall be the sum of the number of Outstanding Units subject to such
Submitted Bids made by all such Existing Holders that specified a rate
equal to the Winning Bid Rate; and
(E) the Submitted Bid of each of the Potential Holders
specifying a rate that is equal to the Winning Bid Rate shall be accepted
but only in an amount equal to the number of Outstanding Units obtained by
multiplying (x) the difference between the Available Units and the number
of Outstanding Units subject to the Submitted Bids described inparagraphs
(e)(i)(B), (e)(i)(C) and (e)(i)(D) by (y) a fraction the numerator of which
shall be the number of Outstanding shares of Units subject to such
Submitted Bid and the denominator of which shall be the sum of the number
of Outstanding Units subject to such Submitted Bids made by all such
Potential Holders that specified rates equal to the Winning Bid Rate.
(ii) If Sufficient Clearing Bids have been made (other than because
all of the Outstanding Units are subject to Submitted Hold Orders), subject
to the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Orders
shall be accepted or rejected as follows in the following order of priority
and all other Submitted Bids shall be rejected:
(A) the Submitted Bid of each Existing Holder specifying any
rate that is equal to or lower than the Maximum Applicable Rate shall be
accepted, thus entitling such Existing Holder to continue to hold the
Outstanding Units that are the subject of such Submitted Bid;
(B) the Submitted Bid of each Potential Holder specifying any
rate that is equal to or lower than the Maximum Applicable Rate shall be
accepted, thus requiring such Potential Holder to purchase the Outstanding
Units that are the subject of such Submitted Bid; and
(C) the Submitted Bids of each Existing Holder specifying any
rate that is higher than the Maximum Applicable Rate shall be rejected and
the Submitted Sell Orders of each Existing Holder shall be accepted, in
both cases only in an amount equal to the difference between (1) the number
of Outstanding Units then held by such Existing Holder subject to such
Submitted Bid or Submitted Sell Order and (2) the number of Units obtained
by multiplying (x) the difference between the Available Units and the
aggregate number of Outstanding Units subject to Submitted Bids described
in paragraphs (e)(ii)(A) and (e)(ii)(B) by (y) a fraction the numerator of
which shall be the number of Outstanding Units held by such Existing Holder
subject to such Submitted Bid or Submitted Sell Order and the denominator
of which shall be the number of Outstanding Units subject to all such
Submitted Bids and Submitted Sell Orders.
(iii) If, as a result of the procedures described in paragraph (e)(i)
or (e)(ii), any Existing Holder would be entitled or required to sell, or
any Potential Holder would be entitled or required to purchase, a fraction
of a Unit on any Auction Date, the Trust Company shall, in such manner as,
in its sole discretion, it shall determine, round up or down the number of
Units to be purchased or sold by any Existing Holder or Potential Holder on
such Auction Date so that the number of Outstanding shares purchased or
sold by each Existing Holder or Potential Holder on such Auction Date shall
be whole Units.
(iv) If, as a result of the procedures described in paragraph
(e)(i), any Potential Holder would be entitled or required to purchase less
than a whole Unit on any Auction Date, the Trust Company shall, in such
manner as, in its sole discretion, it shall determine, allocate Units for
purchase among Potential Holders so that only whole Units are purchased on
such Auction Date by any Potential Holder, even if such allocation results
in one or more of such Potential Holders not purchasing Units on such
Auction Date.
(v) Based on the results of each Auction, the Trust Company shall
determine the aggregate number of Outstanding Units to be purchased and the
aggregate number of Outstanding Units to be sold by Potential Holders and
Existing Holders on whose behalf each Broker-Dealer submitted Bids or Sell
Orders, and, with respect to each Broker-Dealer, to the extent that such
aggregate number of Outstanding shares to be purchased and such aggregate
number of Outstanding shares to be sold differ, determine to which other
Broker-Dealer or Broker-Dealers acting for one or more purchasers such
Broker-Dealer
shall deliver, or from which other Broker-Dealer or Broker-Dealers acting
for one or more sellers such Broker-Dealer shall receive, as the case may
be, Outstanding Units.
(f) Miscellaneous
The Board of Directors may interpret the provisions of these Auction
Procedures to resolve any inconsistency or ambiguity, and may remedy any
formal defect or make any other change or modification which does not
adversely affect the rights of Existing Holders of Units. An Existing
Holder (A) may sell, transfer or otherwise dispose of Units only pursuant
to a Bid or Sell Order in accordance with the procedures described in this
paragraph or to or through a Broker-Dealer or to a Person that has
delivered a signed copy of a Purchaser's Letter to the Trust Company,
provided that in the case of all transfers other than pursuant to Auctions
such Existing Holder, its Broker-Dealer or its Agent Member advises the
Trust Company of such transfer and (B) shall have the ownership of the
Units held by it maintained in book entry form by the Securities Depository
in the account of its Agent Member, which in turn will maintain records of
such Existing Holder's beneficial ownership. Neither the Company nor any
Affiliate shall submit an Order, either directly or indirectly, in any
Auction. Except as otherwise provided by law, all of the Outstanding Units
shall be represented by a certificate registered in the name of the nominee
of the Securities Depository and no Person acquiring Units shall be
entitled to receive a certificate representing such shares.
(g) Headings of Subdivisions
The headings of the various subdivisions of these Auction Procedures are
for convenience of reference only and shall not affect the interpretation
of any of the provisions hereof.
ARTICLE XVIII
AMENDMENTS
Except as otherwise provided in Article XVI hereof, these By-Laws may
be altered, amended or repealed at any meeting of the stockholders called
for the purpose by vote of a majority of stock present and voting thereon
SUPPLEMENTAL INDENTURE
Dated as of June 1, 1994
TO
Indenture of Mortgage and Deed of Trust
Dated as of May 1, 1921
THE CONNECTICUT LIGHT AND POWER COMPANY
TO
BANKERS TRUST COMPANY, Trustee
1994 Series C Bonds, Due June 1, 2024
THE CONNECTICUT LIGHT AND POWER COMPANY
Supplemental Indenture, Dated as of June 1, 1994
TABLE OF CONTENTS
PAGE
Parties 1
Recitals 1
Granting Clauses 2
Habendum 2
Grant in Trust 2
ARTICLE 1.
FORM AND PROVISIONS OF BONDS OF SERIES C
SECTION 1.01. Designation; Amount 3
SECTION 1.02. Form of Bonds of Series C 3
SECTION 1.03. Provisions of Bonds of Series C; Interest Accrual 3
SECTION 1.04. Transfer and Exchange of Bonds of Series C 4
SECTION 1.05. Sinking and Improvement Fund 4
ARTICLE 2.
REDEMPTION OF BONDS OF SERIES C 4
ARTICLE 3.
MISCELLANEOUS
SECTION 3.01. Benefits of Supplemental Indenture and
Bonds of Series C 5
SECTION 3.02. Effect of Table of Contents and Headings 5
SECTION 3.03. Counterparts 5
TESTIMONIUM 5
SIGNATURES 5
ACKNOWLEDGMENTS 6
SCHEDULE A - Form of Bond of Series C, Form of
Trustee's Certificate 7
SCHEDULE B - Property Subject to the Lien of the Mortgage 12
SUPPLEMENTAL INDENTURE, dated as of the first day of June, 1994, between
THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing
under the laws of the State of Connecticut (hereinafter called "Company") and
BANKERS TRUST COMPANY, a corporation organized and existing under the laws of
the State of New York (hereinafter called "Trustee").
WHEREAS, the Company heretofore duly executed, acknowledged and delivered
to the Trustee a certain Indenture of Mortgage and Deed of Trust dated as of May
1, 1921, and sixty-one Supplemental Indentures thereto dated respectively as of
May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July
1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936,
December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1,
1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958,
February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1, 1967,
January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970, October 1,
1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1, 1974, February
1, 1975, September 1, 1975, May 1, 1977, March 1, 1978, September 1, 1980,
October 1, 1981, June 30, 1982, October 1, 1982, July 1, 1983, January 1, 1984,
October 1, 1985, September 1, 1986, April 1, 1987, October 1, 1987, November 1,
1987, April 1, 1988, November 1, 1988, June 1, 1989, September 1, 1989, December
1, 1989, April 1, 1992, July 1, 1992, October 1, 1992, July 1, 1993, July 1,
1993, December 1, 1993, February 1, 1994 and February 1, 1994 (said Indenture of
Mortgage and Deed of Trust (i) as heretofore amended, being hereinafter
generally called the "Mortgage Indenture," and (ii) together with said
Supplemental Indentures thereto, being hereinafter generally called the
"Mortgage"), all of which have been duly recorded as required by law, for the
purpose of securing its First and Refunding Mortgage Bonds (of which
$1,330,176,000 aggregate principal amount are outstanding at the date of this
Supplemental Indenture) to an unlimited amount, issued and to be issued for the
purposes and in the manner therein provided, of which Mortgage this Supplemental
Indenture is intended to be made a part, as fully as if therein recited at
length;
WHEREAS, the Company by appropriate and sufficient corporate action in
conformity with the provisions of the Mortgage has duly determined to create a
further series of bonds under the Mortgage to be designated "First and Refunding
Mortgage 8-1/2% Bonds, 1994 Series C" (hereinafter generally referred to as the
"bonds of Series C"), to consist of fully registered bonds containing terms and
provisions duly fixed and determined by the Board of Directors of the Company
and expressed in this Supplemental Indenture, such fully registered bonds and
the Trustee's certificate of its authentication thereof to be substantially in
the forms thereof respectively set forth in Schedule A appended hereto and made
a part hereof; and
WHEREAS, the execution and delivery of this Supplemental Indenture and the
issue of not in excess of one hundred and fifteen million dollars ($115,000,000)
in aggregate principal amount of bonds of Series C and other necessary actions
have been duly authorized by the Board of Directors of the Company; and
WHEREAS, the Company proposes to execute and deliver this Supplemental
Indenture to provide for the issue of the bonds of Series C and to confirm the
lien of the Mortgage on the property referred to below, all as permitted by
Section 14.01 of the Mortgage Indenture; and
WHEREAS, all acts and things necessary to constitute this Supplemental
Indenture a valid, binding and legal instrument and to make the bonds of Series
C, when executed by the Company and authenticated by the Trustee valid, binding
and legal obligations of the Company have been authorized and performed;
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF TRUST
WITNESSETH:
That in order to secure the payment of the principal of and interest on all
bonds issued and to be issued under the Mortgage, according to their tenor and
effect, and according to the terms of the Mortgage and this Supplemental
Indenture, and to secure the performance of the covenants and obligations in
said bonds and in the Mortgage and this Supplemental Indenture respectively
contained, and for the better assuring and confirming unto the Trustee, its
successor or successors and its or their assigns, upon the trusts and for the
purposes expressed in the Mortgage and this Supplemental Indenture, all and
singular the hereditament, premises, estates and property of the Company thereby
conveyed or assigned or intended so to be, or which the Company may thereafter
have become bound to convey or assign to the Trustee, as security for said bonds
(except such hereditament, premises, estates and property as shall have been
disposed of or released or withdrawn from the lien of the Mortgage and this
Supplemental Indenture, in accordance with the provisions thereof and subject to
alterations, modifications and changes in said hereditament, premises, estates
and property as permitted under the provisions thereof), the Company, for and in
consideration of the premises and the sum of One Dollar ($1.00) to it in hand
paid by the Trustee, the receipt whereof is hereby acknowledged, and of other
valuable considerations, has granted, bargained, sold, assigned, mortgaged,
pledged, transferred, set over, aliened, enfeoffed, released, conveyed and
confirmed, and by these presents does grant, bargain, sell, assign, mortgage,
pledge, transfer, set over, alien, enfeoff, release, convey and confirm unto
said Bankers Trust Company, as Trustee, and its successor or successors in the
trusts created by the Mortgage and this Supplemental Indenture, and its and
their assigns, all of said hereditament, premises, estates and property (except
and subject as aforesaid), as fully as though described at length herein,
including, without limitation of the foregoing, the property, rights and
privileges of the Company described or referred to in Schedule B hereto.
Together with all plants, buildings, structures, improvements and machinery
located upon said real estate or any portion thereof, and all rights, privileges
and easements of every kind and nature appurtenant thereto, and all and singular
the tenements, hereditament and appurtenances belonging to the real estate or
any part thereof described or referred to in Schedule B or intended so to be, or
in any wise appertaining thereto, and the reversions, remainders, rents, issues
and profits thereof, and also all the estate, right, title, interest, property,
possession, claim and demand whatsoever, as well in law as in equity, of the
Company, of, in and to the same and any and every part thereof, with the
appurtenances; except and subject as aforesaid.
TO HAVE AND TO HOLD all and singular the property, rights and privileges
hereby granted or mentioned or intended so to be, together with all and singular
the reversions, remainders, rents, revenues, income, issues and profits,
privileges and appurtenances, now or hereafter belonging or in any way
appertaining thereto, unto the Trustee and its successor or successors in the
trust created by the Mortgage and this Supplemental Indenture, and its and their
assigns, forever, and with like effect as if the above described property,
rights and privileges had been specifically described at length in the Mortgage
and this Supplemental Indenture.
Subject, however, to permitted liens, as defined in the Mortgage Indenture.
IN TRUST, NEVERTHELESS, upon the terms and trusts of the Mortgage and this
Supplemental Indenture for those who shall hold the bonds and coupons issued and
to be issued thereunder, or any of them, without preference, priority or
distinction as to lien of any of said bonds and coupons over any others thereof
by reason of priority in the time of the issue or negotiation thereof, or
otherwise howsoever, subject, however, to the provisions in reference to
extended, transferred or pledged coupons and claims for interest set forth in
the Mortgage and this Supplemental Indenture (and subject to any sinking fund
that may heretofore have been or hereafter be created for the benefit of any
particular series).
And it is hereby covenanted that all such bonds of Series C are to be
issued, authenticated and delivered, and that the mortgaged premises are to be
held by the Trustee, upon and subject to the trusts, covenants, provisions and
conditions and for the uses and purposes set forth in the Mortgage and this
Supplemental Indenture and upon and subject to the further covenants, provisions
and conditions and for the uses and purposes hereinafter set forth, as follows,
to wit:
ARTICLE 1.
FORM AND PROVISIONS OF BONDS OF SERIES C
SECTION 1.01. Designation; Amount. The bonds of Series C shall be
designated "First and Refunding Mortgage 8-1/2% Bonds, 1994 Series C" and,
subject to Section 2.08 of the Mortgage Indenture, shall not exceed one hundred
and fifteen million dollars ($115,000,000) in aggregate principal amount at any
one time outstanding. The initial issue of the bonds of Series C may be
effected upon compliance with the applicable provisions of the Mortgage
Indenture.
SECTION 1.02. Form of Bonds of Series C. The bonds of Series C
shall be issued only in fully registered form without coupons in denominations
of one thousand dollars ($1,000) and multiples thereof.
The bonds of Series C and the certificate of the Trustee upon said bonds
shall be substantially in the forms thereof respectively set forth in Schedule A
appended hereto.
SECTION 1.03. Provisions of Bonds of Series C; Interest Accrual. The
bonds of Series C shall mature on June 1, 2024 and shall bear interest, payable
semiannually on the first days of June and December of each year, commencing
December 1, 1994, at the rate specified in their title, until the Company's
obligation in respect of the principal thereof shall be discharged; and shall be
payable both as to principal and interest at the office or agency of the Company
in the Borough of Manhattan, New York, New York, in any coin or currency of the
United States of America which at the time of payment is legal tender for the
payment of public and private debts. The interest on the bonds of Series C,
whether in temporary or definitive form, shall be payable without presentation
of such bonds; and only to or upon the written order of the registered holders
thereof of record at the applicable record date. The bonds of Series C shall be
callable for redemption in whole or in part according to the terms and
provisions provided herein in Article 2.
Each bond of Series C shall be dated as of June 1, 1994 and shall bear
interest on the principal amount thereof from the interest payment date next
preceding the date of authentication thereof by the Trustee to which interest
has been paid on the bonds of Series C, or if the date of authentication thereof
is prior to November 16, 1994, then from the date of original issuance, or if
the date of authentication thereof be an interest payment date to which interest
is being paid or a date between the record date for any such interest payment
date and such interest payment date, then from such interest payment date.
The person in whose name any bond of Series C is registered at the close of
business on any record date (as hereinafter defined) with respect to any
interest payment date shall be entitled to receive the interest payable on such
interest payment date notwithstanding the cancellation of such bond upon any
registration of transfer or exchange thereof subsequent to the record date and
prior to such interest payment date, except that if and to the extent the
Company shall default in the payment of the interest due on such interest
payment date, then such defaulted interest shall be paid to the person in whose
name such bond is registered on a subsequent record date for the payment of
defaulted interest if one shall have been established as hereinafter provided
and otherwise on the date of payment of such defaulted interest. A subsequent
record date may be established by the Company by notice mailed to the owners of
bonds of Series C not less than ten days preceding such record date, which
record date shall not be more than thirty days prior to the subsequent interest
payment date. The term "record date" as used in this Section with respect to
any regular interest payment (i.e., June 1 or December 1) shall mean the May 15
or November 15, as the case may be, next preceding such interest payment date,
or if such May 15 or November 15 shall be a legal holiday or a day on which
banking institutions in the Borough of Manhattan, New York, New York are
authorized by law to close, the next preceding day which shall not be a legal
holiday or a day on which such institutions are so authorized to close.
SECTION 1.04. Transfer and Exchange of Bonds of Series C. The bonds of
Series C may be surrendered for registration of transfer as provided in Section
2.06 of the Mortgage Indenture at the office or agency of the Company in the
Borough of Manhattan, New York, New York, and may be surrendered at said office
for exchange for a like aggregate principal amount of bonds of Series C of other
authorized denominations. Notwithstanding the provisions of Section 2.06 of the
Mortgage Indenture, no charge, except for taxes or other governmental charges,
shall be made by the Company for any registration of transfer of bonds of Series
C or for the exchange of any bonds of Series C for such bonds of other
authorized denominations.
SECTION 1.05. Sinking and Improvement Fund. Each holder of a bond of
Series C, solely by virtue of its acquisition thereof, shall have and be deemed
to have consented, without the need for any further action or consent by such
holder, to any and all amendments to the Mortgage Indenture which are intended
to eliminate or modify in any manner the requirements of the sinking and
improvement fund as provided for in Section 6.14 thereof.
ARTICLE 2.
REDEMPTION OF BONDS OF SERIES C.
The bonds of Series C are not subject to redemption at the option of the
Company prior to June 1, 2004. Thereafter, the bonds of Series C shall be
redeemable as a whole at any time or in part from time to time in accordance
with the provisions of the Mortgage and upon not less than thirty (30) days'
prior notice given by mail as provided in the Mortgage (which notice may state
that it is subject to the receipt of the 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), either at the option
of the Company, or for the purpose of any applicable provision of the Mortgage,
at the following prices:
(a) if redeemed with trust moneys deposited with or received by the
Trustee pursuant to Section 3.55 or Section 6.06 or Section 6.09 or Section
6.14 or Article 8.5 of the Mortgage Indenture, then at the applicable
special redemption price, stated as a percentage of the principal amount,
specified under the column headed Special Redemption Price in the form of
bond of Series C set forth in Schedule A appended hereto, together in every
case with accrued and unpaid interest thereon to the date fixed for
redemption; and
(b) otherwise, at the applicable general redemption price, stated as
a percentage of the principal amount, specified under the column headed
General Redemption Price in the form of bond of Series C set forth in
Schedule A appended hereto, together in every case with accrued and unpaid
interest thereon to the date fixed for redemption.
ARTICLE 3.
MISCELLANEOUS.
SECTION 3.01. Benefits of Supplemental Indenture and Bonds of Series C.
Nothing in this Supplemental Indenture, or in the bonds of Series C, expressed
or implied, is intended to or shall be construed to give to any person or
corporation other than the Company, the Trustee and the holders of the bonds and
interest obligations secured by the Mortgage and this Supplemental Indenture,
any legal or equitable right, remedy or claim under or in respect of this
Supplemental Indenture or of any covenant, condition or provision herein
contained. All the covenants, conditions and provisions hereof are and shall be
held to be for the sole and exclusive benefit of the Company, the Trustee and
the holders of the bonds and interest obligations secured by the Mortgage and
this Supplemental Indenture.
SECTION 3.02. Effect of Table of Contents and Headings. The table of
contents and the descriptive headings of the several Articles and Sections of
this Supplemental Indenture are inserted for convenience of reference only and
are not to be taken to be any part of this Supplemental Indenture or to control
or affect the meaning, construction or effect of the same.
SECTION 3.03. Counterparts. For the purpose of facilitating the recording
hereof, this Supplemental Indenture may be executed in any number of
counterparts, each of which shall be and shall be taken to be an original and
all collectively but one instrument.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused
these presents to be executed by a Vice President and its corporate seal to be
hereunto affixed, duly attested by its Secretary or an Assistant Secretary, and
Bankers Trust Company has caused these presents to be executed by a Vice
President or Assistant Vice President and its corporate seal to be hereunto
affixed, duly attested by one of its Assistant Secretaries, as of the day and
year first above written.
THE CONNECTICUT LIGHT AND POWER
COMPANY
Attest:
/s/ Mark A. Joyse By /s/ John B. Keane
Mark A. Joyse John B. Keane
Assistant Secretary Vice President
(SEAL) Signed, sealed and delivered
in the presence of:
/s/ Tracy A. DeCredico
/s/ Jane P. Seidl
BANKERS TRUST COMPANY
Attest:
/s/ Scott Thiel By /s/ Robert Caporale
(SEAL) Signed, sealed and delivered
in the presence of:
/s/ Denise Mitchell
/s/ Michael Alba
STATE OF CONNECTICUT )
) SS.: BERLIN
COUNTY OF HARTFORD )
On this 18th day of May 1994, before me, Deborah A. Lacus, the undersigned
officer, personally appeared John B. Keane and Mark A. Joyse, who acknowledged
themselves to be Vice President and Assistant Secretary, respectively, of THE
CONNECTICUT LIGHT AND POWER COMPANY, a corporation, and that they, as such Vice
President and such Assistant Secretary, being authorized so to do, executed the
foregoing instrument for the purpose therein contained, by signing the name of
the corporation by themselves as Vice President and Assistant Secretary, and as
their free act and deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Deborah A. Lacus
Deborah A. Lacus
Notary Public
My commission expires December 31, 1995
(SEAL)
STATE OF NEW YORK )
) SS.: NEW YORKCOUNTY OF NEW YORK )
On this 19th day of May, 1994, before me, John Florio, the undersigned
officer, personally appeared Robert Caporale and Scott Thiel who acknowledged
themselves to be Vice President and Assistant Treasurer, respectively, of
BANKERS TRUST COMPANY, a corporation, and that they, as such Vice President and
such Assistant Treasurer, being authorized so to do, executed the foregoing
instrument for the purposes therein contained, by signing the name of the
corporation by themselves as Vice President and Assistant Treasurer, and as
their free act and deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ John Florio
John Florio
Notary Public, State of New York
No. 01FL5021631
Qualified in New York County
My Commission Expires December 20, 1995
(SEAL)
SCHEDULE A
[FORM OF BONDS OF SERIES C]
No. $
THE CONNECTICUT LIGHT AND POWER COMPANY
Incorporated under the Laws of the State of Connecticut
FIRST AND REFUNDING MORTGAGE 8-1/2% BOND, 1994 SERIES C
PRINCIPAL DUE JUNE 1, 2024
FOR VALUE RECEIVED, THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation
organized and existing under the laws of the State of Connecticut (hereinafter
called the Company), hereby promises to pay to /s/ or registered
assigns, the principal sum of dollars, on the first day of
----------------
June, 2024 and to pay interest on said sum, semiannually on the first days of
June and December in each year, commencing December 1, 1994, until the Company's
obligation with respect to said principal sum shall be discharged, at the rate
per annum specified in the title of this bond from the interest payment date
next preceding the date of authentication hereof to which interest has been paid
on the bonds of this series, or if the date of authentication hereof is prior to
November 16, 1994, then from the date of original issuance, or if the date of
authentication hereof is an interest payment date to which interest is being
paid or a date between the record date for any such interest payment date and
such interest payment date, then from such interest payment date. Both
principal and interest shall be payable at the office or agency of the Company
in the Borough of Manhattan, New York, New York, in such coin or currency of the
United States of America as at the time of payment is legal tender for the
payment of public and private debts.
Each installment of interest hereon (other than overdue interest) shall be
payable to the person who shall be the registered owner of this bond at the
close of business on the record date, which shall be the May 15 or November 15,
as the case may be, next preceding the interest payment date, or, if such May 15
or November 15 shall be a legal holiday or a day on which banking institutions
in the Borough of Manhattan, New York, New York, are authorized by law to close,
the next preceding day which shall not be a legal holiday or a day on which such
institutions are so authorized to close.
Reference is hereby made to the further provisions of this bond set forth
on the reverse hereof, including without limitation provisions in regard to the
call and redemption and the registration of transfer and exchangeability of this
bond, and such further provisions shall for all purposes have the same effect as
though fully set forth in this place.
This bond shall not become or be valid or obligatory until the certificate
of authentication hereon shall have been signed by Bankers Trust Company
(hereinafter with its successors as defined in the Mortgage hereinafter referred
to, generally called the Trustee), or by such a successor.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused this
bond to be executed in its corporate name and on its behalf by its President by
his signature or a facsimile thereof, and its corporate seal to be affixed or
imprinted hereon and attested by the manual or facsimile signature of its
Secretary.
Dated as of June 1, 1994.
THE CONNECTICUT LIGHT AND POWER COMPANY
By
-------------------------------------
President
Attest:
Secretary
[FORM OF TRUSTEE'S CERTIFICATE]
Bankers Trust Company hereby certifies that this bond is one of the bonds
described in the within mentioned Mortgage.
BANKERS TRUST COMPANY, TRUSTEE
By
-------------------------------------------
Authorized Officer
Dated:
[FORM OF BOND]
[REVERSE]
THE CONNECTICUT LIGHT AND POWER COMPANY
FIRST AND REFUNDING MORTGAGE 8-1/2% BOND, 1994 SERIES C
This bond is one of an issue of bonds of the Company, of an unlimited
authorized amount of coupon bonds or registered bonds without coupons, or both,
known as its First and Refunding Mortgage Bonds, all issued or to be issued in
one or more series, and is one of a series of said bonds limited in principal
amount to one hundred and fifteen million dollars ($115,000,000), consisting
only of registered bonds without coupons and designated "First and Refunding
Mortgage 8-1/2% Bonds, 1994 Series C," all of which bonds are issued or are to
be issued under, and equally and ratably secured by, a certain Indenture of
Mortgage and Deed and Trust dated as of May 1, 1921, and by sixty-two
Supplemental Indentures dated respectively as of May 1, 1921, February 1, 1924,
July 1, 1926, June 20, 1928, June 1, 1932, July 1, 1932, July 1, 1935, September
1, 1936, October 20, 1936, December 1, 1936, December 1, 1938, August 31, 1944,
September 1, 1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1,
1952, December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961,
September 1, 1963, April 1, 1967, May 1, 1967, January 1, 1968, October 1, 1968,
December 1, 1969, January 1, 1970, October 1, 1970, December 1, 1971, August 1,
1972, April 1, 1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1,
1977, March 1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October
1, 1982, July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986,
April 1, 1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1,
1988, June 1, 1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1,
1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1,
1994, February 1, 1994 and June 1, 1994 (said Indenture of Mortgage and Deed of
Trust and Supplemental Indentures being collectively referred to herein as the
"Mortgage"), all executed by the Company to Bankers Trust Company, as Trustee,
all as provided in the Mortgage to which reference is made for a statement of
the property mortgaged and pledged, the nature and extent of the security, the
rights of the holders of the bonds in respect thereof and the terms and
conditions upon which the bonds may be issued and are secured; but neither the
foregoing reference to the Mortgage nor any provision of this bond or of the
Mortgage shall affect or impair the obligation of the Company, which is
absolute, unconditional and unalterable, to pay at the maturities herein
provided the principal of and interest on this bond as herein provided. The
principal of this bond may be declared or may become due on the conditions, in
the manner and at the time set forth in the Mortgage, upon the happening of an
event of default as in the Mortgage provided.
This bond is transferable by the registered holder hereof in person or by
attorney upon surrender hereof at the office or agency of the Company in the
Borough of Manhattan, New York, New York, together with a written instrument of
transfer in approved form, signed by the holder, and a new bond or bonds of this
series for a like principal amount in authorized denominations will be issued in
exchange, all as provided in the Mortgage. Prior to due presentment for
registration of transfer of this bond the Company and the Trustee may deem and
treat the registered owner hereof as the absolute owner hereof, whether or not
this bond be overdue, for the purpose of receiving payment and for all other
purposes, and neither the Company nor the Trustee shall be affected by any
notice to the contrary.
This bond is exchangeable at the option of the registered holder hereof
upon surrender hereof, at the office or agency of the Company in the Borough of
Manhattan, New York, New York, for an equal principal amount of bonds of this
series of other authorized denominations, in the manner and on the terms
provided in the Mortgage.
Bonds of this series are to be issued initially under a book-entry only
system and, except as hereinafter provided, registered in the name of The
Depository Trust Company, New York, New York ("DTC") or its nominee, which shall
be considered to be the holder of all bonds of this series for all purposes of
the Mortgage, including, without limitation, payment by the Company of principal
of and interest on such bonds of this series and receipt of notices and exercise
of rights of holders of such bonds of this series. There shall be a single bond
of this series which shall be immobilized in the custody of DTC with the owners
of book-entry interests in bonds of this series ("Book-Entry Interests") having
no right to receive bonds of this series in the form of physical securities or
certificates. Ownership of Book-Entry Interests shall be shown by book-entry on
the system maintained and operated by DTC, its participants (the "Participants")
and certain persons acting through the Participants. Transfers of ownership of
Book-Entry Interests are to be made only by DTC and the Participants by that
book-entry system, the Company and the Trustee having no responsibility therefor
so long as bonds of this series are registered in the name of DTC or its
nominee. DTC is to maintain records of positions of Participants in bonds of
this series, and the Participants and persons acting through Participants are to
maintain records of the purchasers and owners of Book-Entry Interests. If DTC
or its nominee determines not to continue to act as a depository for the bonds
of this series in connection with a book-entry only system, another depository,
if available, may act instead and the single bond of this series will be
transferred into the name of such other depository or its nominee, in which case
the above provisions will continue to apply to the new depository. If the book-
entry only system for bonds of this series is discontinued for any reason, upon
surrender and cancellation of the single bond of this series registered in the
name of the then depository or its nominee, new registered bonds of this series
will be issued in authorized denominations to the holders of Book-Entry
Interests in principal amounts coinciding with the amounts of Book-Entry
Interests shown on the book-entry system immediately prior to the discontinuance
thereof. Neither the Trustee nor the Company shall be responsible for the
accuracy of the interests shown on that system.
The bonds of this series are not subject to redemption at the option of the
Company prior to June 1, 2004. Thereafter, the bonds of this series are
subject to redemption prior to maturity as a whole at any time or in part from
time to time in accordance with the provisions of the Mortgage, upon not less
than thirty (30) days' prior notice (which notice may be made subject to the
deposit of redemption moneys with the Trustee before the date fixed for
redemption) given by mail as provided in the Mortgage, either at the option of
the Company, or for the purposes of any applicable provision of the Mortgage, at
the following prices, together in every case with accrued and unpaid interest
thereon to the date fixed for redemption:
(a) if redeemed with trust moneys deposited with or received by the
Trustee pursuant to specified provisions of the Mortgage, then at the
applicable special redemption price, stated as a percentage of the
principal amount, set forth below; and
(b) otherwise, at the applicable general redemption price, stated as
a percentage of the principal amount, set forth below:
If date fixed for General Special
redemption falls Redemption Redemption
within twelve months' Price (% Price (%
period ending the of principal of principal
last day of May amount called) amount called)
--------------- -------------- --------------
2005 103.87 100.00
2006 103.48 100.00
2007 103.09 100.00
2008 102.71 100.00
2009 102.32 100.00
2010 101.94 100.00
2011 101.55 100.00
2012 101.16 100.00
2013 100.78 100.00
2014 100.39 100.00
2015 100.00 100.00
2016 100.00 100.00
2017 100.00 100.00
2018 100.00 100.00
2019 100.00 100.00
2020 100.00 100.00
2021 100.00 100.00
2022 100.00 100.00
2023 100.00 100.00
2024 100.00 100.00
The Mortgage provides that the Company and the Trustee, with consent of the
holders of not less than 66-2/3% in aggregate principal amount of the bonds at
the time outstanding which would be affected by the action proposed to be taken,
may by supplemental indenture add any provisions to or change or eliminate any
of the provisions of the Mortgage or modify the rights of the holders of the
bonds and coupons issued thereunder; provided, however, that without the consent
of the holder hereof no such supplemental indenture shall affect the terms of
payment of the principal of or interest or premium on this bond, or reduce the
aforesaid percentage of the bonds the holders of which are required to consent
to such a supplemental indenture, or permit the creation by the Company of any
mortgage or pledge or lien in the nature thereof ranking prior to or equal with
the lien of the Mortgage or deprive the holder hereof of the lien of the
Mortgage on any of the property which is subject to the lien thereof.
As set forth in the Supplemental Indenture establishing the terms and series of
the bonds of this series, each holder of this bond, solely by virtue of its
acquisition thereof, shall have and be deemed to have consented, without the
need for any further action or consent by such holder, to any and all amendments
to the Mortgage which are intended to eliminate or modify in any manner the
requirements of the sinking and improvement fund as set forth in Section 6.14 of
the Mortgage.
No recourse shall be had for the payment of the principal of or the interest on
this bond, or any part thereof, or for any claim based thereon or otherwise in
respect thereof, to any incorporator, or any past, present or future
stockholder, officer or director of the Company, either directly or indirectly,
by virtue of any statute or by enforcement of any assessment or otherwise, and
any and all liability of the said incorporators, stockholders, officers or
directors of the Company in respect to this bond is hereby expressly waived and
released by every holder hereof.
SCHEDULE B
PROPERTY SUBJECT TO THE LIEN OF THE MORTGAGE
IN CONNECTICUT
TOWN OF ASHFORD
All of the following described rights, privileges and easements situated
in the Town of Ashford, County of Windham and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(1) Rex Harkness et al January 18, 1994 103 547
(2) C. Nelson Construction,Inc. January 17, 1994 103 641
(3) Town of Ashford March 11, 1994 104 002
TOWN OF AVON
All of the following described rights, privileges and easements situated
in the Town of Avon, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(4) Edward M. Ferrigno Construction December 13, 1993 288 808
Company, Inc.
(5) Solo Development January 13, 1994 291 325
TOWN OF BERLIN
All of the following described rights, privileges and easements situated
in the Town of Berlin, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(6) Kensington Woods, Incorporated December 16, 1993 356 40
TOWN OF BRISTOL
All of the following described rights, privileges and easements situated
in the Town of Bristol, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(7) Bruce Development Corporation, December 10, 1993 1115 650
Inc. et al
TOWN OF BURLINGTON
All of the following described rights, privileges and easements situated
in the Town of Burlington, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(8) Woodland Notch Development May 27, 1993 140 756
Corporation
TOWN OF CANTON
All of the following described rights, privileges and easements situated
in the Town of Canton, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(9) Michael A. Hollender et al October 2, 1993 196 384
TOWN OF CHESHIRE
All of the following described rights, privileges and easements situated
in the Town of Cheshire, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(10) Thomas J. Norback et al December 7, 1993 1024 224
(11) Neda DeMayo et al February 1, 1994 1036 223*
* Inter Alia: Hamden
TOWN OF CLINTON
All of the following described rights, privileges and easements situated
in the Town of Clinton, County of Middlesex and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(12) Lione Enterprises August 30, 1993 225 67
TOWN OF DANBURY
All of the following described rights, privileges and easements situated
in the Town of Danbury, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(13) Warren Ramey February 1, 1994 1077 823
(14) Mario Aldo Ljubicic et al January 12, 1994 1077 903
TOWN OF DURHAM
All of the following described rights, privileges and easements situated
in the Town of Durham, County of Middlesex and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(15) William J. O'Neal December 2, 1993 140 107
TOWN OF EAST WINDSOR
All of the following described rights, privileges and easements situated
in the Town of East Windsor, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(16) Connecticut Development Group, December 3, 1993 176 1061
Inc. of Glastonbury
TOWN OF ELLINGTON
All of the following described rights, privileges and easements situated
in the Town of Ellington, County of Tolland and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(17) The SBD Partnership December 21, 1993 207 136
(18) MMS Country Home Properties, January 26, 1994 207 138
Inc.
TOWN OF ENFIELD
All of the following described rights, privileges and easements situated
in the Town of Enfield, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(19) Hazard Avenue Associates May 25, 1988 575 225
(20) Lan Associates XII, Limited May 29, 1986 519 1118
Partnership
(21) Leaska Construction Co. October 22, 1990 622 15
(22) Carriage House I-Enfield, Inc.October 8, 1987 561 611
(23) Daro Development Corporation October 22, 1986 530 724
(24) ADS Realty Co., Inc. April 24, 1989 594 1189
TOWN OF GREENWICH
All of the following described rights, privileges and easements situated
in the Town of Greenwich, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(25) Mario E. Autera et al December 7, 1992 2450 75
TOWN OF HAMDEN
All of the following described rights, privileges and easements situated
in the Town of Hamden, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(26) Neda DeMayo et al February 1, 1994 1399 294*
TOWN OF LEBANON
All of the following described rights, privileges and easements situated
in the Town of Lebanon, County of New London and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(27) G. Bradford Foster et al November 1, 1993 155 515
(28) Farmers & Mechanics Bank December 10, 1993 156 87
(29) Donald A. Demar January 17, 1994 156 589
TOWN OF LITCHFIELD
All of the following described rights, privileges and easements situated
in the Town of Litchfield, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(30) Nancy D. Goldring et al October 25, 1993 219 1162
&
November 15, 1993
* Inter Alia: Cheshire
TOWN OF MANCHESTER
All of the following described rights, privileges and easements situated
in the Town of Manchester, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(31) TAVCO Associates December 8, 1992 1671 343
TOWN OF MIDDLEBURY
All of the following described rights, privileges and easements situated
in the Town of Middlebury, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(32) Christine N. Lavigne et al August 11, 1992 127 912
TOWN OF MONROE
All of the following described rights, privileges and easements situated
in the Town of Monroe, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(33) Carol B. Steiner October 13, 1988 425 154
TOWN OF MONTVILLE
All of the following described rights, privileges and easements situated
in the Town of Montville, County of New London and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(34) Bernard Barnett et al June 17, 1993 255 777
(35) Jean K. Milefski et al December 15, 1993 264 250
TOWN OF NAUGATUCK
All of the following described rights, privileges and easements situated
in the Town of Naugatuck, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(36) Realrock Associates December 20, 1993 389 919
TOWN OF NEW MILFORD
All of the following described rights, privileges and easements situated
in the Town of New Milford, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(37) Joseph S. Tarzia May 21, 1993 476 791
(38) John W. Dinneen, Jr. et al November 10, 1993 484 812
TOWN OF NEWTOWN
All of the following described rights, privileges and easements situated
in the Town of Newtown, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(39) Joseph Scherpf December 21, 1993 486 88
(40) Early Settlers Limited February 9, 1994 488 630
Partnership
TOWN OF NORTH STONINGTON
All of the following described rights, privileges and easements situated
in the Town of North Stonington, County of New London and State of Connecticut,
more particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(41) B & D Associates January 3, 1994 99 581
TOWN OF OLD LYME
All of the following described rights, privileges and easements situated
in the Town of Old Lyme, County of New London and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(42) Gary D. Smith June 17, 1993 211 551
TOWN OF PLAINFIELD
All of the following described rights, privileges and easements situated
in the Town of Plainfield, County of Windham and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(43) Kenneth E. Tetreault March 30, 1994 222 12
TOWN OF RIDGEFIELD
All of the following described rights, privileges and easements situated
in the Town of Ridgefield, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(44) Sturges Brothers, Inc. August 28, 1993 476 98
(45) William A. Jones January 14, 1994 485 911
TOWN OF SIMSBURY
All of the following described rights, privileges and easements situated
in the Town of Simsbury, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(46) Estate of George L. Engel April 8, 1994 429 68
TOWN OF SOUTHBURY
All of the following described rights, privileges and easements situated
in the Town of Southbury, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(47) Naugatuck Savings Bank et al May 7, 1993 271 549
(48) T D I, Ltd. April 8, 1993 271 613
TOWN OF SOUTHINGTON
All of the following described rights, privileges and easements situated
in the Town of Southington, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(49) David W. Florian September 25, 1992 548 826
(50) Katherine Florian September 25, 1992 548 828
(51) Carl J. Sokolowski, Trustee September 30, 1992 548 830
(52) LePage Homes, Inc. March 8, 1993 560 840
(53) William G. Gioia February 14, 1994 594 795
TOWN OF SOUTH WINDSOR
All of the following described rights, privileges and easements situated
in the Town of South Windsor, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(54) Dart Hill Realty, Inc. March 22, 1994 784 30
TOWN OF STAFFORD
All of the following described rights, privileges and easements situated
in the Town of Stafford, County of Tolland and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(55) Maiolo Real Estate Investment November 18, 1993 313 3
Company, Inc.
TOWN OF STERLING
All of the following described rights, privileges and easements situated
in the Town of Sterling, County of Windham and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(56) Christopher Adam Sliwinski August 18, 1993 69 707
(57) Peter F. Maerkel July 16, 1993 69 1052
(58) Patten Liquidation Sales January 11, 1994 70 40
Corporation
TOWN OF SUFFIELD
All of the following described rights, privileges and easements situated
in the Town of Suffield, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(59) Briarwood Homes, Inc. February 8, 1994 252 455
TOWN OF THOMASTON
All of the following described rights, privileges and easements situated
in the Town of Thomaston, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(60) Robert D. Scanlon et al February 18, 1993 144 31
TOWN OF TOLLAND
All of the following described rights, privileges and easements situated
in the Town of Tolland, County of Tolland and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(61) Alan D. Williams et al November 22, 1993 474 73
TOWN OF TORRINGTON
All of the following described rights, privileges and easements situated
in the Town of Torrington, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(62) David Vaill November 18, 1992 574 1031
(63) The Charlotte Hungerford June 4, 1993 575 697
Hospital et al
(64) The Charlotte Hungerford December 8, 1993 587 965
Hospital et al
TOWN OF VOLUNTOWN
All of the following described rights, privileges and easements situated
in the Town of Voluntown, County of New London and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(65) Town of Voluntown March 8, 1994 61 994
TOWN OF WATERBURY
All of the following described rights, privileges and easements situated
in the Town of Waterbury, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(66) Daniel W. Ferraro May 26, 1993 2972 12
TOWN OF WATERTOWN
All of the following described rights, privileges and easements situated
in the Town of Watertown, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(67) The Torrington Company May 12, 1993 700 237
TOWN OF WESTON
All of the following described rights, privileges and easements situated
in the Town of Weston, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(68) KHM Family Trust January 26, 1994 217 625
TOWN OF WILTON
All of the following described rights, privileges and easements situated
in the Town of Wilton, County of Fairfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(69) Thomas T. Adams, Trustee April 20, 1992 785 51
(70) Thomas T. Adams, Trustee January 3, 1994 887 112
TOWN OF WOODBURY
All of the following described rights, privileges and easements situated
in the Town of Woodbury, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
(71) Garwin D. Hardisty June 10, 1993 195 939
TOWN OF WOODSTOCK
All of the following described rights, privileges and easements situated
in the Town of Woodstock, County of Windham and State of Connecticut, more
particularly described in the following deeds, viz:
Recorded
Grantor Date of Instrument Volume Page
SUPPLEMENTAL INDENTURE
Dated as of October 1, 1994
TO
Indenture of Mortgage and Deed of Trust
Dated as of May 1, 1921
THE CONNECTICUT LIGHT AND POWER COMPANY
TO
BANKERS TRUST COMPANY, Trustee
1994 Series D Bonds, Due October 1, 2024
THE CONNECTICUT LIGHT AND POWER COMPANY
Supplemental Indenture, Dated as of October 1, 1994
TABLE OF CONTENTS
PAGE
Parties 1
Recitals 1
Granting Clauses 2
Habendum 2
Grant in Trust 2
ARTICLE 1.
FORM AND PROVISIONS OF BONDS OF SERIES D
SECTION 1.01. Designation; Amount 3
SECTION 1.02. Form of Bonds of Series D 3
SECTION 1.03. Provisions of Bonds of Series D; Interest Accrual 3
SECTION 1.04. Transfer and Exchange of Bonds of Series D 4
SECTION 1.05. Sinking and Improvement Fund 4
ARTICLE 2.
REDEMPTION OF BONDS OF SERIES D 4
ARTICLE 3.
REPAYMENT OF BONDS OF SERIES D AT OPTION OF HOLDER 4
ARTICLE 4.
MISCELLANEOUS
SECTION 4.01. Benefits of Supplemental Indenture and
Bonds of Series D 4
SECTION 4.02. Effect of Table of Contents and Headings 5
SECTION 4.03. Counterparts 5
TESTIMONIUM 5
SIGNATURES 5
ACKNOWLEDGMENTS 6
SCHEDULE A - Form of Bond of Series D, Form of
Trustee's Certificate 7
SCHEDULE B - Property Subject to the Lien of the Mortgage 13
SUPPLEMENTAL INDENTURE, dated as of the first day of October, 1994, between
THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing
under the laws of the State of Connecticut (hereinafter called "Company") and
BANKERS TRUST COMPANY, a corporation organized and existing under the laws of
the State of New York (hereinafter called "Trustee").
WHEREAS, the Company heretofore duly executed, acknowledged and delivered
to the Trustee a certain Indenture of Mortgage and Deed of Trust dated as of
May 1, 1921, and sixty-two Supplemental Indentures thereto dated respectively as
of May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932,
July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1,
1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945,
October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955,
January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1,
1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969,
January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1,
1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1,
1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982,
July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1,
1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988,
June 1, 1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992,
October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1, 1994,
February 1, 1994 and June 1, 1994 (said Indenture of Mortgage and Deed of Trust
(i) as heretofore amended, being hereinafter generally called the "Mortgage
Indenture," and (ii) together with said Supplemental Indentures thereto, being
hereinafter generally called the "Mortgage"), all of which have been duly
recorded as required by law, for the purpose of securing its First and Refunding
Mortgage Bonds (of which $1,330,000,000 aggregate principal amount are
outstanding at the date of this Supplemental Indenture) to an unlimited amount,
issued and to be issued for the purposes and in the manner therein provided, of
which Mortgage this Supplemental Indenture is intended to be made a part, as
fully as if therein recited at length;
WHEREAS, the Company by appropriate and sufficient corporate action in
conformity with the provisions of the Mortgage has duly determined to create a
further series of bonds under the Mortgage to be designated "First and Refunding
Mortgage 7-7/8% Bonds, 1994 Series D" (hereinafter generally referred to as the
"bonds of Series D"), to consist of fully registered bonds containing terms and
provisions duly fixed and determined by the Board of Directors of the Company
and expressed in this Supplemental Indenture, such fully registered bonds and
the Trustee's certificate of its authentication thereof to be substantially in
the forms thereof respectively set forth in Schedule A appended hereto and made
a part hereof; and
WHEREAS, the execution and delivery of this Supplemental Indenture and the
issue of not in excess of one hundred and forty million dollars ($140,000,000)
in aggregate principal amount of bonds of Series D and other necessary actions
have been duly authorized by the Board of Directors of the Company; and
WHEREAS, the Company proposes to execute and deliver this Supplemental
Indenture to provide for the issue of the bonds of Series D and to confirm the
lien of the Mortgage on the property referred to below, all as permitted by
Section 14.01 of the Mortgage Indenture; and
WHEREAS, all acts and things necessary to constitute this Supplemental
Indenture a valid, binding and legal instrument and to make the bonds of Series
D, when executed by the Company and authenticated by the Trustee valid, binding
and legal obligations of the Company have been authorized and performed;
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF TRUST
WITNESSETH:
That in order to secure the payment of the principal of and interest on all
bonds issued and to be issued under the Mortgage, according to their tenor and
effect, and according to the terms of the Mortgage and this Supplemental
Indenture, and to secure the performance of the covenants and obligations in
said bonds and in the Mortgage and this Supplemental Indenture respectively
contained, and for the better assuring and confirming unto the Trustee, its
successor or successors and its or their assigns, upon the trusts and for the
purposes expressed in the Mortgage and this Supplemental Indenture, all and
singular the hereditament, premises, estates and property of the Company thereby
conveyed or assigned or intended so to be, or which the Company may thereafter
have become bound to convey or assign to the Trustee, as security for said bonds
(except such hereditament, premises, estates and property as shall have been
disposed of or released or withdrawn from the lien of the Mortgage and this
Supplemental Indenture, in accordance with the provisions thereof and subject to
alterations, modifications and changes in said hereditament, premises, estates
and property as permitted under the provisions thereof), the Company, for and in
consideration of the premises and the sum of One Dollar ($1.00) to it in hand
paid by the Trustee, the receipt whereof is hereby acknowledged, and of other
valuable considerations, has granted, bargained, sold, assigned, mortgaged,
pledged, transferred, set over, aliened, enfeoffed, released, conveyed and
confirmed, and by these presents does grant, bargain, sell, assign, mortgage,
pledge, transfer, set over, alien, enfeoff, release, convey and confirm unto
said Bankers Trust Company, as Trustee, and its successor or successors in the
trusts created by the Mortgage and this Supplemental Indenture, and its and
their assigns, all of said hereditament, premises, estates and property (except
and subject as aforesaid), as fully as though described at length herein,
including, without limitation of the foregoing, the property, rights and
privileges of the Company described or referred to in Schedule B hereto.
Together with all plants, buildings, structures, improvements and machinery
located upon said real estate or any portion thereof, and all rights, privileges
and easements of every kind and nature appurtenant thereto, and all and singular
the tenements, hereditament and appurtenances belonging to the real estate or
any part thereof described or referred to in Schedule B or intended so to be, or
in any wise appertaining thereto, and the reversions, remainders, rents, issues
and profits thereof, and also all the estate, right, title, interest, property,
possession, claim and demand whatsoever, as well in law as in equity, of the
Company, of, in and to the same and any and every part thereof, with the
appurtenances; except and subject as aforesaid.
TO HAVE AND TO HOLD all and singular the property, rights and privileges
hereby granted or mentioned or intended so to be, together with all and singular
the reversions, remainders, rents, revenues, income, issues and profits,
privileges and appurtenances, now or hereafter belonging or in any way
appertaining thereto, unto the Trustee and its successor or successors in the
trust created by the Mortgage and this Supplemental Indenture, and its and their
assigns, forever, and with like effect as if the above described property,
rights and privileges had been specifically described at length in the Mortgage
and this Supplemental Indenture.
Subject, however, to permitted liens, as defined in the Mortgage Indenture.
IN TRUST, NEVERTHELESS, upon the terms and trusts of the Mortgage and this
Supplemental Indenture for those who shall hold the bonds and coupons issued and
to be issued thereunder, or any of them, without preference, priority or
distinction as to lien of any of said bonds and coupons over any others thereof
by reason of priority in the time of the issue or negotiation thereof, or
otherwise howsoever, subject, however, to the provisions in reference to
extended, transferred or pledged coupons and claims for interest set forth in
the Mortgage and this Supplemental Indenture (and subject to any sinking fund
that may heretofore have been or hereafter be created for the benefit of any
particular series).
And it is hereby covenanted that all such bonds of Series D are to be
issued, authenticated and delivered, and that the mortgaged premises are to be
held by the Trustee, upon and subject to the trusts, covenants, provisions and
conditions and for the uses and purposes set forth in the Mortgage and this
Supplemental Indenture and upon and subject to the further covenants, provisions
and conditions and for the uses and purposes hereinafter set forth, as follows,
to wit:
ARTICLE 1.
FORM AND PROVISIONS OF BONDS OF SERIES D
SECTION 1.01. Designation; Amount. The bonds of Series D shall be
designated "First and Refunding Mortgage 7-7/8% Bonds, 1994 Series D" and,
subject to Section 2.08 of the Mortgage Indenture, shall not exceed one hundred
and forty million dollars ($140,000,000) in aggregate principal amount at any
one time outstanding. The initial issue of the bonds of Series D may be
effected upon compliance with the applicable provisions of the Mortgage
Indenture.
SECTION 1.02. Form of Bonds of Series D. The bonds of Series D
shall be issued only in fully registered form without coupons in denominations
of one thousand dollars ($1,000) and multiples thereof.
The bonds of Series D and the certificate of the Trustee upon said bonds
shall be substantially in the forms thereof respectively set forth in Schedule A
appended hereto.
SECTION 1.03. Provisions of Bonds of Series D; Interest Accrual. The
bonds of Series D shall mature on October 1, 2024 and shall bear interest,
payable semiannually on the first days of April and October of each year,
commencing April 1, 1995, at the rate specified in their title, until the
Company's obligation in respect of the principal thereof shall be discharged;
and shall be payable both as to principal and interest at the office or agency
of the Company in the Borough of Manhattan, New York, New York, in any coin or
currency of the United States of America which at the time of payment is legal
tender for the payment of public and private debts. The interest on the bonds
of Series D, whether in temporary or definitive form, shall be payable without
presentation of such bonds; and only to or upon the written order of the
registered holders thereof of record at the applicable record date. The bonds
of Series D shall be callable for redemption in whole or in part according to
the terms and provisions provided herein in Article 2.
Each bond of Series D shall be dated as of October 1, 1994 and shall bear
interest on the principal amount thereof from the interest payment date next
preceding the date of authentication thereof by the Trustee to which interest
has been paid on the bonds of Series D, or if the date of authentication thereof
is prior to March 16, 1995, then from the date of original issuance, or if the
date of authentication thereof be an interest payment date to which interest is
being paid or a date between the record date for any such interest payment date
and such interest payment date, then from such interest payment date.
The person in whose name any bond of Series D is registered at the close of
business on any record date (as hereinafter defined) with respect to any
interest payment date shall be entitled to receive the interest payable on such
interest payment date notwithstanding the cancellation of such bond upon any
registration of transfer or exchange thereof subsequent to the record date and
prior to such interest payment date, except that if and to the extent the
Company shall default in the payment of the interest due on such interest
payment date, then such defaulted interest shall be paid to the person in whose
name such bond is registered on a subsequent record date for the payment of
defaulted interest if one shall have been established as hereinafter provided
and otherwise on the date of payment of such defaulted interest. A subsequent
record date may be established by the Company by notice mailed to the owners of
bonds of Series D not less than ten days preceding such record date, which
record date shall not be more than thirty days prior to the subsequent interest
payment date. The term "record date" as used in this Section with respect to
any regular interest payment (i.e., April 1 or October 1) shall mean the March
15 or September 15, as the case may be, next preceding such interest payment
date, or if such March 15 or September 15 shall be a legal holiday or a day on
which banking institutions in the Borough of Manhattan, New York, New York are
authorized by law to close, the next preceding day which shall not be a legal
holiday or a day on which such institutions are so authorized to close.
SECTION 1.04. Transfer and Exchange of Bonds of Series D. The bonds of
Series D may be surrendered for registration of transfer as provided in
Section 2.06 of the Mortgage Indenture at the office or agency of the Company in
the Borough of Manhattan, New York, New York, and may be surrendered at said
office for exchange for a like aggregate principal amount of bonds of Series D
of other authorized denominations. Notwithstanding the provisions of
Section 2.06 of the Mortgage Indenture, no charge, except for taxes or other
governmental charges, shall be made by the Company for any registration of
transfer of bonds of Series D or for the exchange of any bonds of Series D for
such bonds of other authorized denominations.
SECTION 1.05. Sinking and Improvement Fund. Each holder of a bond of
Series D, solely by virtue of its acquisition thereof, shall have and be deemed
to have consented, without the need for any further action or consent by such
holder, to any and all amendments to the Mortgage Indenture which are intended
to eliminate or modify in any manner the requirements of the sinking and
improvement fund as provided for in Section 6.14 thereof.
ARTICLE 2.
REDEMPTION OF BONDS OF SERIES D.
The bonds of Series D shall not be redeemable as a whole or in part at any
time.
ARTICLE 3
REPAYMENT OF BONDS OF SERIES D AT OPTION OF HOLDER
Any of the bonds of Series D are subject to repayment on October 1, 2001 at
the option of the holder of the bond of Series D as set forth in the form of
bond of Series D appended hereto.
ARTICLE 4
MISCELLANEOUS.
SECTION 4.01. Benefits of Supplemental Indenture and Bonds of Series D.
Nothing in this Supplemental Indenture, or in the bonds of Series D, expressed
or implied, is intended to or shall be construed to give to any person or
corporation other than the Company, the Trustee and the holders of the bonds and
interest obligations secured by the Mortgage and this Supplemental Indenture,
any legal or equitable right, remedy or claim under or in respect of this
Supplemental Indenture or of any covenant, condition or provision herein
contained. All the covenants, conditions and provisions hereof are and shall be
held to be for the sole and exclusive benefit of the Company, the Trustee and
the holders of the bonds and interest obligations secured by the Mortgage and
this Supplemental Indenture.
SECTION 4.02. Effect of Table of Contents and Headings. The table of
contents and the descriptive headings of the several Articles and Sections of
this Supplemental Indenture are inserted for convenience of reference only and
are not to be taken to be any part of this Supplemental Indenture or to control
or affect the meaning, construction or effect of the same.
SECTION 4.03. Counterparts. For the purpose of facilitating the recording
hereof, this Supplemental Indenture may be executed in any number of
counterparts, each of which shall be and shall be taken to be an original and
all collectively but one instrument.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused
these presents to be executed by a Vice President and its corporate seal to be
hereunto affixed, duly attested by its Secretary or an Assistant Secretary, and
Bankers Trust Company has caused these presents to be executed by a Vice
President or Assistant Vice President and its corporate seal to be hereunto
affixed, duly attested by one of its Assistant Secretaries, as of the day and
year first above written.
THE CONNECTICUT LIGHT AND POWER
COMPANY
Attest:
/s/ Mark A. Joyse By /s/ John B. Keane
Mark A. Joyse John B. Keane
Assistant Secretary Vice President
(SEAL) Signed, sealed and delivered
in the presence of:
/s/ Tracy A. DeCredico
/s/ Jeffrey C. Miller
BANKERS TRUST COMPANY
Attest:
/s/ Scott Thiel By /s/ Robert Caporale
Scott Thiel Robert Caporale
Assistant Treasurer Vice President
(SEAL) Signed, sealed and delivered
in the presence of:
/s/ Kerri O'Brien
/s/ Denise Mitchell
(STATE OF CONNECTICUT )
) SS.: BERLIN
COUNTY OF HARTFORD )
On this 28th day of September, 1994, before me, Deborah A. Tawrel, the
undersigned officer, personally appeared John B. Keane and Mark A. Joyse who
acknowledged themselves to be Vice President and Assistant Secretary,
respectively, of THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation, and
that they, as such Vice President and such Assistant Secretary, being authorized
so to do, executed the foregoing instrument for the purpose therein contained,
by signing the name of the corporation by themselves as Vice President and
Assistant Secretary, and as their free act and deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Deborah A. Tawrel
Deborah A. Tawrel
Notary Public
My commission expires December 31, 1995
(SEAL)
STATE OF NEW YORK )
) SS.: NEW YORK
COUNTY OF NEW YORK )
On this day of September, 1994, before me, Sharon V. Alston, the
----
undersigned officer, personally appeared Robert Caporale and Scott Thiel who
acknowledged themselves to be Vice President and Assistant Treasurer,
respectively, of BANKERS TRUST COMPANY, a corporation, and that they, as such
Vice President and such Assistant Treasurer, being authorized so to do, executed
the foregoing instrument for the purposes therein contained, by signing the name
of the corporation by themselves as Vice President and Assistant Treasurer, and
as their free act and deed.
IN WITNESS WHEREOF, I hereunto set my hand and official seal.
/s/ Sharon V. Alston
Sharon V. Alston
Notary Public, State of New York
No. 31-4966275
Qualified in New York County
My Commission expires
--------------
(SEAL)
(SEAL)
SCHEDULE A
[FORM OF BONDS OF SERIES D]
No. $
THE CONNECTICUT LIGHT AND POWER COMPANY
Incorporated under the Laws of the State of Connecticut
FIRST AND REFUNDING MORTGAGE 7-7/8% BOND, 1994 SERIES D
PRINCIPAL DUE October 1, 2024
FOR VALUE RECEIVED, THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation
organized and existing under the laws of the State of Connecticut (hereinafter
called the Company), hereby promises to pay to , or registered
---------------
assigns, the principal sum of dollars, on the first day
------------------------
of October, 2024 and to pay interest on said sum, semiannually on the first days
of April and October in each year, commencing April 1, 1995, until the Company's
obligation with respect to said principal sum shall be discharged, at the rate
per annum specified in the title of this bond from the interest payment date
next preceding the date of authentication hereof to which interest has been paid
on the bonds of this series, or if the date of authentication hereof is prior to
March 16, 1995, then from the date of original issuance, or if the date of
authentication hereof is an interest payment date to which interest is being
paid or a date between the record date for any such interest payment date and
such interest payment date, then from such interest payment date. Both
principal and interest shall be payable at the office or agency of the Company
in the Borough of Manhattan, New York, New York, in such coin or currency of the
United States of America as at the time of payment is legal tender for the
payment of public and private debts.
Each installment of interest hereon (other than overdue interest) shall be
payable to the person who shall be the registered owner of this bond at the
close of business on the record date, which shall be the March 15 or
September 15, as the case may be, next preceding the interest payment date, or,
if such March 15 or September 15 shall be a legal holiday or a day on which
banking institutions in the Borough of Manhattan, New York, New York, are
authorized by law to close, the next preceding day which shall not be a legal
holiday or a day on which such institutions are so authorized to close.
This bond is subject to repayment on October 1, 2001 at the option of the
registered holder hereof exercisable during the period from and including August
1, 2001 to and including September 1, 2001 at a repayment price equal to the
principal amount hereof to be repaid, together with interest payable hereon to
the repayment date, as described on the reverse hereof.
Reference is hereby made to the further provisions of this bond set forth
on the reverse hereof, including without limitation provisions in regard to the
call and redemption, repayment at option of holder and the registration of
transfer and exchangeability of this bond, and such further provisions shall for
all purposes have the same effect as though fully set forth in this place.
This bond shall not become or be valid or obligatory until the certificate
of authentication hereon shall have been signed by Bankers Trust Company
(hereinafter with its successors as defined in the Mortgage hereinafter referred
to, generally called the Trustee), or by such a successor.
IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused this
bond to be executed in its corporate name and on its behalf by its President by
his signature or a facsimile thereof, and its corporate seal to be affixed or
imprinted hereon and attested by the manual or facsimile signature of its
Secretary.
Dated as of October 1, 1994.
THE CONNECTICUT LIGHT AND POWER COMPANY
By
--------------------------------------
President
Attest:
Secretary
[FORM OF TRUSTEE'S CERTIFICATE]
Bankers Trust Company hereby certifies that this bond is one of the bonds
described in the within mentioned Mortgage.
BANKERS TRUST COMPANY, TRUSTEE
By
-------------------------------------
Authorized Officer
Dated:
[FORM OF BOND]
[REVERSE]
THE CONNECTICUT LIGHT AND POWER COMPANY
FIRST AND REFUNDING MORTGAGE 7-7/8% BOND, 1994 SERIES D
This bond is one of an issue of bonds of the Company, of an unlimited
authorized amount of coupon bonds or registered bonds without coupons, or both,
known as its First and Refunding Mortgage Bonds, all issued or to be issued in
one or more series, and is one of a series of said bonds limited in principal
amount to one hundred and forty million dollars ($140,000,000), consisting only
of registered bonds without coupons and designated "First and Refunding Mortgage
7-7/8% Bonds, 1994 Series D," all of which bonds are issued or are to be issued
under, and equally and ratably secured by, a certain Indenture of Mortgage and
Deed and Trust dated as of May 1, 1921, and by sixty-three Supplemental
Indentures dated respectively as of May 1, 1921, February 1, 1924, July 1, 1926,
June 20, 1928, June 1, 1932, July 1, 1932, July 1, 1935, September 1, 1936,
October 20, 1936, December 1, 1936, December 1, 1938, August 31, 1944,
September 1, 1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1,
1952, December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961,
September 1, 1963, April 1, 1967, May 1, 1967, January 1, 1968, October 1, 1968,
December 1, 1969, January 1, 1970, October 1, 1970, December 1, 1971, August 1,
1972, April 1, 1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1,
1977, March 1, 1978, September 1, 1980, October 1, 1981, June 30, 1982,
October 1, 1982, July 1, 1983, January 1, 1984, October 1, 1985, September 1,
1986, April 1, 1987, October 1, 1987, November 1, 1987, April 1, 1988,
November 1, 1988, June 1, 1989, September 1, 1989, December 1, 1989, April 1,
1992, July 1, 1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1,
1993, February 1, 1994, February 1, 1994, June 1, 1994 and October 1, 1994 (said
Indenture of Mortgage and Deed of Trust and Supplemental Indentures being
collectively referred to herein as the "Mortgage"), all executed by the Company
to Bankers Trust Company, as Trustee, all as provided in the Mortgage to which
reference is made for a statement of the property mortgaged and pledged, the
nature and extent of the security, the rights of the holders of the bonds in
respect thereof and the terms and conditions upon which the bonds may be issued
and are secured; but neither the foregoing reference to the Mortgage nor any
provision of this bond or of the Mortgage shall affect or impair the obligation
of the Company, which is absolute, unconditional and unalterable, to pay at the
maturities herein provided the principal of and interest on this bond as herein
provided. The principal of this bond may be declared or may become due on the
conditions, in the manner and at the time set forth in the Mortgage, upon the
happening of an event of default as in the Mortgage provided.
This bond is transferable by the registered holder hereof in person or by
attorney upon surrender hereof at the office or agency of the Company in the
Borough of Manhattan, New York, New York, together with a written instrument of
transfer in approved form, signed by the holder, and a new bond or bonds of this
series for a like principal amount in authorized denominations will be issued in
exchange, all as provided in the Mortgage. Prior to due presentment for
registration of transfer of this bond the Company and the Trustee may deem and
treat the registered owner hereof as the absolute owner hereof, whether or not
this bond be overdue, for the purpose of receiving payment and for all other
purposes, and neither the Company nor the Trustee shall be affected by any
notice to the contrary.
This bond is exchangeable at the option of the registered holder hereof
upon surrender hereof, at the office or agency of the Company in the Borough of
Manhattan, New York, New York, for an equal principal amount of bonds of this
series of other authorized denominations, in the manner and on the terms
provided in the Mortgage.
Bonds of this series are to be issued initially under a book-entry only
system and, except as hereinafter provided, registered in the name of The
Depository Trust Company, New York, New York ("DTC") or its nominee, which shall
be considered to be the holder of all bonds of this series for all purposes of
the Mortgage, including, without limitation, payment by the Company of principal
of and interest on such bonds of this series and receipt of notices and exercise
of rights of holders of such bonds of this series. There shall be a single bond
of this series which shall be immobilized in the custody of DTC with the owners
of book-entry interests in bonds of this series ("Book-Entry Interests") having
no right to receive bonds of this series in the form of physical securities or
certificates. Ownership of Book-Entry Interests shall be shown by book-entry on
the system maintained and operated by DTC, its participants (the "Participants")
and certain persons acting through the Participants. Transfers of ownership of
Book-Entry Interests are to be made only by DTC and the Participants by that
book-entry system, the Company and the Trustee having no responsibility therefor
so long as bonds of this series are registered in the name of DTC or its
nominee. DTC is to maintain records of positions of Participants in bonds of
this series, and the Participants and persons acting through Participants are to
maintain records of the purchasers and owners of Book-Entry Interests. If DTC
or its nominee determines not to continue to act as a depository for the bonds
of this series in connection with a book-entry only system, another depository,
if available, may act instead and the single bond of this series will be
transferred into the name of such other depository or its nominee, in which case
the above provisions will continue to apply to the new depository. If the book-
entry only system for bonds of this series is discontinued for any reason, upon
surrender and cancellation of the single bond of this series registered in the
name of the then depository or its nominee, new registered bonds of this series
will be issued in authorized denominations to the holders of Book-Entry
Interests in principal amounts coinciding with the amounts of Book-Entry
Interests shown on the book-entry system immediately prior to the discontinuance
thereof. Neither the Trustee nor the Company shall be responsible for the
accuracy of the interests shown on that system.
The bonds of this series are not subject to redemption as a whole or in
part prior to maturity.
This bond will be repayable on October 1, 2001, at the option of the
registered holder or holders hereof, at 100% of its principal amount together
with interest payable to the date of repayment. The repayment option may be
exercised by a registered holder or holders of this bond for less than the
entire principal amount of the bond, provided the principal amount which is to
be repaid to such holder is equal to $1,000 or an integral multiple of $1,000.
Such election by a registered holder to tender this bond for repayment will be
irrevocable.
So long as this bond is held under the book-entry only system referred to
above, DTC or its nominee, as registered holder of the bond, will be entitled to
tender the bond on October 1, 2001 for repayment and such tender will be
effected by means of DTC's Repayment Option Procedures. During the period from
and including August 1, 2001 to and including September 1, 2001 or, if September
1, 2001 shall be a legal holiday or a day on which banking institutions in the
Borough of Manhattan, New York, New York, are authorized by law to close, the
next succeeding day which shall not be a legal holiday or a day on which such
institutions are so authorized to close, DTC will receive instructions from its
Participant or Participants (acting on behalf of the owner or owners of
beneficial interests in this bond) to tender this bond for purchase under DTC's
Repayment Option Procedures. Such tender for purchase will be made by DTC by
means of a book-entry credit of the bond to the account of the Trustee, provided
that DTC receives instructions from the tendering Participant or Participants by
Noon on September 1, 2001. Promptly after the recording of such book-entry
credit, DTC will provide the Trustee an Agent Put Daily Activity Report in
accordance with its Repayment Option Procedures, identifying this bond and the
aggregate principal amount hereof as to which such tender for purchase has been
made. OWNERS OF BENEFICIAL INTERESTS IN THIS BOND WHO WISH TO EFFECTUATE THE
TENDER AND REPAYMENT OF THIS BOND MUST INSTRUCT THEIR RESPECTIVE DTC PARTICIPANT
OR PARTICIPANTS A REASONABLE PERIOD OF TIME IN ADVANCE OF SEPTEMBER 1, 2001.
If at any time the use of a book-entry only system through DTC (or any
successor securities depository) is discontinued with respect to this bond,
tender for repayment of the bond on October 1, 2001 shall be made according to
the following procedures. The Company must receive at the principal office or
agency of the Trustee, in the Borough of Manhattan, New York, New York, during
the period from and including August 1, 2001 to and including September 1, 2001
or, if September 1, 2001 shall be a legal holiday or a day on which banking
institutions in the Borough of Manhattan, New York, New York, are authorized by
law to close, the next succeeding day which shall not be a legal holiday or a
day on which such institutions are so authorized to close: (i) this bond with
the form entitled "Option to Elect Repayment" below duly completed or (ii) a
telegram, telex, facsimile transmission or letter from a member of a national
securities exchange or the National Association of Securities Dealers Inc., or a
commercial bank or trust company in the United States of America, setting forth
the name of the holder of the bond, the principal amount of the bond, the amount
of the bond to be repaid, a statement that the option to elect repayment is
being exercised thereby and a guarantee that the bond to be repaid with the form
entitled "Option to Elect Repayment" on the reverse thereof duly completed will
be received by the Company not later than five days (which are not legal
holidays or days on which banking institutions in the Borough of Manhattan, New
York, New York are authorized by law to close) after the date of such telegram,
telex, facsimile transmission or letter, and such bond and duly completed form
are received by the Company by such fifth day. Either form of notice duly
received during the period from and including August 1, 2001 to and including
September 1, 2001 shall be irrevocable. All questions as to the validity,
eligibility (including time of receipt) and acceptance of any bond for repayment
will be determined by the Company, whose determination shall be final and
binding.
The Mortgage provides that the Company and the Trustee, with consent of the
holders of not less than 66-2/3% in aggregate principal amount of the bonds at
the time outstanding which would be affected by the action proposed to be taken,
may by supplemental indenture add any provisions to or change or eliminate any
of the provisions of the Mortgage or modify the rights of the holders of the
bonds and coupons issued thereunder; provided, however, that without the consent
of the holder hereof no such supplemental indenture shall affect the terms of
payment of the principal of or interest or premium on this bond, or reduce the
aforesaid percentage of the bonds the holders of which are required to consent
to such a supplemental indenture, or permit the creation by the Company of any
mortgage or pledge or lien in the nature thereof ranking prior to or equal with
the lien of the Mortgage or deprive the holder hereof of the lien of the
Mortgage on any of the property which is subject to the lien thereof.
As set forth in the Supplemental Indenture establishing the terms and series of
the bonds of this series, each holder of this bond, solely by virtue of its
acquisition thereof, shall have and be deemed to have consented, without the
need for any further action or consent by such holder, to any and all amendments
to the Mortgage which are intended to eliminate or modify in any manner the
requirements of the sinking and improvement fund as set forth in Section 6.14 of
the Mortgage.
No recourse shall be had for the payment of the principal of or the interest on
this bond, or any part thereof, or for any claim based thereon or otherwise in
respect thereof, to any incorporator, or any past, present or future
stockholder, officer or director of the Company, either directly or indirectly,
by virtue of any statute or by enforcement of any assessment or otherwise, and
any and all liability of the said incorporators, stockholders, officers or
directors of the Company in respect to this bond is hereby expressly waived and
released by every holder hereof.
[FORM OF OPTION TO ELECT REPAYMENT]
OPTION TO ELECT REPAYMENT
The undersigned hereby irrevocably requests and instructs the Company to repay
the within bond (or portion thereof specified below) pursuant to its terms at a
price equal to the principal amount thereof, together with interest to the
repayment date, to the undersigned, at
(Please Print or Typewrite Name, Address and
-----------------------------------------------------------------------------
Tax Identification Number of the Undersigned)
For this bond to be repaid the Company must receive at the office or agency of
the Trustee in the Borough of Manhattan, New York, New York, during the period
from and including August 1, 2001 to and including September 1, 2001 or, if
September 1, 2001 shall be a legal holiday or a day on which banking
institutions in the Borough of Manhattan, New York, New York are authorized by
law to close, the next succeeding day which shall not be a legal holiday or a
day on which such institutions are so authorized to close: (i) this bond with
this "Option to Elect Repayment" form duly completed or (ii) a telegram, telex,
facsimile transmission or letter from a member of a national securities exchange
or the National Association of Securities Dealers, Inc., or a commercial bank or
trust company in the United States of America, setting forth the name of the
holder of the bond, the principal amount of the bond, the amount of the bond to
be repaid, a statement that the option to elect repayment is being exercised
thereby and a guarantee that the bond to be repaid with the form entitled
"Option to Elect Repayment" on the reverse of the bond duly completed, will be
received by the Company not later than five days (which are not legal holidays
or days on which banking institutions in the Borough of Manhattan, New York, New
York are authorized by law to close) after the date of such telegram, telex,
facsimile transmission or letter, and such bond and form duly completed are
received by the Company by such fifth day.
If less than the entire principal amount of the within bond is to be repaid,
specify the portion thereof (which shall be $1,000 or an integral multiple of
$1,000) which the holder elects to have repaid: $ . Specify the
--------
denomination or denominations (which shall be $1,000 or an integral multiple of
$1,000 in excess of $1,000) of the bond or bonds to be issued to the holder for
the amount of the portion of the within bond not being repaid (in the absence of
any such specification, one such bond will be issued for the portion not being
repaid): $ .
--------
Signature
NOTICE: The signature on this Option to Elect Repayment must correspond with
the name as written upon the face of this bond in every particular without
alteration or enlargement or any other change whatsoever.
SCHEDULE B
PROPERTY SUBJECT TO THE LIEN OF THE MORTGAGE IN CONNECTICUT
TOWN OF ANDOVER
ALL of the following described rights, privileges and easements situated in the
Town of Andover, County of Tolland and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(1) Jodi M. Conway June 6, 1994 61 410
(2) James Arthur Gorman et al June 9, 1994 61 412
TOWN OF AVON
ALL of the following described rights, privileges and easements situated in the
Town of Avon, County of Hartford and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(3) The Secret Lake Association October 15, 1992 267 475
TOWN OF BERLIN
ALL of the following described rights, privileges and easements situated in the
Town of Berlin, County of Hartford and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(4) CT Galaxy Properties, Inc. December 8, 1993 354 734
(5) Robert W. Jud et al December 16, 1993 360 649
(6) John P. Lee March 4, 1994 360 652
(7) Stanley Nalewajek et al December 29, 1993 361 890
TOWN OF BRISTOL
ALL of the following described rights, privileges and easements situated in the
Town of Bristol, County of Hartford and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(8) ARMC Real Estate Divestiture February 28, 1994 1123 449
Corporation
TOWN OF CANTON
ALL of the following described rights, privileges and easements situated in the
Town of Canton, County of Hartford and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
-------
(9) Shepherd M. Holcombe July 18, 1994 201 890
TOWN OF COLCHESTER
ALL of the following described rights, privileges and easements situated in the
Town of Colchester, County of New London and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(10) Donald a. Demar July 25, 1994 364 184
TOWN OF COVENTRY
ALL of the following described rights, privileges and easements situated in the
Town of Coventry, County of Tolland and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(11) Pine Knoll Associates March 15, 1994 513 149
(12) S. R. Blanchard, Inc. March 7, 1994 513 153
TOWN OF ELLINGTON
ALL of the following described rights, privileges and easements situated in the
Town of Ellington, County of Tolland and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(13) Jacob's Hill Associates, Inc. June 16, 1994 210 238
TOWN OF FARMINGTON
ALL of the following described rights, privileges and easements situated in the
Town of Farmington, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(14) Inwood Associates, Inc. June 8, 1994 483 485
(15) Daigle & Son, Inc. July 15, 1994 486 54
(16) Town of Farmington July 21, 1994 486 56
TOWN OF HARWINTON
ALL of the following described rights, privileges and easements situated in the
Town of Harwinton, County of Litchfield and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(17) David J. Nadeau March 15, 1994 134 746
TOWN OF MANCHESTER
ALL of the following described rights, privileges and easements situated in the
Town of Manchester, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(18) Ansaldi Associates May 9, 1994 1693 41
(19) Housing Authority of the June 17, 1994 1698 284
Town of Manchester
(20) Warren E. Howland et al December 8, 1983 893 13
(21) Michael A. DeCaprio et al May 15, 1984 899 38
TOWN OF NAUGATUCK
ALL of the following described rights, privileges and easements situated in the
Town of Naugatuck, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(22) A. & J. Property Management, August 26, 1993 380 852
Ltd.
TOWN OF NEWINGTON
ALL of the following described rights, privileges and easements situated in the
Town of Newington, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(23) Estate of Domenico Pane May 4, 1994 978 220
(24) Ramblewood, Incorporated` May 23, 1994 985 115
(25) Ramblewood, Incorporated July 13, 1994 992 70
TOWN OF OLD SAYBROOK
ALL of the following described rights, privileges and easements situated in the
Town of Old Saybrook, County of Middlesex and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(26) Glenn Michael Rice et al February 5, 1994 315 1079
TOWN OF PLAINFIELD
ALL of the following described rights, privileges and easements situated in the
Town of Plainfield, County of Windham and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(27) George Palmisano et al July 12, 1994 223 716
TOWN OF PLAINVILLE
ALL of the following described rights, privileges and easements situated in the
Town of Plainville, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(28) Joseph C. Ciccio et al May 23, 1994 312 179
TOWN OF PUTNAM
ALL of the following described rights, privileges and easements situated in the
Town of Putnam, County of Windham and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(29) Mark A. Bard, Inc. March 4, 1994 259 315
TOWN OF ROCKY HILL
ALL of the following described rights, privileges and easements situated in the
Town of Rocky Hill, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(30) F&S Associates June 9, 1994 280 571
(31) Seby Romano Construction June 9, 1994 280 573
Company, Inc.
(32) 200 Capital Boulevard January 31, 1990 226 868
Limited Partnership et al
TOWN OF SIMSBURY
ALL of the following described rights, privileges and easements situated in the
Town of Simsbury, County of Hartford and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(33) Town of Simsbury April 25, 1994 429 1034
TOWN OF SOMERS
ALL of the following described rights, privileges and easements situated in the
Town of Somers, County of Tolland and State of Connecticut, more particularly
described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(34) Frank Lomangino et al March 21, 1994 159 658
TOWN OF SOUTHINGTON
ALL of the following described rights, privileges and easements situated in the
Town of Southington, County of Hartford and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(35) Milo & Denorfia Construction, May 23, 1994 598 280
Inc.
TOWN OF WATERBURY
ALL of the following described rights, privileges and easements situated in the
Town of Waterbury, County of New Haven and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(36) The Bank of Stamford Service July 21, 1993 2989 292
Corporation
TOWN OF WESTBROOK
ALL of the following described rights, privileges and easements situated in the
Town of Westbrook, County of Middlesex and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
(37) Frank Esposito et al July 21, 1994 165 437
TOWN OF WILLINGTON
ALL of the following described rights, privileges and easements situated in the
Town of Willington, County of Tolland and State of Connecticut, more
particularly described in the following deeds, viz:
RECORDED
GRANTOR DATE OF INSTRUMENT VOLUME PAGE
STOCKHOLDER AGREEMENT, dated as of July 1, 1964 among the stockholders of
CONNECTICUT YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut
corporation, namely:
State of
Stockholder Incorporation
----------- -------------
The Connecticut Light and Power Company Connecticut
New England Power Company Massachusetts
Boston Edison Company Massachusetts
The Hartford Electric Light Company Connecticut
The United Illuminating Company Connecticut
Western Massachusetts Electric Company Massachusetts
Central Maine Power Company Maine
Public Service Company of New Hampshire New Hampshire
Montaup Electric Company Massachusetts
New Bedford Gas and Edison Light Company Massachusetts
Cambridge Electric Light Company Massachusetts
Central Vermont Public Service Corporation Vermont
(collectively the "Stockholders" and individually the "Stockholder").
It is agreed as follows:
1. Relationship Among the Parties
------------------------------
Connecticut Yankee has been organized to provide for the supply of
power to the Stockholders. It has commenced the construction of a nuclear
electric generating unit of the pressurized water type, which is being designed
to have an initial gross capability of approximately 490 megawatts electric, at
a site adjacent to the Connecticut River at Haddam Neck, Connecticut (the unit
being herein, together with the site and all related facilities, referred to as
the "Unit"). Construction of the Unit is being carried out under contract with
Westinghouse Electric Corporation and Stone & Webster Engineering Corporation.
By separate power contracts (the "Power Contracts") and capital funds
agreements (the "Capital Funds Agreements") Connecticut Yankee is agreeing to
sell the entire output of the Unit to the Stockholders and the Stockholders are
agreeing to purchase the output and to provide Connecticut Yankee with necessary
capital funds. The respective percentages of the capacity and output of the
Unit to be purchased by the Stockholders will be the same as their respective
percentages of stock ownership. The Stockholders' respective stock and
entitlement percentages as of the date of this Agreement are as follows:
Stock
Stockholder Percentage
----------
The Connecticut Light and Power Company 25.0%
New England Power Company 15.0%
Boston Edison Company 9.5%
The Hartford Electric Light Company 9.5%
The United Illuminating Company 9.5%
Western Massachusetts Electric Company 9.5%
Central Maine Power Company 6.0%
Public Service Company of New Hampshire 5.0%
Montaup Electric Company 4.5%
New Bedford Gas and Edison Light Company 2.5%
Cambridge Electric Light Company 2.0%
Central Vermont Public Service Corporation 2.0%
New Bedford Gas and Edison Light Company proposes to transfer the Connecticut
Yankee stock owned by it to Cambridge Electric Light Company. If this transfer
is consummated, the Power Contract and Capital Funds Agreement between
Connecticut Yankee and New Bedford Gas and Edison Light Company will be
cancelled, and the Power Contract and Capital Funds Agreement between
Connecticut Yankee and Cambridge Electric Light Company will be amended to
increase Cambridge Electric Light Company's entitlement and stock percentages
from 2.0% to 4.5%. Upon such cancellation of its Power Contract and Capital
Funds Agreement New Bedford Gas and Edison Light Company shall cease to have any
rights or obligations under this Agreement.
2. Unanimous Consent to Certain Matters
------------------------------------
The Stockholders will not cause or permit Connecticut Yankee to take
any of the following actions unless the holders at the time of all of
Connecticut Yankee's outstanding common stock consent thereto, by vote or
otherwise:
(a) the amendment in any material respect of any of the Power
Contracts or Capital Funds Agreements;
(b) the construction by Connecticut Yankee of an additional
generating unit at the Haddam Neck site or elsewhere; and
(c) participation by Connecticut Yankee, to a material extent,
in any business other than the generation and sale of
electric power.
However, the amendment of particular Power Contracts and Capital Funds
Agreements to effect changes in entitlement and stock percentages shall not
constitute such a material amendment, if, after the amendment, the sum of the
entitlement percentages of all Stockholders under all Power Contracts then in
force, and the sum of the stock percentages of all Stockholders under all
Capital Funds Agreements then in force, continues to be 100%.
3. Consent to Construction of Additional Units by Others
-----------------------------------------------------
The Stockholders will not cause or permit Connecticut Yankee to make
any arrangement with respect to the construction and/or operation by one or more
persons other than Connecticut Yankee of additional generating unit(s) at the
Haddam Neck site unless the holders at the time of at least 66 2/3% of
Connecticut Yankee's outstanding common stock consent thereto by vote. However,
if the holders at the time of at least 66 2/3% of Connecticut Yankee's
outstanding common stock vote to consent to such a proposed arrangement at a
meeting of Stockholders duly held on at least 30 days' notice which shall
specify in reasonable detail the proposed arrangement to be voted on,
Connecticut Yankee may give effect to such arrangement by selling, leasing or
otherwise transferring a portion of the site and of the facilities included in
the Unit to one or more other persons proposing to construct additional
generating unit(s) at the site, and by contracting with such person or persons
with respect to operating and other matters.
Any Stockholder who votes against such a proposed arrangement (a
"dissenting Stockholder") shall have the right to require the Stockholders who
do not vote against the arrangement (the "assenting Stockholders") to purchase
the dissenting Stockholder's shares of Connecticut Yankee stock, if the
dissenting Stockholder elects to require such purchase by written notice given
to the other Stockholders before the meeting at which the vote in question is
taken. The dissenting Stockholder shall designate in such notice the date on
which such purchase will be effected, which date shall be not less than 90 days
nor more than three years after the date on which the vote is taken.
In the case of any such purchase of a dissenting Stockholder's shares,
the assenting Stockholders shall be obligated to purchase the dissenting
Stockholder's shares pro rata, according to their respective holdings of
Connecticut Yankee's outstanding stock. However, the assenting Stockholders
shall have the right to direct the dissenting Stockholder to transfer its shares
and power entitlement to such of them and in such proportions as they may
designate.
The purchase price to be paid to a dissenting Stockholder for its
shares pursuant to this Section shall be the book value thereof as of the date
on which the vote in question is taken, as determined in accordance with the
formula specified in Section 2 of Article VIII of Connecticut Yankee's By-Laws,
as in effect on the date of this Agreement, plus interest thereon at the rate of
----
6% per annum, from such date to the date of purchase, minus the amount of any
-----
dividends or other distributions paid or payable with respect to such shares to
stockholders of record on any date subsequent to the date of the vote and prior
to the purchase date.
The rights and obligations of the dissenting Stockholder and the
assenting Stockholders with respect to a purchase of stock under this Section 3
shall be subject to the condition that all necessary regulatory approvals shall
have been obtained with respect to the action to be taken by the seller and the
action to be taken by the purchaser(s). The parties will use their best efforts
to obtain, or to assist in obtaining, the foregoing regulatory approvals. If
such regulatory approvals cannot be obtained prior to the specified purchase
date, the dissenting Stockholder may postpone the closing by not more than 90
days by written notice to the assenting Stockholders.
On the purchase date the dissenting Stockholder shall deliver the
certificates representing its share of Connecticut Yankee stock to the
designated purchaser(s) against payment of the purchase price by certified or
official bank check in New York, Hartford or Boston Clearing House funds. Such
certificates shall be duly assigned or accompanied by appropriate instruments of
transfer, and the shares transferred shall be free and clear of all liens and
encumbrances. All transfer and other similar taxes with respect to the
transaction shall be paid by the seller.
At the time of the closing the dissenting Stockholder shall assign to
the purchaser(s), in such proportions as they may direct, all of the dissenting
Stockholder's rights under its Power Contract and Capital Funds Agreement, free
and clear of all liens and encumbrances, and the purchaser(s) shall assume, in
the same proportions, all of the dissenting Stockholder's obligations under such
agreements. Thereafter the dissenting Stockholder will be released, except as
hereinafter provided, from all further obligations, and shall have no further
rights, under such agreements and this Agreement. If at the time of the closing
Connecticut Yankee has in effect a pledge and assignment for security purposes
of its Power Contract and Capital Funds Agreement with the dissenting
Stockholder, and the pledgee's consent is required for a complete release of the
dissenting Stockholder from further obligations under any of such agreements,
the parties will use their best efforts to obtain such consent. If such consent
cannot be obtained prior to the purchase date, the dissenting Stockholder may
elect not to go forward with the sale of its stock.
4. Power Entitlement Upon Failure to Provide Additional Capital
------------------------------------------------------------
If, as the result of any Stockholder's failure to provide capital to
Connecticut Yankee as requested by Connecticut Yankee pursuant to Sections 4, 5,
or 6 of such Stockholder's Capital Funds Agreement, such Stockholder's
entitlement percentage under its Power Contract is in excess of its "capital
percentage" (as hereinafter defined), then, in such event and so long as such
condition continues, such Stockholder shall, if requested to do so by
Stockholders whose respective entitlement percentages are less than their
respective capital percentages, enter into appropriate arrangements to sell to
such Stockholders at its cost some or all, as such Stockholders may from time to
time determine, of its "excess power" (as hereinafter defined).
For the purposes of this Section, (i) a Stockholder's "capital
percentage" as of any time shall be the percentage which that portion of
Connecticut Yankee's then outstanding capital theretofore provided by such
Stockholder bears to the aggregate amount of Connecticut Yankee's then
outstanding capital theretofore provided by all of the Stockholders, and (ii) a
Stockholder's "excess power" as of any time shall be that amount of Connecticut
Yankee's capacity and net electric output determined by subtracting such
Stockholder's then capital percentage of such capacity and output from such
Stockholder's entitlement percentage of such capacity and output.
5. Cancellation of Power Contracts
-------------------------------
If at any time:
(a) Stockholders owning more than 50% of Connecticut Yankee's
outstanding common stock have cancelled their Power
Contracts, pursuant to Section 9 thereof, because either (i)
the Unit is damaged to the extent of being completely or
substantially completely destroyed, or (ii) the Unit is
taken by exercise of the right of eminent domain or a
similar right or power, and
---
(b) Connecticut Yankee has paid in full, or made adequate
provision for the payment in full of, all its outstanding
bonds and notes and other indebtedness and liabilities,
other than its indebtedness to Stockholders for loans and
advances made pursuant to Section 6 of the Capital Funds
Agreements,
then, and in such case, upon the request of any Stockholder who has theretofore
so cancelled its Power Contract, the Stockholders whose Power Contracts are
still in effect will forthwith cancel their respective Power Contracts pursuant
to Section 9 thereof.
6. Arbitration
-----------
In case any dispute shall arise as to the interpretation or
performance of this Agreement which cannot be settled by mutual agreement, such
dispute shall be submitted to arbitration. The parties shall if possible agree
upon a single arbitrator. In case of failure to agree upon an arbitrator within
15 days after the delivery by any party to the others of a written notice
requesting arbitration, any party may request the American Arbitration
Association to appoint the arbitrator. The arbitrator, after opportunity for
each of the parties to be heard, shall consider and decide the dispute and
notify the parties in writing of his decision. Such decision shall be binding
upon the parties, and the expenses of the arbitration shall be borne equally by
them.
7. Interpretation
--------------
The interpretation and performance of this Agreement shall be in
accordance with and controlled by the law of the State of Connecticut.
8. Addresses
---------
Except as the parties may otherwise agree, any notice, request or
other communication from a party to any other party, relating to this Agreement,
or the rights, obligations or performance of the parties hereunder, shall be in
writing and shall be effective upon delivery to the other party. Any such
communication shall be considered as duly delivered when mailed to the
respective post office address of the other party shown following the signature
of such other party hereto, or such other post office address as may be
designated by written notice given as provided in this Section 8.
9. Successors and Assigns
----------------------
This Agreement shall be binding upon and shall inure to the benefit of
and may be performed by the corporate successors of the parties. No assignment
of this Agreement, other than to a corporate successor to all or substantially
all the electric business and property of a party, shall operate to relieve the
assignor of its obligations under this Agreement without the written consent of
the remaining parties hereto.
10. Execution in Counterparts
-------------------------
This Agreement may be executed in any number of counterparts, each of
which shall be an original but all of which together shall constitute one and
the same instrument. This Agreement shall become effective at such time as
counterparts thereof have been executed by each of the parties and it shall not
be a condition to its effectiveness that each of the parties have executed the
same counterpart.
IN WITNESS WHEREOF, the undersigned parties have executed this
Stockholder Agreement dated as of July 1, 1964 by their respective officers
thereunto duly authorized.
(Stockholder Agreement)
-----------------------
THE CONNECTICUT LIGHT AND POWER COMPANY
P.O. BOX 2010
Hartford, Connecticut 06101
By /s/ S. R. Knapp
--------------------
Chairman
(Stockholder Agreement)
-----------------------
NEW ENGLAND POWER COMPANY
441 Stuart Street
Boston, Massachusetts 02116
By /s/ Robert F. Kramer
------------------------
President
(Stockholder Agreement)
-----------------------
BOSTON EDISON COMPANY
182 Tremont Street
Boston, Massachusetts 02112
By /s/ Charles F. Avila
-----------------------
President
(Stockholder Agreement)
-----------------------
THE HARTFORD ELECTRIC LIGHT COMPANY
P.O. BOX 2370
Hartford, Connecticut 06101
By /s/ R. A. Gibson
------------------
Chairman
(Stockholder Agreement)
-----------------------
THE UNITED ILLUMINATING COMPANY
80 Temple Street
New Haven, Connecticut 06506
By /s/ William J. Cooper
---------------------------
President
(Stockholder Agreement)
-----------------------
WESTERN MASSACHUSETTS ELECTRIC COMPANY
174 Brush Hill Avenue
West Springfield, Massachusetts 01089
By /s/ Howard J. Cadwell
------------------------
Chairman of the Board
(Stockholder Agreement)
-----------------------
CENTRAL MAINE POWER COMPANY
9 Green Street
Augusta, Maine 04332
By /s/ W. H. Dunham
----------------------
President
(Stockholder Agreement)
-----------------------
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
1087 Elm Street
Manchester, New Hampshire 03105
By /s/ D. Miller
-------------------------------
President
(Stockholder Agreement)
-----------------------
MONTAUP ELECTRIC COMPANY
49 Federal Street
Boston, Massachusetts 02107
By /s/ Bill M. Perry
-----------------------
President
(Stockholder Agreement)
-----------------------
NEW BEDFORD GAS AND EDISON LIGHT COMPANY
130 Austin Street
Cambridge, Massachusetts 02139
By /s/ John F. Rich
---------------------------
President
CAMBRIDGE ELECTRIC LIGHT COMPANY
130 Austin Street
Cambridge, Massachusetts 02139
By /s/ John F. Rich
---------------------------
President
(Stockholder Agreement)
-----------------------
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
77 Grove Street
Rutland, Vermont 05701
[COMPOSITE CONFORMED COPY]
POWER CONTRACT, dated as of July 1, 1964, between CONNECTICUT YANKEE
ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation, and (The
names of the Purchasers appear in the attached Appendix) (the "Purchaser").
It is agreed as follows:
1. Basic Understandings
Connecticut Yankee has been organized to provide for the supply of power
to the twelve utility companies (including the Purchaser) which are its
stockholders. It has commenced the construction of a nuclear electric generating
unit of the pressurized water type, which is being designed to have an initial
gross capability of approximately 490 megawatts electric, at a site adjacent to
the Connecticut River at Haddam Neck, Connecticut (the unit being herein,
together with the site and all related facilities, referred to as the "Unit").
Construction of the Unit is being carried out under contracts with Westinghouse
Electric Corporation and Stone & Webster Engineering Corporation.
The Unit is to be operated to supply power to Connecticut Yankee's
stockholders, each of which is undertaking to purchase a fixed percentage of the
capacity and output of the Unit. The respective percentages of the capacity and
output of the Unit to be purchased by the Purchaser and the other Connecticut
Yankee stockholders are the same as the respective percentages of Connecticut
Yankee's stock now owned by them. The names of the stockholders and their
respective percentages ("entitlement percentages") of the capacity and output of
the Unit are as follows:
Stockholder Entitlement Percentage
The Connecticut Light and Power Company 25.0%
New England Power Company 15.0%
Boston Edison Company 9.5%
The Hartford Electric Light Company 9.5%
The United Illuminating Company 9.5%
Western Massachusetts Electric Company 9.5%
Central Maine Power Company 6.0%
Public Service Company of New Hampshire 5.0%
Montaup Electric Company 4.5%
New Bedford Gas and Edison Light Company* 2.5%
Cambridge Electric Light Company* 2.0%
Central Vermont Public Service Corporation 2.0%
Connecticut Yankee and its other stockholders are entering into power contracts
which are identical to this contract except for necessary changes in the names
of the parties. New Bedford Gas and Edison Light Company has informed
Connecticut Yankee that it proposes to transfer the Connecticut Yankee stock
owned by it to Cambridge Electric Light Company. If this transfer is
consummated, the Power Contract between Connecticut Yankee and New Bedford Gas
and Edison Light Company will be cancelled and the contract between Connecticut
Yankee and Cambridge Electric Light Company will be amended to increase
Cambridge Electric Light Company's entitlement percentage from 2.0% to 4.5%.*
* As contemplated by Section 1 of the contract, New Bedford Gas and Edison
Light Company has transferred the Connecticut Yankee stock owned by it to
Cambridge Electric Light Company, the Power Contract between Connecticut Yankee
and New Bedford Gas and Edison Light Company has been cancelled, and the
contract between Connecticut Yankee and Cambridge Electric Light Company has
been amended to increase Cambridge Electric Light Company's entitlement
percentage from 2.0% to 4.5%. As a result of the transfer by New Bedford Gas and
Edison Light Company of the Connecticut Yankee stock owned by it to Cambridge
Electric Light Company, the number of Connecticut Yankee's stockholders has been
reduced from twelve to eleven.
2. Effective Date and Term
This contract shall become effective upon receipt by the Purchaser of
notice that Connecticut Yankee has entered into power contracts, as contemplated
by Section 1 above, with each of its other stockholders. The term of this
contract shall expire 30 years after the plant completion date.
The "plant completion date" shall be the earlier of (i) October 1, 1968,
and (ii) the date on which the Unit is placed in commercial operation, as
determined by Connecticut Yankee (the "commercial operation date").
3. Construction of the Unit
Connecticut Yankee will proceed with due diligence with construction of
the Unit, and will exercise its best efforts to complete and place it in
commercial operation by October 1, 1967, on the presently estimated schedule
therefor and within present cost estimates, and will keep the Purchaser
currently informed as to the progress of construction and expected plant
completion date.
4. Operation and Maintenance of the Unit
Connecticut Yankee will operate and maintain the Unit in accordance with
good utility practice under the circumstances and all applicable law, including
the applicable provisions of the Atomic Energy Act of 1954 and of any license
issued thereunder to Connecticut Yankee. Within the limits imposed by good
utility practice under the circumstances and applicable law, the Unit will be
operated at its maximum capability and on a long hour use basis.
Outages for inspection, maintenance, refueling and repairs and
replacements will be scheduled in accordance with good utility practice and
insofar as practicable shall be mutually agreed upon by Connecticut Yankee and
the Purchaser. In the event of an outage, Connecticut Yankee will use its best
efforts to restore the Unit to service as promptly as possible.
5. Purchaser's Entitlement
The Purchaser will, throughout the term of this contract, be entitled and
obligated to take its entitlement percentage of the capacity and net electrical
output of the Unit, at all levels at which the Unit is operated or operable,
whether more or less than 490 megawatts electric.
6. Deliveries and Metering
The Purchaser's entitlement percentage of the output of the Unit will be
delivered to and accepted by it at the step-up substation at the site. All
deliveries will be made in the form of 3-phase, 60 cycle, alternating current at
a nominal voltage of 345,000 volts. The Purchaser will make its own arrangements
for the transmission of the power.
Connecticut Yankee will supply and maintain all necessary metering
equipment for determining the quantity and conditions of supply of deliveries
under this contract, will make appropriate tests of such equipment in accordance
with good utility practice and as reasonably requested by the Purchaser, and
will maintain the accuracy of such equipment within reasonable limits.
Connecticut Yankee will furnish the Purchaser with such summaries of meter
readings as the Purchaser may reasonably request.
7. Payment
With respect to each month commencing prior to the plant completion date,
the Purchaser will pay Connecticut Yankee at the rate of 5 mills per kilowatt
hour, for the Purchaser's entitlement percentage of the net electrical output
(if any) of the Unit during the particular month.
With respect to each month commencing on or after the plant completion
date, the Purchaser will pay Connecticut Yankee an amount equal to the
Purchaser's entitlement percentage of the sum of (a) Connecticut Yankee's total
operating expenses for the month with respect to the Unit, plus (b) an amount
equal to one-twelfth of 6% per annum of the net Unit investment as most recently
determined in accordance with this Section 7.
Connecticut Yankee's "operating expenses" shall include all amounts
properly chargeable to operating expense accounts, less any applicable credits
thereto, in accordance with the Uniform System of Accounts (the "Uniform
System") prescribed by the Federal Power Commission for Class A and Class B
Public Utilities and Licensees as in effect on the date of this contract;
provided, that, for purposes of this contract, the accrual of depreciation as an
operating expense shall commence on the plant completion date at the rate of 4%
per annum, whether or not the Unit is then in operation, and during each of the
first twenty-five years after the plant completion date the amount included in
operating expenses on account of depreciation accruals (and amortization, if
any, of property losses) shall in no event be less than 4% of the excess of:
(a) the amount properly chargeable at the plant completion date in
accordance with the Uniform System to electric plant accounts (including
construction work in progress) with respect to the depreciable portion of the
Unit (or, if the plant completion date is prior to the commercial operation date
and the amount so chargeable with respect to the depreciable portion of the Unit
on the commercial operation date is greater than it was on the plant completion
date, then such greater amount), over
(b) the amount of net available cash.
The "net Unit investment" shall consist, in each case with respect to the
Unit, of (i) the aggregate amount properly chargeable at the time in accordance
with the Uniform System to Connecticut Yankee's electric plant accounts
(including construction work in progress), less the balance, if any, at the time
of the accumulated provision for depreciation, as determined in accordance with
the Uniform System; plus (ii) the aggregate amount properly chargeable at the
time in accordance with the Uniform System to accounts representing materials
and supplies; plus (iii) such reasonable allowances for prepaid items and cash
working capital as may from time to time be determined by Connecticut Yankee.
However, for purposes of this contract, the net amount included at any date
after the plant completion date in net Unit investment under clause (i) of the
immediately preceding sentence shall in no event be less than the excess of:
(a) the amount properly chargeable at the plant completion date in
accordance with the Uniform System to electric plant accounts (including
construction work in progress) with respect to the Unit (or, if the plant
completion date is prior to the commercial operation date and the amount so
chargeable with respect to the Unit on the commercial operation date is greater
than it was on the plant completion date, then such greater amount),
over
(b) the sum of (1) the aggregate minimum amount required by the proviso to
the third paragraph of this Section 7 to be included in operating expenses from
the plant completion date to the date in question on account of depreciation
accruals (and amortization, if any, of property losses), plus (2) the amount of
net available cash.
The net Unit investment shall be determined as of the plant completion date and
thereafter as of the commencement of each calendar year, or, if Connecticut
Yankee elects, at more frequent intervals.
"Net available cash" means, at any date as of which the amount thereof is
to be determined, the excess of (a) the aggregate amount received by Connecticut
Yankee after the plant completion date and prior to two years before the
determination date as insurance proceeds on account of loss or damage to the
Unit or as the proceeds of a sale or condemnation of a portion of the Unit, over
(b) the aggregate amount expended after the plant completion date and prior to
the determination date on account of rebuilding, repairs, replacements and
additions to the Unit, provided that insurance proceeds received with respect to
a particular loss shall be taken into account for purposes of the foregoing
computation only if the amount received with respect to the loss exceeds
$150,000.
Connecticut Yankee will bill the Purchaser, as soon as practicable after
the end of each month, for all amounts payable by the Purchaser with respect to
the particular month. Such bills will be rendered in such detail as the
Purchaser may reasonably request and may be rendered on an estimated basis
subject to corrective adjustments in subsequent billing periods. All bills shall
be paid in full within 10 days after receipt thereof by the Purchaser.
8. Make-up Term and Option Term
(a) The Purchaser may elect to extend the contract term by written notice
to Connecticut Yankee upon the following conditions and for the following period
or periods:
(i) in the event that the Unit is not in commercial operation on the plant
completion date, the contract term may be extended for a period equal to the
number of consecutive days by which commercial operation is delayed beyond the
plant completion date; and
(ii) if at any time after the commencement of commercial operation no
deliveries are made under this contract for a period of at least 120 consecutive
days, the contract may be extended for a period equal to the aggregate of such
periods during which no deliveries were made.
If the term of the contract is extended pursuant to the provisions of this
subsection (a), all of the contract provisions shall remain in effect for the
extended term.
(b) Upon expiration of the initial term of this contract or upon
expiration of the term as extended in accordance with subsection (a) of this
Section 8, the Purchaser shall continue to be entitled, at its option, to its
entitlement percentage of the capacity and output of the Unit upon terms at
least as favorable as those obtained by any other person.
9. Cancellation of Contract
If deliveries cannot be made to the Purchaser because either
(i) the Unit is damaged to the extent of being completely or substantially
completely destroyed, or
(ii) the Unit is taken by exercise of the right of eminent domain or a
similar right or power, or
(iii) (a) the Unit cannot be used because of contamination, or because a
necessary license or other necessary public authorization cannot be obtained or
is revoked, or because the utilization of such a license or authorization is
made subject to specified conditions which are not met, and (b) the situation
cannot be rectified to an extent which will permit Connecticut Yankee to make
deliveries to the Purchaser from the Unit;
then and in any such case, the Purchaser may cancel this contract. Such
cancellation shall be effected by written notice given by the Purchaser to
Connecticut Yankee. In the event of such cancellation, all continuing
obligations of the parties, including the Purchaser's obligations to continue
payments, shall cease forthwith. Any dispute as to the Purchaser's right to
cancel this contract pursuant to the foregoing provisions shall be referred to
arbitration in accordance with the provisions of Section 13.
Notwithstanding anything in this contract elsewhere contained, the
Purchaser may cancel this contract or be relieved of its obligations to make
payments hereunder only as provided in the next preceding paragraph of this
Section 9. Further, if for reasons beyond Connecticut Yankee's reasonable
control, deliveries are not made as contemplated by this contract, Connecticut
Yankee shall have no liability to the Purchaser on account of such non-delivery.
10. Insurance
Prior to the first shipment of fuel to the plant site, Connecticut Yankee
will obtain, and thereafter will at all times maintain, insurance to cover its
"public liability" for personal injury and property damage resulting from a
"nuclear incident" (as those terms are defined in the Atomic Energy Act of 1954,
as amended), with limits not less than Connecticut Yankee may be required to
maintain to qualify for governmental indemnity under said Act and shall execute
and maintain an indemnification agreement with the Atomic Energy Commission as
provided by said Act. Connecticut Yankee will also at all times maintain such
other types of liability insurance, including workmen's compensation insurance,
in such amounts, as is customary in the case of other similar electric utility
companies, or as may be required by law.
Connecticut Yankee will at all times keep insured such portions of the
Unit as are of a character usually insured by electric utility companies,
similarly situated and operating like properties, against the risk of a "nuclear
incident", and such other risks as electric utility companies, similarly
situated and operating like properties, usually insure against. Such insurance
shall to the extent available be carried in an amount at least equal to the
original cost of the insured facilities, less accrued depreciation thereon.
11. Additional Units
Connecticut Yankee or its nominee may install one or more additional
generating units at the Haddam Neck site. The installation of such unit or units
shall not affect the terms of this contract, but in such case, if and to the
extent appropriate, if any portion of the Unit (whether such portion constitutes
land, structures or equipment) is also used with the additional unit(s), an
appropriate allocation of the cost of the Unit shall be made and the net Unit
investment shall be reduced accordingly, subject, however, to the limitation
that the aggregate amount of the reduction in net Unit investment resulting from
all such allocations shall not exceed $2,000,000.
12. Audit
Connecticut Yankee's books and records (including metering records) shall
be open to reasonable inspection and audit by the Purchaser.
13. Arbitration
In case any dispute shall arise as to the interpretation or performance of
this contract which cannot be settled by mutual agreement, such dispute shall be
submitted to arbitration. The parties shall if possible agree upon a single
arbitrator. In case of failure to agree upon an arbitrator within 15 days after
the delivery by either party to the other of a written notice requesting
arbitration, either party may request the American Arbitration Association to
appoint the arbitrator. The arbitrator, after opportunity for each of the
parties to be heard, shall consider and decide the dispute and notify the
parties in writing of his decision. Such decision shall be binding upon the
parties, and the expenses of the arbitration shall be borne equally by them.
14. Regulation
This contract, and all rights, obligations and performance of the parties
hereunder, are subject to all applicable state and federal law and to all duly
promulgated orders and other duly authorized action of governmental authority
having jurisdiction in the premises.
15. Assignment
This contract shall be binding upon and shall inure to the benefit of, and
may be performed by, the successors and assigns of the parties, except that no
assignment, pledge or other transfer of this contract by either party shall
operate to release the assignor, pledgor or transferor of any of its obligations
under this contract unless consent to the release is given in writing by the
other party, or, if the other party has theretofore assigned, pledged or
otherwise transferred its interest in this contract, by the other party's
assignee, pledgee or transferee.
16. Right of Setoff
The Purchaser shall not be entitled to set off against the payments
required to be made by it under this contract (i) any amounts owed to it by
Connecticut Yankee or (ii) the amount of any claim by it against Connecticut
Yankee. However, the foregoing shall not affect in any other way the Purchaser's
rights and remedies with respect to any such amounts owed to it by Connecticut
Yankee or any such claim by it against Connecticut Yankee.
17. Interpretation
The interpretation and performance of this contract shall be in accordance
with and controlled by the law of the State of Connecticut.
18. Addresses
Except as the parties may otherwise agree, any notice, request, bill or
other communication from one party to the other, relating to this contract, or
the rights, obligations or performance of the parties hereunder, shall be in
writing and shall be effective upon delivery to the other party. Any such com-
munication shall be considered as duly delivered when mailed to the respective
post office address of the other party shown following the signatures of such
other party hereto, or such other post office address as may be designated by
written notice given as provided in this Section 18.
19. Corporate Obligations
This contract is the corporate act and obligation of the parties hereto,
and any claim hereunder against any stockholder, director or officer of either
party, as such, is expressly waived.
20. All Prior Agreements Superseded
This contract represents the entire agreement between us relating to the
subject matter hereof, and all previous agreements, discussions, communications
and correspondence with respect to the subject matter are hereby superseded and
are of no further force and effect.
IN WITNESS WHEREOF, the parties have executed this contract by their
respective officers thereunto duly authorized as of the date first above
written.
CONNECTICUT YANKEE ATOMIC POWER COMPANY
Attest:
By
---------------------------------
Its
--------------------------- -----------------------------
P.O. Box 2010
Hartford, Connecticut 06101
(Purchaser)
Attest:
By
----------------------------------
(Officer)
---------------------------
Its
-----------------------------
(Title)
(Address)
(Forms of signatures appear in the attached Appendix)
APPENDIX
Separate Power Contracts were entered into, identical in form with the foregoing
except as to the execution thereof and except that on page 1 the names of the
respective Purchasers were inserted.
The Power Contracts were executed by the respective parties thereto, under their
Corporate seals, as follows:
Attest: CONNECTICUT YANKEE ATOMIC POWER COMPANY
R. F. PROBST By S. R. KNAPP
Secretary Its President
P.O. Box 2010
(CORPORATE SEAL) Hartford, Connecticut 06101
Attest: THE CONNECTICUT LIGHT AND POWER COMPANY
C. J. RAMAGE By PAUL V. HAYDEN
Assistant Secretary Its President
P.O. Box 2010
(CORPORATE SEAL) Hartford, Connecticut 06101
Attest: NEW ENGLAND POWER COMPANY
JOSEPH X. CORBETT By ROBERT F. KRAUSE
Clerk Its President
441 Stuart Street
(CORPORATE SEAL) Boston, Massachusetts 02116
Attest: BOSTON EDISON COMPANY
EDWIN J. LEE By CHARLES F. AVILA
Clerk Its President
182 Tremont Street
(CORPORATE SEAL) Boston, Massachusetts 02112
Attest: THE HARTFORD ELECTRIC LIGHT COMPANY
J. B. MADIGAN By R. A. GIBSON
Secretary Its Chairman
P.O. Box 2370
(CORPORATE SEAL) Hartford, Connecticut 06101
Attest: THE UNITED ILLUMINATING COMPANY
A. ROYAL WOOD By WILLIAM J. COOPER
Secretary Its President
80 Temple Street
(CORPORATE SEAL) New Haven, Connecticut 06506
Attest: WESTERN MASSACHUSETTS ELECTRIC COMPANY
N. F. PLANTE By HOWARD J. CADWELL
Clerk Its Chairman of the Board
174 Brush Hill Avenue
(CORPORATE SEAL) W. Springfield, Massachusetts 01089
Attest: CENTRAL MAINE POWER COMPANY
C. W. TOTMAN By W. H. DUNHAM
Assistant Secretary Its President
9 Green Street
(CORPORATE SEAL) Augusta, Maine 04332
Attest: PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
ANNABELLE LANDERS By A. R. SCHILLER
Secretary Its President
1087 Elm Street
(CORPORATE SEAL) Manchester, New Hampshire 03105
Attest: MONTAUP ELECTRIC COMPANY
R. M. KEITH By GUIDO R. PERERA
Clerk Its President
49 Federal Street
(CORPORATE SEAL) Boston, Massachusetts 02107
Attest: NEW BEDFORD GAS AND EDISON LIGHT COMPANY*
R. E. ROLLS By JOHN F. RICH
Clerk Its President
130 Austin Street
(CORPORATE SEAL) Cambridge, Massachusetts 02139
* The contract between Connecticut Yankee and New Bedford Gas and Edison Light
Company has been cancelled.
Attest: CAMBRIDGE ELECTRIC LIGHT COMPANY
R. E. ROLLS By JOHN F. RICH
Clerk Its President
130 Austin Street
(CORPORATE SEAL) Cambridge, Massachusetts 02139
Attest: CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PORTER E. NOBLE By ALBERT A. CREE
Clerk Its Chairman
ADDITIONAL POWER CONTRACT
ADDITIONAL POWER CONTRACT, dated as of April 30, 1984, between CONNECTICUT
YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation,
and The Connecticut Light and Power Company, (the "Purchaser").
In consideration of the following understandings and the respective
undertakings of the parties, it is agreed as follows:
1. Basic Understandings.
Connecticut Yankee was organized in 1962 to provide for the supply of
power to its sponsoring utility companies (including the Purchaser). Connecticut
Yankee constructed a nuclear electric generating unit of the pressurized water
type, having a maximum net capability of approximately 582 megawatts electric,
at a site adjacent to the Connecticut River at Haddam, Connecticut (said unit,
together with the site and all related facilities owned or to be owned by
Connecticut Yankee, being referred to herein as the "Unit"). On June 30, 1967,
Connecticut Yankee was issued a full-term, operating license for the Unit from
the Atomic Energy Commission (now the Nuclear Regulatory Commission which,
together with any successor agency or agencies, is hereafter called the "NRC"),
which license expires on May 26, 2004, and the Unit commenced commercial
operation on January 1, 1968.
The Unit is operated to supply power to the purchasers from Connecticut
Yankee (collectively the "Purchasers"), each of which by a Power Contract dated
as of July 1, 1964, as supplemented by Supplementary Power Contracts dated as of
March 1, 1978, such Supplementary Power Contracts amended on August 22, 1980 and
October 15, 1982 (collectively the "Power Contracts"), has undertaken to
purchase a fixed percentage of the capacity and output of the Unit for a term
extending through December 31, 1997. The names of the Purchasers and their
respective percentages ("entitlement percentages") of the capacity and output of
the Unit are as follows:
Entitlement
Percentage
The Connecticut Light and Power Company 34.5%
New England Power Company 15.0
Western Massachusetts Electric Company 9.5
The United Illuminating Company 9.5
Boston Edison Company 9.5
Central Maine Power Company 6.0
Public Service Company of New Hampshire 5.0
Montaup Electric Company 4.5
Cambridge Electric Light Company 4.5
Central Vermont Public Service Corporation 2.0
The Power Contracts have been supplemented most recently by Second
Supplementary Power Contracts, dated as of 1984, between Connecticut Yankee and
each of the Purchasers (the "Second Supplementary Power Contracts"). The Second
Supplementary Power Contracts provide for the collection of funds to defray the
ultimate cost of decommissioning the Unit and to provide an allowance for
potential taxes payable by Connecticut Yankee with respect to the
decommissioning fund.
Connecticut Yankee and the Purchasers desire to provide for the orderly
continuation of the sale and purchase of the capacity and output of the Unit
during the useful life of the Unit to the extent that such useful life continues
beyond the termination date of the Power Contracts and the Second Supplementary
Power Contracts and to provide appropriate provisions for the collection of
funds for, and the payment of, decommissioning costs and any other costs,
including potential taxes, with respect to the Unit during and after the useful
life of the Unit. Connecticut Yankee and the other Purchasers are entering into
Additional Power Contracts which are identical to this contract except for
necessary changes in the names of the parties.
2. Effective Date, Term and Waiver.
This contract shall become effective upon receipt by the Purchaser of
notice that Connecticut Yankee has entered into Additional Power Contracts, as
contemplated by Section 1 above, with each of the other Purchasers. The
operative term of this contract shall commence on January 1, 1998
notwithstanding the fact that the useful service life of the Unit may have been
terminated prior to that date, and shall terminate upon the later to occur of
(i) 30 days after the date on which the last of the financial obligations of
Connecticut Yankee which constitute elements of the payment calculated pursuant
to Section 7 of this contract has been extinguished by Connecticut Yankee, or
(ii) 30 days after the date on which Connecticut Yankee is finally relieved of
any obligations under the last of any licenses (operating and/or possessory)
which it now holds from, or which may hereafter be issued to it by, the NRC with
respect to the Unit under applicable provisions of the Atomic Energy Act of
1954, as amended from time to time (the "Act").
Connecticut Yankee and the Purchaser acknowledge that, if the useful
service life of the Unit is terminated prior to January 1, 1998, then only the
provisions of this contract applicable to decommissioning of the Unit will apply
during the operative term of this contract.
The Purchaser hereby irrevocably waives its right to extend the contract
term of its Power Contract pursuant to subsections (a) or (b) of Section 8
thereof.
3. Operation and Maintenance of the Unit.
Connecticut Yankee will operate and maintain the Unit in accordance with
good utility practice under the circumstances and all applicable law, including
the applicable provisions of the Act and of any licenses issued thereunder to
Connecticut Yankee. Within the limits imposed by good utility practice under
the circumstances and applicable law, the Unit will be operated at its maximum
capability and on a long hour use basis.
Outages for inspection, maintenance, refueling and repairs and
replacements will be scheduled in accordance with good utility practice and
insofar as practicable shall be mutually agreed upon by Connecticut Yankee and
the Purchaser. In the event of an outage, Connecticut Yankee will use its best
efforts to restore the Unit to service as promptly as practicable.
4. Decommissioning.
After commercial operation of the Unit permanently ceases, Connecticut
Yankee will decommission the Unit in a manner authorized by Connecticut Yankee's
board of directors and approved by the NRC in accordance with the Act and the
rules and regulations thereunder then in effect and by any agency having
jurisdiction over decommissioning of the Unit.
It is understood that, pursuant to the Second Supplementary Power
Contracts, the Purchasers are currently being billed for Total Decommissioning
Costs which, as of the date of this contract, are being accumulated in a
separate fund which was established for the purpose of reimbursing Connecticut
Yankee for Decommissioning Expenses incurred in the process of decommissioning
the Unit and that such billings are subject to change in accordance with the
provisions of the Second Supplementary Power Contracts subject to the
jurisdiction of the Federal Energy Regulatory Commission or any successor agency
thereto (the "FERC"). It is contemplated that sufficient funds will be
accumulated pursuant to those contracts and paragraph 7 hereof to make payment
to reimburse Connecticut Yankee for the full cost of decommissioning the Unit.
The Purchaser will, throughout the term of this contract, be entitled and
obligated to take its entitlement percentage of the capacity and net electrical
output of the Unit, at whatever level the Unit is operated or operable, whether
more or less than 582 megawatts electric.
6. Deliveries and Metering.
The Purchaser's entitlement percentage of the output of the Unit will be
delivered to and accepted by the Purchaser at the step-up substation at the
site. All deliveries will be made in the form of 3-phase, 60 cycle, alternating
current at a nominal voltage of 345,000 volts. The Purchaser will make its own
arrangements for the transmission of its entitlement percentage of the output of
the Unit.
Connecticut Yankee will supply and maintain all necessary metering
equipment for determining the quantity and conditions of supply of deliveries
under this contract, will make appropriate tests of such equipment in accordance
with good utility practice and as reasonably requested by the Purchaser, and
will maintain the accuracy of such equipment within reasonable limits.
Connecticut Yankee will furnish the Purchaser with such summaries of meter
readings as the Purchaser may reasonably request.
7. Payment.
With respect to each month commencing on or after January 1, 1998, the
Purchaser will pay Connecticut Yankee an amount equal to the Purchaser's
entitlement percentage of the sum of (a) the Total Decommissioning Costs for the
month with respect to the Unit, plus (b) Connecticut Yankee's total operating
expenses for the month with respect to the Unit, plus (c) an amount equal to
one-twelfth of the composite percentage for such month of the net Unit
investment as most recently determined in accordance with this Section 7.
"Composite percentage" shall be computed as of the last day of each month
during the term hereof (the "computation date") and for any month the composite
percentage shall be that computed as of the last day of the previous month.
"Composite percentage" as of a computation date shall be the sum of (i) the
equity percentage as of such date multiplied by the ratio which the equity
investment with respect to the Unit, as of such date, is to the total capital as
of such date; plus (ii) the "effective interest rate" per annum of each
principal amount of long-term debt outstanding on such date for money borrowed
with respect to the Unit, multiplied by the ratio which such principal amount is
to total capital as of such date; plus (iii) the "effective dividend rate" per
annum of each series of preferred stock outstanding as of such date with respect
to the Unit multiplied by the ratio which the amount at which such preferred
stock would be reflected on a balance sheet of Connecticut Yankee is to total
capital as of such date. The "effective interest rate" of each principal amount
of long-term debt referred to in clause (ii) will reflect the annual interest
requirements and to the extent applicable, amortization of issue expenses,
discounts and premiums, sinking fund call premiums, expenses and discounts,
refunding and retirement expenses, discounts and premiums, and all other
expenses applicable to the issue of such indebtedness.
The "effective dividend rate" of each series of preferred stock referred
to in clause (iii) will reflect the annual dividend requirements applicable to
each such series of preferred stock.
"Equity percentage" as of any date after commencement of the operative
term hereof shall be that percentage which was the "equity percentage"
applicable under the Power Contracts on the last day of the term of the Power
Contracts or such other percentage as may from time to time thereafter be
approved by the FERC or any successor regulatory authority.
"Equity investment" as of any date shall consist of the sum of (i) all
amounts theretofore paid to Connecticut Yankee for all common capital stock
theretofore issued, plus all amounts paid to Connecticut Yankee by any of its
common stockholders as capital contributions or advances less the sum of any
amounts paid by Connecticut Yankee to its common stockholders in the form of
stock retirements, repurchases or redemptions, return of capital or repayments
of such contributions or advances; plus (ii) any credit balance in the capital
surplus account not included under (i) and in the retained earnings account on
the books of Connecticut Yankee as of such date.
"Total capital" as of any date shall be the equity investment with respect
to the Unit, plus the total of the amount which would be reflected on a balance
sheet of Connecticut Yankee for all other securities (excluding short-term
debt), including long-term debt and preferred stock then outstanding with
respect to the Unit.
"Uniform System" shall mean the Uniform System of Accounts prescribed by
the FERC for Class A and Class B Public Utilities and Licensees, as from-time to
time in effect.
Connecticut Yankee's "operating expenses" shall include all amounts
properly chargeable to operating expense accounts, less any applicable credits
thereto, in accordance with the Uniform System; however, excluding for purposes
of this contract Total Decommissioning Costs.
"net Unit investment" shall consist, in each case with respect to the
Unit, of (i) the aggregate amount properly chargeable at the time in accordance
with the Uniform System to Connecticut Yankee's plant accounts (including -
construction work in progress to the extent allowed by the FERC) less the
balance, if any, at the time of the accumulated provision for depreciation, as
determined in accordance with the Uniform System (excluding any amounts
specifically allowed by the FERC to be so excluded); plus (ii) the aggregate
amount properly chargeable at the time in accordance with the Uniform System to
accounts representing materials and supplies; plus (iii) such reasonable
allowances for prepaid items and cash working capital as may from time to time
be determined by Connecticut Yankee and, for purposes hereof, net Unit
investment shall include, in addition to all other amounts which may be
includable therein under this section, but without duplication, the aggregate
amount properly chargeable at the time in accordance with the Uniform System to
Connecticut Yankee's nuclear fuel accounts (other than nuclear fuel in process
of fabrication), less the balance at the time of the accumulated provision for
amortization of the cost of nuclear fuel (excluding any amounts specifically
permitted by the FERC), all as determined in accordance with the Uniform System.
The net Unit investment shall be determined as of the commencement of each
calendar year, or, if Connecticut Yankee elects, at more frequent intervals.
"Total Decommissioning Costs" for any month shall mean the sum of (x) an
amount equal to all accruals in such month to any reserve, as from time to time
established by Connecticut Yankee and approved by its board of directors to
provide for the ultimate payment of the Decommissioning Expenses of the Unit
plus (y) Decommissioning Tax Liability for such month. It is understood (i)
that such funds may be held by Connecticut Yankee or by an independent trust or
other separate fund, as determined by said board of directors, (ii) that, upon
compliance with Section 17 hereof, the amount, custody and/or timing of such
accruals may from time to time during the term hereof be modified by said board
of d rectors in its discretion or to comply with applicable statutory or
regulatory requirements or to reflect changes in the amount, custody or timing
of anticipated Decommissioning Expenses, and (iii) that the use of the term "to
decommission" herein encompasses compliance with all requirements (other than
those relating to spent nuclear fuel) of the NRC for permanent cessation of
operation of a nuclear facility and any other activities reasonably related
thereto.
"Decommissioning Expenses" shall include:
(1) All costs and expenses of removing the Unit from service, including
without limitation, dismantling, mothballing, removing radioactive material
(excluding spent nuclear fuel) to temporary and/or permanent storage sites,
decontaminating, restoring and supervising the site, and any costs and expenses
incurred in connection with proceedings before governmental authorities relating
to any authorization to decommission the Unit or remove the Unit from service;
(2) All costs of labor and services, whether directly or indirectly
incurred, including without limitation, services of foremen, inspectors,
supervisors surveyors, engineers, security personnel, counsel and accountants,
performed or rendered in connection with the decommissioning of the Unit and the
removal of the Unit from service, and all costs of materials, supplies,
machinery, construction equipment and apparatus acquired or used (including
rental charges for machinery equipment or apparatus hired) for or in connection
with the decommissioning of the Unit and the removal of the Unit from service,
and all administrative costs, including services of counsel and financial
advisers, of any applicable independent trust or other separate fund; it being
understood that any amount, exclusive of proceeds of insurance, realized by
Connecticut Yankee as salvage on any machinery, construction equipment and
apparatus, the cost of which was charged to Decommissioning Expense, shall be
treated as a reduction of the amounts otherwise chargeable on account of the
costs of decommissioning of the Unit; and
(3) All overhead costs applicable to the Unit during its decommissioning
period, including, without limiting the generality of the foregoing, taxes
(other than taxes on or in respect of income), charges, licenses, excises and
assessments, casualties, surety bond premiums and insurance premiums.
"Decommissioning Tax Liability" for any month shall be an amount
established by Connecticut Yankee and approved by its board of directors to meet
possible income tax obligations, which amount shall not exceed: the amount to
be included in the clause (x) portion of Total Decommissioning Costs for such
month multiplied by a fraction whose numerator is equal to the combined highest
applicable statutory Federal and state marginal income tax rate and whose
denominator is equal to one minus the combined highest statutory Federal and
state marginal income tax rate.
Without limiting the generality of the foregoing, any other amounts
expended or to be paid with respect to decommissioning of the Unit or removal of
the Unit from service shall constitute part of the Decommissioning Expenses if
they are, or when paid will be, either (i) properly chargeable to any account
related to decommissioning of a nuclear generating unit in accordance with the
Uniform System or generally accepted accounting principles as then in effect, or
(ii) properly chargeable to decommissioning of a nuclear generating unit in
accordance with then applicable regulations of the NRC or the FERC or any other
regulatory agency having jurisdiction.
8. Billing.
Connecticut Yankee will bill the Purchaser, as soon as practicable after
the end of each month, for all amounts payable by the Purchaser with respect
to-the-particular month pursuant to Section 7 hereof. Such bills will be
rendered in such detail as the Purchaser may reasonably request and may be
rendered on an estimated basis subject to corrective adjustments in subsequent
billing periods. All bills shall be due and payable when rendered and any
amount remaining unpaid 15 days following the date of receipt of bills shall
bear interest at an annual rate equal to 2% in excess of the current prime rate
then in effect at The Connecticut Bank and Trust Company, National Association,
from the due date to the date payment is received by Connecticut Yankee.
9. Decommissioning Fund.
Connecticut Yankee agrees to cause an appropriate decommissioning reserve
to be maintained in accordance with applicable regulatory requirements.
Connecticut Yankee has established an independent trust or other separate fund
(the "Connecticut Yankee Trust") which has the necessary powers to hold and
invest all funds collected for the decommissioning of the Unit and to disburse
the same to reimburse Connecticut Yankee for such costs when actually incurred
for decommissioning of the Unit or removal of the Unit from service. If during
the term of the Connecticut Yankee Trust applicable legislation or regulations
are promulgated which so permit or require, or an alternative entity is created
for funding decommissioning of the Unit, the Connecticut Yankee Trust has the
authority, with the concurrence of Connecticut Yankee, to transfer its trust
estate to such newly authorized entity for the purpose of providing for the
decommissioning of the Unit or removal of the Unit from service.
Connecticut Yankee agrees to pay to, or cause to be paid to, the
Connecticut Yankee Trust or any successor trust approved by the board of
directors of Connecticut Yankee all funds collected hereunder for the express
purpose of decommissioning the Unit or removing the Unit from service and
further agrees that, after the tax consequences of decommissioning collections
have been resolved, any funds collected hereunder to meet Decommissioning Tax
Liability which are not used for that purpose will be refunded to the Purchaser.
10. Cancellation of Contract.
If deliveries cannot be made to the Purchaser because either
(i) the Unit is damaged to the extent of being completely or
substantially completely destroyed, or
(ii) the Unit is taken by exercise of the right of eminent domain or a
similar right or power, or
(iii) (a) the Unit cannot be used because of contamination, or because
a necessary license or other necessary public authorization cannot be obtained
or is revoked or because the utilization of such a license or authorization is
made subject to specified conditions which are not met, and (b) the situation
cannot be rectified to an extent which will permit Connecticut Yankee to make
deliveries to the Purchaser from the Unit;
then and in any such case, the Purchaser may cancel the provisions of this
contract, except that in all cases other than those described in clause (ii)
above, the provisions relating to the payment of Total Decommissioning Costs
shall, whether or not the Unit is operated or operable and notwithstanding any
earlier termination of the service life of the Unit, remain in full force and
effect until the expiration of the term hereof, it being recognized that such
costs represent deferred payments in connection with power theretofore delivered
by Connecticut Yankee hereunder. Such cancellation shall be effected by written
notice given by the Purchaser to Connecticut Yankee. In the event of such
cancellation, all continuing obligations of the parties hereunder as to
subsequently incurred costs of Connecticut Yankee other than the obligations
relating to the payment and application of Total Decommissioning Costs excluded
from such cancellation by the second preceding sentence, but including the
Purchaser's obligations to continue payments pursuant to clauses (b) and (c) of
the first paragraph of Section 7 hereof, shall cease forthwith. Notwithstanding
the foregoing, the applicable provisions of this contract shall continue in
effect after the cancellation hereof to the extent necessary to permit final
billings and adjustments hereunder with respect to obligations incurred through
the date of cancellation and the collection thereof. Any dispute as to the
Purchaser's right to cancel this contract pursuant to the foregoing provisions
shall be referred to arbitration in accordance with the provisions of Section
13.
Notwithstanding anything in this contract elsewhere contained, the
Purchaser may cancel this contract or be relieved of its obligations to make
payments hereunder only as provided in the next preceding paragraph of this
Section 10. Further, if for reasons beyond Connecticut Yankee's reasonable
control, deliveries are not made as contemplated by this contract, Connecticut
Yankee shall have no liability to the Purchaser on account of such non-delivery.
11. Insurance.
Connecticut Yankee presently has in effect, and hereafter will at all
times maintain until the expiration of the term hereof, insurance to cover its
"public liability" for personal injury and property damage resulting from a
"nuclear incident" (as those terms are defined in the Act), with limits not less
than Connecticut Yankee may be required to maintain to qualify for governmental
indemnity under the Act and shall maintain an indemnification agreement with the
NRC as provided by the Act. Connecticut Yankee will also at all time maintain
such other types of liability insurance, including workmen's compensation
insurance, in such amounts, as is customary in the case of other similar
electric utility companies, or as may be required by law.
Connecticut Yankee will at all times keep insured such portions of the
Unit as are of a character usually insured by electric utility companies
similarly situated and operating like properties, against the risk of a
"nuclear incident" and such other risks as electric utility companies, similarly
situated and operating like properties, usually insure against; and such
insurance shall to the extent available be carried in amounts sufficient to
prevent Connecticut Yankee from becoming a co-insurer. Such insurance shall to
the extent available be carried in an amount at least equal to the original cost
of the insured facilities, less accrued depreciation thereon.
12. Audit.
Connecticut Yankee's books and records (including metering records) shall
be open to reasonable inspection and audit by the Purchaser.
13. Arbitration.
In case any dispute shall arise as to the interpretation or performance of
this contract which cannot be settled by mutual agreement, such dispute shall be
submitted to arbitration. The parties shall if possible agree upon a single
arbitrator. In case of failure to agree upon an arbitrator within 15 days after
the delivery by either party to the other of a written notice requesting
arbitration, either party may request the American Arbitration Association to
appoint the arbitrator. The arbitrator, after opportunity for each of the
parties to be heard, shall consider and decide the dispute and notify the
parties in writing of his decision. Such decision shall be binding upon the
parties, and the expenses of the arbitration shall be borne equally by them.
14. Regulation.
This contract, and all rights, obligations and performance of the parties
hereunder, are subject to all applicable state and Federal law and to all duly
promulgated orders and other duly authorized action of governmental authorities
having jurisdiction.
15. Assignment.
This contract shall be binding upon and shall inure to the benefit of, and
may be performed by, the successors and assigns of the parties, except that no
assignment, pledge or other transfer of this contract by either party shall
operate to
the assignor, pledgor or transferor from any of its obligations under this
contract unless consent to the given in writing by the other party, or, if the
other party has theretofore assigned, pledged or otherwise transferred its
interest in this contract by the other party's assignee, pledgee or transferee,
or unless such transfer is incident to a merger or consolidation with, or
transfer of all or substantially all of the assets of the transferor to, another
Purchaser which shall, as a part of such succession, assume all the obligations
of the transferor under this contract.
16. Right of Setoff.
The Purchaser shall not be entitled to set off against the payments
required to be made by it under this contract (i) any amounts owed to it by
Connecticut Yankee or (ii) the amount of any claim by it against Connecticut
Yankee. However, the foregoing shall not affect in any other way the
Purchaser's right and remedies with respect to any such amounts owed to it by
Connecticut Yankee or any such claim by it against Connecticut Yankee.
17. Amendments.
Upon authorization by Connecticut Yankee's board of directors of uniform
amendments to all the Additional Power Contracts, Connecticut Yankee shall have
the right to amend the provisions of Section 7 hereof by serving an appropriate
statement of such amendment upon the Purchaser and filing the same with the FERC
(or such other regulatory agency as may have jurisdiction in the premises) in
accordance with the provisions of applicable laws and any rules and regulations
thereunder, and the amendment shall thereupon become effective on the date
specified therein, subject to any suspension order issued by such agency. All
other amendments to this contract shall be by mutual agreement, evidenced by a
written amendment signed by the parties hereto.
18. Interpretation.
The interpretation and performance of this contract shall be in accordance
with and controlled by the law of the State of Connecticut.
19. Addresses.
Except as the parties may otherwise agree, any notice, request, bill or
other communication from one party to the other, relating to this contract, or
the rights, obligations or performance of the parties hereunder, shall be in
writing and shall be effective upon delivery to the other party. Any such
communication shall be considered as duly delivered when delivered in person or
mailed by registered or certified mail, postage prepaid, to the respective post
office address of the other party shown following the signatures of such other
party hereto, or such other address as may be designated by written notice given
as provided in this Section 19.
20. Corporate Obligations.
This contract is the corporate act and obligation of the parties hereto,
and any claim hereunder against any stockholder, director or officer of either
party, as such, is expressly waived.
21. All Prior Agreements Superseded.
This contract represents the entire agreement between the parties relating
to the subject matter hereof during the operative term hereof (i.e., post-
December 31, 1997), and all previous agreements, discussions, communications and
correspondence with respect to the subject matter are hereby superseded and are
of no further force and effect.
22. Counterparts.
This contract may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if all the parties to all of the counterparts had signed the
same instrument. Any signature page of this contract may be detached from any
counterpart without impairing the legal effect of any signatures thereon, and
may be attached to another counterpart of this contract identical in form hereto
but having attached to it one or more signature pages.
IN WITNESS WHEREOF, the parties have executed this contract by their
respective officers thereunto duly authorized as of the date first above
written.
CONNECTICUT YANKEE ATOMIC POWER COMPANY
By /s/ Bernard M. Fox
Its Senior Vice President
P.O. Box 270
Hartford, Connecticut 06141
THE CONNECTICUT LIGHT AND POWER COMPANY
By /s/ E. James Ferland
(Officer and Title)
E. JAMES FERLAND, PRESIDENT & CHIEF
OPERATING OFFICER
(Address)
CAPITAL FUNDS AGREEMENT, dated as of September 1, 1964, between CONNECTICUT
YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation,
and THE CONNECTICUT LIGHT AND POWER COMPANY (the "Stockholder"), a Connecticut
corporation.
It is agreed as follows:
1. Basic Understandings
Connecticut Yankee has been organized to provide for the supply of power
to the eleven utility companies (including the Stockholder) which are its
stockholders. It has commenced the construction of a nuclear electric generating
unit of the pressurized water type, which is being designed to have an initial
gross capability of approximately 490 megawatts electric, at a site adjacent to
the Connecticut River at Haddam Neck, Connecticut (the unit being herein,
together with the site and all related facilities, referred to as the "Unit").
Construction of the Unit is being carried out under contracts with Westinghouse
Electric Corporation and Stone & Webster Engineering Corporation.
The respective percentages of the capacity and output of the Unit to be
purchased by the Stockholder and the other Connecticut Yankee stockholders are
the same as the respective percentages of Connecticut Yankee's stock now owned
by them. The names of the stockholders and their respective stock percentages
("stock percentages") are as follows:
Stockholder Stock Percentage
The Connecticut Light and Power Company 25.0%
New England Power Company 15.0%
Boston Edison Company 9.5%
The Hartford Electric Light Company 9.5%
The United Illuminating Company 9.5%
Western Massachusetts Electric Company 9.5%
Central Maine Power Company 6.0%
Public Service Company of New Hampshire 5.0%
Cambridge Electric Light Company 4.5%
Montaup Electric Company 4.5%
Central Vermont Public Service Corporation 2.0%
Connecticut Yankee and each of its other stockholders are entering into capital
funds agreements which are identical to this agreement except for necessary
changes in the names of the parties.
Connecticut Yankee's capitalization as of the date of this agreement is
$7,500,000 consisting of 75,000 shares of common stock, $100 par value, which
have been purchased at the par value thereof by its stockholders. Connecticut
Yankee's stockholders have entered into subscription agreements with it covering
their purchase of their respective stock percentages of an additional 75,000
shares of its common stock, $100 par value, at the par value thereof.
Connecticut Yankee's estimated capital requirements with respect to the Unit
aggregate $98,500,000 and Connecticut Yankee proposes to finance the balance of
these requirements through the issuance and sale of first mortgage bonds or
other securities, and through the issuance and sale of common stock to its
stockholders.
2. Effective Date
This agreement shall become effective upon receipt by the Stockholder of
notice that Connecticut Yankee has entered into capital funds agreements, as
contemplated by Section 1 above, with each of its other stockholders, and the
execution of capital funds agreements by the other stockholders shall constitute
consideration for the obligations of the Stockholder hereunder.
3. Construction of the Unit
Connecticut Yankee will proceed with due diligence with construction of
the Unit, and will exercise its best efforts to complete and place it in
commercial operation by October 1, 1967, on the presently estimated schedule
therefor and within present cost estimates, and will keep the Stockholder
currently informed as to the progress of construction and expected plant
completion date.
4. Stock Purchases to Provide the Capital Requirements of the Unit
From time to time when Connecticut Yankee requires capital to meet the
capital requirements of the Unit, it may offer shares of its common stock to its
stockholders for subscription to raise such capital. Subject to the conditions
in Section 7, when Connecticut Yankee offers any such shares for such purpose,
the Stockholder will subscribe for and purchase for cash at the par value
thereof its stock percentage of the shares so offered. However, the aggregate
amount required to be paid by the Stockholder pursuant to this Section
(including for this purpose the amount paid by the Stockholder on account of its
purchase of the shares of Connecticut Yankee common stock which are outstanding
on the date of this agreement, as referred to in Section 1, and any additional
amount paid by it after said date on account of the purchase of additional
shares of said stock pursuant to its outstanding subscription agreement referred
to in Section 1 or any further subscription agreements entered into by the
Stockholder with Connecticut Yankee prior to the time at which the conditions
specified in the second paragraph of Section 7 are satisfied) shall not exceed
the sum of (a) its stock percentage of $70,000,000, and (b) amounts paid to it
by Connecticut Yankee as return of capital.
5. Capital Requirements of the Unit Defined
Connecticut Yankee shall be deemed to have capital requirements of the
Unit within the meaning of Section 4 if it requires additional capital for any
of the following purposes:
(i) to complete construction of the Unit and place it in commercial
operation at a gross capability of at least 490 megawatts electric;
(ii) to make additions and replacements (other than those chargeable to
maintenance) to the Unit which are required to insure the continued regular
operation of the Unit at a gross capability of at least 490 megawatts electric
or to restore it to regular operation at such gross capability;
(iii) to make any changes in or additions to the Unit which must be
effected in order to obtain or maintain, or to meet the conditions of, any
license or other public authorization which is required for the regular
operation of the Unit at a gross capability of at least 490 megawatts electric;
(iv) to provide materials and supplies, or funds for prepaid items or cash
working capital, required for the regular operation of the Unit at a gross
capability of at least 490 megawatts electric, or to finance the costs of
acquiring and maintaining an inventory of nuclear cores owned by Connecticut
Yankee.
If the Company shall at any time or times determine that it would be more
feasible, economic or otherwise desirable for regular operation for the
generation of power and energy for delivery under its Power Contracts with its
Stockholders for the Unit to operate at a lower gross capability than 490
megawatts or with heat supplied in whole or part other than by a nuclear
reactor, and if it holds or can obtain all licenses and other public
authorizations required for the regular operation of the Unit at such lower
level or with such other heating system, then the "capital requirements of the
Unit" shall include any additional capital required for any of the foregoing
purposes for operation of the Unit at any such lower level of capability or with
such other heating system as from time to time determined.
6. Loans and Advances
In lieu of offering additional shares of its common stock for subscription
and purchase under Section 4, Connecticut Yankee may, at its option, request its
stockholders to provide required capital by means of loans or advances. In any
case where Connecticut Yankee requests such loans or advances, in lieu of stock
purchases, the Stockholder, subject to the conditions in Section 7, will provide
its stock percentage thereof. However, Connecticut Yankee shall not be entitled
to request such loans or advances except in circumstances where it would be
entitled to require the Stockholder to make a stock subscription pursuant to
Section 4. Further, the aggregate amount of capital which the Stockholder is
required to provide under Sections 4 and 6 of this agreement shall be the same
whether the capital is provided in whole through stock subscriptions and
purchases or loans or advances, or is provided instead through a combination of
them. However, in determining whether the aggregate of (x) the amounts paid or
to be paid by the Stockholder for shares of common stock purchased or to be
purchased under Section 4 and (y) the amounts of any loans or advances provided
or to be provided in lieu of such stock purchases, equals or exceeds the limit
specified in Section 4, the aggregate principal amount of all such loans or
advances previously made shall be excluded to the extent repaid.
The terms of any loans and advances requested by Connecticut Yankee under
this Section 6, as to interest, maturity date, rights and terms of prepayment,
and otherwise shall be the same for all stockholders. Such terms shall be as
determined by Connecticut Yankee in its discretion, except that the terms of
each such loan or advance shall provide for quarterly payments of interest at an
annual rate not less than 1-1/2% in excess of the prime rate for commercial
loans at the time in effect at The Connecticut Bank and Trust Company and for a
maturity date not later than October 1, 1994.
7. Conditions to the Stockholders's Obligations
The obligation of the Stockholder to subscribe for and purchase its stock
percentage of any stock issue under Section 4, or to provide its stock
percentage of any loan or advance under Section 6, shall be subject to the
condition that all necessary regulatory approvals shall have been obtained with
respect to both the action to be taken by Connecticut Yankee and the action to
be taken by the Stockholder. The parties will use their best efforts to obtain,
or to assist in obtaining, the foregoing regulatory approvals.
The obligation of the Stockholder to subscribe for and purchase its stock
percentage of any stock issue under Section 4, or to provide its stock
percentage of any loan or advance under Section 6, shall be subject to the
further condition that Connecticut Yankee shall first (i) have sold at least
$40,000,000 aggregate principal amount of its first mortgage bonds at a price
not lower than the aggregate principal amount thereof, and (ii) have entered
into an agreement with one or more banks providing for the loan from such
bank(s) to Connecticut Yankee of up to $25,000,000 on terms and conditions
approved by Connecticut Yankee's Board of Directors.
Except as expressly provided in this Section 7, notwithstanding anything
in this agreement elsewhere contained, no action of, nor failure to act by,
Connecticut Yankee or any of the several stockholders referred to in Section 1
hereof shall permit cancellation of, or relieve the Stockholder from any of its
obligations under, this agreement. However, the failure of any of Connecticut
Yankee's other stockholders to purchase its stock percentage of any Connecticut
Yankee stock issue, or to make its stock percentage of any loan or advance
requested by Connecticut Yankee, shall under no circumstances require an
increase in the amount of stock to be purchased, or the amount of loans and
advances to be made, by the Stockholder.
8. Financing by Other Means
Nothing in this agreement shall be construed as precluding Connecticut
Yankee from offering shares of its common stock to, or requesting loans and
advances from, its stockholders to finance capital requirements other than those
contemplated by Section 5, or from financing, in its discretion, its capital
requirements (including the capital requirements contemplated by Section 5) by
means other than the sale of its common stock to its stockholders, or loans or
advances from them.
9. Cooperation By Stockholder
The Stockholder agrees that it will cooperate with Connecticut Yankee in
taking all such action as may be necessary or appropriate to effectuate the
purposes of this agreement.
10. Restrictions on Transfer
The Stockholder acknowledges notice of the restrictions on stock transfers
contained in Article VIII, Section 2 of Connecticut Yankee's by-laws, and agrees
to be bound by said provisions with respect to all shares of Connecticut
Yankee's capital stock which it now owns or may hereafter acquire.
11. Interpretation
The interpretation and performance of this agreement shall be in
accordance with and controlled by the law of the State of Connecticut.
12. Addresses
Except as the parties may otherwise agree, any notice, request or other
communication from one party to the other, relating to this agreement or the
rights, obligations or performance of the parties hereunder, shall be in writing
and shall be effective upon delivery to the other party. Any such communication
shall be considered as duly delivered when mailed to the respective post office
address of the other party shown following the signatures of such other party
hereto, or such other post office address as may be designated by written notice
given as provided in this Section 12.
13. Assignment
This agreement shall be binding upon and shall inure to the benefit of,
and may be performed by, the successors and assigns of the parties, except that
no assignment, pledge or other transfer of this agreement by either party shall
operate to release the assignor, pledgor or transferor of any of its obligations
under this agreement unless consent to the release is given in writing by the
other party, or, if the other party has theretofore assigned, pledged or
otherwise transferred its interest in this agreement, by the other party's
assignee, pledgee or transferee.
14. Corporate Obligations
This agreement is the corporate act and obligation of the parties hereto,
and any claim hereunder against any stockholder, director or officer of either
party, as such, is expressly waived.
15. All Prior Agreements Superseded
This agreement represents the entire agreement between us relating to the
subject matter hereof, and all previous agreements (including our prior Capital
Funds Agreement dated as of July 1, 1964), discussions, communications and
correspondence with respect to the subject matter are hereby superseded and are
of no further force and effect, except that the outstanding subscription
agreement, as referred to in Section 1, between the Stockholder and Connecticut
Yankee with respect to the Stockholder's subscription for its stock percentage
of an additional 75,000 shares of Connecticut Yankee's common stock, $100 par
value, is not superseded and shall remain in full force and effect.
IN WITNESS WHEREOF, the parties have executed this agreement by their
respective officers thereunto duly authorized as of the date first above
written.
Attest: CONNECTICUT YANKEE ATOMIC POWER COMPANY
/s/ R. F. Probst By /s/ S. R. Knapp
Secretary Its President
P.O. Box 2010
Hartford, Connecticut 06101
Attest: THE CONNECTICUT LIGHT AND POWER COMPANY
/s/ C. J. Ramage By /s/ P. V. Hayden
Asst. Secretary Its President
MAINE YANKEE ATOMIC POWER COMPANY
Amendment No. 3
to
Power Contract
AMENDMENT, dated as of this first day of October, 1984, between MAINE
YANKEE ATOMIC POWER COMPANY ("Maine Yankee"), a Maine Corporation, and THE
CONNECTICUT LIGHT AND POWER COMPANY a corporation (the "Purchaser"), to the
Power Contract dated as of May 20, 1968 between Maine Yankee and the Purchaser
(the "Power Contract").
W I T N E S S E T H
WHEREAS, pursuant to the Power Contract, Maine Yankee supplies to the
Purchaser and, pursuant to separate Power Contracts, to the other Sponsors of
Maine Yankee, each of whom is contemporaneously entering into Amendments which
are identical to the Amendment except for the necessary changes in the names of
the parties, all of the capacity and the electric energy available from the
nuclear generating unit owned by Maine Yankee at a site on the tidewater in the
Town of Wiscasset, Maine, (such unit being herein together with the site and all
related facilities owned by Maine Yankee, referred to as the "Unit").
WHEREAS, the Federal Energy Regulatory Commission ("FERC") in a final Order
(the "Order") issued August 14, 1984 in Docket No. ER84-344 has directed Maine
Yankee to amend the Power Contract to conform with the FERC's regulations
regarding the treatment of construction work in progress ("CWIP") and nuclear
fuel in process ("NFIP") in rate base.
WHEREAS, in the Order the FERC also directed Maine Yankee to amend the
Power Contract to conform with the FERC's regulations regarding the treatment of
accumulated deferred income taxes in rate base.
NOW, THEREFORE, in consideration of the premises and to other good and
valuable consideration, receipt of which is hereby acknowledged, the parties
hereto agree that the Power Contract is hereby amended as follows:
1. Terms used herein and not defined shall have meanings set forth in the
Power Contract.
2. Section 7 of the Power Contract is amended by adding the following
paragraph to the end thereof:
Notwithstanding any other provision of this contract, the treatment of (1)
construction work in progress ("CWIP"), (2) nuclear fuel in process ("NFIP"),
and (3) accumulated deferred income taxes ("ADIT") for purposes of any
calculations relevant to the computation of monthly payments under this Section
7 shall conform to the Federal Energy Regulatory Commission's regulations
respecting such items, as such regulations may be modified from time to time.
This Agreement shall become effective on October 1, 1984, or upon such
later date as it shall be permitted to become effective by the Federal Energy
Regulatory Commission or other governmental regulatory authority having
jurisdiction.
This Agreement may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if all the parties to all of the counterparts had signed the
same instrument. Any signature page of this Agreement may be detached from any
counterpart without impairing the legal effect of any signatures thereon, and
may be detached from any counterpart without impairing the legal effect of any
signatures thereon, and may be attached to another counterpart of this contract
identical in form hereto by having attached to it one or more signature pages.
IN WITNESS WHEREOF, the parties have executed this Agreement by their
respective officers hereto duly authorized, as of the date first above written.
MAINE YANKEE ATOMIC POWER COMPANY
By
--------------------------
Its President
--------------------------
Title
Address: Edison Drive
Agusta, Maine 04336
THE CONNECTICUT LIGHT & POWER COMPANY
-------------------------------------
(PURCHASER)
By /s/E. JAMES FERLAND
-----------------------
E. JAMES FERLAND
Its PRESIDENT & CHIEF OPERATING
---------------------------
OFFICER
-------
Title
This Amendment No. 1, dated as of August 1, 1985, between MAINE YANKEE
ATOMIC POWER COMPANY ("Maine Yankee"), a Maine corporation, and THE CONNECTICUT
LIGHT AND POWER COMPANY (the "Sponsor"), amending the Capital Funds Agreement,
dated as of May 20, 1968, between said parties.
WHEREAS, Maine Yankee and the Sponsor are parties to the Capital Funds
Agreement which was executed concurrently with a Power Contract between the same
parties providing for the sale of power by Maine Yankee to the Sponsor for a
term of 30 years which ends on January 1, 2003 and Maine Yankee has comparable
agreements with its other sponsors; and
WHEREAS, Maine Yankee and the Sponsor have entered into an Additional Power
Contract, dated as of February 1, 1984, which continues the provisions of said
Power Contract until the expiration of Maine Yankee's operating license and
completion of decommissioning of Maine Yankee's plant and Maine Yankee has
comparable agreements with its other sponsors; and
WHEREAS, Maine Yankee is concurrently entering into an amendment similar to
this with each of its other sponsors.
NOW, THEREFORE, it is agreed that
1. Section 2 of the Capital Funds Agreement is hereby amended by deleting
the date "December 31, 2003" and inserting in lieu thereof the date "October 21,
2008".
2. Section 5 of the Capital Funds Agreement is hereby amended by changing
the period at the end of the first sentence thereof to a semicolon and inserting
the following clause:
"(vi) to provide moneys for funding the Maine Yankee Spent Fuel
Disposal Trust established pursuant to Chapter 508 of the Public Laws
of 1985 of Maine."
3. This Amendment No. 1 shall become effective upon receipt by the Sponsor
of notice that Maine Yankee has entered into a substantially identical agreement
with each of the other sponsors with respect to their respective Capital Funds
Agreements.
IN WITNESS WHEREOF, the parties have executed this amendment by their
respective officers thereunto duly authorized as of the date first above
written.
MAINE YANKEE ATOMIC POWER COMPANY
By
------------------------------
Amendment No. 3
to
Power Contract
AMENDMENT, dated as of this 24th day of April, 1985, between VERMONT
YANKEE NUCLEAR CORPORATION ("Vermont Yankee"), a Vermont corporation, and
THE CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation (the
"Purchaser"), for itself and as successor to The Hartford Electric Light
Company ("HELC"), to the Power Contracts dated February 1, 1968, as
heretofore amended on June 1, 1972 and April 15, 1983, one between Vermont
Yankee and HELC (collectively the "Power Contract"), as previously amended.
WITNESSETH
WHEREAS, pursuant to the Power Contract, Vermont Yankee supplies to
the Purchaser and, pursuant to separate power contracts substantially
identical to the Power Contract except for the names of the parties, to the
other Sponsors of Vermont Yankee, each of whom is contemporaneously
entering into an amendment to its power contract which is identical hereto
except for the necessary changes in the names of the parties, all of the
capacity and the electric energy available from the nuclear generating unit
owned by Vermont Yankee at a site adjacent to the Connecticut River at
Vernon, Vermont (such unit being herein together with the site and all
related facilities owned by Vermont Yankee, referred to as the "Unit").
WHEREAS, Vermont Yankee, the Purchaser and the other Sponsors of
Vermont Yankee believe that the monthly payments provided in the Power
Contracts are no longer sufficient to provide a return on the equity
investment in the Unit which is equal to the return achieved on investments
of comparable risk.
WHEREAS, in order to assure the maintenance of an appropriate level of
return on common equity, Vermont Yankee and the Purchaser have agreed to
enter into this Agreement.
NOW, THEREFORE, in consideration of the above and of other good and
valuable consideration, receipt of which is hereby acknowledged, the
parties hereto agree that the Power Contract is hereby amended as follows:
1. Terms used herein and not defined shall have the meanings set
forth in the Power Contract.
2. The fourth paragraph of Section 7 of the Power Contract is amended
to read as follows:
"Equity percentage" as of any date shall be eight and one-half percent
(8 1/2%) or such greater percentage, if any, as shall be obtained by
dividing (a) the sum of (i) fifteen and one-half percent (15.5%) multiplied
by common stock equity investment as of such date plus (ii) the stated
dividend rate per annum of each issue of preferred stock bearing a
particular dividend rate outstanding on such date multiplied by the
aggregate par value of said issue, by (b) equity investment as of such
date.
This Agreement shall become effective on May 14, 1985, or upon such
later date as it shall be permitted to become effective by the Federal
Energy Regulatory Commission or other governmental regulatory authority
having jurisdiction.
The Agreement may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if both parties to all of the counterparts had signed the
same instrument. Any signature page of the Agreement may be detached from
any counterpart without impairing the legal effect of any signatures
thereon, and may be attached to another counterpart of this contract
identical in form hereto but having to it one more signature pages.
IN WITNESS WHEREOF, the parties have executed this Agreement by their
respective officers hereto duly authorized, as of the date first above
written.
VERMONT YANKEE NUCLEAR POWER CORPORATION
By /s/John T. Pearson
-------------------------
Its Treasurer
-------------------------
Title
Address:
THE CONNECTICUT LIGHT AND POWER COMPANY
By /s/E. James Ferland
------------------------------
E. JAMES FERLAND
Its PRESIDENT AND CHIEF OPERATING
OFFICER
Title
Address: 107 SELDEN STREET
BERLIN, CT 06307
Amendment No. 3
to
Power Contract
AMENDMENT, dated as of this 24th day of April, 1985, between VERMONT YANKEE
NUCLEAR CORPORATION ("Vermont Yankee"), a Vermont corporation, and PUBLIC
SERVICE COMPANY OF NEW HAMPSHIRE, a New Hampshire corporation (the "Purchaser"),
for itself and as successor to The Hartford Electric Light Company ("HELC"), to
the Power Contracts dated February 1, 1968, as heretofore amended on June 1,
1972 and April 15, 1983, one between Vermont Yankee and HELC (collectively the
"Power Contract"), as previously amended.
WITNESSETH
WHEREAS, pursuant to the Power Contract, Vermont Yankee supplies to the
Purchaser and, pursuant to separate power contracts substantially identical to
the Power Contract except for the names of the parties, to the other Sponsors of
Vermont Yankee, each of whom is contemporaneously entering into an amendment to
its power contract which is identical hereto except for the necessary changes in
the names of the parties, all of the capacity and the electric energy available
from the nuclear generating unit owned by Vermont Yankee at a site adjacent to
the Connecticut River at Vernon, Vermont (such unit being herein together with
the site and all related facilities owned by Vermont Yankee, referred to as the
"Unit").
WHEREAS, Vermont Yankee, the Purchaser and the other Sponsors of Vermont
Yankee believe that the monthly payments provided in the Power Contracts are no
longer sufficient to provide a return on the equity investment in the Unit which
is equal to the return achieved on investments of comparable risk.
WHEREAS, in order to assure the maintenance of an appropriate level of return on
common equity, Vermont Yankee and the Purchaser have agreed to enter into this
Agreement.
NOW, THEREFORE, in consideration of the above and of other good and valuable
consideration, receipt of which is hereby acknowledged, the parties hereto agree
that the Power Contract is hereby amended as follows:
1. Terms used herein and not defined shall have the meanings set forth in
the Power Contract.
2. The fourth paragraph of Section 7 of the Power Contract is amended to
read as follows:
"Equity percentage" as of any date shall be eight and one-half percent (8
1/2%) or such greater percentage, if any, as shall be obtained by dividing (a)
the sum of (i) fifteen and one-half percent (15.5%) multiplied by common stock
equity investment as of such date plus (ii) the stated dividend rate per annum
of each issue of preferred stock bearing a particular dividend rate outstanding
on such date multiplied by the aggregate par value of said issue, by (b) equity
investment as of such date.
This Agreement shall become effective on May 14, 1985, or upon such later
date as it shall be permitted to become effective by the Federal Energy
Regulatory Commission or other governmental regulatory authority having
jurisdiction.
The Agreement may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if both parties to all of the counterparts had signed the same
instrument. Any signature page of the Agreement may be detached from any
counterpart without impairing the legal effect of any signatures thereon, and
may be attached to another counterpart of this contract identical in form hereto
but having to it one more signature pages.
IN WITNESS WHEREOF, the parties have executed this Agreement by their
respective officers hereto duly authorized, as of the date first above written.
VERMONT YANKEE NUCLEAR POWER CORPORATION
By /s/John T. Pearson
-------------------------------
Its Treasurer
-------------------------------
Title
Address:
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
By /s/R. J. Hanson
--------------------------------
Its PRESIDENT AND CHIEF EXECUTIVE OFFICER
Title
Amendment No. 3
to
Power Contract
AMENDMENT, dated as of this 24th day of April, 1985, between VERMONT YANKEE
NUCLEAR CORPORATION ("Vermont Yankee"), a Vermont corporation, and WESTERN
MASSACHUSETTS ELECTRIC COMPANY, a Massachusetts corporation (the "Purchaser"),
for itself and as successor to The Hartford Electric Light Company ("HELC"), to
the Power Contracts dated February 1, 1968, as heretofore amended on June 1,
1972 and April 15, 1983, one between Vermont Yankee and HELC (collectively the
"Power Contract"), as previously amended.
WITNESSETH
WHEREAS, pursuant to the Power Contract, Vermont Yankee supplies to the
Purchaser and, pursuant to separate power contracts substantially identical to
the Power Contract except for the names of the parties, to the other Sponsors of
Vermont Yankee, each of whom is contemporaneously entering into an amendment to
its power contract which is identical hereto except for the necessary changes in
the names of the parties, all of the capacity and the electric energy available
from the nuclear generating unit owned by Vermont Yankee at a site adjacent to
the Connecticut River at Vernon, Vermont (such unit being herein together with
the site and all related facilities owned by Vermont Yankee, referred to as the
"Unit").
WHEREAS, Vermont Yankee, the Purchaser and the other Sponsors of Vermont
Yankee believe that the monthly payments provided in the Power Contracts are no
longer sufficient to provide a return on the equity investment in the Unit which
is equal to the return achieved on investments of comparable risk.
WHEREAS, in order to assure the maintenance of an appropriate level of
return on common equity, Vermont Yankee and the Purchaser have agreed to enter
into this Agreement.
NOW, THEREFORE, in consideration of the above and of other good and
valuable consideration, receipt of which is hereby acknowledged, the parties
hereto agree that the Power Contract is hereby amended as follows:
1. Terms used herein and not defined shall have the meanings set forth in
the Power Contract.
2. The fourth paragraph of Section 7 of the Power Contract is amended to
read as follows:
"Equity percentage" as of any date shall be eight and one-half percent (8
1/2%) or such greater percentage, if any, as shall be obtained by dividing (a)
the sum of (i) fifteen and one-half percent (15.5%) multiplied by common stock
equity investment as of such date plus (ii) the stated dividend rate per annum
of each issue of preferred stock bearing a particular dividend rate outstanding
on such date multiplied by the aggregate par value of said issue, by (b) equity
investment as of such date.
This Agreement shall become effective on May 14, 1985, or upon such later
date as it shall be permitted to become effective by the Federal Energy
Regulatory Commission or other governmental regulatory authority having
jurisdiction.
The Agreement may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if both parties to all of the counterparts had signed the same
instrument. Any signature page of the Agreement may be detached from any
counterpart without impairing the legal effect of any signatures thereon, and
may be attached to another counterpart of this contract identical in form hereto
but having to it one more signature pages.
IN WITNESS WHEREOF, the parties have executed this Agreement by their
respective officers hereto duly authorized, as of the date first above written.
VERMONT YANKEE NUCLEAR POWER CORPORATION
By /s/John T. Pearson
----------------------------
Its Treasurer
-----------------------------
Title
Address:
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By /s/E. James Ferland
----------------------------------
E. JAMES FERLAND
Its PRESIDENT AND CHIEF OPERATING
AMENDED AND RESTATED
MILLSTONE PLANT AGREEMENT
This Amended and Restated Millstone Plant Agreement (the "Agreement") is
dated as of December 1, 1984, and is by and among Northeast Nuclear Energy
Company ("NNECO"), The Connecticut Light and Power Company ("CL&P"), and Western
Massachusetts Electric Company ("WMECO").
BACKGROUND
CL&P, WMECO and NNECO are parties to an Amended and Restated Millstone
Plant Agreement dated as of December 1, 1982 (the "Millstone Plant Agreement"),
which is a comprehensive restatement and amendment of a prior agreement dated as
of June 30, 1966, as supplemented by a Supplemental Agreement dated as of
December 1, 1967 and as amended by an amendment dated as of December 1, 1972.
Under the Millstone Plant Agreement, NNECO agreed to act as CL&P's and WMECO's
agent for the following purposes:
(1) Operating and maintaining Millstone 1 and 2 ("Unit 1" and "Unit 2,"
respectively), which are two nuclear electric generating units located at a site
of approximately 500 acres (the "Millstone Site") at Millstone Point in the Town
of Waterford, Connecticut, in which units CL&P and WMECO have 81 percent and 19
percent, respectively, joint ownership interests as tenants in common, and
(2) Designing, constructing, operating, and maintaining a third nuclear
generating unit ("Unit 3") located at the Millstone Site, as agent for CL&P and
WMECO in their capacities as Lead Participants for Unit 3 pursuant to a Sharing
Agreement dated as of September 1, 1973, as amended on August 1, 1974 and
December 15, 1975 (as the same may be further amended or modified from time to
time, and in effect, the "Sharing Agreement"), by and among CL&P and WMECO and
the Associate Participants (as defined in the Sharing Agreement) named therein.
When the Millstone Plant Agreement was amended and restated in 1982, it
was contemplated that NNECO would arrange under separate agreements to construct
and finance a building (the "Simulator Building") at the Millstone Site in which
would be located a separate control room simulator for each of Unit 1 (the "Unit
1 Simulator"), Unit 2 (the "Unit 2 Simulator"), Unit 3 (the "Unit 3 Simulator")
(collectively the "Millstone Simulators") and a nuclear electric generating unit
(the "Haddam Neck Unit") owned and operated by Connecticut Yankee Atomic Power
Company ("CYAPC") in the Town of Haddam, Connecticut (the "CY Simulator") (each
a "Simulator" and all four collectively the "Simulators"). It was also
contemplated at that time that the Niantic Bay Fuel Trust would assume all of
NNECO's prior responsibilities for procuring, supplying and financing nuclear
fuel on behalf of CL&P and WMECO.
Subsequently, it has been determined that it is desirable for NNECO to
acquire the Millstone Simulators and the Simulator Building upon their
completion and to operate and maintain the Simulator Building for CL&P and WMECO
with respect to the Unit 1 and 2 Simulators, for CL&P, WMECO and the Associate
Participants with respect to the Unit 3 Simulator, and for CYAPC with respect to
the CY Simulator. In furtherance thereof, NNECO and CYAPC have entered into an
agreement as of the date hereof (the "CYAPC Agreement") setting forth the rights
and responsibilities of NNECO and CYAPC with respect to the CY Simulator and the
Simulator Building.
It has also been recognized that there are many opportunities for NNECO to
apply its nuclear engineering, construction and operations expertise for the
benefit of the Northeast Utilities System and/or the Associate Participants, and
that there may in the future be benefits to the Northeast Utilities system
and/or the Associate Participants in having NNECO assume all or part of the
functions involved in procuring, financing, owning, leasing (as lessor or
lessee) and otherwise performing supply and disposal functions with respect to
nuclear fuel, the Simulators, the Simulator Building, and any other assets for
any one or more of Units 1, 2 and 3 (collectively the "Millstone Units").
Accordingly, the parties desire to restate further the Millstone Plant
Agreement to remove the current restrictions on NNECO's activities with respect
to the Simulator Building and the Millstone Simulators, and to provide more
generally for NNECO to render such services with respect to the Millstone Units
and the nuclear fuel for the Millstone Units as CL&P and/or WMECO may from time
to time request.
AGREEMENTS
Now, therefore, in consideration of the premises and the mutual agreements
hereinafter contained, and for other good and valuable consideration, the
receipt and sufficiency of which is hereby acknowledged, the parties agree as
follows:
1. Description of Millstone Plant and Ownership.
CL&P and WMECO own the Millstone Site as tenants in common. Unit 1, a 660
MW boiling water reactor nuclear electric generating unit, and Unit 2, an 870 MW
pressurized water reactor nuclear electric generating unit, are both currently
licensed for operation at the Millstone Site. Unit 3, a 1,150 MW pressurized
water reactor electric generating unit, is under construction at the Millstone
Site and is scheduled to begin commercial operations in May, 1986.
CL&P owns an 81 percent undivided interest in Units 1 and 2, the portion
of the Millstone Site on which Units 1 and 2 are located, and all existing and
future improvements thereto, except for a refuel outage building, the Simulator
Building and the Simulators, and WMECO owns an 19 percent interest similarly
therein. These percentage interests, as the same may change from time to time
to reflect the acquisition or disposition of interests in Units 1 and 2, are
hereinafter referred to as the "Unit 1 and 2 Ownership Percentages."
Pursuant to the Sharing Agreement, CL&P and WMECO collectively own a 64.85
percent undivided interest in Unit 3 (representing approximately 745.8 MW), the
portion of the Millstone Site on which Unit 3 is located, and all existing and
future improvements thereto. CL&P and WMECO presently own, respectively,
52.6115 percent (605.032 MW) and 12.2385 percent (140.743 MW) undivided
interests in Unit 3. These shares, as the same may change from time to time as
a result of acquisition or disposition of undivided interests in Unit 3 in
compliance with the Sharing Agreement, are hereinafter referred to as the "Unit
3 Ownership Percentages."
Certain facilities and structures constructed on or used in connection
with the Millstone Site, including but not limited to, an information center, a
training building, an emergency operations center, the refuel outage building,
and warehouses, serve Units l, 2 and 3. Such facilities and structures (other
than the Simulator Building), and all renewals, replacements, additions,
retirements and modifications thereto, are hereinafter referred to as the
"Millstone Common Facilities." Title to the Millstone Common Facilities (other
than the refuel outage building, which is owned by Interet Land Co. and leased
to CL&P and WMECO) is held by CL&P and WMECO in accordance with their Unit 1 and
2 Ownership Percentages. For the purposes of this Agreement, Units 1, 2 and 3,
the associated transmission substations, the Millstone Common Facilities and
other related facilities (other than [i] related transmission lines and rights
of way, which are to be separately owned, and [ii] the Simulator Building and
the Simulators), are hereinafter referred to as the "Millstone Plant."
2. NNECO's General Responsibility.
CL&P and WMECO hereby each severally appoint and authorize NNECO as its
respective agent, with the right to employ employees and subagents, and NNECO
hereby agrees, as such agent, all subject to and in accordance with the
requirements of this Agreement and, in the case of Unit 3, the Sharing
Agreement, (i) to act for CL&P and WMECO in all matters with respect to the
procurement of materials, nuclear fuel, supplies and services for the Millstone
Plant, (ii) to operate and maintain the Millstone Plant, (iii) to manage the
Millstone Site, (iv) to act for CL&P and WMECO in all matters with respect to
the performance of their obligations as the Lead Participants under the Sharing
Agreement, including, but not limited to, their obligations concerning the
design, engineering, licensing and construction of Unit 3, (v) to own, operate
and maintain the Simulator Building on behalf of CL&P and WMECO, (vi) to enter
into leasing and/or financing transactions with respect to, and to operate and
maintain, each of the Millstone Simulators on behalf of each of the respective
owners thereof, and for the benefit of the respective owners of the Millstone
Unit to which each Millstone Simulator relates, and (vii) to provide, at the
request of CL&P and/or WMECO, in general or in specific circumstances, such
engineering, design, construction, operations, leasing (as lessor or lessee),
maintenance, management, financing and other related services with respect to
any or all of the Millstone Units and the Millstone Simulators, or portions
thereof, as the owner and/or operator thereof may reasonably request and to
which NNECO may consent, including, without limiting the generality thereof, the
procurement, financing, ownership, leasing (as lessor or lessee), supply and
disposal of nuclear fuel for any such Millstone Unit, and the ownership or
leasing (as lessor or lessee) of facilities, equipment, materials or supplies.
In furtherance of this general authority, and without limiting the
generality thereof, CL&P and WMECO severally hereby authorize NNECO, as such
agent, (a) to enter into contracts and other arrangements in the name and on
behalf of CL&P and WMECO with respect to the operation and maintenance of the
Millstone Plant, the procurement of equipment, materials, nuclear fuel, supplies
and services for the Millstone Plant, the design, engineering, licensing or
construction of Unit 3, and with respect to renewals replacements, additions,
retirements and modifications to the Millstone Plant; (b) to enter into
contracts and other arrangements in the name or on behalf of CL&P, WMECO and/or
any or all of the Associate Participants with respect to the leasing (as lessee
or lessor), financing, operation and/or maintenance of the Millstone Simulators,
the procurement of equipment, materials, supplies and services for the Millstone
Simulators, and with respect to renewals, replacements, additions, retirements
and modifications to the Millstone Simulators; (c) if requested by CL&P, WMECO,
and/or any or all of the Associate Participants to act for CL&P, WMECO and/or
such Associate Participants in all respect administration and enforcement of all
such contracts and other arrangements; (d) to take such steps as may be required
to obtain and keep in force all licenses and permits required by law, rule,
regulation or order of any governmental agency for the ownership, construction,
operation and maintenance of the Millstone Plant; (e) to make and receive all
payments in connection with the foregoing, in the name or on behalf of CL&P and
WMECO; and (f) to enter into, renew and modify leases and other arrangements
permitting the use of portions of the Millstone Site and the Simulator Building
by others where such arrangements will not interfere with the operation of the
Millstone Plant and will be to the benefit of CL&P and/or WMECO.
CL&P and WMECO each hereby affirms and ratifies any and all such
contracts, arrangements and actions heretofore taken by NNECO within the scope
of the authority conferred by this Agreement.
3. Financial Obligations of CL&P and WMECO.
(a) General.
CL&P and WMECO each agrees to pay its respective Unit 1 and 2 Ownership
Percentage of all amounts required to be paid with respect to the ownership,
licensing, maintenance, operation, leasing (including all amounts payable by
NNECO as lessee under any lease, including rent and amounts payable upon
termination of such lease) and financing of Units 1 and 2, the Unit 1 and 2
Simulators, and all renewals, replacements, additions, retirements and
modifications to any thereof, and of that portion of the costs incurred with
respect to the Simulator Building and the ownership, maintenance and operation
of the Millstone Common Facilities and the Millstone Site that is allocable to
Units 1 and 2.
Pursuant to the Sharing Agreement, each Associate Participant is liable
for its respective ownership percentage of the costs with respect to the
ownership, design, construction, maintenance and operation of Unit 3, the Unit 3
Simulator, and all renewals, replacements, additions, retirements and
modifications to either thereof, and for its respective ownership percentage of
that portion of the costs incurred with respect to the Simulator Building and
the ownership, maintenance and operation of the Millstone Common Facilities and
the Millstone Site that is allocable to Unit 3. CL&P and WMECO each agrees to
pay its respective Unit 3 Percentage Share, as hereinafter defined, of all
amounts required to be paid with respect to the ownership, design, construction,
licensing, maintenance, operation, leasing (including all amounts payable by
NNECO as lessee under any lease, including rent and amounts payable upon
termination of such lease) and financing of Unit 3, the Unit 3 Simulator, and
all renewals, replacement, additions, retirements and modifications to either
thereof, and of that portion of the costs incurred with respect to the Simulator
Building and the ownership, maintenance and operation of the Millstone Common
Facilities and the Millstone Site that is allocable to Unit 3, except to the
extent that NNECO is directly reimbursed for such amounts by the Associate
Participants. For purposes of this Agreement, the "Unit 3 Percentage Share of
each Lead Participant shall be that number, expressed as a percentage,
determined by dividing such Lead Participant's Unit 3 Ownership Percentage by
the sum of the Unit 3 Ownership Percentages of both Lead Participants.
NNECO shall allocate, in an equitable manner as instructed by CL&P and
WMECO, costs related to the Millstone Common Facilities and the Millstone Site
among Units 1, 2 and 3, and costs related to the Simulator Building among Units
1, 2 and 3 and the Haddam Neck Unit.
(b) Reimbursement payments.
With respect to each month commencing as of December 1, 1984, CL&P and
WMECO each shall pay NNECO an amount equal to such company's Allocable Share (as
defined below) of the sum of (i) all expenses of NNECO (other than those for
which NNECO is directly reimbursed by Associate Participants and/or CYAPC) for
the month with respect to the ownership, design, construction, licensing,
maintenance, operation, leasing and financing of the Millstone Plant, or any
part thereof, the Millstone Site or any portion thereof, the Simulator Building,
and the Millstone Simulators, including, but not limited to, all interest
expenses, cost of preferred stock, commitment fees and other similar fees and
expenses with respect to short-term borrowings, long-term borrowings, preferred
stock and any and all other securities issued by NNECO, other than those
described in clause (ii) below, as well as any rentals, lease payments,
termination payments, or other amounts payable by NNECO as lessee under or in
connection with any lease of the Millstone Simulators or other assets, to
finance assets and to finance other costs of performance of this Agreement; and
(ii) to the extent not directly paid to NNECO by the Associate Participants
and/or CYAPC, an amount equal to one-twelfth of the Annual Equity Return based
on NNECO's Total Equity Capitalization as at the end of the preceding month.
Payments made by CL&P and WMECO under this Subsection (b) shall be made by each
such company both in its capacity as an owner of Units 1 and 2 and as a Lead
Participant (as defined in the Sharing Agreement).
For purposes of this Subsection (b):
(A) The term "Allocable Share" shall mean that percentage of the total
payments to be made pursuant to this Subsection (b) as NNECO shall determine is
equitably attributable to each of CL&P and WMECO on the basis of the ownership
of the Unit with respect to which the costs to be reimbursed are allocable, with
allocations to Units 1 and 2 being made to each of CL&P and WMECO on the basis
of its Unit 1 and 2 Ownership Percentage, and allocations to Unit 3 being made
to each of CL&P and WMECO on the basis of its Unit 3 Ownership Percentage.
(B) the term "NNECO's Total Equity Capitalization" shall include the
amount properly reflected on NNECO's balance sheet at month end for common
stock, retained earnings, capital contributions and other paid-in capital (other
than preferred stock), and for any non-interest bearing notes or other
non-interest bearing evidences of indebtedness issued by NNECO to CL&P, WMECO,
Northeast Utilities or any other associate company (as said term is defined in
the Public Utility Holding Company Act of 1935) of NNECO, so long as the payment
of such indebtedness is expressly subordinated to borrowings by NNECO from
persons which are not affiliates of NNECO; and
(C) the term "Annual Equity Return" shall mean the weighted average
return on equity approved for CL&P and WMECO in their most recent retail rate
proceedings before the Connecticut and Massachusetts regulatory commissions,
such weighted average return to be determined annually as of December 31 for the
following calendar year and to be calculated by taking the equity return
approved for each of CL&P and WMECO in its most recent retail rate proceeding on
or before the applicable December 31 and weighting each company's equity return
by the average of its respective December 31 for the following calendar Unit 1
and 2 Ownership Percentage and its Share.
NNECO shall allocate, in accordance with instructions from CL&P and WMECO,
the amount of NNECO's Total Equity Capitalization not payable by CYAPC under the
CYAPC Agreement among Units 1, 2 and 3 so as to result in an equitable sharing
of the monthly payments with respect to Annual Equity Return among CL&P, WMECO
and the Associate Participants. Pursuant to the Sharing Agreement, each
Associate; Participant will be liable each month for its applicable ownership
percentage of one-twelfth of the Annual Equity Return on that portion of NNECO's
Total Equity Capitalization applicable to Unit 3 as of the end of the preceding
month.
The expenses referred to in clause (i) of this Subsection (b) shall
include, but shall not be limited to: operation and maintenance expenses as
determined in accordance with the Uniform System of Accounts prescribed by the
Federal Energy Regulatory Commission; license fees; assessments and other
governmental charges and sales, use, excise, franchise, personal property, gross
receipts, income and other taxes which are payable by NNECO on account of the
ownership, occupation, lease or use of the Millstone Plant, the Millstone Site
or any portion thereof, the Simulator Building, the Millstone Simulators or
other assets therefor, the construction, maintenance or operation of the
Millstone Plant, the Simulator Building or the Millstone Simulators, earnings
arising therefrom and the receipt of payments hereunder, the shutdown or
demolition of the Millstone Plant or any portion thereof, the Millstone
Simulators, earnings arising therefrom and the receipt of payments hereunder,
the shutdown or demolition of the Millstone Plant or any portion thereof, the
Simulator Building or the Millstone Simulators or on account of costs and
expenses for administration, labor, payroll taxes, employee benefits, research
and development.
The costs and expenses of NNECO with respect to the Ownership of the
Simulator Building shall be allocated among the Millstone Units so that the
respective Lead Participants or owners of each such Unit shall pay an amount
each month which will result in the payment to NNECO by such Lead Participants
or owners, over the useful life of each such Unit, in equal monthly
installments, of twenty-five percent (25%) of the cost of the Simulator Building
and all renewals, replacements, additions, retirements and modifications
thereto.
NNECO shall bill CL&P and WMECO and, as agent of CL&P and WMECO in their
capacities as Lead Participants under the Sharing Agreement, each Associate
Participant, as soon as practicable after the end of each month for all amounts
payable to NNECO by CL&P, WMECO or such Associate Participant with respect to
such month. Such bills shall be rendered in such detail as CL&P or WMECO (on
behalf of itself or on behalf of any Associate Participant) may determine is
reasonable and may be rendered on an estimated basis subject to corrective
adjustments in subsequent billing periods. CL&P and WMECO shall pay in full all
bills addressed to them within fifteen (15) days after the invoice date. In the
event CL&P or WMECO fails to pay any bill within fifteen (15) days after the
invoice date, it shall be obligated to pay interest thereon from the date of the
bill at a rate per annum two percent (2%) above the prime rate (or comparable
rate) in effect at The Connecticut Bank and Trust Company, N.A., in Hartford,
Connecticut, from time to time. Each Associate Participant shall pay NNECO in
full all bills rendered to such Associate Participant, in accordance with the
payment terms of the Sharing Agreement, including interest on late payments. If
any bill so rendered to an Associate Participant is not paid within sixty (60)
days after thereof, CL&P and WMEC0 shall pay such bill and any interest due
thereon under the Sharing Agreement and shall be reimbursed for such payment by
such Associate Participant as provided in the Sharing Agreement.
All costs and expenses with respect to the ownership, design,
construction, operation, licensing and maintenance of the Millstone Plant and
the Millstone Site and renewals, replacements, additions, modifications and
retirements in respect thereof shall be accounted for in accordance with the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission.
Notwithstanding the foregoing, interest charges on borrowed funds,
depreciation and amortization, income taxes, and property, business and
occupation and like taxes of CL&P and WMECO shall be borne entirely by such
companies.
4. Records and Accounting.
(a) NNECO shall keep all necessary books of records, books of
account and memoranda of all transactions involving the Millstone Plant, the
Millstone Site, the Simulator Building and the Millstone Simulators, and shall
make such calculations on behalf of CL&P and WMECO as may be necessary or
appropriate (i) to enable each to conform to the record keeping and reporting
requirements of the Federal Energy Regulatory Commission, (ii) to permit each to
maintain its own records and books of account, and (iii) to enable each to
fulfill its record keeping and accounting obligations under the Sharing
Agreement. NNECO shall perform all necessary invoicing and other actions on
behalf of CL&P and WMECO as required in any instance by the foregoing, all in
accordance with and subject to the provisions of this Agreement. CL&P and WMECO
shall have the right to inspect and audit NNECO books and records during normal
business hours and in a reasonable manner and for so long as such books and
records shall be preserved.
(b) NNECO shall account at least annually to all Participants (as
defined under the Sharing Agreement) in Unit 3 in such form as CL&P and WMECO
may reasonably determine for all expenses incurred in the design, engineering,
procurement, installation, construction, operation, maintenance, insuring,
licensing and shutdown of Unit 3. NNECO shall provide to Participants all other
reports required by the Sharing Agreement, including, but not limited to, cash
flow estimates, projected costs and construction progress reports.
5. Renewals, Replacements, Additions, Retirements and Modifications.
NNECO, as the agent of CL&P and WMECO, shall make on their behalf all such
renewals, replacements, additions, retirements and modifications to or with
respect to the Millstone Plant, the Millstone Common Facilities, the Millstone
Site, the Simulator Building, and the Millstone Simulators as it deems necessary
or appropriate, except that the approval of CL&P and WMECO shall be required for
any expenditure of more than $500,000 or for the replacement or retirement of
any property having an original cost of more than $500,000, and except that no
commitment, whether preliminary or otherwise, shall be made with respect to
additional generating units at the Millstone Site without the consent of both
CL&P and WMECO. Retirements, sales and other dispositions of Millstone Plant
property (including the Millstone Plant, the Millstone Common Facilities, the
Simulator Building, and the Millstone Simulators) shall be effected only in a
manner consistent with the respective mortgage indentures and other instruments
or documents under which liens on all or part of such Millstone Plant property
may arise, and, in the case of retirements, sales and other dispositions of Unit
3 property, in a manner consistent with the Sharing Agreement. Renewals,
replacements, additions, retirements and related dispositions and sales shall be
effected for the respective accounts of CL&P and/or WMECO, or, in the case of
Unit 3 property, the Participants.
6. Millstone Plant Operations.
NNECO shall have sole authority to determine when and how the Millstone
Plant shall be operated. If, in its opinion, the requests of CL&P and WMECO as
to the time or manner of operation are, in any respect, inconsistent with safety
of operation, it shall operate the Millstone Plant in accordance with its
judgment as to the requirements of safety. Subject to the foregoing, NNECO
agrees to use its best efforts to operate the Millstone Plant in accordance with
good utility operating practice and such policies as are established from time
to time by CL&P and WMECO. NNECO shall consult with CL&P and WMECO as to times
for scheduled shutdowns for refueling and maintenance, but in any case when, in
its opinion, a non-scheduled shutdown is required, it shall have full authority
to effect the shutdown.
7. Title to Property.
Except for property conveyed by any Lead Participant or Associate
Participant to a third party in connection with a leasing or other transaction
permitted by the Sharing Agreement, including but not limited to the Lead
Participants' interest in the Unit 3 Simulator, title to all property acquired
or constructed in connection with Unit 3 (including, without limitation,
property acquired for use or consumption in connection with the design,
construction, operation and maintenance of Unit 3 and any related leasehold
estate), including the Unit 3 Simulator but excluding the Simulator Building and
the refuel outage building, and also excluding materials and supplies acquired,
paid for and owned by NNECO and held in inventory (until such materials and
supplies are used), shall be held in accordance with the Sharing Agreement and
shall be in CL&P and WMECO and the Associate Participants as tenants in common
in proportion to their ownership percentages set forth in the Sharing Agreement,
subject to the right of NNECO under other provisions of this Agreement to convey
title to such property to a third party in connection with a leasing or other
transaction.
Except for property conveyed by CL&P or WMECO to a third party in
connection with a leasing or other transaction, title to all other property
acquired or constructed in connection with the Millstone Plant or the Millstone
Site (including, without limitation, property acquired for use or consumption in
connection with the operation and maintenance of the Millstone Plant and any
related leasehold estate), including the Unit 1 and 2 Simulators but excluding
the Simulator Building and the refuel outage building, and also excluding
materials and supplies acquired, paid for and owned by NNECO and held in
inventory (until such materials and supplies are used), shall be in CL&P and
WMECO as tenants in common in proportion to their Unit 1 and 2 Ownership
Percentages, subject to the right of NNECO under other provisions of this
Agreement to convey title to such property to a third party in connection with a
leasing or other transaction.
Title to the Simulator Building shall be in NNECO and shall be held in
accordance with this Agreement, subject to the right of NNECO under other
provisions of this Agreement to convey title to such property to a third party
in connection with a leasing or other transaction.
8. Capacity and Energy of Millstone Units.
CL&P and WMECO shall at all times have full ownership of, and available to
it at Units 1 and 2, that portion of the generating capability of Units 1 and 2
and the net electrical output associated therewith corresponding to their Unit 1
and 2 Ownership Percentages, and CL&P and WMECO shall each be obligated to take
its Unit 1 and 2 Ownership Percentage of the net electrical output of Units 1
and 2. The portion of the generating capability and net electrical output of
Unit 3 to which CL&P, WMECO and each Associate Participant shall be entitled
shall be governed by the Sharing Agreement and subsequent agreements among the
Participants in Unit 3.
Subject to NNECO's right to determine when and how the Millstone Plant
shall be operated, the dispatching of generation shall be done on behalf of the
respective owners by and through such dispatching agency as they may designate
from time to time.
9. Limitation of NNECO's Activities and Liability.
NNECO agrees that, during the term of this Agreement, it will confine its
activities to those contemplated by and reasonably incidental to its
responsibilities under this Agreement and the CYAPC Agreement and such other
incidental activities as may be required in order to preserve its corporate
existence, its right to do business and its other rights and franchises.
Accordingly, and inasmuch as NNECO is intended as an instrumentality for the
design, construction, operation, maintenance, leasing and financing of the
Millstone Plant, the Millstone Site, the Millstone Common Facilities, the
Simulator Building and the Millstone Simulators, it is expressly agreed that the
costs and expenses of NNECO to be reimbursed hereunder, extent not payable by
CYAPC under the Letter Agreement, shall include all of NNECO's necessary
corporate and general expenses and all other expenses, if any, necessarily
incurred by NNECO for the payment of taxes on its income or property, or
necessarily incurred by NNECO to protect and preserve its corporate existence,
its right to do business or its rights and franchises. Further, it is expressly
understood and agreed that neither CL&P, WMECO nor any Associate Participant
shall, at any time, or under any circumstances, have or make any claim for
damages against NNECO on account of damages to property, if any, caused by it or
the nondelivery by it, at any time, of all or any portion of the net electrical
output agreed to be made available from the Millstone Plant, or for any
reduction or delay in such delivery, however caused, or for any other reason of
any nature; all such claims for money damages, however and whenever arising,
being hereby expressly waived and released by each owner respectively. No
provision herein shall be construed as waiving, impairing or releasing such
rights as CL&P or WMECO may have to require the specific performance of this
Agreement.
10. Furnishing of Funds to NNECO.
CL&P and WMECO shall make funds available to NNECO for NNECO's use in
carrying out its functions under this Agreement, either by directly turning over
such funds to NNECO or by making such funds available in bank accounts of CL&P
and WMECO (either joint or several), as NNECO may request from time to time, and
NNECO may draw upon any such bank accounts.
11. Term of Agreement.
This Agreement shall continue in full force and effect, with respect to
each Unit, for the useful life and decommissioning periods of Units 1, 2 and 3,
as applicable, unless earlier terminated with respect to any or all Millstone
Units by mutual agreement of NNECO and the respective Lead Participants or
owners of the affected Millstone Unit; provided, however, that this Agreement,
or any part thereof, shall be canceled to the extent and from the time that the
performance hereunder may conflict with any rule, regulation or order of the
Securities and Exchange Commission adopted before or after the execution hereof
under the provisions of the Public Utility Holding Company Act of 1935 or with
any rule regulation or order of any federal or state regulatory body having
jurisdiction to review and to make determinations with respect to any provision
of this Agreement, this Agreement to be subject to such review and
determinations in accordance with applicable law. In the event that this
Agreement is terminated with respect to one or more of the Millstone Units prior
to the payment by the respective Lead Participants or owners of each such Unit
of a twenty-five percent (25%) share of the cost of the Simulator Building and
any renewals, replacements, additions, retirements and modifications thereto,
such respective Lead Participants or owners shall within thirty (30) days of
such termination pay to NNECO the remaining balance of such share.
12. Amendments.
This Agreement may be amended at any time by mutual written agreement of
the parties hereto.
13. Successors and Assigns.
This Agreement shall inure to the benefit of and bind the successors and assigns
of the parties hereto, but it may be assigned in whole or in part by CL&P and/or
WMECO only as part of an assignment (including any assignment in connection with
a financing) of a corresponding ownership interest in one or more of the
Millstone Units and/or any part of the Millstone Plant, the Millstone Site, the
Millstone Common Facilities, the Simulator Building, any one or more of the
Millstone Simulators, the nuclear fuel or other assets for any one or more of
the Millstone Units.
IN WITNESS WHEREOF each of the parties has caused this Agreement to be
duly executed.
THE CONNECTICUT LIGHT AND POWER COMPANY
By /s/Leonard A. O'Connor
----------------------------------------------
Name: Leonard A. O'Connor
Title: Vice President & Treasurer
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By /s/Leonard A. O'Connor
----------------------------------------------
Name: Leonard A. O'Connor
Title: Vice President & Treasurer
NORTHEAST NUCLEAR ENERGY COMPANY
By /s/Leonard A. O'Connor
----------------------------------------------
MEMORANDUM OF UNDERSTANDING
JOINT USE OF SPECIFIED LOCAL TRANSMISSION AND DISTRIBUTION FACILITIES
Memorandum of Understanding dated as of January 1, 1984 by and among The
Connecticut Light and Power Company, Holyoke Power and Electric Company, Holyoke
Water Power Company and Western Massachusetts Electric Company, each an
operating subsidiary of Northeast Utilities (the "Companies").
RECITALS
Certain of the Companies presently serve portions of their respective
local load areas by making joint use of particular local transmission and
distribution facilities with one or more of the other Companies under the terms
of the agreement listed in Exhibit A hereof.
The Companies have entered into a MEMORANDUM OF UNDERSTANDING regarding
POOLING OF GENERATION AND TRANSMISSION, dated as of June 1, 1970, whereby the
Companies have agreed to pool their generation and backbone transmission
facilities on a one-system basis. Said MEMORANDUM OF UNDERSTANDING superseded
portions of various agreements between the Companies pursuant to which certain
of the Companies had formerly made joint use of both backbone and local
transmission and distribution facilities.
The Companies have constructed and are operating local transmission and
distribution facilities on a joint basis, and intend to plan, construct and
operate additional facilities of this type with the objective of supplying the
electric requirements of their customers at the lowest practicable costs
consistent with proper standards of reliability.
The Companies have agreed that their respective joint uses of local
transmission and distribution facilities will be on the basis of coordinated
operations by the Companies and in accordance with good utility practice.
The Companies contemplate that their joint use of specified local
transmission and distribution facilities will be for relatively long periods of
time and should be made in accordance with consistent and uniform understandings
regarding sharing of resulting benefits and burdens.
The Companies intend, with the assistance of Northeast Utilities Service
Company, from time to time to review the adequacy of jointly used local
transmission and distribution facilities and appropriately adjust charges for
such use.
The Companies, with the assistance of Northeast Utilities Service Company,
further intend to coordinate and share the use of local transmission and
distribution facilities wherever practicable in order that such facilities will
have the least adverse effect on the environment.
In the light of these circumstances, therefore, the Companies have
concluded that a more comprehensive arrangement among them is necessary and
desirable to provide reasonable assurance of attaining the above objectives and
have decided to share the costs of specified local transmission and distribution
facilities commencing as of the effective date of the Agreement.
ACCORDINGLY, it is agreed that:
SECTION 1. DATES OF COMMENCEMENT, TERMINATION, ETC.
(a) Subject to the acceptance of this Memorandum as a rate filing by the
Federal Energy Regulatory Commission, this Memorandum shall be effective as of
January 1, 1984. The agreement listed in Exhibit A attached hereto shall be
terminated as of the effective date of this Agreement and relating to the
respective facility.
(b) This Memorandum shall continue in effect until amended or terminated
by mutual agreement or by order of public authority having jurisdiction.
SECTION 2. JOINT-USE FACILITIES
The Companies shall plan, construct, participate in and operate local
transmission and distribution facilities for joint use wherever practicable in
order to achieve the objectives recited above. Each such specified facility
shall be known as a Joint-Use Facility. The non-owner(s) of such Joint-Use
Facilities shall be known as the joint user(s).
SECTION 3. GENERAL PRINCIPLES OF JOINT USE
(a) Normally, the use of a Joint-Use Facility will be in order to
transmit electricity from one point, station or substation, to another location,
using one (or more) Company's local transmission and distribution facilities
which have sufficient load carrying capabilities to permit the efficient use of
a portion of such capacity by another Company, or such joint use may take the
form of utilizing substation and distribution facilities (either existing or
jointly planned) thereby making duplicate investments unnecessary. In some
instances, one Company may install new facilities for the initial sole use of
another Company.
(b) The owner of a Joint-Use Facility should be reimbursed by the joint
user(s) for an appropriate share of the owner's costs with respect thereto. The
components of costs to be considered in determining such amount to be paid to
the owner should include an adequate provision for investment return to the
owner and all operation and maintenance expense, depreciation expense and tax
expense borne by the owner with respect to the Joint-Use Facility.
(c) The Companies agree that it is generally reasonable to determine the
amount to be paid by one Company for the use of another's local transmission and
distribution facilities by allocating the costs with respect to such facilities
between the owner and joint user(s) in proportion to the respective relative
loads supplied therefrom. It is recognized, however, that in many
circumstances, allocation of costs based on factors other than, or in addition
to, the actual load supplied may result in a more equitable sharing of costs.
(d) It is expected that the joint use of certain facilities will continue
for many years. Therefore, the load carrying capabilities (existing and
potential) of particular facilities and the forecasted use by each Company of
such facilities should be considered in making decisions with respect to joint
use.
(e) If, in the opinion of the owning Company, the total load carrying
capability of a Joint-Use Facility may became inadequate for its own needs
together with the joint use of another Company, the facilities required for the
purposes of the owning Company and those required to continue to adequately
serve the particular local area load of the joint user(s), and the extent, if
any, of continued joint use of such facilities shall be determined by mutual
agreement.
(f) The extent of joint use of facilities, the amounts to be paid for
such use, and the method of determining such amounts shall be reviewed
periodically and changed by mutual agreement to the extent appropriate.
(g) Each Company shall be solely responsible for providing all
electricity required to supply its own loads including all capacity and energy
losses incidental to the transmission, transformation and distribution of such
electricity incurred on any Joint-Use Facility owned by another Company.
(h) Metering of electricity provided by one Company and transmitted and
distributed on transmission and distribution facilities of another Company shall
be done in such manner and at such places as may be mutually agreed from time to
time. For accounting purposes, segregation shall be made of such electricity
from other electricity flowing on and between the systems of the Companies.
SECTION 4. SHARING COSTS OF JOINT-USE FACILITIES
(a) The Companies shall share the costs of Joint-Use Facilities on the
basis of the relation of their respective uses of each such facility. For the
purposes of this Memorandum, the method of determination of the respective uses
of each Joint-Use Facility will be specified in Appendix I attached hereto.
(b) Costs of each such Joint-Use Facility for any month shall be those
costs associated with the Operation and Maintenance Expense, Depreciation
Expense, Property Tax Expense, Leasing Expense, Investment Return, Income Tax
Expense and Other Tax Expense with respect to each such facility for each month
of joint use.
(c) Northeast Utilities Service Company shall act as accounting and
billing agent for the Companies under this Memorandum. Bills shall be rendered
monthly on a net basis and may be based on estimates subject to subsequent
correction to actual.
SECTION 5. DEFINITIONS
As used in this Memorandum and all Attachments, Exhibits and Appendices
hereto, the following terms shall have the following respective meanings:
(a) The term Accumulated Depreciation means an amount equal to the
accrued Depreciation Expense minus the original cost of retirements and the cost
of removal plus any salvage with respect thereto.
(b) The term Billing Peak Load means the maximum load supplied by a
Company on a Joint-Use Facility during any clock hour during the preceding
sixteen (16) calendar months. The Billing Peak load may be adjusted by mutual
agreement to reflect transfer of load from one Joint-Use Facility to another or
otherwise, provided that such transfer shall be part of a mutually agreed upon
system change or coordinated operation among the Companies.
(c) The term Depreciable Investment, as applied to any Joint-Use Facility
means the part of the Investment in such Joint-Use Facility which is depreciable
in accordance with the provisions of the Uniform System of Accounts prescribed
by the Federal Energy Regulatory Commission.
(d) The term Investment as applied to any Joint-Use Facility means the
original cost thereof as shown on the books of the owner in accordance with the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission at the applicable time (reflecting the cost of any betterments,
improvements and additions thereto and the cost of any retirements therefrom ).
(e) The term Joint-Use Facilities and/or Local Facilities as used herein
means any facility included in Utility Plant (including, but not limited to,
station structures and improvements, station equipment, overhead and underground
lines, land and land rights) which by mutual agreement is used by a joint
user(s) to supply its local loads and is described in an attachment to Appendix
I attached hereto.
References in this Section to mutual agreement relate to the agreement
between the owner of the Joint-Use Facility and the one or more joint users
participating in or directly affected by the joint use of the Joint-Use Facility
which agreement is to be included as part of the appropriate attachment to
Appendix I attached hereto relating to each specified Joint-Use Facility.
SECTION 6. REIMBURSEMENT OF CERTAIN TAXES
If at any time, any of the Companies is required by any state or local
governmental authority to pay a gross revenue or other similar tax with respect
to payments made to it under this Memorandum by any other Company, the Company
paying the tax must be promptly reimbursed by the joint user(s) for such amount
of the tax.
SECTION 7. LIABILITY
(a) As among the Companies, each Company will indemnify and save the
others harmless from and against all costs and damages by reason of bodily
injury, death or damage to the property of third persons caused by or sustained
on facilities owned by it, except that each Company shall be solely responsible
and shall bear all costs of claims by its own employees growing out of any
workmen's compensation law.
(b) The Companies agree that they shall endeavor to operate and maintain
the irrespective facilities involved in this Memorandum in accordance with good
utility practice, but none of the Companies guarantees an uninterrupted transfer
of electricity on its facilities, and each Company hereby waives all claims
against any other Company for damages of any kind resulting from any stoppage,
interruption, increase, diminution or variation in service whether resulting
from the negligence of another Company otherwise.
SECTION 8. TREATMENT OF HOLYOKE COMPANIES
Holyoke Water Power Company and Holyoke Power and Electric Company shall
constitute a single party for all purposes of Sections 3 and 4 of this
Memorandum.
SECTION 9. TERMINATION
(a) Upon termination of this Memorandum or the retirement of one or more
of the jointly uses local facilities or upon a significant decrease in the use
of the facilities specified in one or more of the attachments to Appendix I
attached hereto, the Companies shall determine by mutual agreement such
appropriate adjustments and provisions as may be necessary to provide for
reasonable reimbursement to each owning Company for and with respect to such
portions of the facilities constructed to effectuate the purposes of this
Memorandum but which are not required by the owning Company in connection with
its own operations after such termination or decrease.
(b) Notwithstanding the termination of this Memorandum or the retirement
of one or more of the facilities list in the attachments to Appendix I attached
hereto, the applicable provisions shall continue in effect after such
termination to the extent necessary to provide for adjustments and provisions
under this Section and for final billing and other adjustments.
SECTION 10. ARBITRATION
In the event of any dispute between any of Companies or failure of any of
the Companies to agree as to any matter to be determined by mutual agreement
under the provisions of this Memorandum or as to the interpretation of or
operation under any provision of this Memorandum upon notice from any Company,
such dispute shall be submitted to arbitration. If agreement is not reached
regarding appointment of an arbitrator within 30 days after the notice of
submission to arbitration is given by a Company, any affected Company may apply
to the American Arbitration Association for appointment of the arbitrator. The
arbitrator shall be a disinterested person who is qualified in the area of the
matter in dispute. The arbitrator shall conduct the proceeding in accordance
with and subject to the rules of the American Arbitration Association and shall
render his decision with respect to the matter in controversy as promptly as
practicable. The arbitrator shall be authorized only to interpret and apply the
provisions of this Memorandum, and he shall have no power to modify or change
this Memorandum in any manner. The decision of the arbitrator shall be final
and binding on the Companies. Each of the Companies in any arbitration
proceeding shall bear its own expenses, and the expenses and fees of the
arbitrator and any other expenses arising from the arbitration proceeding shall
be shared equally by the Companies participating in the arbitration.
SECTION 11. MISCELLANEOUS
(a) This Memorandum shall be binding upon and shall inure to the benefit
of the Companies and their respective successors and assigns.
(b) This Memorandum including all Appendices, Exhibits and Attachments is
subject to present and future state or federal statutes and to present or future
regulations or orders properly issued by any regulatory agencies having
jurisdiction over matters contained herein.
SECTION 12. APPLICABLE LAW
This Memorandum shall be interpreted, performed and controlled by and in
accordance with the laws of the state of Connecticut.
THE CONNECTICUT LIGHT AND POWER COMPANY
By /s/ Frank P. Sabatino
Its Vice President
WESTERN MASSACHUSETTS ELECTRIC COMPANY
By /s/ Frank P. Sabatino
Its
HOLYOKE WATER POWER COMPANY
By /s/ Frank P. Sabatino
Its
HOLYOKE POWER AND ELECTRIC COMPANY
By /s/ Frank P. Sabatino
Its
EXHIBIT A
The following agreement is to be terminated as of the effective date of
this Agreement and relating to the specific facility:
1. Agreement between The Hartford Electric Light Company and Western
Massachusetts Electric Company relating to the Southwick Substation (MWME FPC
Rate Schedule 13).
Appendix I
Local Facilities Agreement
The annual costs of the Local Facilities shall be the estimated annual costs of
owning, operating, maintaining, and supporting those facilities, including
applicable leasing costs. These costs shall be computed
annually. In determining such costs, the provisions of the Uniform System of
Accounts prescribed by the Federal Energy Regulatory Commission for major
electric utilities and licensees shall be controlling, to the extent applicable.
I. Determination of Investment Base
The Investment Base is the sum of Net Investment and Working Capital as
determined at the end of the preceding calendar year unless there is a
substantial change (of $500,000 or more) in the Investment Base during the
calendar year.
A. Net Investment
Net investment shall be the original cost (including the cost of any
betterments, improvements, and additions thereto and excluding the cost of any
retirements therefrom) of the Local Facility, as reflected on the Owner's books
of account, less the sum of (1) accumulated depreciation and (2) accumulated
deferred federal and state income taxes arising from liberalized depreciation
and accelerated amortization. Accumulated depreciation shall reflect retirements
and net salvage realized. Accumulated deferred income taxes shall be computed
using the same life, methods, rates, salvage factors, and accounting practices
as reflected on the Owner's books of account, and shall be applicable to
investments made in such facilities on or subsequent to the effective date of
this Agreement.
In the event that the Owner has employed a liberalized tax
depreciation or accelerated depreciation method and thereafter employs a
different method, any necessary allowance or adjustment shall be made in order
to insure that any such change of methods does not result in any overcollection
or undercollection by the Owner.
B. Working Capital
Working capital to be included in the Investment Base shall include
45 days (out of 360) of related operation and maintenance expense and the
Owner's best estimate of the cost of related materials and supplies and an
appropriate allowance for any payments made pursuant to the prepayment
provisions applicable leases.
II. Determination of Annual Carrying Costs of Local Facilities
The following cost factors shall be used in determining the annual
carrying costs of the Local Facilities:
A. Operation and Maintenance Expense
B. Property Tax Expense
C. Depreciation Expense
D. Investment Return
E. Income Tax Expense
F. Investment Tax Credit Allowance
G. Leasing Expense
H. Other Tax Expense
A. Operation and Maintenance Expense
Operation and maintenance expense means an amount equal to the sum of
the following: (1) the actual cost (or the best estimate thereof) of the annual
expense of operating and maintaining the Local Facility; (2) an appropriate
allowance to cover the related administrative and general expenses, including,
but not limited to, employee pensions and benefits, federal and state taxes
related to the direct payroll expense,
and property insurance expense for the Local Facility. The allowance for the
administrative and general expenses is initially estimated at 40 percent of the
operation and maintenance expense provided in (1) above. This allowance shall be
subject to periodic review, and shall be revised, when and to the extent deemed
appropriate by the Owner, in accordance with the results of any such review.
B. Property Tax Expense
Property tax expense shall consist of those taxes or excise payments
that are based upon the assessed value of the Local Facility, and specifically
identified with that facility, or the Owner's best estimate thereof. The
procedures for determining the amounts of any such estimates shall be determined
by the Owner. The Owner shall have the sole discretion in any negotiations with
taxing authorities.
C. Depreciation Expense
Depreciation expense shall be determined on the same basis as
recorded on the Owner's books of account.
D. Investment Return
Investment return for the Local Facility shall be determined by
multiplying the Owner's investment base by the Owner's composite cost of
capital. The Owner's composite cost of capital shall be computed on the basis of
its cost, expressed in percentages, for (1) bonds and other long-term
indebtedness, (2) preferred stock, and (3) for the return on common equity as
granted in its most recent rate order from the regulatory authority having
principal jurisdiction over the Owner's rates. These costs shall be combined in
accordance with the following formula to determine the Owner's composite cost of
capital:
Composite Cost of Capital = Ax8 + CxD + ExF in which:
A - the Owner's cost for long-term indebtedness
B - the percentage of the Owner's capitalization represented by long-term
indebtedness
C - the Owner's cost for preferred stock
D - the percentage of the Owner's capitalization represented by preferred
stock
E - the Owner's return on common equity
F - the percentage of the Owner's capitalization represented by common
equity
In the above formula, the Owner's capitalization consists of its components of
long-term indebtedness, preferred stock, and common equity. Those components and
the percentage of capitalization represented by each of those components shall
be rounded off to the nearest whole number.
The Owner's cost of long-term indebtedness in the above formula is the weighted
average of the costs of its various issues of long-term indebtedness. The cost
of an issue of long-term indebtedness shall be computed in accordance with the
following formula:
Cost of Issue in Percent =
(Dividend Rate (%) x Aggregate Par or Stated Value) /
(Proceeds to Company from Underwriter or Investor less Company Expenses of
Issue)
The Owner's investment return for a year shall be computed initially at the
beginning of the year on the basis of its investment base and its composite cost
of capital as of the beginning of the year. The investment return, as so
computed, shall be recomputed each time that a substantial change in its
Investment Base or composite cost of capital occurs during the year, and at any
such other time as the Companies mutually agree is appropriate.
E. Income Tax Expense
An allowance for income taxes shall be computed in accordance with
the following formula:
(Te / 1-Te) x [(IB (PE + CE)) + (DB - DT)]
Te - the effective combined federal and state statutory income tax
rate of the Owner
IB - Investment Base
PE - Weighted Preferred Stock Component (C x D in II.D.)
CE - Weighted Common Equity Component (E x F in II.D.)
DB - Book depreciation
DT - Tax depreciation
Where the book depreciation (DB) and tax depreciation (DT) apply only
to investments made in the Local Facility prior to the effective date of this
Agreement.
F. Investment Tax Credit Allowance
Applicable investment tax credits are those based upon the Owner's
applicable investments placed in service on or subsequent to the effective date
of this Agreement.
An allowance for any applicable investment tax credit shall be
reflected ratably over the remaining book depreciable life of the Local
Facility. This allowance for the normalized investment tax credit shall be
calculated by dividing the investment tax credit by the estimated remaining book
depreciable life, by one minus the effective tax rate, as described below:
IC / (1-Td)N
IC - the applicable investment tax credit
Te - as previously defined
N - remaining book depreciable life of the Local Facility expressed
in years
G. Leasing Expense
Leasing expense shall consist of those leasing costs (or rental
payments) charged to the Owner and related to the Local Facility.
H. Other Tax Expense
Other tax expense shall consist of any taxes or excises which are
incurred in the future as a result of constructing, owning, operating, or
leasing the Local Facility. Such tax expense shall include any tax, on gross
revenues or any tax pertaining to the billing of those annual costs, which is
not recognized elsewhere in this Agreement.
III. Allocation of Annual Carrying Costs of NU Local Facilities
The Annual Carrying Costs listed above (II.A. through II.E.) shall be
allocated to the Participants as follows:
A. Transmission Facilities
Jointly used transmission facilities shall be allocated in accordance
with the provisions of the NUG&T Agreement.
B. Substation Facilities
One-half of the cost of such jointly used substation facilities shall
be allocated in accordance with the provisions of the NUG&T Agreement and the
remainder of such costs shall be allocated on the basis of the number of feeder
positions assigned. Spare (unloaded) feeder positions shall be included in this
allocation. When one party's feeder is tapped in the field, this allocation will
still reflect the number of feeder positions assigned to each party.
C. Distribution Facilities
1. Duct Lines - Shall be allocated on the basis of the number of
ducts actually utilized by each party. Spare ducts shall be included in this
allocation.
2. Feeders - When one party's feeder is tapped in the field, the
costs of the jointly used portion shall be allocated on an equal basis between
the parties.
ATTACHMENT 1
January 6, 1993
TO: H. C. Walmsley
FROM: B. K. Morton (x5369)
SUBJECT: NU Local Facilities Adjustment
Below are the adjustments to the December 1992 NU Local Facilities billings:
Chicopee Franconia Silver St Southwick Trans.
S/S S/S S/S S/S Distrib.
HWP=User CL&P=User CL&P=User CL&P=User CL&P=User
Total User Carrying Charge $ 0 $78,285 $24,165 $47,096 $18,041
Less: Amount Billed
Jan-Nov 1992 369,600 67,100 20,900 79,200 14,300
Less: Adjustment for
Nov & Dec 1991 67,169
Adjustment Due To/
(Reimbursed By) WMECO ($436,769) $11,185 $3,265 ($32,104) $3,741
Detailed below are the 1993 monthly billings for NU Local Facilities.
Monthly Billing To Be
Collected Jan-Nov $ 0 $6,500 $2,000 $3,900 $1,500
We will provide you with the December adjustment to actual carrying cost in
January of 1994.
Please contact me if you have any questions.
bkm/bm
cc: R. A. Baumann
J. M. Geruch
J. J. Roman
NORTHEAST UTILITIES
LOCAL FACILITIES
FRANCONIA SUBSTATION
1992 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $37,660 5,380 10,760
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 11,475 221 1,367
WKNG CAP ALLOW 20,621 465 3,043
TOTAL ALLOWANCE 32,096 686 4,410
TOTAL NON-DEPRECIABLE 69,756 6,066 15,170
DEPRECIABLE INVESTMENT 1,311,950 25,231 156,312
ACCUMULATED DEPRECIATION (595,088) (19,918) (66,865)
ACCUM DEFERRED INC TAXES (21,582) 0 (1,133)
NET INVESTMENT $765,036 11,379 103,484
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $112,265 2,328 14,427
ADMIN. & GEN. EXPENSE 44,906 931 5,771
LEASING EXPENSE 31,192 1,843 16,591
DEPRECIATION EXPENSE 25,580 487 3,017
PROPERTY TAX EXPENSE 13,328 302 1,650
INVESTMENT RETURN 72,143 1,073 9,758
INCOME TAX EXPENSE 23,537 329 3,224
INVESTMENT TAX CREDIT (114) 0 0
OTHER TAX EXPENSE 0 0 0
TOTAL CARRYING CHARGES $322,837 7,293 54,438
ALLOCATED % TO NON-OWNER 21.99% 100.00%
CARRYING CHARGE ALLOCATION $70,992 7,293
TOTAL CARRYING CHARGE
TO NON-OWNER (CL&P) 78,285
NORTHEAST UTILITIES
LOCAL FACILITIES
SILVER ST SUBSTATION
1992 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0 N/A 0
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 8,135 N/A 1,648
WKNG CAP ALLOW 14,642 N/A 3,018
TOTAL ALLOWANCE 22,777 N/A 4,666
TOTAL NON-DEPRECIABLE 22,777 N/A 4,666
DEPRECIABLE INVESTMENT 930,072 N/A 188,428
ACCUMULATED DEPRECIATION (379,849) N/A (113,096)
ACCUM DEFERRED INC TAXES (33,735) N/A (1,092)
NET INVESTMENT $539,265 N/A 78,906
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $83,668 N/A 17,248
ADMIN. & GEN. EXPENSE 33,467 N/A 6,899
DEPRECIATION EXPENSE 18,138 N/A 3,639
PROPERTY TAX EXPENSE 11,962 N/A 2,423
INVESTMENT RETURN 50,853 N/A 7,441
INCOME TAX EXPENSE 17,118 N/A 2,293
INVESTMENT TAX CREDIT (26) N/A 0
OTHER TAX EXPENSE 0 N/A 0
TOTAL CARRYING CHARGES $215,180 N/A 39,943
ALLOCATED % TO NON-OWNER 11.23%
CARRYING CHARGE ALLOCATION
TO NON-OWNER (CL&P) $24,165
NORTHEAST UTILITIES
LOCAL FACILITIES
SOUTHWICK SUBSTATION
1992 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $8,355 0 440
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 8,208 0 264
WKNG CAP ALLOW 14,685 0 477
TOTAL ALLOWANCE 22,893 0 741
TOTAL NON-DEPRECIABLE 31,248 0 1,181
DEPRECIABLE INVESTMENT 938,352 0 30,143
ACCUMULATED DEPRECIATION (574,715) 0 (21,113)
ACCUM DEFERRED INC TAXES (14,552) 0 (524)
NET INVESTMENT $380,333 0 9,687
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE 83,914 0 2,727
ADMIN. & GEN. EXPENSE 33,566 0 1,091
DEPRECIATION EXPENSE 18,254 0 583
PROPERTY TAX EXPENSE 8,633 0 279
INVESTMENT RETURN 35,865 0 914
INCOME TAX EXPENSE 11,227 0 272
INVESTMENT TAX CREDIT (90) 0 (22)
OTHER TAX EXPENSE 0 0 0
TOTAL CARRYING CHARGES $191,369 0 5,844
ALLOCATED % TO NON-OWNER 24.61% 0.00%
CARRYING CHARGE ALLOCATION $47,096 0
TOTAL CARRYING CHARGE
TO NON-OWNER (CL&P) $47,096
NORTHEAST UTILITIES
LOCAL FACILITIES
FRANCONIA DISTRIBUTION
1992 CHARGES
WMECO
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 1,656
WKNG CAP ALLOW 1,195
TOTAL ALLOWANCE 2,851
TOTAL NON-DEPRECIABLE 2,851
DEPRECIABLE INVESTMENT 189,271
ACCUMULATED DEPRECIATION (97,944)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 94,178
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 6,827
ADMIN. & GEN. EXPENSE 2,731
DEPRECIATION EXPENSE 3,785
PROPERTY TAX EXPENSE 2,421
INVESTMENT RETURN 8,881
INCOME TAX EXPENSE 3,061
INVESTMENT TAX CREDIT 0
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 27,706
ADJUSTMENT PERCENTAGE 0.1875
CL&P OWES TO WMECO $ 5,195
NORTHEAST UTILITIES
LOCAL FACILITIES
FRANCONIA DISTRIBUTION
1992 CHARGES
CL&P
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 807
WKNG CAP ALLOW 583
TOTAL ALLOWANCE 1,390
TOTAL NON-DEPRECIABLE 1,390
DEPRECIABLE INVESTMENT 92,225
ACCUMULATED DEPRECIATION (46,380)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 47,235
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 3,333
ADMIN. & GEN. EXPENSE 1,333
DEPRECIATION EXPENSE 3,042
PROPERTY TAX EXPENSE 1,180
INVESTMENT RETURN 4,454
INCOME TAX EXPENSE 1,618
INVESTMENT TAX CREDIT 0
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 14,960
ADJUSTMENT PERCENTAGE 0.5000
CL&P OWES TO WMECO $ 7,480
NORTHEAST UTILITIES
LOCAL FACILITIES
SILVER STREET DISTRIBUTION
1992 CHARGES
COMMON
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 1,865
WKNG CAP ALLOW 1,348
TOTAL ALLOWANCE 3,213
TOTAL NON-DEPRECIABLE 3,213
DEPRECIABLE INVESTMENT 213,187
ACCUMULATED DEPRECIATION (21,019)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $195,381
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 7,702
ADMIN. & GEN. EXPENSE 3,081
DEPRECIATION EXPENSE 4,100
PROPERTY TAX EXPENSE 2,727
INVESTMENT RETURN 18,424
INCOME TAX EXPENSE 6,485
INVESTMENT TAX CREDIT (39)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 42,480
ADJUSTMENT PERCENTAGE 0.0833
CL&P OWES TO WMECO $ 3,539
NORTHEAST UTILITIES
LOCAL FACILITIES
SOUTHWICK DISTRIBUTION
1992 CHARGES
COMMON
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 489
WKNG CAP ALLOW 353
TOTAL ALLOWANCE 842
TOTAL NON-DEPRECIABLE 842
DEPRECIABLE INVESTMENT 55,908
ACCUMULATED DEPRECIATION (6,357)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 50,393
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 2,018
ADMIN. & GEN. EXPENSE 807
DEPRECIATION EXPENSE 1,085
PROPERTY TAX EXPENSE 715
INVESTMENT RETURN 4,752
INCOME TAX EXPENSE 1,595
INVESTMENT TAX CREDIT (14)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 10,958
ADJUSTMENT PERCENTAGE 0.1667
CL&P OWES TO WMECO $ 1,827
NOT EFFECTIVE AS OF NOVEMBER 1, 1991
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
CHICOPEE SUBSTATION
1984 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (HWP) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 3,295 1,098 1,098
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 12,297 2,390 1,378
WKNG CAP ALLOW 12,429 2,584 1,503
TOTAL ALLOWANCE 24,726 4,974 2,881
TOTAL NON-DEPRECIABLE 28,021 6,072 3,979
DEPRECIABLE INVESTMENT 1,218,604 236,837 136,537
ACCUMULATED DEPRECIATION (508,492) (66,191) (39,641)
ACCUM DEFERRED INC TAXES 0 0 0
NET INVESTMENT $ 738,133 176,718 100,875
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 71,023 14,764 8,589
ADMIN. & GEN. EXPENSE 28,409 5,906 3,436
DEPRECIATION EXPENSE 39,447 7,759 4,481
PROPERTY TAX EXPENSE 22,825 4,445 2,571
INVESTMENT RETURN 88,945 21,295 12,155
INCOME TAX EXPENSE 54,991 13,119 7,501
INVESTMENT TAX CREDIT (2,287) (559) (311)
OTHER TAX EXPENSE 0 0 0
TOTAL CARRYING CHARGES $ 303,353 66,730 38,422
ALLOCATED % TO NON-OWNER * 81.28% 100.00%
CARRYING CHARGE ALLOCATION 246,565 66,730
TOTAL CARRYING CHARGE
TO NON-OWNER (HWP) 313,295
* SEE PAGE 3 OF EXHIBIT 1 TO APPENDIX I
NOT EFFECTIVE AS OF NOVEMBER 1, 1991
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
CHICOPEE SUBSTATION
1984 INVESTMENTS
SOLE USE SOLE USE
ITEM JOINT USE NON-OWNER (HWP) OWNER (WMECO)
TOTAL STATION LAND INVEST. $ 3,295 1,098 1,098
"PTF" LAND INVEST. 0 0 0
"NUG&T" LAND INVEST. 0 0 0
LOCAL FACIL. LAND INVEST. $ 3,295 1,098 1,098
TOTAL STATION DEPR. INVEST. $ 1,218,604 236,837 136,537
"PTF" DEPRECIABLE INVEST. 0 0 0
"NUG&T" DEPRECIABLE INVEST. 0 0 0
LOCAL FACIL. DEPR. INVEST. $ 1,218,604 236,837 136,537
LOCAL FACIL. TOTAL INVEST. $ 1,221,899 237,935 137,635
NOT EFFECTIVE AS OF NOVEMBER 1, 1991
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
CHICOPEE SUBSTATION
1984 ALLOCATORS
LOAD PERCENTAGES:
NON-OWNER PEAK (HWP) 238.2 MW
OWNER PEAX (WMECO) 10.2 MW
TOTAL OF PEAK LOADS 248.4 MW
NON-OWNER PERCENTAGE 95.89%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 47.95%
FEEDER POSITIONS:
NON-OWNER FEEDERS (HWP) 8.0
OWNER FEEDERS (WMECO) 4.0
TOTAL OF FEEDER POSITIONS 12.0
NON-OWNER PERCENTAGE 66.67%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 33.33%
TOTAL NON-OWNER ALLOCATOR (HWP) 81.28%
ALLOCATED PER APPENDIX I SECTION III
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
FRANCONIA SUBSTATION
1984 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 37,660 5,380 10,760
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 10,274 383 1,288
WKNG CAP ALLOW 11,579 613 1,953
TOTAL ALLOWANCE 21,853 996 3,241
TOTAL NON-DEPRECIABLE 59,513 6,376 14,001
DEPRECIABLE INVESTMENT 1,018,179 37,932 127,635
ACCUMULATED DEPRECIATION (303,273) (10,426) (37,407)
ACCUM DEFERRED INC TAXES 0 0 0
NET INVESTMENT $ 774,419 33,882 104,229
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 60,937 2,526 8,501
ADMIN. & GEN. EXPENSE 24,375 1,010 3,400
LEASING EXPENSE 29,280 5,459 14,888
DEPRECIATION EXPENSE 33,094 1,259 4,237
PROPERTY TAX EXPENSE 15,688 644 2,056
INVESTMENT RETURN 93,317 4,083 12,560
INCOME TAX EXPENSE 57,181 22,510 7,758
INVESTMENT TAX CREDIT (2,721) (124) (343)
OTHER TAX EXPENSE 0 0 0
TOTAL CARRYING CHARGES $ 311,151 17,367 53,057
ALLOCATED % TO NON-OWNER * 24.91% 100.00%
CARRYING CHARGE ALLOCATION 77,508 17,367
TOTAL CARRYING CHARGE
TO NON-OWNER (HWP) 94,875
* SEE PAGE 7 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
FRANCONIA SUBSTATION
1984 INVESTMENTS
SOLE USE SOLE USE
ITEM JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
TOTAL STATION LAND INVEST. $ 37,660 5,380 10,760
"PTF" LAND INVEST. 0 0 0
"NUG&T" LAND INVEST. 0 0 0
LOCAL FACIL. LAND INVEST. $ 37,660 5,380 10,760
TOTAL STATION DEPR. INVEST. $ 1,018,179 37,932 127,635
"PTF" DEPRECIABLE INVEST. 0 0 0
"NUG&T" DEPRECIABLE INVEST. 0 0 0
LOCAL FACIL. DEPR. INVEST. $ 1,018,179 37,932 127,635
LOCAL FACIL. TOTAL INVEST. $ 1,055,839 43,312 138,395
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
FRANCONIA SUBSTATION
1984 ALLOCATORS
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 85.8 MW
OWNER PEAX (WMECO) 259.8 MW
TOTAL OF PEAK LOADS 345.6 MW
NON-OWNER PERCENTAGE 24.83%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 12.41%
FEEDER POSITIONS:
NON-OWNER FEEDERS (CL&P) 2.0
OWNER FEEDERS (WMECO) 6.0
TOTAL OF FEEDER POSITIONS 8.0
NON-OWNER PERCENTAGE 25.00%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 12.50%
TOTAL NON-OWNER ALLOCATOR (CL&P) 24.91%
ALLOCATED PER APPENDIX I SECTION III
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SILVER ST. SUBSTATION
1984 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0 N/A 0
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 5,884 N/A 1,973
WKNG CAP ALLOW 6,592 N/A 2,258
TOTAL ALLOWANCE 12,476 N/A 4,231
TOTAL NON-DEPRECIABLE 12,476 N/A 4,231
DEPRECIABLE INVESTMENT 583,085 N/A 195,535
ACCUMULATED DEPRECIATION (194,276) N/A (65,328)
ACCUM DEFERRED INC TAXES 0 N/A 0
NET INVESTMENT $ 401,285 N/A 134,438
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 37,670 N/A 12,903
ADMIN. & GEN. EXPENSE 15,068 N/A 5,161
DEPRECIATION EXPENSE 19,239 N/A 6,480
PROPERTY TAX EXPENSE 8,336 N/A 2,796
INVESTMENT RETURN 48,355 N/A 16,200
INCOME TAX EXPENSE 30,056 N/A 10,098
INVESTMENT TAX CREDIT (1,540) N/A (349)
OTHER TAX EXPENSE 0 N/A 0
TOTAL CARRYING CHARGES $ 157,184 N/A 53,289
ALLOCATED % TO NON-OWNER * 9.77%
TOTAL CARRYING CHARGE
TO NON-OWNER (CL&P) $ 15,357
* SEE PAGE 11 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SILVER ST. SUBSTATION
1984 INVESTMENTS
SOLE USE SOLE USE
ITEM JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
TOTAL STATION LAND INVEST. $ 0 N/A 0
"PTF" LAND INVEST. 0 N/A 0
"NUG&T" LAND INVEST. 0 N/A 0
LOCAL FACIL. LAND INVEST. $ 0 N/A 0
TOTAL STATION DEPR. INVEST. $ 583,085 N/A 195,535
"PTF" DEPRECIABLE INVEST. 0 N/A 0
"NUG&T" DEPRECIABLE INVEST. 0 N/A 0
LOCAL FACIL. DEPR. INVEST. $ 583,085 N/A 195,535
LOCAL FACIL. TOTAL INVEST. $ 583,085 N/A 195,535
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SILVER ST. SUBSTATION
1984 ALLOCATORS
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 38.4 MW
OWNER PEAX (WMECO) 304.4 MW
TOTAL OF PEAK LOADS 342.8 MW
NON-OWNER PERCENTAGE 11.20%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 5.60%
FEEDER POSITIONS:
NON-OWNER FEEDERS (CL&P) 0.5 *
OWNER FEEDERS (WMECO) 5.5 *
TOTAL OF FEEDER POSITIONS 6.0
NON-OWNER PERCENTAGE 8.33%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 4.17%
TOTAL NON-OWNER ALLOCATOR (CL&P) 9.77%
ALLOCATED PER APPENDIX I SECTION III
* 1 WMECO FEEDER TAPPED IN THE FIELD
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK SUBSTATION
1984 CHARGES
SOLE USE SOLE USE
JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 7,036 1,319 440
ALLOW FOR WKNG CAP:
MAT. & SUPPLIES 7,127 829 257
WKNG CAP ALLOW 7,923 936 288
TOTAL ALLOWANCE 15,050 1,765 545
TOTAL NON-DEPRECIABLE 22,086 3,084 985
DEPRECIABLE INVESTMENT 706,305 82,153 25,442
ACCUMULATED DEPRECIATION (312,397) (47,011) (14,013)
ACCUM DEFERRED INC TAXES 0 0 0
NET INVESTMENT $ 415,994 38,226 12,414
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 45,274 5,351 1,648
ADMIN. & GEN. EXPENSE 18,110 2,140 659
DEPRECIATION EXPENSE 23,267 2,715 840
PROPERTY TAX EXPENSE 10,635 1,244 386
INVESTMENT RETURN 50,127 4,606 1,496
INCOME TAX EXPENSE 31,435 2,962 957
INVESTMENT TAX CREDIT (1,128) (17) (14)
OTHER TAX EXPENSE 0 0 0
TOTAL CARRYING CHARGES $ 177,720 19,001 5,972
ALLOCATED % TO NON-OWNER * 40.59% 100.00%
CARRYING CHARGE ALLOCATION $ 72,137 19,001
TOTAL CARRYING CHARGE
TO NON-OWNER (CL&P) 91,138
* SEE PAGE 15 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK SUBSTATION
1984 INVESTMENT
SOLE USE SOLE USE
ITEM JOINT USE NON-OWNER (CL&P) OWNER (WMECO)
TOTAL STATION LAND INVEST. $ 7,036 1,319 440
"PTF" LAND INVEST. 0 0 0
"NUG&T" LAND INVEST. 0 0 0
LOCAL FACIL. LAND INVEST. $ 7,036 1,319 440
TOTAL STATION DEPR. INVEST. $ 706,305 82,153 25,442
"PTF" DEPRECIABLE INVEST. 0 0 0
"NUG&T" DEPRECIABLE INVEST. 0 0 0
LOCAL FACIL. DEPR. INVEST. $ 706,305 82,153 25,442
LOCAL FACIL. TOTAL INVEST. $ 713,341 83,472 25,882
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK SUBSTATION
1984 ALLOCATORS
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 60.8 MW
OWNER PEAX (WMECO) 134.2 MW
TOTAL OF PEAK LOADS 195.0 MW
NON-OWNER PERCENTAGE 31.18%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 15.59%
FEEDER POSITIONS:
NON-OWNER FEEDERS (CL&P) 1.5 *
OWNER FEEDERS (WMECO) 1.5 *
TOTAL OF FEEDER POSITIONS 3.0
NON-OWNER PERCENTAGE 50.00%
50% OF TOTAL ALLOCATOR X .5
NET LOAD ALLOCATOR 25.00%
TOTAL NON-OWNER ALLOCATOR (CL&P) 40.59%
ALLOCATED PER APPENDIX I SECTION III
* 1 WMECO FEEDER TAPPED IN THE FIELD
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK TRANSMISSION
1984 CHARGES
CL&P (OWNER)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 223,363
ALLOW FOR WORKING CAPITAL:
MATERIALS & SUPPLIES 3,556
WORKING CAPITAL ALLOWANCE 1,506
TOTAL ALLOWANCE 5,062
TOTAL NON-DEPRECIABLE 228,425
DEPRECIABLE INVESTMENT 352,434
ACCUMULATED DEPRECIATION (122,698)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 458,161
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 8,607
ADMIN. & GEN. EXPENSE 3,443
DEPRECIATION EXPENSE 11,253
PROPERTY TAX EXPENSE 4,300
INVESTMENT RETURN 55,208
INCOME TAX EXPENSE 32,979
INVESTMENT TAX CREDIT (7)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 115,783
ALLOCATED % TO NON-OWNER (WMECO) * 0.1624
WMECO OWES TO CL&P $ 18,803
* SEE PAGE 20 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK TRANSMISSION
1984 CHARGES
WMECO (OWNER)
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 135,280
ALLOW FOR WORKING CAPITAL:
MATERIALS & SUPPLIES 2,890
WORKING CAPITAL ALLOWANCE 1,224
TOTAL ALLOWANCE 4,114
TOTAL NON-DEPRECIABLE 139,394
DEPRECIABLE INVESTMENT 286,424
ACCUMULATED DEPRECIATION (99,094)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 326,724
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 6,995
ADMIN. & GEN. EXPENSE 2,798
DEPRECIATION EXPENSE 8,981
PROPERTY TAX EXPENSE 6,725
INVESTMENT RETURN 39,370
INCOME TAX EXPENSE 23,429
INVESTMENT TAX CREDIT 0
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 88,298
ALLOCATED % TO NON-OWNER (CL&P) * 0.8376
CL&P OWES TO WMECO $ 73,959
* SEE PAGE 20 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
TRANSMISSION
1984 INVESTMENT
TRANSMISSION TRANSMISSION
LINE SOUTHWICK LINE SOUTHWICK
ITEM CL&P (OWNER) WMECO (OWNER)
LOCAL TRANS. LAND INVEST. $ 223,363 $ 135,280
"PTF" LAND INVEST. 0 0
"NUG&T" LAND INVEST. 0 0
LOCAL TRANS. LAND INVEST. $ 223,363 $ 135,280
LOCAL TRANS. DEPRE. INVEST. $ 352,434 $ 286,424
"PTF" DEPRECIABLE INVEST. 0 0
"NUG&T" DEPRECIABLE INVEST. 0 0
LOCAL TRANS. DEPR. INVEST. $ 352,434 $ 286,424
LOCAL FACIL. TOTAL INVEST. $ 575,797 $ 421,704
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK TRANSMISSION
1984 ALLOCATORS
CL&P (OWNERS)
LOAD PERCENTAGES:
NON-OWNER PEAK (WMECO) 7873.0 * MW
OWNER PEAX (CL&P) 40594.7 * MW
TOTAL OF PEAK LOADS 48467.7 MW
NON-OWNER PERCENTAGE 16.24%
SOUTHWICK TRANSMISSION
1984 ALLOCATORS
WMECO (OWNERS)
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 40594.7 * MW
OWNER PEAX (WMECO) 7873.0 * MW
TOTAL OF PEAK LOADS 48467.7 MW
NON-OWNER PERCENTAGE 83.76%
ALLOCATED PER APPENDIX I SECTION III
* SUM OF THE MONTHLY RATCHETED PEAK LOADS PER NUG&T
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
FRANCONIA DISTRIBUTION
1984 CHARGES
COMMON
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WORKING CAPITAL:
MATERIALS & SUPPLIES 78
WORKING CAPITAL ALLOWANCE 166
TOTAL ALLOWANCE 244
TOTAL NON-DEPRECIABLE 244
DEPRECIABLE INVESTMENT 7,771
ACCUMULATED DEPRECIATION (2,767)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 5,248
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 949
ADMIN. & GEN. EXPENSE 380
DEPRECIATION EXPENSE 341
PROPERTY TAX EXPENSE 190
INVESTMENT RETURN 632
INCOME TAX EXPENSE 477
INVESTMENT TAX CREDIT (3)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 2,966
ADJUSTMENT PERCENTAGE * 0.1875
CL&P OWES TO WMECO $ 556
* SEE PAGE 26 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
FRANCONIA DISTRIBUTION
1984 CHARGES
COMMON
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WORKING CAPITAL:
MATERIALS & SUPPLIES 267
WORKING CAPITAL ALLOWANCE 566
TOTAL ALLOWANCE 833
TOTAL NON-DEPRECIABLE 833
DEPRECIABLE INVESTMENT 26,455
ACCUMULATED DEPRECIATION (7,193)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 20,095
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 3,232
ADMIN. & GEN. EXPENSE 1,293
DEPRECIATION EXPENSE 929
PROPERTY TAX EXPENSE 648
INVESTMENT RETURN 2,421
INCOME TAX EXPENSE 137
INVESTMENT TAX CREDIT (26)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 8,634
ADJUSTMENT PERCENTAGE * 0.7500
CL&P OWES TO WMECO $ 6,476
* SEE PAGE 26 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SILVER STREET DISTRIBUTION
1984 CHARGES
COMMON
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WORKING CAPITAL:
MATERIALS & SUPPLIES 361
WORKING CAPITAL ALLOWANCE 765
TOTAL ALLOWANCE 1,126
TOTAL NON-DEPRECIABLE 1,126
DEPRECIABLE INVESTMENT 35,781
ACCUMULATED DEPRECIATION (11,404)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 25,503
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 4,371
ADMIN. & GEN. EXPENSE 1,748
DEPRECIATION EXPENSE 1,432
PROPERTY TAX EXPENSE 876
INVESTMENT RETURN 3,073
INCOME TAX EXPENSE 357
INVESTMENT TAX CREDIT (74)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 11,783
ADJUSTMENT PERCENTAGE * 0.0833
CL&P OWES TO WMECO $ 982
* SEE PAGE 27 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SOUTHWICK DISTRIBUTION
1984 CHARGES
COMMON
INVESTMENT BASE:
NON-DEPRECIABLE
LAND $ 0
ALLOW FOR WORKING CAPITAL:
MATERIALS & SUPPLIES 87
WORKING CAPITAL ALLOWANCE 185
TOTAL ALLOWANCE 272
TOTAL NON-DEPRECIABLE 272
DEPRECIABLE INVESTMENT 8,653
ACCUMULATED DEPRECIATION (3,144)
ACCUM DEFERRED INC TAXES 0
NET INVESTMENT $ 5,781
ANNUAL CARRYING CHARGES:
OPER. AND MAINT. EXPENSE $ 1,057
ADMIN. & GEN. EXPENSE 423
DEPRECIATION EXPENSE 387
PROPERTY TAX EXPENSE 212
INVESTMENT RETURN 697
INCOME TAX EXPENSE 126
INVESTMENT TAX CREDIT (37)
OTHER TAX EXPENSE 0
TOTAL CARRYING CHARGES $ 2,865
ADJUSTMENT PERCENTAGE * 0.5000
CL&P OWES TO WMECO $ 1,432
* SEE PAGE 27 OF EXHIBIT 1 TO APPENDIX I
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
DISTRIBUTION
1984 INVESTMENT
Distrib. Distrib. Distrib. Distrib.
Franconia Franconia Silver St Southwick
ITEM Common Common Common Common
TOTAL STATION LAND INVEST. $ 0 0 0 0
"PTF" LAND INVEST. 0 0 0 0
"NUG&T" LAND INVEST. 0 0 0 0
LOCAL FACIL. LAND INVEST. $ 0 0 0 0
TOTAL STATION DEPRE. INVEST. $ 7,771 26,455 35,781 8,653
"PTF" DEPRECIABLE INVEST. 0 0 0 0
"NUG&T" DEPRECIABLE INVEST. 0 0 0 0
LOCAL FACIL. DEPR. INVEST. $ 7,771 26,455 35,781 8,653
LOCAL FACIL. TOTAL INVEST. $ 7,771 26,455 35,781 8,653
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
FRANCONIA DISTRIBUTION
1984 ALLOCATORS
COMMON
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 1.5 *
OWNER PEAX (WMECO) 6.5 *
TOTAL OF PEAK LOADS 8.0
NON-OWNER PERCENTAGE (CL&P) 18.75%
FRANCONIA DISTRIBUTION
1984 ALLOCATORS
CL&P
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 5.1 *
OWNER PEAX (WMECO) 0.5 *
TOTAL OF PEAK LOADS 2.0
NON-OWNER PERCENTAGE (CL&P) 75.00%
ALLOCATED PER APPENDIX I SECTION III
* 1 WMECO FEEDER TAPPED IN THE FIELD
EXHIBIT 1 TO APPENDIX I
LOCAL FACILITIES
SILVER STREET DISTRIBUTION
1984 ALLOCATORS
COMMON
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 0.5 *
OWNER PEAX (WMECO) 5.5 *
TOTAL OF PEAK LOADS 6.0
NON-OWNER PERCENTAGE (CL&P) 8.33%
SOUTHWICK DISTRIBUTION
1984 ALLOCATORS
COMMON
LOAD PERCENTAGES:
NON-OWNER PEAK (CL&P) 1.5 *
OWNER PEAX (WMECO) 1.5 *
TOTAL OF PEAK LOADS 3.0
NON-OWNER PERCENTAGE (CL&P) 50.00%
THE PRUDENTIAL
INSURANCE COMPANY OF AMERICA
SIMULATOR FINANCING LEASE AGREEMENT
Simulator Financing Lease Agreement (the "Agreement") dated as of the 2nd
day of May, 1985, by and between THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, a
New Jersey corporation, as lessor and secured party (herein called "Lessor") and
NORTHEAST NUCLEAR ENERGY COMPANY, a Connecticut corporation, as lessee and
debtor (herein called "Lessee").
In consideration of the mutual covenants contained herein, the parties
covenant and agree as follows:
1. Definitions. As herein used:
(a) "Acquisition Cost" of the Unit (as hereinafter defined) or Units or
any part thereof is an amount equal to the sum of the vendor's invoice price
(less any discounts or credits actually utilized by Lessor), any progress
payments, any costs of freight, packing, insurance, handling, storage, shipment
and delivery, any sales, use and other taxes, capitalized overheads, labor and
interest, allowance for funds used during construction and reasonable
consultants and attorneys fees, and such other costs as may be agreed to by
Lessor and Lessee in writing.
(b) "Applicable Percentage" is equal to the sum of (i) 1.50% plus (ii)
either (x) the "C/P Rate" or (y) the "Fixed Rate". The "C/P Rate" for any month
shall mean the yield adjusted rate (meaning the nominal rate increased by the
cost of any discount) charged to Prudential Funding Corporation, a subsidiary of
Lessor, on 30-day, dealer-placed commercial paper issued by Prudential Funding
Corporation ("Commercial Paper") on the fifteenth day of such month or, if such
fifteenth day is not a Business Day, on the next succeeding Business Day (such
Business Day being herein called the "Rate Day"), or if Commercial Paper has not
been issued on the Rate Day, the rate quoted for Commercial Paper by the
commercial paper dealer on the Rate Day. If, on any Rate Day, more than one rate
is charged or quoted for Commercial Paper, the last of such charged or quoted
rates, whichever is applicable, shall be used. Upon execution of this Agreement,
Lessor shall notify Lessee in writing of the then C/P Rate. Thereafter, Lessor
shall notify Lessee in writing of an) change in such C/P Rate. "Fixed Rate"
shall mean the yield on 10 year Treasury Notes (based on the bid price on the
"Fixed Rate Day" (as hereinafter defined)) as reported by "Telerate - the
Financial Information Network," published by Telerate Systems, Incorporated, or
its successor company and provided to Lessee by Lessor. The "Fixed Rate Day"
shall be the Business Day or Business Days on or before June 24, 1986 on which
Lessee shall request verbally, Lessor shall provide verbally, and Lessee shall
accept verbally and confirm in writing, the Fixed Rate for each Interim Leasing
Record (as hereinafter defined) relating to the Acquisition Cost of each Unit or
portion thereof as estimated by the Lessee (the "Fixed Rate Amount"); provided,
however, Lessee may request no more than two Fixed Rate Amounts for all portions
of each Unit; provided further, however, if Lessee does not request and accept a
Fixed Rate for all such portions of a Unit prior to June 24, 1986, the Fixed
Rate Day for all such portions of such Unit shall be June 24, 1986. At the time
Lessee requests the Fixed Rate, Lessee shall also notify Lessor, and confirm in
writing, as to the date on which such Fixed Rate shall become applicable to the
lease of each portion of each Unit ("Fixed Rate Effective Date"); provided,
however, the Fixed Rate Effective Date may not be a date earlier than four
Business Days following the Fixed Rate Day nor, in any event, later than June
30, 1986.
(c) "Basic Lease Term" shall have the meaning set forth in Section 5
hereof.
(d) "Business Day" means every day except Saturday, Sunday any other day
which in New York, New York or Hartford, Connecticut shall be a legal holiday
and any day on which banking institutions in New York, New York or Hartford,
Connecticut are authorized by law to close.
(e) "Equipment" means all or any portion of the two nuclear power plant
control room simulator systems (hereinafter referred to each in its entirety as
"Unit" or "Units"), for the Millstone Nuclear Power Station, Units No. 1 and 2,
each evidenced by an Individual Leasing Record (as hereinafter defined) and all
related materials, parts and accessions leased or to be leased by Lessor to
Lessee as provided herein including any replacements of such related materials,
parts and accessions, approved in writing by Lessor and Lessee.
(f) "Individual Leasing Record" is a form signed by Lessor and Lessee to
record the leasing of each Unit hereunder. The first Individual Leasing Record
for each Unit shall be dated the date of the acceptance by Lessee of the lease
hereunder of the Unit or Units specified in such Individual Leasing Record.
Such date shall constitute the effective beginning date as of which such Unit is
subject to the terms and provisions of this Agreement. The signature of Lessee
on an Individual Leasing Record shall constitute acknowledgment by Lessee (x)
that the Equipment specified in such Individual Leasing Record has been
delivered to Lessee in good condition and has been accepted for lease hereunder
by Lessee as of the date of such Individual Leasing Record, and (y) that the
Equipment specified in such Individual Leasing Record is subject to all of the
covenants, terms and conditions of this Agreement. An Individual Leasing Record
shall give a full description of the Equipment specified therein, the
Acquisition Cost, Rent (as hereinafter defined), location and such other details
with respect to the Equipment specified therein as the parties may agree. An
Individual Leasing Record may be either an "Interim Leasing Record" or a "Final
Leasing Record" (as hereinafter defined), as the case may be.
(i) An "Interim Leasing Record" is a form of Individual Leasing Record
signed by Lessor and Lessee to record the leasing of each Unit during any period
that such Unit or a portion thereof is subject to the provisions of this
Agreement prior to a "Lease Commencement Date" (as hereinafter defined). Each
entry for a Unit on an Interim Leasing Record which reflects a payment of
Acquisition Cost shall be dated the date Lessee authorized payment by Lessor
with respect to the Acquisition Cost of such Unit specified in such Interim
Leasing Record. During the period Equipment is subject to the provisions hereof
prior to a Lease Commencement Date, if Lessor shall make any further payment or
payments with respect to such Equipment, a supplemental entry shall be made on
an Interim Leasing Record dated the date Lessee authorizes Lessor to make such
further payments to record the revised Acquisition Cost (after giving effect to
any such payment), the revised Rent, any change in location and such additional
details as the parties may agree; provided, however, when the Rent on an Interim
Leasing Record is based on a Fixed Rate, subsequent to an initial non-funding
Individual Leasing Record, there may not be more than two such Interim Leasing
Records for each Unit and after such Interim Leasing Records have been delivered
to Lessor, such Interim Leasing Records may no longer be revised. An Interim
Leasing Record shall be substantially in the form as set forth on Exhibit A
hereto.
(ii) A "Final Leasing Record" is a form of Individual Leasing Record
signed by Lessor and Lessee to record the leasing of each Unit during any period
that such Unit is leased hereunder as of a Lease Commencement Date. A Final
Leasing Record shall be dated the Lease Commencement Date and shall be delivered
to Lessor promptly following the Lease Commencement Date of such Unit. In
addition to the provisions of this Section 1(f) concerning the effect of the
signature of Lessee on an Individual Leasing Record, such signature on a Final
Leasing Record shall constitute acknowledgment by Lessee that the Equipment
specified in such Final Leasing Record requires the addition of no further
Acquisition Cost thereto. A Final Leasing Record shall be substantially in the
form as set forth on Exhibit B hereto.
(g) "Interim Lease Term" shall mean the period beginning after the date
hereof commencing with the effective date of an Interim Leasing Record of a Unit
and ending on the day immediately prior to the Lease Commencement Date for such
Unit.
(h) "Lease Commencement Date" for a Unit shall mean a "Rent Payment Date"
(as hereinafter defined in Section 6) designated in writing by Lessee to Lessor
which date shall be on or prior to July 1, 1986; provided, however, such date
must be concurrent with or subsequent to the Fixed Rate Effective Dates for all
portions of such Unit. Each such Lease Commencement Date shall constitute the
beginning of the Basic Lease Term of such Unit.
(i) "Renewal Lease Term" shall have the meaning set forth in Section 5
hereof.
(j) "Rent" shall mean either "Interim Rent" or "Basic Rent":
(i) "Interim Rent" for any month of this Agreement during an Interim
Lease Term for Equipment with respect to which Lessor has made a payment of
Acquisition Cost shall be an amount computed by multiplying the following:
(a) the Acquisition Cost of such Equipment, by
(b) a fraction, the numerator of which is equal to the number of
days in such month during which such Equipment is covered by an Interim Leasing
Record, and the denominator of which is 360, by
(c) the Applicable Percentage.
(ii) "Basic Rent" for a Unit for each full month during the Basic
Lease Term and Renewal Lease Terms shall be made in level payments, monthly in
arrears, and the present value of such Rent payments (each discounted at a rate
equal to the sum of (x) the Fixed Rates for such Unit or portion thereof, and
(y) 1.50%, from the Rent Payment Date (as hereinafter defined in Section 6)
thereof to the Lease Commencement Date) over the Basic Lease Term and Renewal
Lease Terms of such Unit, as of the Lease Commencement Date, shall be equal to
the Acquisition Cost of such Unit, as such Basic Rent is set forth on the
Exhibit attached to each Final Leasing Record substantially in the form of
Exhibit C attached hereto.
(k) "Stipulated Termination Value" for each Unit for any full month during
the Basic Lease Term and the Renewal Lease Terms of such Unit shall be a dollar
amount determined by multiplying the Unamortized Cost of such Unit by the
"Termination Rate" (as hereinafter defined).
(l) "Termination Rate" for each Unit or portion thereof shall be a rate
equal to the sum of (x) the applicable Fixed Rate for such Unit or portion
thereof, and (y) 101.5%. The Termination Rate shall decline ratably annually to
100% from the beginning of the First Renewal Lease Term through the end of the
96th Renewal Lease Term as set forth on the Exhibit attached to each Final
Leasing Record substantially in the form of Exhibit C attached hereto.
(m) "Unamortized Cost" for each Unit shall be the amount set forth for
each month of the Basic Lease Term and the Renewal Lease Terms on the Exhibit
attached to each Final Leasing Record substantially in the form of Exhibit C
attached hereto.
(n) "Delayed Takedown Fee" for all or any portion of a Unit shall be an
amount computed by multiplying the following:
(A) the Fixed Rate Amount of such Unit or portion thereof, by
(B) a fraction having a numerator equal to the number of days from
the applicable Fixed Rate Day for such Unit or portion thereof to but not
including the applicable Fixed Rate Effective Date for such Unit or portion
thereof and a denominator of 360, by
(C) 1/2 of 1%.
(o) "Cancellation Fee" shall be an amount computed by multiplying (i) 1/2
of 1% by (ii) the "Deficiency". The "Deficiency" is an amount equal to the
amount by which the aggregate of the Fixed Rate Amounts of both Units exceeds
the sum of (x) the aggregate of the Acquisition Costs shown on the Final Leasing
Records for both Units and (y) $500,000.
(p) Notwithstanding subsection (j) above, when the Unamortized Cost of a
Unit has been reduced to zero, the lease term of such Unit shall terminate, and
Lessor shall release to Lessee all of Lessor's right, title and security
interest in such Unit and execute such documents as Lessee may reasonably
request to evidence such release.
2. This Agreement is Intended as Security.
Lessor and Lessee declare and agree that this Agreement is intended as
security. Subject to the terms, conditions and limitations contained herein,
Lessor shall make available funds for the acquisition of Equipment. Title to the
Equipment shall be retained or reserved by Lessor for the purpose of securing
payment by Lessee to Lessor of Rent, Unamortized Cost, and other amounts as
provided herein and to secure performance by Lessee of the other terms and
conditions hereof. Lessee shall promptly execute and deliver to Lessor such
documents as Lessor shall deem necessary to further evidence Lessor's security
interests hereunder and in the Equipment. Such documents, or evidence thereof,
shall be filed and recorded as provided in Section 7. Lessor and Lessee agree
that the Lessor holds legal title to the Equipment only to evidence Lessor's
security interest therein and the Equipment is and shall be treated as, owned
by Lessee for all other purposes.
3. Agreement for Lease of Equipment.
Subject to satisfaction of all terms and conditions of this Agreement,
including, without limitation, the conditions set forth in Section 20 hereof,
Lessor commits to lease to Lessee and Lessee commits to lease from Lessor the
Equipment, provided that Lessee is not in default hereunder, and further
provided that the aggregate total Acquisition Cost of Equipment leased hereunder
shall not exceed $23,000,000 or such other amount as Lessor and Lessee may agree
in writing. Lessor and Lessee shall evidence their agreement to lease a specific
Unit under this Agreement by executing and promptly upon execution delivering to
each other an Individual Leasing Record covering such Unit.
4. Delivery.
Lessor shall not be liable to Lessee for any failure or delay in obtaining
Equipment or making delivery thereof. Upon acceptance for lease (as provided in
Section 1(f) hereof) of Equipment by Lessee and receipt by Lessor of vendor's
invoice approved by Lessee or Lessee's invoice signed by Lessee for such
Equipment together with an Individual Leasing Record with respect to such
Equipment duly executed by Lessee, Lessor shall pay such invoice for such
Equipment. If the amount paid to vendors by Lessor is less than the Acquisition
Cost of such Equipment, to the extent that costs includable in the Acquisition
Cost of Equipment have been paid, incurred, or accrued by Lessee, Lessor shall
reimburse Lessee to the extent of such payment, incurrence or accrual made by
Lessee. Lessee shall (i) pay all costs and expenses of freight, packing,
insurance, handling, storage, shipment and delivery of the Equipment to the
extent that the same have not been included in Acquisition Cost and (ii) at its
own cost and expense, furnish such labor, equipment and other facilities and
supplies, if any, as may be required to install and erect the Equipment to the
extent that the cost and expense thereof have not been included in the
Acquisition Cost. Such installation and erection shall be in accordance, in all
material respects, with the specifications and requirements of each vendor as
set forth in the contracts between Lessee and such vendors, as the same may have
been or may hereafter be amended. AS BETWEEN LESSOR AND LESSEE, ACCEPTANCE FOR
LEASE OF THE EQUIPMENT (AS PROVIDED IN SECTION 1(f) HEREOF) SHALL CONSTITUTE
LESSEE'S ACKNOWLEDGEMENT AND AGREEMENT THAT LESSEE HAS FULLY INSPECTED SUCH
EQUIPMENT, THAT THE EQUIPMENT IS IN GOOD ORDER AND CONDITION AND IS OF THE
MANUFACTURE, DESIGN, SPECIFICATIONS AND CAPACITY SELECTED BY LESSEE, THAT LESSEE
IS SATISFIED THAT THE SAME IS SUITABLE FOR ITS PURPOSE AND THAT LESSOR IS NOT A
MANUFACTURER OR ENGAGED IN THE SALE OR DISTRIBUTION OF EQUIPMENT, AND HAS NOT
MADE AND DOES NOT HEREBY MAKE ANY REPRESENTATION, WARRANTY OR COVENANT WITH
RESPECT TO MERCHANTABILITY, CONDITION, QUALITY, DURABILITY OR SUITABILITY OF THE
EQUIPMENT IN ANY RESPECT OR IN CONNECTION WITH, OR FOR THE PURPOSES OR USES OF
LESSEE, OR ANY OTHER REPRESENTATION, WARRANTY OR COVENANT OF ANY KIND OR
CHARACTER, EXPRESS OR IMPLIED, WITH RESPECT THERETO.
5. Basic Lease Term; Renewal Lease Terms.
The Basic Lease Term for each Unit shall become effective on the Lease
Commencement Date as provided in Section 1(h) hereof. The Basic Lease Term of
each Unit shall be for a period beginning with the Lease Commencement Date and
ending five years thereafter. Following the Basic Lease Term with respect to a
Unit, the lease thereof shall be extended from month to month (the "Renewal
Lease Terms") until terminated as provided in Section 1(p), 11, 12(c), 14, 15 or
18 hereof, provided, however, the last Renewal Lease Term shall end no later
than fifteen (15) years from the Lease Commencement Date for such Unit.
Notwithstanding the foregoing, the provisions of Section 10 hereof and the first
sentence of Section 12 hereof shall apply as between Lessor and Lessee with
respect to any Equipment from the time such Equipment is ordered by Lessor
pursuant to a request from Lessee. Notwithstanding any other provision of this
Agreement to the contrary, Lessee shall not terminate the lease hereunder of
Equipment for the purpose of refinancing such Equipment with funds borrowed at a
rate which is less than the Applicable Percentage set forth in Section 1(b)
hereof.
6. Rent and Other Payments.
Lessee shall pay Rent monthly in arrears in such a manner that payment is
received by Lessor on the first day of the month following the month for which
such Rent is tue ("Rent Payment Date"). If any such Rent Payment Date is not a
Business Day then payment shall be made on the next preceding Business Day.
Lessor shall give Lessee written notice of the address to which all payments of
Rent and other payments to be made hereunder shall be directed and all such
payments shall be made by check and shall be deemed to have been received by
Lessor when received in immediately available funds at such address. Without
prejudice to the full exercise by Lessor of its rights under Section 13 and 14
hereof for failure of Lessee to pay Rent when due as provided above, to the
extent legally enforceable Lessee shall promptly pay Lessor additional Rent with
respect to all sums not paid by Lessee to Lessor as provided in this Agreement
on or before the Rent Payment Date said additional Rent to be in an amount equal
to such unpaid sums multiplied by (i) the Applicable Percentage referred to in
Section 1(b) hereof and (ii) a fraction having a numerator equal to the number
of days in the period from and including such Rent Payment Date and ending upon
the date of payment thereof and a denominator of 360. Lessee shall also promptly
pay to Lessor an amount equal to any expenses incurred by Lessor in collecting
such unpaid sums. Lessee shall pay Lessor a Delayed Takedown Fee if the Fixed
Rate Effective Date for all or any portion of a Unit occurs more than 90 days
after the Fixed Rate Day for such Unit or portion thereof. Such Delay Takedown
Fee shall be payable by Lessee on the Fixed Rate Effective Date for such Unit or
portion thereof. Lessee shall pay Lessor a Cancellation Fee, if any, on the
Lease Commencement Date of the second Unit leased hereunder; provided, however,
if, notwithstanding Lessee's best efforts, any regulatory body having
jurisdiction over Lessee or this Agreement denies approval of this Agreement
within 90 days of a Fixed Rate Day, Lessee shall not be required to pay Lessor a
Cancellation Fee or Delayed Takedown Fee on the Fixed Rate Amount pertaining to
such Fixed Rate Day.
7. Restricted Use and Compliance with Laws
So long as Lessee is not in default pursuant to Section 13 hereof, Lessee
may use Equipment in the regular course of its business or the business of any
subsidiary or affiliate of Lessee, and may permit others to use the same for any
lawful purpose. Such use shall be confined to the United States. Lessee shall
promptly and duly execute, deliver, file and record all such documents,
statements, filings and registrations, and take such further actions as Lessor
shall from time to time reasonably request in order to establish, perfect and
maintain the rights and remedies created or intended to be created in favor of
Lessor hereunder and Lessor's security interest in the Equipment as against
Lessee or any third party in any applicable jurisdiction. Lessee may after
notice in writing to Lessor and at Lessee's sole expense change the place of
principal location of any Equipment. Notwithstanding the foregoing, no change of
location shall be undertaken unless such Equipment shall be and remain subject
to the security interest of Lessor, subject to this Agreement and until all
legal requirements shall have been met or obtained and all necessary or
advisable recordings, filings and registrations which Lessor shall reasonably
request shall have been duly made in order to protect the validity and
effectiveness of this Agreement. If Lessor reasonably so requests, Lessee shall
advise Lessor in writing where all Equipment leased hereunder as of such date is
principally located. Lessee shall not use any Equipment or allow the same to be
used for any unlawful purpose. Lessee shall use every reasonable precaution to
prevent loss or damage to Equipment and to prevent injury to third persons or
property of third persons arising out of Equipment or the use thereof. Lessee
shall cooperate fully with Lessor and all insurance companies providing
insurance under Section 9 hereof in the investigation and defense of any claims
and suits arising from the operation of Equipment. To the extent necessary to
avoid any impairment of Lessor's rights and interests hereunder and to avoid any
adverse affect on Lessee's ability to perform under this Agreement and the
transactions contemplated hereby, Lessee shall comply and shall cause all
persons operating Equipment to comply with all insurance policy conditions and
with all statutes, decrees, ordinances and regulations regarding acquiring,
titling, perfecting a security interest in, registering, leasing, insuring,
using, operating and disposing of Equipment, and the licensing of operators
thereof. Lessor or any authorized representative of Lessor may during reasonable
business hours from time to time inspect Equipment and registration
certificates, certificates of title and related documents covering Equipment
wherever the same be located. Lessee shall not without prior written consent of
Lessor sublease any Equipment nor permit, or suffer to exist, any lien or
encumbrance on any Equipment other than those placed thereon by Lessor or by
persons claiming only against Lessor and not against Lessee, nor shall Lessee
assign any right or interest herein or in any Equipment, provided, however, that
Lessee may sublet Equipment to any subsidiary or affiliate of Lessee, or to any
contractor for use in performing work for Lessee, provided that such subletting
shall in no way affect the obligations of Lessee hereunder, or the rights of
Lessor hereunder, with respect to any Equipment. Lessee agrees to furnish
Lessor, upon reasonable request, a certificate that all registration
certificates and certificates of title required by applicable law and
regulations, endorsed to show Lessor's security interest, have been obtained and
are being held on behalf of Lessor. Lessee shall not without the prior
permission of Lessor change or remove (or permit to be changed or removed or
otherwise permit a decrease in the visibility of) any insignia or lettering
which is on any Equipment at the time of delivery thereof or which is thereafter
placed thereon indicating Lessor's security interest therein, and at any time
during the term of this Agreement, upon request of Lessor, or if necessary or
advisable under applicable law, Lessee shall affix to Equipment, in the place
designated by Lessor (or, if no such place shall have been designated, in a
prominent place), labels, plates or other markings as provided by Lessor
indicating Lessor's security interest in the Equipment.
8. Maintenance, Improvement and Repair of Equipment.
Upon request of Lessee, Lessor will assign or otherwise make available to
Lessee all of its rights under any vendor's or manufacturer's warranty on
Equipment. Lessee shall pay all costs, expenses, fees and charges incurred in
connection with the use and operation of Equipment during the lease term
thereof. Except as otherwise provided in Section 12 hereof, Lessee shall at all
times, at its own expense, and subject to reasonable wear and tear, keep
Equipment in good mechanical condition and repair. The foregoing undertaking to
maintain Equipment in good repair shall apply regardless of the cause
necessitating repair, and as between Lessor and Lessee all risks of damage to
Equipment are assumed by Lessee. It is acknowledged by Lessor and Lessee that
the Units to be leased hereunder will be modified, upgraded or enhanced from
time to time in order that the Units may continue to replicate the actual
operation of and reflect changes to the nuclear power plants whose control rooms
they simulate. Lessee shall not make any material alterations to any Equipment
without giving prior notice thereof to Lessor. Without the prior written consent
of Lessor, Lessee shall not make any material alterations of Equipment which, in
Lessee's reasonable judgment, will result in a reduction of value of such
Equipment. At the same time that Lessee provides notice to Lessor of any
material alterations, Lessee shall certify to Lessor that such alterations will
not result in a reduction of the value of such Equipment. Any improvements or
additions to any Equipment shall be deemed to constitute an accession to such
Equipment, except that any addition to Equipment made by Lessee shall not be
deemed to constitute an accession to such Equipment if it can be disconnected
from Equipment without impairing the functioning of such Equipment or it's
resale value excluding such addition.
9. Insurance.
Lessee shall, at its own cost and expense, with respect to Equipment
maintain insurance insuring the respective interests of Lessor and Lessee and
covering (a) physical damage to Equipment and (b) liability for bodily injury
and property damage resulting from the operation of Equipment. All such
insurance shall be with reputable companies. Policies covering physical damage
risks shall be an amount not less than the Unamortized Cost of Equipment.
Policies covering bodily injury and property damage shall provide not less than
$5,000,000 for injury to or death of one person and, subject to that limit for
each person, a total liability of not less than $10,000,000 for all persons
injured or killed in the same accident and shall also provide not less than
$5,000,000 for damage, destruction and loss of use of property of third persons
as a result of any one accident. Lessor shall be named as an additional insured
and, with respect to physical damage coverage, a named loss payee in all
insurance policies required under this Section. All such policies or
certificates of insurance with respect thereto shall provide for thirty days
prior written notice to Lessor of any cancellation or material alteration of
such policies. Lessee shall furnish Lessor certificates or other evidence
satisfactory to Lessor of compliance by Lessee with the provisions hereof, but
Lessor shall be under no duty to examine such certificates or to advise Lessee
in the event its insurance is not in compliance herewith. Lessee covenants that
it will not use or operate or permit the use or operation of any Equipment at
any time when the insurance required by this Section is not in force with
respect to such Equipment. The foregoing coverage may be subject to such
deductible amounts and Lessee may itself insure such portions of the foregoing
coverage as Lessor may approve in writing.
10. Indemnity.
Lessee agrees to indemnify and hold harmless Lessor and its
representative, PruCapital Management, Inc., and their respective directors,
officers and employees, and all companies, persons or firms controlling,
controlled by or under common control with any of them (including, without
limitation, PruCapital, Inc. and PRUCO, Inc.) against any and all claims,
demands and liabilities of whatsoever nature and all costs and expenses
(including but not limited to attorneys' fees) directly or indirectly relating
to or in any way arising out of:
(a) the ordering, delivery, acquisition, security interest in, title on
acquisition, rejection, installation, possession, titling, retitling,
registration, reregistration, custody by Lessee of title and registration
documents, use, non-use, misuse, operation, transportation, inspection, repair,
control or disposition of Equipment leased or to be leased hereunder, except to
the extent that such costs are included in the Acquisition Cost of such
Equipment within the dollar limit provided in Section 3 hereof (or within any
change of such limit agreed to in writing by Lessor and Lessee) and except for
any general administrative or overhead expenses of Lessor and of its
representative;
(b) all costs, charges, damages or expenses for royalties and claims and
expenses of litigation arising out of or necessitated by the assertion of any
claim or demand based upon any infringement or alleged infringement of any
patent or other right, by or in respect of any Equipment, provided, however,
that Lessor will make available to Lessee Lessor's rights under any similar
indemnification from the manufacturer of equipment arising by contract, by
quasi-contract or by operation of law;
(c) all federal, state, county, municipal, foreign or other fees and taxes
of whatsoever nature, including but not limited to license, qualification,
franchise, sales, use, gross receipts, ad valorem, business, property (real or
personal), excise, motor vehicle, and occupation fees and taxes, and penalties
and interest thereon, to the extent not incurred solely as a result of Lessor's
failure to make payments in a timely fashion, which failure is not due to the
negligence or willful misconduct of the Lessee, whether assessed, levied against
or payable by Lessor or otherwise, with respect to Equipment or the acquisition,
purchase, security interest in, sale, rental, use, operation, control, ownership
or disposition of Equipment or measured in any way by the value thereof or by
the business of, investment in, financing of, security interest in, or ownership
by Lessor with respect thereto, excepting only (i) net income taxes on the net
income of Lessor determined substantially in the same manner but not necessarily
at the same rates as net income is presently determined under the Federal
Internal Revenue Code, and (ii) any sales, use, excise or other taxes included
in Acquisition Cost of the Equipment;
(d) any violation or alleged violation, of this Agreement by Lessee or of
any contracts or agreements to which Lessee is a party or by which it is bound
or any laws, rules, regulations, orders, writs, injunctions, decrees, consents,
approvals, exemptions, authorizations, licenses and withholdings of objection,
of any governmental or public body or authority and all other requirements
having the force of law applicable at any time to Equipment or any action or
transaction by Lessee with respect thereto or pursuant to this Agreement, or any
representation or statement by Lessee in this Agreement or in any written
instrument furnished by Lessee to Lessor in connection with this Agreement which
is not true and correct in all material respects on the date as of which made
and on the date Lessor makes any payment with respect to the Acquisition Cost of
Equipment, or such representation or statement omits to state a material fact
necessary in order to make such representation or statement not misleading in
light of the circumstances under which it is made.
Lessee shall forthwith upon demand reimburse Lessor for any sum or sums expended
with respect to any of the foregoing, or shall pay such amounts directly upon
request from Lessor. To the extent that Lessee in fact indemnifies Lessor under
the indemnity provisions of this Agreement, Lessee shall be subrogated to
Lessor's right in the affected transaction and shall have a right to determine
the settlement of claims therein. Lessor shall not settle any claim for which
Lessor is indemnified by Lessee hereunder without first notifying Lessee of such
claim and providing Lessee with the opportunity to in fact indemnify Lessor. The
foregoing indemnity shall not be affected by any termination of this Agreement
as a whole or in respect of any unit of Equipment leased hereunder.
11. Termination of the Lease of Equipment.
After the expiration of the Basic Lease Term or any Renewal Lease Term of any
Unit, provided that Lessee is not in default hereunder, Lessee may notify Lessor
in writing that it desires to terminate the lease term of such Unit; provided,
however, that Lessee shall not terminate the lease term hereunder of any Unit
for the purpose of refinancing such Unit with funds borrowed at a rate which is
less than the Applicable Percentage set forth in Section 1(b) hereof. Within
thirty (30) days after the date of such notice Lessee shall pay to Lessor an
amount equal to the Stipulated Termination Value of such Unit. The obligation of
Lessee to pay Rent for such Unit shall continue until the end of the month
during which Lessor has received payment of the Stipulated Termination Value
thereof. Upon receipt of such payment, Lessor shall release its title and
security interest in such Unit and execute such documents as Lessee may
reasonably request to evidence such release and upon such release the lease of
such Unit shall terminate.
12. Loss of or Damage to Equipment.
(a) Lessee hereby assumes all risk of loss or damage of Equipment however
caused. No loss of or damage to any Equipment shall impair any obligation of
Lessee under this Agreement, which shall continue in full force and effect.
(b) In the event of damage of any kind whatsoever to any Equipment (unless
the same is determined by Lessee to be damaged beyond repair) Lessee, at its own
expense, shall place the same in good operating order, repair, condition and
appearance.
(c) If any Equipment is lost, stolen, destroyed, seized, confiscated,
rendered unfit for use or damaged beyond repair, or if the use thereof by Lessee
in its regular course of business is prevented by the act of any third person or
persons, or any governmental instrumentality for a period exceeding ninety (90)
days, or if such Equipment is attached (other than on a claim against Lessor but
not Lessee) and the attachment is not removed within ninety (90) days, then in
any such event, (a) Lessee shall notify Lessor in writing of such fact, (b)
within sixty (60) days of such event Lessee shall pay to Lessor an amount equal
to the difference between any proceeds of insurance collected by Lessor as a
result of such loss, damage or destruction and the Unamortized Cost of such
Equipment at the time of payment by Lessee and (c) the lease term of such
Equipment shall continue until the end of the month during which Lessor receives
payment from Lessee and shall thereupon terminate.
13. Events of Default.
The following events of default by Lessee shall give rise to rights on the
part of Lessor described in Section 14 hereof:
(a) Default in the payment of Rent (or additional Rent or expenses of
collection, as provided by Section 6 hereof), or any other amount payable by
Lessee hereunder beyond the tenth (10th) day after such payment is due; or
(b) Default in the payment or performance of any other liability,
obligation or covenant of Lessee to Lessor and the continuance of such default
for fifteen (15) days after written notice to Lessee sent by registered or
certified mail; or
(c) Lessee suspends or discontinues its business operations or becomes
insolvent, as such term is defined in the Bankruptcy Reform Act, 11 USC para.
101 (26), (however such insolvency may be evidenced) or admits in writing
insolvency or bankruptcy or its inability to pay its debts as they mature, makes
an assignment for the benefit of creditors or applies for or consents to the
appointment of a trustee or receiver for Lessee, or for the major part of its
property; or
(d) Bankruptcy, reorganization, liquidation or receivership proceedings
for relief under any bankruptcy law or similar law for the relief of debtors are
instituted by or against Lessee and, if instituted against Lessee, its consent
thereto or the pendency of such proceedings for sixty (60) days; or
(e) An event of default (the effect of which is to permit the holder or
holders of any instrument, or a trustee or agent on behalf of such holder or
holders, to cause the indebtedness evidenced by such instrument to become due
prior to its stated maturity) shall occur under the provisions of any instrument
evidencing indebtedness for borrowed money of Lessee (or under the provisions of
any agreement pursuant to which such instrument was issued) or any obligation of
Lessee for the payment of such indebtedness shall become or be declared to be
due and payable prior to its stated maturity (other than at the option of
Lessee) or shall not be paid when due, provided, in each such case, that such
event could, in the reasonable judgment of Lessor, materially and adversely
affect Lessee's ability to perform its obligations under this Agreement; or
(f) Any representation or statement made by Lessee herein or in any
written instrument furnished by Lessee to Lessor in connection herewith shall
not be true and correct in all material respects on the date as of which made
and on the date Lessor makes any payment with respect to the Acquisition Cost of
Equipment, or any such representation or statement omits to state of material
fact necessary in order to make such representation or statement not misleading
in light of the circumstances under which it is made.
14. Rights of Lessor Upon Default of Lessee.
(a) Upon the occurrence of any of the events of default described in
Section 13, Lessor may in its discretion terminate the lease of any or all
Equipment hereunder upon 5 days written notice to Lessee sent by registered or
certified mail and upon such termination Lessee shall immediately pay to Lessor
(i) all Rent and other amounts then due and payable under this Agreement, (ii)
the then Stipulated Termination Value of such Equipment and (iii) all losses,
damages and expenses (including, without limitation, reasonable attorneys' fees
and disbursements) sustained by Lessor by reason of such default and the
exercise of Lessor's remedies with respect thereto.
(b) If Lessee shall fail to pay Lessor all or any part of the amounts
specified in Section 14(a) on any such termination date, Lessor may in its
discretion do one or more of the following:
(i) subject to any applicable law or regulation, and subject to
Lessee's normal and reasonable security arrangements in effect where the
Equipment is located, take immediate possession of and remove any or all
Equipment or cause such Equipment to be taken from the possession of Lessee,
and/or take immediate possession of and remove other property of Lessor in the
possession of Lessee, wherever situated, and for such purpose, subject to any
applicable law or regulation and subject to Lessee's normal and reasonable
security arrangements in effect where the Equipment is located, enter upon any
premises without liability for so doing or require Lessee, at Lessee's expense,
to deliver the Equipment to Lessor or to such other person as Lessor may
designate, in which case the risk of loss shall be upon Lessee until such
delivery is made;
(ii) subject to any applicable law or regulation, sell any Equipment
(with or without the concurrence or request of Lessee) at public or private sale
and Lessee shall be liable for and shall promptly pay to Lessor all unpaid Rent
to the date of receipt by Lessor of the proceeds of such sale plus any
deficiency between the net proceeds of such sale and the Stipulated Termination
Value of such Equipment plus all losses, damages and expenses (including,
without limitation, reasonable attorneys' fees and disbursements) sustained by
Lessor by reason of Lessee's default and the exercise of Lessor's remedies with
respect thereto, and to the extent that the net proceeds of any such sale are in
excess of such Stipulated Termination Value plus all such losses, damages and
expenses, Lessor shall promptly pay to Lessee such excess;
(iii) proceed by appropriate judicial proceedings, either at law or
in equity to enforce performance or observation by Lessee of the applicable
provisions of this Agreement, or to recover damages for the breach of any
thereof.
(c) The remedies herein provided in favor of Lessor in case of any default
by Lessee shall not be deemed to be exclusive, but shall be cumulative and shall
be in addition to all other remedies in its favor existing at law, in equity or
in bankruptcy.
15. Equipment to be and Remain Personal Property.
It is the intention and understanding of both Lessor and Lessee that all
Equipment shall be and at all times remain personal property. Lessee shall
obtain and record such instruments and take such steps as may be necessary to
prevent any person from acquiring any rights in Equipment paramount to the
rights of Lessor, its assignees or mortgagees by reason of such Equipment being
deemed to be real property. If notwithstanding the intention of the parties and
the provisions of this Section 15, any person acquires or reasonably claims to
have acquired any rights in any Equipment superior to the rights of Lessor, its
assignees or mortgagees, by reason of such Equipment being deemed to be real
property, and such person seeks by judicial process or by taking possession to
interfere with the continued quiet enjoyment of the Equipment by Lessee as
contemplated by this Agreement, then Lessee shall promptly notify Lessor in
writing of such fact (unless the basis for such interference is waived or
eliminated to the satisfaction of Lessor within a period of ninety (90) days
from the date it is asserted) and Lessee shall within ninety (90) days after
such notice pay to Lessor or Lessor's assignee an amount equal to the
Unamortized Cost of such Equipment at the time of payment. The lease term of
such Equipment shall continue until such payment and shall thereupon terminate
at the end of the month during which such payment shall have been received by
Lessor. Upon receipt of such payment, Lessor shall release to Lessee all of
Lessor's right, title and security interest in such Equipment and execute such
documents as Lessee may reasonably request to evidence such release.
16. Sale or Assignment by Lessor.
Lessor shall have the right to finance the acquisition of such Equipment
by selling or assigning its right, title and interest in moneys due from Lessee
and any third party under this Agreement and in that connection to assign its
security interest in Equipment, provided that in no event may Lessor assign any
of its obligations hereunder without remaining secondarily liable therefor, and
provided, further, that any such sale or assignment shall be subject and
subordinate to the rights and interest of Lessee in such Equipment and under
this Agreement. Lessor's transferee or assignee shall have all the rights,
powers, privileges and remedies of Lessor hereunder and Lessee's obligations as
between itself and such transferee or assignee hereunder shall not be subject to
any claims or defense which Lessee may have against Lessor. Upon written notice
to Lessee of any such sale or assignment, Lessee shall thereafter make payments
of all rents and other sums due hereunder to the party specified in such notice
and such payments shall discharge the obligation of Lessee to Lessor hereunder
to the extent of such payments.
17. Unconditional Obligation of Lessee to Pay Rent.
Lessee's obligation to pay all Rent and other amounts payable hereunder
shall be absolute and unconditional and shall not be affected by any
circumstance, including, without limitation, (i) any setoff, counterclaim,
recoupment, defense or other right which Lessee may have against Lessor or
anyone else for any reason whatsoever, (ii) any defect in the title, compliance
with specifications, condition, design, operation or fitness for use of, or any
damage to or loss or destruction of, any Equipment, or (iii) any interruption or
cessation in the use or possession of any Equipment by Lessee for any reason
whatsoever, provided, however, that if an interruption or cessation in Lessee's
use or possession of any Equipment is caused by any attachment or similar act by
or on behalf of any creditor of Lessor, and is not attributable to any failure
by Lessee to perform its obligations under this Agreement, then Lessee's
obligation to pay Rent with respect to such Equipment shall be appropriately
reduced for the period of such interruption or cessation, and, provided further,
that the foregoing shall be without prejudice to Lessee's right to pursue by
separate legal action any claim Lessee may have against Lessor arising out of
this Agreement. Lessee hereby waives, to the extent permitted by applicable law,
any and all rights which it may now have or which at any time hereafter may be
conferred upon it, by statute or otherwise, to terminate, cancel, quit or
surrender this Agreement except in accordance with the express terms hereof.
Subject to the second proviso in the first sentence of this Section 17, each
Rent and other payment made by Lessee shall be final and Lessee will not seek to
recover all or any part of such payment from Lessor for any reason whatsoever.
18. Additional Right of Termination.
A. In addition to any other right of termination contained in this
Agreement, Lessor may terminate the lease of all Equipment upon any "Special
Terminating Event", by giving Lessee 5 days prior written notice of such
termination. For purposes of this Section 18A, "Special Terminating Events"
shall mean any of the following:
(i) any assignment of the Millstone Plant Agreement by and among The
Connecticut Light and Power Company ("CL&P"), Western Massachusetts Electric
Company ("WMECO") and Lessee ("Plant Agreement"), without Lessor's prior written
consent, which consent shall not be unreasonably withheld; provided that this
clause (i) shall not apply to any assignment of the Millstone Plant Agreement as
part of any merger, consolidation or reorganization of CL&P or WMECO with or
into each other or with or into Northeast Utilities ("NU");
(ii) any modification to the Plant Agreement which could materially
adversely affect Lessee's ability to perform all of its obligations under this
Agreement;
(iii) cancellation of the Plant Agreement;
(iv) the Plant Agreement shall become illegal, unenforceable or
invalid;
(v) any merger, consolidation or reorganization of Lessee which in
Lessor's reasonable judgment could cause an adverse material change in Lessee's
ability to perform all of its obligations under this Agreement; or
(vi) Lessee shall no longer be a direct or indirect wholly-owned
subsidiary of Northeast Utilities or any successor thereof.
B. In addition to any other right of termination contained in this
Agreement, Lessee may terminate the lease of all Equipment upon Lessee paying
Lessor for taxes on the net income of Lessor under the tax indemnity provisions
of Section 10(c) hereof as a result of any change in the applicable laws, rules
or regulations from those in effect on the date of this Agreement, by giving
Lessor 5 days prior written notice of such termination.
Upon the termination date specified in such notice, Lessee shall pay to Lessor
an amount equal to the Unamortized Cost of the Equipment and upon receipt by
Lessor of such amount, Lessor shall release all of its right, title and security
interest therein and execute such documents as Lessee may reasonably request to
evidence such release.
19. Notice and Request
Any notice or request which by any provision of this Agreement is required
or permitted to be given by either party to the other shall be deemed to have
been given when deposited in the mail, postage prepaid, by first class mail or
air mail (unless certified or registered mail is otherwise specified for such
notice under this Agreement), and addressed as follows (or to such other address
as either party may specify by written notice to the other party):
If to Lessor -
The Prudential Insurance
Company of America
c/o PruCapital Management, Inc.
Box 1613
Newark, New Jersey 07101
Attention: Comptroller
If to Lessee -
Northeast Nuclear Energy Company
P.O. Box 270
Hartford, Connecticut 06141-0270
Attention: Treasurer
20. Conditions to Lease.
This Agreement, and the rights and obligations of the parties hereunder,
is subject to the following conditions:
A. Regulatory Approvals
Lessee shall obtain all federal and state regulatory approvals which are
required in connection with the execution, delivery and performance of this
Agreement and the transactions contemplated hereby.
B. Board of Directors and Other Approvals
Lessee shall obtain the approval of its Board of Directors, if required,
and Lessor shall obtain the approval of the Finance Committee of its Board of
Directors, if required, for the execution, delivery and performance of this
Agreement and the transactions contemplated hereby.
C. Indenture Release
Lessee shall obtain a release of the Equipment from the lien of the
Indenture of Mortgage, Assignment and Security Agreement dated as of August 26,
1983, granted by NUSIMCO, Inc. to The Toronto-Dominion Bank, Atlanta Agency, as
amended and supplemented to the date hereof.
D. Consent of Singer/Link
Lessee shall obtain the consent of the Link Simulation Systems Division of
The Singer Company ("Singer/Link"), the vendor of the Equipment, if such consent
shall be required under the Contract for Nuclear Power Plant Control Room
Simulators dated as of July 1, 1982, between Northeast Utilities Service Company
acting as agent for certain other entities, and Singer/Link, as the same may
have been amended, modified, and supplemented.
E. Material and Adverse Change
At the time each Individual Leasing Record is executed by Lessee, since
March 31, 1985 there shall not have occurred or be threatened (i) a material and
adverse change in Lessee's financial condition, or (ii) any condition, event or
act which would materially and adversely affect Lessee's financial condition or
its ability to perform its obligations under this Agreement, and Lessee shall
have delivered to Lessor an officer's certificate to both such effects.
F. Representations and Warranties
All representations and warranties of Lessee contained in Exhibit D
attached hereto or in any document or certificate furnished to Lessor in
connection herewith shall be true and correct on the date of each Individual
Leasing Record subsequent to May 2, 1985 and Lessee shall have delivered to
Lessor an officer's certificate to such effect.
G. Additional Assurances by Lessee
Lessee shall provide Lessor with such additional certificates, documents,
evidences of title and opinions of counsel, and shall make such filings and
recordations, as Lessor shall reasonably request, and all legal and title
matters with respect to this Agreement and the transactions contemplated hereby
shall be satisfactory in form and substance to Lessor.
21. Miscellaneous.
The parties hereto agree that the other party shall not by act, delay,
omission or otherwise be deemed to have waived any of its rights or remedies
hereunder unless such waiver is given in writing. A waiver on one occasion shall
not be construed to be a waiver on any other occasion. This Agreement, the
Individual Leasing Records covering Equipment leased pursuant to this Agreement,
agreements in the form of exhibits annexed hereto and the certificate certifying
as to various matters relating to Lessee furnished by Lessee to Lessor in
connection herewith constitute the entire agreement between the parties hereto
with respect to the leasing of and creation of a security interest in the
Equipment and no representations, warranties, promises, guaranties or
agreements, oral or written, express or implied have been made by either party
hereto with respect to this Agreement or the Equipment, except as expressly
provided herein. Any change or modification of this Agreement must be in writing
and duly executed by the parties hereto. The captions in this Agreement are for
convenience or reference only and shall not be deemed to affect the meaning or
construction of any of the provisions hereof. Any provision of this Agreement
which is prohibited or unenforceable in any jurisdiction shall, as to such
jurisdiction, be ineffective to the extent of such prohibition or
unenforceability without invalidating the remaining provisions hereof, and any
such prohibition or unenforceability in any jurisdiction shall not invalidate or
render unenforceable such provision in any other jurisdiction. To the extent
permitted by applicable law, Lessee hereby waives any provision of law which
renders any provision hereof prohibited or unenforceable in any respect. Lessee
from time to time shall deliver to Lessor, promptly upon reasonable request such
information with respect to Lessee's operations, business, property, assets,
financial condition or litigation as Lessor shall reasonably request, including
without limitation annual unaudited financial statements and quarterly unaudited
financial statements of Lessee and Lessee's annual Form 1 filing with the
Federal Energy Regulatory Commission, and promptly after filing, copies of any
prospectus on any proposed public issue, any report on Form 10-K, Form 10-Q, or
Form 8-K which CL&P, WMECO and NU or their successors shall file with the
Securities and Exchange Commission or any securities exchange. Lessee hereby
certifies to Lessor that any representation or statement made by Lessee herein
or in any written instrument furnished by Lessee to Lessor in connection
herewith shall be true and correct in all material respects as of the date when
made, and further certifies to Lessor that no such representation or statement
omitted to state a material fact necessary in order to make such representation
or statement not misleading in light of the circumstances under which it was
made. This Agreement and the rights and obligations of the parties hereunder
shall be construed in accordance with and be governed by the laws of the State
of Connecticut. Lessor hereby agrees that whenever this Agreement requires
Lessor to convey title to Equipment to Lessee or its designee, Lessor shall
convey title free and clear of all liens, charges and encumbrances created by or
against Lessor.
IN WITNESS WHEREOF, Lessor and Lessee have caused this Agreement to be
executed and delivered by their duly authorized officers as of the day and year
first above written.
(Corporate Seal) THE PRUDENTIAL INSURANCE
COMPANY OF AMERICA
ATTEST: By its authorized agent,
PRUCAPITAL MANAGEMENT INC.,
Lessor
/s/ /s/ John K. Wand
Assistant Secretary Vice President
(Corporate Seal) NORTHEAST NUCLEAR ENERGY COMPANY
Lessee
/s/ Cheryl W. Grise /s/ David H. Boguslawski
Assistant Secretary Assistant Treasurer
STATE OF )
ss:
COUNTY OF )
On this 14th day of June, 1985, before me personally appeared John K. Wand, to
me personally known, who, being by me duly sworn, says that he is Vice President
of PruCapital Management Inc., that one of the seals affixed to the foregoing
instrument is the corporate seal of said corporation, that said instrument was
signed and sealed on behalf of said corporation by proper corporate authority
and he acknowledged that the execution of the foregoing instrument was the free
act and deed of said corporation.
/s/ Marcia L. Grimes
Notary Public
My Commission Expires: 2/28/91
STATE OF CONNECTICUT )
ss: BERLIN
COUNTY OF HARTFORD )
On this 19th day of June, 1985, before me personally appeared David H.
Boguslawski, to me personally known, who, being by me duly sworn, says that he
is Assistant Treasurer of Northeast Nuclear Energy Company, that one of the
seals affixed to the foregoing instrument is the corporate seal of said
corporation, that said instrument was signed and sealed on behalf of said
corporation by proper corporate authority and he acknowledged that the execution
of the foregoing instrument was the deed of said corporation.
/s/ Andrea Allen
Exhibit 13.1
1994
PORTIONS OF ANNUAL REPORT TO SHAREHOLDERS
NORTHEAST UTILITIES
FINANCIAL AND STATISTICAL SECTION
TABLE OF CONTENTS
Page 16-23
Management's Discussion and Analysis
Page 24
Company Report
Page 24
Report of Independent Public Accountants
Page 25
Consolidated Statements of Income
Page 26
Consolidated Statements of Cash Flows
Page 27
Consolidated Statements of Income Taxes
Page 28-29
Consolidated Balance Sheets
Page 30-31
Consolidated Statements of Capitalization
Page 32
Consolidated Statements of Common Shareholders' Equity
Page 33-46
Notes to Consolidated Financial Statements
Page 47
Consolidated Statements of Quarterly Financial Data
Page 47
Consolidated General Operating Statistics
Page 48-49
Selected Consolidated Financial Data
Page 50
Consolidated Electric Operating Statistics
MANAGEMENT DISCUSSION AND ANALYSIS
FINANCIAL CONDITION
Overview
Earnings per common share were $2.30 in 1994, as compared to $2.02
in 1993. The 1994 earnings were higher as a result of higher retail
kilowatt-hour sales, retail rate increases for CL&P and PSNH, the deferral of
cogeneration expenses in Connecticut, and reduced operation and interest
costs. These increases were partially offset by lower revenues from wholesale
sales. The 1993 earnings were impacted by a number of one-time items,
including the cumulative effect of a one-time change in the accounting for
Connecticut municipal property taxes, which resulted in an increase in 1993
earnings of $0.42 per common share. In addition, 1993 earnings reflected a
decrease of $0.14 per share for the costs of the company's employee-reduction
program and a decrease of $0.12 per share for disallowances in 1993 ordered
by Connecticut regulators in the CL&P rate case. Earnings per common share
before the effects of the change in accounting for property taxes and other
one-time items were $1.86 in 1993.
Increased earnings will help the company to achieve its objective
of increasing total return to shareholders (stock price plus dividend
return). In 1994, total return to shareholders was more than 13 percentage
points better than the Dow Jones Utilities Index.
In 1994, NU experienced its most significant retail kilowatt-hour
sales growth in six years, due in large part to the beginning of an economic
recovery in New England. Employment levels-particularly in New Hampshire -
have risen, unemployment rates have fallen, and personal income has
increased in all three states served by the NU operating companies (the
system). NU's 1994 retail sales rose by 2.9 percent over 1993. Overall,
weather had little effect on sales volume, with mild weather after mid-August
offsetting unusually cold weather in January and hot weather in late June and
July.
In 1995, the company expects little retail sales growth over
1994, primarily because of the effects of higher interest rates on the
regional economy and further cutbacks in defense-related industries in
Connecticut. Over the longer term, retail kilowatt-hour sales growth is
expected to be strongest in New Hampshire, which by some measures has the
fastest growing economy in New England. In 1994, many businesses announced
plans to expand in New Hampshire. NU estimates PSNH to have compounded annual
sales growth of 1.9 percent from 1994 through 1999, compared with 1.4 percent
for CL&P and 0.9 percent for WMECO.
Competitive forces within the electric utility industry are
continuing to increase due to a variety of influences, including legislative
and regulatory actions, technological advances, and changes in consumer
demand. The company has developed, and is continuing to develop, a number of
initiatives to retain and to continue to serve its existing customers and to
expand its retail and wholesale customer base.
NU believes the steps it is taking, including a companywide
process reengineering effort, will have significant, positive effects,
including reduced operating costs and improved customer service, in the next
few years. The system also benefits from a diverse retail base with no
significant dependence on any one retail customer or industry.
NU's electric utility subsidiaries continue to operate
predominantly in state-approved franchise territories under traditional
cost-of-service regulation. Retail wheeling, under which a retail customer
would be permitted to select an electricity supplier and require the local
electric utility to transmit the power to the customer's site, is not
required in any of the system's jurisdictions. In 1994, Connecticut
regulators reviewed the desirability of retail wheeling and determined that
it was not in the best interest of the state until new generating capacity is
needed, which the company projects to be in the year 2009. In New Hampshire
and Massachusetts, bills related to retail wheeling have been introduced in
the legislature. Connecticut, New Hampshire, and Massachusetts regulators are
presently studying the potential restructuring of the electric utility
industry. To date, none of these bills have been enacted and none of the
regulatory proceedings have progressed to the point where management can assess
the impact of any potential outcomes on the company.
While retail competition is not required in the system's retail
service territory, competitive forces are nonetheless influencing retail
pricing. These forces include competition from alternate fuels such as
natural gas, competition from customer-owned generation, and regional
competition for business retention and expansion. The company's retail
business group continues to work with customers to address their concerns.
The system has reached long-term rate agreements with many new and existing
customers to gain or retain their business. In general, these rate agreements
have terms of about five years. Negotiated retail rate reductions for system
customers under rate agreements in effect for 1994 amounted to approximately
$20 million. Management believes that the aggregate amount of negotiated
retail rate reductions will increase in 1995 but that the related agreements
will continue to provide significant benefits to the company, including the
preservation of approximately 4 percent of retail revenues.
The company is also working with regulators to address the needs
of customers more widely. The company has multiyear rate plans in effect in
each of its retail jurisdictions. Management will continue to evaluate the
use of agreements of this type to keep retail rates competitive.
The system acts as both a buyer and a seller of electricity in
the highly competitive wholesale electricity market in the Northeastern
United States (Northeast). Many of the contracts signed in the late 1980s
have or will expire in the mid-1990s and much of the revenue produced by such
contracts has not been replaced through new wholesale power arrangements. As
a result, wholesale power revenues fell to approximately $331 million in 1994
from approximately $383 million in 1993. Unless prices on the wholesale market
improve, revenues are expected to fall still further in 1995 before stabilizing
in late 1996 and 1997. Wholesale sales are made primarily to investor-owned
utilities and municipal or cooperative electric systems in the Northeast. The
system will be increasing its efforts to increase wholesale sales through
intensified marketing efforts. The system's wholesale power marketing efforts
benefit from the interconnection of its transmission system with all of the
major utilities in New England, as well as with three of the larger electric
utilities in New York state.
Rate Matters
The operating companies of the system follow accounting principles
that allow the rate treatment for certain events or transactions to be
reflected. These principles may differ from the accounting principles followed
by nonregulated enterprises. Regulators may permit incurred costs, which would
normally be treated as expenses by nonregulated enterprises, to be deferred as
regulatory assets and recovered in revenues at a later date. Regulatory assets
at December 31, 1994 were approximately $2.7 billion. Based on current
regulation, the company believes that its use of regulatory accounting is still
appropriate.
See the "Notes To Consolidated Financial Statements," Note 1H,
for further details on regulatory accounting.
Connecticut
CL&P's retail rates increased by approximately $47 million, or 2.04
percent, in July 1994, representing the second step of a three-year rate plan
approved by the Department of Public Utility Control (DPUC) in 1993. The third
step of an approximately $48-million, or 2.06 percent, increase will become
effective in July 1995. CL&P's 1993 rate decision has been appealed by the
Connecticut Office of Consumer Counsel and the city of Hartford. If this appeal
prevails, there may be revenues subject to refund; however, management believes
that the possibility of the appeal prevailing is unlikely.
CL&P recovers from or refunds to customers certain fuel costs if
the nuclear units do not operate at a predetermined capacity factor (currently
72 percent) through a Generation Utilization Adjustment Clause (GUAC). For the
GUAC year ended July 31, 1994, the DPUC found that CL&P overrecovered its fuel
costs and reduced by approximately $8 million CL&P's overall request to recover
approximately $24 million of deferred GUAC costs. The company plans to appeal
the decision in court as it did for a similar DPUC decision on the 1992-1993
GUAC period, which also disallowed approximately $8 million of GUAC costs.
For the GUAC year ended July 31, 1995, CL&P expects to defer in
excess of $50 million of GUAC fuel costs for projected nuclear performance below
72 percent. As of December 31, 1994, CL&P has reserved approximately $13 million
against this amount, based on the methodology applied by the DPUC in the
previous GUAC decisions.
New Hampshire
In June 1994, PSNH's base rates increased by 5.5 percent under a
seven-year 1989 rate agreement approved by the New Hampshire Public Utilities
Commission (NHPUC).
The costs associated with purchases by PSNH from certain
nonutility generators (NUGs) over the level assumed in rates are deferred and
recovered over ten-year periods through the Fuel and Purchased Power
Adjustment Clause (FPPAC). At December 31, 1994, the unrecovered deferrals
were approximately $174 million. PSNH is attempting to renegotiate these
arrangements with the NUGs.
On September 23, 1994, the NHPUC approved settlement agreements
with two wood-fired NUGs covering approximately 20 megawatts (MW) of
capacity. These two NUGs gave up their rights to sell their output to PSNH in
exchange for lump-sum cash payments by PSNH totaling approximately $40
million. The buyout payments were added to the deferred balance of NUG costs.
The savings resulting from the agreements will be used to reduce the NUG
deferred balance over the remaining period of the canceled arrangements. PSNH
is involved in mediations with the owners of the six remaining wood-fired
facilities, which account for approximately 87 MW of capacity. PSNH has reached
an agreement with one of these six NUGs, which calls for a payment by PSNH of
$52 million in return for a substantial reduction in the rates charged to
PSNH. This agreement was filed with the NHPUC in February 1995.
Massachusetts
On May 26, 1994, the Massachusetts Department of Public Utilities
(DPU) approved a settlement agreement under which WMECO's customers received a
base-rate reduction of approximately $13 million over a 20-month period
effective June 1, 1994 and a guarantee of no general base-rate increases before
February 1996. This agreement also terminated, without findings, all performance
review proceedings regarding the treatment of replacement-power costs incurred
by WMECO during power outages from mid-1987 through mid-1993. The DPU also
approved the amortization of previously deferred expenses for postretirement
benefits beginning in July 1994. In addition, under the agreement, WMECO's
larger customers will be offered discounts on their electric bills in return for
providing WMECO with five years' notice of any plans to self-generate or
purchase electricity from a different provider. The combined base-rate reduction
and service-extension discounts will total 5 percent for those larger customers.
The settlement agreement did not have a significant adverse impact on WMECO's
earnings.
Nuclear Performance
The composite capacity factor of the five nuclear generating units
that the system operates-including the Connecticut Yankee (CY) nuclear unit-was
67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national
average of 73.2 percent. The lower 1994 capacity factor was primarily the result
of extended refueling and maintenance outages for Millstone 1, Millstone 2, and
Seabrook. CY, Seabrook, and Millstone 2 were also out of service for varying
lengths of time in 1994 because of unexpected technical and operating
difficulties. These difficulties included a manual shutdown of CY when both
service water headers were declared inoperable, an automatic trip from 100
percent power for Seabrook when a main steam isolation valve closed during
quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded
lower seal on a reactor coolant pump.
On October 1, 1994, Millstone 2 was shut down for a planned
63-day refueling and maintenance outage. The outage has encountered several
unexpected difficulties, which will lengthen the duration of the outage. The
outage extensions were caused by a significant scope increase in service
water system repairs, as identified through a comprehensive inspection plan
and by a need for management to exercise a deliberate approach to the conduct
of work during the early portions of the outage. The outage schedule is
currently under review, but the unit is not expected to return to service
before April 1995. Total replacement-power costs attributable to the
extension of the outage for CL&P and WMECO are expected to be in the range of
$8 million per month. CL&P's share of these costs is deferred for future
recovery through the GUAC. (See page 18 for further discussion of the GUAC.) In
addition, operation and maintenance costs to be incurred during the outage are
estimated to be $52 million, an increase of $19 million as a result of the
extension. The recovery of these costs is subject to prudence reviews in both
Connecticut and Massachusetts.
The Nuclear Regulatory Commission's (NRC's) latest report for the
Millstone Station noted significant weaknesses in Millstone 2's operations
and maintenance. In a public statement in late 1994, a senior NRC official
expressed disappointment with the continued weaknesses in Millstone 2's
performance. The primary cause of the NRC's disappointment with Millstone 2's
performance appears to be that, despite significant management attention and
action over a period of years, the NRC does not believe it has seen enough
objective evidence of improvement in reducing procedural noncompliance and
other human errors. Management has acknowledged the basis for the NRC's
concern with Millstone 2 and has been devoting increased attention to
resolving these issues. Management and the NRC expect to continue to monitor
closely the developments at Millstone 2.
Environmental Matters
The system devotes substantial resources to identify and then to
meet the multitude of environmental requirements it faces. The company has
active auditing programs addressing a variety of different regulatory
requirements, including an environmental auditing program to detect and
remedy noncompliance with environmental laws or regulations.
The system is potentially liable for environmental cleanup costs
at a number of sites both inside and outside its service territories. To
date, the future estimated environmental remediation liability has not been
material with respect to the earnings or financial position of the company.
At December 31, 1994, the liability recorded by the company amounted to
approximately $11 million. These costs could rise to as much as $16 million
if alternate remedies become necessary.
The company expects that the implementation of the 1990 Clean Air
Act Amendments (CAAA) as they relate to sulfur-dioxide emissions will require
only modest emission reductions for the NU system. NU's exposure is minimal
because of the company's investment in nuclear energy in the 1970s and 1980s and
the burning of low-sulfur fuels. PSNH is subject to more stringent emission
limits for nitrogen oxides within the next five years under the CAAA
requirements. PSNH will install at Merrimack Station a selective catalytic
reduction (SCR) pollution control system by May 1995 to comply with CAAA
requirements. The cost of the SCR installation is approximately $22 million,
with approximately $10 million of costs incurred as of December 31, 1994.
Nuclear Decommissioning
The system's estimated cost to decommission its shares of Millstone
units 1, 2, and 3 and Seabrook is approximately $1.2 billion in year-end 1994
dollars. In addition, the system's estimated cost to decommission its shares of
the regional nuclear generating units is estimated to be approximately $300
million. These costs are being recognized over the lives of the respective units
and a portion of the costs is being recovered through rates. Yankee Atomic
Electric Company (YAEC) has begun component removal activities related to the
decommissioning of its nuclear facility. The system's estimated obligation to
YAEC has been recorded on the Consolidated Balance Sheets. Management expects
that the system will continue to be allowed to recover these costs.
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the electric
utility industry, including this company, regarding the recognition,
measurement, and classification of decommissioning costs for nuclear
generating stations in the financial statements of electric utilities. The
Financial Accounting Standards Board is currently reviewing the accounting
for removal costs, including decommissioning and similar costs. If current
electric utility industry accounting practices for such decommissioning costs
were changed: (1) annual provisions for decommissioning could increase, (2)
the estimated costs for decommissioning could be recorded as a liability
rather than as accumulated depreciation, and (3) trust fund income from the
external decommissioning trust could be reported as investment income rather
than as a reduction to decommissioning expense.
See the "Notes To Consolidated Financial Statements," Note 3, for
further information on nuclear decommissioning.
Two separate stacked bar graphs illustrate the sources and uses of cash
requirements for 1993 and 1994 and projections for 1995 through 1999.
NORTHEAST UTILITIES
SOURCES AND USES OF CASH REQUIREMENTS
1993 - 1999
Sources of Cash
Requirements 1993 1994 1995 1996 1997 1998 1999
--------------- ---- ---- ---- ---- ---- ---- ----
(Percentages)
Internally
Generated Funds 36.7 46.7 80.5 80.4 86.2 88.3 69.0
Nuclear Fuel Trust 5.2 6.7 7.2 16.3 13.8 9.3 11.5
LTD and Preferred
Stock 56.9 44.3 12.3 0.0 0.0 0.0 17.5
Short-Term Debt 0.0 1.2 0.0 1.1 0.0 0.0 0.0
Common Stock 1.2 1.1 0.0 2.2 0.0 2.4 2.0
----- ----- ----- ----- ----- ----- -----
Total Sources 100.0 100.0 100.0 100.0 100.0 100.0 100.0
Uses of Cash
Requirements 1993 1994 1995 1996 1997 1998 1999
--------------- ---- ---- ---- ---- ---- ---- ----
(Percentages)
Construction 15.6 18.4 31.1 34.8 32.4 35.8 27.7
Nuclear Fuel 5.9 7.2 9.1 18.9 14.3 11.7 13.7
Maturities and
Sinking Fund 66.1 70.2 36.5 43.1 43.4 41.0 49.1
Repayment of
Short-Term Debt 10.1 0.0 19.6 0.0 8.2 10.6 8.6
Other 2.3 4.2 3.7 3.2 1.7 0.9 0.9
----- ----- ----- ----- ----- ----- -----
Total Uses 100.0 100.0 100.0 100.0 100.0 100.0 100.0
Property Taxes
CY and PSNH have had significant court appeals for municipal property
tax assessments in the towns of Haddam, Connecticut, and Bow, New Hampshire. In
each case, the central issue is the fair market value of utility property. The
company believes that the assessments should be based on a fair market value
that approximates net book cost. This is the assessment level that taxing
authorities are predominantly using throughout Connecticut, Massachusetts, and
in some of New Hampshire. However, towns such as Haddam and Bow advocate a
method that approximates reproduction costs.
PSNH's appeal of the property tax as assessed against them by Bow
has been dismissed by the Supreme Court of New Hampshire. CY's appeal is
still pending. The company estimates that, for assessments in towns such as
Haddam and Bow, the change to the reproduction cost methodology could result
in property valuations approximately three times greater than values
approximating net book cost. If other towns adopt this methodology, there
could be a significant adverse impact on the company's future results of opera
tions and financial condition. However, the extent to which other towns
successfully adopt this methodology and any subsequent increase in the
company's property tax liability cannot be determined at this time.
Liquidity And Capital Resources
Cash provided from operations increased approximately $7 million
in 1994, as compared to 1993, primarily due to higher revenues from rate
increases and sales, combined with lower cash operating expenses. Cash used
for financing activities was approximately $10 million higher in 1994, as
compared to 1993, primarily due to higher net reacquisition and retirements
of long-term debt, partially offset by an increase in short-term debt. Cash
used for investments was approximately $20 million lower in 1994, as compared
to 1993, primarily due to lower construction expenditures in 1994.
The charts opposite illustrate the sources and uses of cash
requirements for 1993 and 1994 and the projections for 1995 through 1999.
In 1994, the NU system companies refinanced $625 million of debt,
which is expected to reduce interest costs by approximately $3 million
annually. With interest rates rising in mid-1994, a lot of refinancing
completed, and construction needs remaining modest, the focus in NU's
financing activities will shift toward using the significant amount of cash
generated by each subsidiary to retire debt and to prepare the company for an
increasingly competitive business environment.
The system companies are obligated to meet approximately $1.4
billion of long-term debt and preferred stock maturities and cash
sinking-fund requirements during the 1995 through 1999 period, including
approximately $176 million for 1995.
The system's construction program expenditures, including
allowance for funds used during construction, for the period 1995 through
1999 are estimated to be approximately $1.2 billion, including approximately
$254 million for 1995. The construction program's main focus is maintaining
and upgrading the existing transmission and distribution system, as well as
nuclear and fossil-generating facilities. The company does not foresee the
need for new, major generating facilities until at least the year 2009.
Construction expenditures and debt maturities and sinking-fund
requirements will continue to be met through internal cash generation. PSNH
may need to supplement its internal cash generation with outside financing,
including additional borrowings, if additional agreements are reached with
the wood-fired NUGs.
CL&P, PSNH, and WMECO entered into interest-rate cap contracts to
reduce a portion of the interest-rate risk on certain variable-rate
tax-exempt pollution control revenue bonds and a PSNH variable-rate term
loan. CL&P also uses fossil-fuel-swap agreements to hedge against fuel-price
risk on certain long-term, negotiated energy contracts. Any premiums paid on
these contracts are deferred and amortized over the life of the contracts.
The differential paid or received as interest rates or fuel prices change is
recognized in income when realized.
See the "Notes To Consolidated Financial Statements," Note 8, for
further information on derivative financial instruments.
Results of Operations
The relative magnitude of the various expenditures incurred by
the system's continuing operations in 1994 is illustrated in the chart on
page 23.
A majority of the changes in items affecting results of
operations between 1992 and 1993 is due to the inclusion of PSNH and NAEC
results for a full year in 1993 and only seven months in 1992.
Operating Revenues
The components of the change in operating revenues for the past
two years are provided in the table above.
Operating revenues increased approximately $14 million in 1994
from 1993. Revenues related to regulatory decisions increased, primarily
because of the effects of the July 1993 and 1994 retail rate increases for
CL&P, the June 1993 and 1994 retail rate increases for PSNH, and the July
1993 retail rate increase for WMECO, partially offset by the June 1994 retail
rate reduction for WMECO and lower recoveries for demand-side-management
costs. Sales volume increased as a result of higher retail sales from an
improving economy. Retail sales increased 2.9 percent in 1994 from 1993 sales
levels. Wholesale revenues decreased, primarily due to the expiration in late
1993 and 1994 of some significant capacity sales contracts.
Operating revenues increased approximately $412 million in 1993
from 1992, primarily due to the additional revenues of PSNH for a full year
in 1993. Operating revenues, excluding PSNH, increased approximately $45
million in 1993 from 1992. Revenues related to regulatory decisions
increased, primarily because of the effects of the June 1993 retail rate
increase for CL&P and the July 1992 and 1993 retail rate increases for WMECO.
Fuel, purchased power, and FPPAC cost recoveries decreased, primarily due to
lower energy costs. Retail sales for CL&P and WMECO increased only 0.2 percent
in 1993 from 1992 sales levels.
Fuel, Purchased And Net Interchange Power
Fuel, purchased and net interchange power decreased approximately
$86 million in 1994, as compared to 1993, primarily due to the lower recognition
of CL&P replacement-power fuel costs in 1994, partially offset by a higher level
of outside energy purchases from other utilities in 1994.
Fuel, purchased and net interchange power increased approximately
$145 million in 1993, as compared to 1992, primarily due to the additional
PSNH and NAEC expenses (approximately $99 million), the timing in the
recognition of fuel expenses under the provisions of CL&P's fuel adjustment cl
auses, and disallowances of replacement- power costs as a result of
regulatory reviews in Connecticut, partially offset by lower outside
purchases due to better nuclear performance in 1993.
Other Operation And Maintenance Expenses
Other operation and maintenance expenses decreased approximately $20
million in 1994, as compared to 1993, primarily due to higher costs in 1993
associated with early retirement programs, lower 1994 payroll and benefit costs,
lower fossil-unit costs, and lower capacity charges from the regional nuclear
generating units, partially offset by higher 1994 costs associated with the
operation and maintenance activities of the nuclear units (approximately $23
million), higher reserves for excess/obsolete inventory at the nuclear and
fossil units in 1994, and higher outside services primarily related to the
companywide process reengineering efforts.
Other operation and maintenance expenses increased approximately
$143 million in 1993, as compared to 1992, primarily due to the additional
PSNH and NAEC expenses (approximately $105 million), the 1993 costs
associated with an employee-reduction program (approximately $33 million),
the 1992 reimbursement of previously expended costs associated with the PSNH
acquisition, and 1993 postretirement benefit costs, partially offset by lower
costs associated with the operation and maintenance activities of the nuclear
units.
Depreciation Expenses
Depreciation expenses increased approximately $14 million in
1994, as compared to 1993, primarily as a result of higher depreciable plant
balances, higher average depreciation rates, and higher decommissioning
collections.
Depreciation expenses increased $39 million in 1993, as compared
to 1992, primarily as a result of the additional PSNH and NAEC depreciation
expense ($27 million, including Seabrook), higher depreciation rates, and high
er depreciable plant balances.
Amortization Of Regulatory Assets, Net
Amortization of regulatory assets, net decreased approximately
$48 million in 1994, as compared to 1993, primarily because of the deferral
of CL&P cogeneration expenses beginning in July 1994 as allowed under CL&P's
1993 retail rate decision, the higher amortization in 1994 of PSNH's
regulatory liability as allowed under a 1993 global settlement, and lower
expenses associated with the recovery of Hydro-Quebec support payments,
partially offset by higher amortization of Millstone 3 and Seabrook 1
phase-in costs.
Amortization of regulatory assets, net increased approximately
$58 million in 1993, as compared to 1992, primarily because of the additional
amortization of the PSNH regulatory asset as provided for in the rate
agreement (approximately $38 million) and higher amortization of Millstone 3
and Seabrook phase-in costs. The increase in 1993 is also attributable to the
gross-up of taxes due to a required change in the accounting for income taxes
and the amortization in 1993 of costs paid by CL&P to the developers of two
wood-to-energy plants as allowed in the 1993 rate decision, partially offset
by the amortization of the PSNH regulatory liability recognized as a result
of a 1993 global settlement.
Federal And State Income Taxes
Federal and state income taxes increased approximately $66
million in 1994, as compared to 1993, primarily because of higher taxable
income.
Taxes Other Than Income Taxes
Taxes other than income taxes increased approximately $7 million in
1994, as compared to 1993, primarily due to higher Connecticut sales tax
expense.
Taxes other than income taxes increased approximately $19 million
in 1993, as compared to 1992, primarily due to the additional PSNH and NAEC
taxes ($20 million, including property taxes on Seabrook).
Deferred Nuclear Plants Return
Deferred nuclear plants return decreased approximately $25
million in 1994, as compared to 1993, primarily because additional Millstone
3 and Seabrook investments were phased into rates in 1994.
Deferred nuclear plants return increased approximately $19
million in 1993, as compared to 1992, primarily because of deferred return
associated with NAEC's ownership share of Seabrook (approximately $30
million), partially offset by a decrease in Millstone 3 deferred return
because additional Millstone 3 investment was phased into rates.
Other Income, Net
Other income, net decreased approximately $11 million in 1993, as
compared to 1992, primarily because of the allocation to customers of a
portion of the property tax accounting change as ordered by the DPUC in the
CL&P 1993 rate decision.
Interest Charges
Interest on long-term debt decreased approximately $19 million in
1994, as compared to 1993, primarily because of lower average interest rates
as a result of refinancing activities and lower 1994 debt levels.
Interest on long-term debt increased approximately $57 million in
1993, as compared to 1992, primarily because of higher debt levels from the
addition of PSNH and NAEC (approximately $57 million), partially offset by
lower average interest rates as a result of substantial refinancing activities.
The increase in 1993 is also due to the absence of an interest expense offset in
1993 for Employee Stock Option Plan (ESOP) dividends due to a change in
accounting for ESOPs.
Cumulative Effect Of Accounting Change
The cumulative effect of the accounting change of approximately
$52 million in 1993 represents the one-time change in the method of accounting
for Connecticut municipal property tax expense recognized in the first quarter
of 1993.
Tax Benefit Of Employee Stock Ownership Plan Dividends
The tax benefit of ESOP dividends of approximately $7 million in 1992
is the result of the company adopting an ESOP. In 1993, these benefits are
reflected as a reduction to income tax expense. See the "Notes To Consolidated
Financial Statements," Note 6, for further information regarding ESOP.
A pie chart illustrates the magnitude of the various expenses incurred by
the System's continuing operations in 1994.
NORTHEAST UTILITIES
1994 DISTRIBUTION OF REVENUE
Percent
-------
Energy Costs 22.9%
Other Operation and
Maintenance Expenses 21.3
Taxes 14.5
Other Operating Expenses
and Other Income, Net 13.0
Wages and Benefits 12.3
Interest Charges 8.8
Common and Preferred Dividends 7.2
-----
100.0%
COMPANY REPORT
The consolidated financial statements of Northeast Utilities and subsidiaries
and other sections of this Annual Report were prepared by the company. These
financial statements, which were audited by Arthur Andersen LLP, were prepared
in accordance with generally accepted accounting principles using estimates and
judgment, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that encourages
the maintenance of high standards of conduct in all of its business activities.
The company maintains a system of internal controls over financial reporting,
which is designed to provide reasonable assurance to the company's management
and Board of Trustees regarding the preparation of reliable published financial
statements. The system is supported by an organization of trained management
personnel, policies and procedures, and a comprehensive program of internal
audits. Through established programs, the company regularly communicates to its
management employees their internal control responsibilities and policies
prohibiting conflicts of interest.
The Audit Committee of the Board of Trustees is composed entirely of outside
trustees. This committee meets periodically with management, the internal
auditors, and the independent auditors to review the activities of each and
to discuss audit matters, financial reporting, and the adequacy of internal
controls.
Because of inherent limitations in any system of internal controls, errors or
irregularities may occur and not be detected. The company believes, however,
that its system of internal accounting controls and control environment
provide reasonable assurance that its assets are safeguarded from loss or
unauthorized use and that its financial records, which are the basis for the
preparation of all financial statements, are reliable.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF TRUSTEES AND SHAREHOLDERS OF NORTHEAST UTILITIES:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Northeast Utilities (a Massachusetts trust) and
subsidiaries as of December 31, 1994 and 1993, and the related consolidated
statements of income, common shareholders' equity, cash flows, and income taxes
for each of the three years in the period ended December 31, 1994. 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 Northeast Utilities and
subsidiaries as of December 31, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
As explained in Notes 1B, 5B, and 6 to the financial statements, effective
January 1, 1993, Northeast Utilities and subsidiaries changed their methods
of accounting for property taxes, postretirement benefits other than
pensions, and employee stock ownership plans.
/s/Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Income
<TABLE>
<CAPTION>
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------------------------
(Thousands of Dollars,
except share information)
<S> <C> <C> <C>
Operating Revenues................................ $ 3,642,742 $ 3,629,093 $ 3,216,874
------------- ------------- -------------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power....... 832,420 917,957 772,804
Other........................................... 919,044 979,403 828,345
Maintenance...................................... 306,429 265,926 274,495
Depreciation..................................... 335,019 321,359 282,738
Amortization of regulatory assets, net........... 160,909 208,506 150,413
Federal and state income taxes(See Consolidated
Statements Of Income Taxes)(Note 1I)<F1I>...... 293,644 224,678 246,227
Taxes other than income taxes.................... 247,045 240,413 221,422
------------- ------------- -------------
Total operating expenses.................. 3,094,510 3,158,242 2,776,444
------------- ------------- -------------
Operating Income.................................. 548,232 470,851 440,430
------------- ------------- -------------
Other Income:
Deferred nuclear plants return--other
funds (Note 1L)<F1L>.......................... 27,085 38,373 45,299
Equity in earnings of regional nuclear
generating and transmission companies......... 14,426 12,980 15,357
Other, net...................................... 7,745 4,747 15,672
Income taxes--credit............................ 13,518 10,772 36,787
------------- ------------- -------------
Other income, net......................... 62,774 66,872 113,115
------------- ------------- -------------
Income before interest charges............ 611,006 537,723 553,545
------------- ------------- -------------
Interest Charges:
Interest on long-term debt...................... 314,191 333,163 275,819
Other interest.................................. 8,037 13,059 3,503
Deferred nuclear plants return--borrowed
funds (Note 1L)<F1L>.......................... (41,138) (54,462) (28,838)
------------- ------------- -------------
Interest charges, net..................... 281,090 291,760 250,484
------------- ------------- -------------
Income before cumulative effect of
accounting change....................... 329,916 245,963 303,061
Cumulative effect of accounting
change (Note 1B)<F1B>........................... - 51,681 -
------------- ------------- -------------
Income before Preferred Dividends
of Subsidiaries....................... 329,916 297,644 303,061
Preferred Dividends of Subsidiaries............... 43,042 47,691 47,007
------------- ------------- -------------
Net Income 286,874 249,953 256,054
Tax benefit of Employee Stock Ownership
Plan dividends (Note 6)<F6>................ - - 7,348
------------- ------------- -------------
Earnings For Common Shares........................ $ 286,874 $ 249,953 $ 263,402
============= ============= =============
Earnings Per Common Share:
Before cumulative effect of accounting
change......................................... $ 2.30 $ 1.60 $ 2.02
Cumulative effect of accounting
change (Note 1B)<F1B>.......................... - 0.42 -
------------- ------------- -------------
Total Earnings Per Common Share................... $ 2.30 $ 2.02 $ 2.02
============= ============= =============
Common Shares Outstanding (average) (Note 6)<F6>.. 124,678,192 123,947,631 130,403,488
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Cash Flows<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Income before preferred dividends of subsidiaries........ $ 329,916 $ 297,644 $ 303,061
Adjustments to reconcile to net cash
from operating activities:
Depreciation........................................... 335,019 321,359 282,738
Deferred income taxes and investment tax credits, net.. 146,560 63,506 103,089
Deferred nuclear plants return, net of amortization.... 49,994 18,189 (3,619)
Recoverable energy costs, net of amortization.......... (85,573) 93,302 (109,013)
Amortization of regulatory asset-PSNH, net............. 55,319 67,379 51,143
Deferred demand-side management, net of amortization... (4,691) (23,955) (31,989)
Other sources of cash.................................. 42,375 136,346 127,519
Other uses of cash..................................... (52,260) (3,915) (53,711)
Changes in working capital:
Receivables and accrued utility revenues............... 8,133 2,797 3,162
Fuel, materials, and supplies.......................... 4,906 10,126 (9,686)
Accounts payable....................................... 51,824 (678) (38,889)
Accrued taxes.......................................... 17,031 (97,789) (8,627)
Other working capital (excludes cash).................. 22,329 30,010 30,109
----------- ------------ ------------
Net cash flows from operating activities................... 920,882 914,321 645,287
----------- ------------ ------------
Cash Flows Used For Financing Activities:
Issuance of common shares................................ 14,551 22,252 271,128
Issuance of long-term debt............................... 625,000 924,650 1,141,995
Issuance of preferred stock.............................. - 80,000 75,000
Net increase (decrease) in short-term debt............... 16,500 (179,240) 182,240
Reacquisitions and retirements of long-term debt......... (982,920) (1,051,501) (744,771)
Reacquisitions and retirements of preferred stock........ (7,325) (116,496) (106,893)
Cash dividends on preferred stock........................ (43,042) (47,691) (49,399)
Cash dividends on common shares.......................... (219,317) (218,179) (229,074)
----------- ------------ ------------
Net cash flows (used for) from financing activities........ (596,553) (586,205) 540,226
----------- ------------ ------------
Investment Activities:
Investments in plant:
Electric and other utility plant....................... (259,904) (275,741) (311,892)
Nuclear fuel........................................... (28,308) (33,202) 3,498
----------- ------------ ------------
Net cash flows used for investments in plant............. (288,212) (308,943) (308,394)
Acquisition of the net assets of PSNH (Note 1A)<F1A>..... - - (828,237)
Other investment activities, net......................... (33,546) (32,811) (40,507)
----------- ------------ ------------
Net cash flows used for investments........................ (321,758) (341,754) (1,177,138)
----------- ------------ ------------
Net Increase (Decrease) In Cash for the Period............. 2,571 (13,638) 8,375
Cash - beginning of period................................. 32,008 45,646 37,271
----------- ------------ ------------
Cash - end of period....................................... $ 34,579 $ 32,008 $ 45,646
=========== ============ ============
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amount capitalized during construction.. $ 306,224 $ 325,552 $ 218,515
=========== ============ ============
Income taxes............................................. $ 134,727 $ 142,669 $ 96,821
=========== ============ ============
Increase in obligations:
Niantic Bay Fuel Trust................................... $ 64,590 $ 49,509 $ 38,172
=========== ============ ============
Capital leases........................................... $ 1,342 $ 4,696 $ 2,985
=========== ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements of Income Taxes<TABLE>
<CAPTION>
1994 1993 1992
For the Years Ended December 31, (Note 1I)<F1I>
----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
The components of the federal and state income
tax provisions charged to operations are:
Current income taxes:
Federal.......................................... $ 88,483 $ 99,591 $ 74,768
State............................................ 45,083 50,809 31,583
---------- -------------- ----------
Total current.................................. 133,566 150,400 106,351
---------- -------------- ----------
Deferred income taxes, net:
Federal.......................................... 149,391 87,105 101,025
State............................................ 6,988 (10,058) 12,550
---------- -------------- ----------
Total deferred................................. 156,379 77,047 113,575
---------- -------------- ----------
Investment tax credits, net....................... (9,819) (13,541) (8,182)
---------- -------------- ----------
Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744
========== ============== ==========
The components of total income tax expense are
classified as follows:
Income taxes charged to operating expenses........ $ 293,644 $ 224,678 $ 246,227
Income taxes associated with the amortization of
deferred nuclear plants return--borrowed funds... - - (17,566)
Income taxes associated with the allowance for
funds used during construction and deferred
nuclear plants return--borrowed funds............ - - 19,870
Other income taxes--credit........................ (13,518) (10,772) (36,787)
---------- -------------- ----------
Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744
========== ============== ==========
Deferred income taxes are comprised of the tax
effects of temporary differences as follows:
Depreciation, leased nuclear fuel, settlement
credits, and disposal costs..................... 72,078 79,288 66,683
Energy adjustment clauses........................ 49,017 (39,660) 22,484
Demand-side management........................... 217 8,117 13,635
Alternative minimum tax.......................... (601) 2,306 (13,462)
Early retirement program......................... 1,169 (7,715) 220
Organization costs............................... - - 10,042
Deferred tax asset associated with net
operating losses................................ 23,611 25,438 9,335
Other............................................ 10,888 9,273 4,638
---------- -------------- ----------
Deferred income taxes, net......................... $ 156,379 $ 77,047 $ 113,575
========== ============== ==========
A reconciliation between income tax expense and
the expected tax expense at the applicable
statutory rates is as follows:
Expected federal income tax at 35 percent of
pretax income for 1994 and 1993 and at
34 percent for 1992.............................. $ 213,515 $ 179,043 $ 175,033
Tax effect of differences:
Depreciation differences......................... 20,003 21,319 14,090
Deferred nuclear plants return--other funds...... (9,480) (13,486) (15,402)
Amortization of deferred Millstone 3 return--
other funds..................................... 23,103 21,988 17,367
Amortization of regulatory asset--PSNH........... 20,007 23,764 17,624
Seabrook intercompany loss....................... (19,637) (19,176) (11,903)
Investment tax credits amortization.............. (9,819) (13,541) (8,182)
State income taxes, net of federal benefit....... 33,847 26,488 29,130
Property tax differences......................... 5,824 (13,514) (901)
Other, net....................................... 2,763 1,021 (5,112)
---------- -------------- ----------
Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744
========== ============== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets<TABLE>
<CAPTION>
At December 31, 1994 1993
---------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
------
Utility Plant, at original cost:
Electric............................................. $ 9,334,912 $ 9,119,285
Other................................................ 157,632 146,228
------------ ------------
9,492,544 9,265,513
Less: Accumulated provision for depreciation...... 3,293,660 3,021,987
------------ ------------
6,198,884 6,243,526
Construction work in progress........................ 179,724 208,084
Nuclear fuel, net.................................... 224,839 218,051
------------ ------------
Total net utility plant.......................... 6,603,447 6,669,661
------------ ------------
Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994
and at cost in 1993 (Note 9)<F9>.................... 240,229 206,179
Investments in regional nuclear generating
companies, at equity................................ 82,464 81,029
Investments in transmission companies, at equity..... 26,106 26,536
Other, at cost....................................... 40,896 36,882
------------ ------------
389,695 350,626
------------ ------------
Current Assets:
Cash................................................. 34,579 32,008
Receivables, less accumulated provision for
uncollectible accounts of $16,826,000 in 1994
and $14,629,000 in 1993............................. 357,322 357,449
Accrued utility revenues............................. 142,788 150,794
Fuel, materials, and supplies, at average cost....... 190,062 194,968
Prepayments and other................................ 54,886 35,278
------------ ------------
779,637 770,497
------------ ------------
Deferred Charges:
Regulatory Assets (Note 1H)<F1H>..................... 2,724,364 2,801,283
Unamortized debt expense............................. 33,517 37,444
Other................................................ 54,220 38,653
------------ ------------
2,812,101 2,877,380
------------ ------------
Total Assets........................................... $10,584,880 $10,668,164
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Balance Sheets<TABLE>
<CAPTION>
At December 31, 1994 1993
---------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization: (See Consolidated Statements Of Capitalization)
Common shareholders' equity: (see Note(a)--
Consolidated Statements Of Common Shareholders'
Equity):
Common shares, $5 par value--authorized
225,000,000 shares; 134,210,226 shares issued and
124,962,981 shares outstanding in 1994 and
134,207,025 shares issued and 124,326,836 shares
outstanding in 1993................................ $ 671,051 $ 671,035
Capital surplus, paid in............................ 904,371 901,740
Deferred benefit plan--employee stock
ownership plan (Note 6)<F6>........................ (213,324) (228,205)
Retained earnings................................... 946,988 879,518
------------ ------------
Total common shareholders' equity................. 2,309,086 2,224,088
Preferred stock not subject to mandatory redemption.. 234,700 239,700
Preferred stock subject to mandatory redemption...... 375,250 380,500
Long-term debt....................................... 3,942,005 4,045,468
------------ ------------
Total capitalization.............................. 6,861,041 6,889,756
------------ ------------
Obligations Under Capital Leases....................... 166,018 171,004
------------ ------------
Current Liabilities:
Notes payable to banks............................... 180,000 173,500
Commercial paper..................................... 10,000 -
Long-term debt and preferred stock--current portion.. 174,948 420,142
Obligations under capital leases--current portion.... 73,103 72,756
Accounts payable..................................... 280,942 229,118
Accrued taxes........................................ 57,532 40,501
Accrued interest..................................... 70,639 69,682
Accrued pension benefits............................. 90,194 82,513
Other................................................ 98,296 83,853
------------ ------------
1,035,654 1,172,065
------------ ------------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)<F1I>..... 1,968,230 1,911,981
Accumulated deferred investment tax credits.......... 188,005 201,635
Deferred contract obligation--YAEC (Note 3)<F3>...... 157,147 132,826
Other................................................ 208,785 188,897
------------ ------------
2,522,167 2,435,339
------------ ------------
Commitments and Contingencies (Note 7)<F7>
Total Capitalization and Liabilities $10,584,880 $10,668,164
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION<TABLE>
<CAPTION>
At December 31, 1994 1993
---- ----
(Thousands of Dollars)
<S> <C> <C>
COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets)............. $2,309,086 $2,224,088
---------- ----------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
$25 par value--authorized 36,600,000 shares at December 31, 1994 and 1993;
12,927,000 shares outstanding in 1994 and 13,220,000 shares in 1993
$50 par value--authorized 9,000,000 shares at December 31, 1994 and 1993;
5,424,000 shares outstanding in 1994 and 1993;
$100 par value--authorized 1,000,000 shares at December 31, 1994 and 1993;
200,000 shares outstanding in 1994 and 1993
Current Redemption Current Shares
Dividend Rates Prices <F1>(a) Outstanding
-------------- ------------------ --------------
NOT SUBJECT TO MANDATORY REDEMPTION:
$25 par value--Adjustable Rate $ 25.00 3,940,000..... 98,500 103,500
$50 par value--$1.90 to $3.28 $ 50.50 to $ 54.00 2,324,000..... 116,200 116,200
$100 par value--$7.72 $103.51 200,000..... 20,000 20,000
---------- ----------
Total Preferred Stock Not Subject to Mandatory Redemption............... 234,700 239,700
---------- ----------
SUBJECT TO MANDATORY REDEMPTION: <F2>(b)
$25 par value--$1.90 to $2.65 $ 25.00 to $ 26.50 8,987,000..... 224,675 227,000
$50 par value--$2.65 to $3.615 $ 51.00 to $ 52.41 3,100,000..... 155,000 155,000
---------- ----------
Total Preferred Stock Subject to Mandatory Redemption................... 379,675 382,000
Less: Preferred Stock to be redeemed within one year.................... 4,425 1,500
---------- ----------
Preferred Stock Subject to Mandatory Redemption, Net.................... 375,250 380,500
---------- ----------
LONG-TERM DEBT: <F3>(c)
First Mortgage Bonds--
Maturity Interest Rate
-------- -------------
1994 4.25% to 4.50%......................................... - 182,000
1995 9.25%.................................................... 34,300 34,650
1996 8.875%................................................... 172,500 172,500
1997 5.625% to 7.625%........................................ 214,850 265,000
1998 6.50% to 9.17%......................................... 199,900 290,000
1999 5.50% to 7.25%......................................... 280,000 100,000
2000-2002 5.75% to 9.05%......................................... 700,000 875,000
2003-2004 6.125% to 7.75%......................................... 190,000 90,000
2016-2020 7.375% to 10.13%......................................... 20,000 303,569
2023-2025 7.375% to 8.50%.......................................... 480,000 225,000
---------- ----------
Total First Mortgage Bonds .......................................... 2,291,550 2,537,719
---------- ----------
Other Long-Term Debt--<F4>(d)
Pollution Control Notes and Other Notes--
1996 Adjustable Rate - Term Loan.............................. 141,000 235,000
2000 15.23% .................................................. 205,000 205,000
2005-2006 8.38% to 8.58%........................................... 236,000 245,000
2013-2016 Adjustable Rate.......................................... 23,400 23,400
2018-2020 7.17% and Adjustable Rate................................ 50,191 50,300
2021-2022 7.50% to 7.65% and Adjustable Rate....................... 552,485 552,485
2028 Adjustable Rate.......................................... 369,300 369,300
---------- ----------
Total Pollution Control Notes and Other Notes........................ 1,577,376 1,680,485
Fees and interest due for spent fuel disposal costs <F1N>(Note 1N)..... 174,934 168,055
Other.................................................................. 78,090 86,731
---------- ----------
Total Other Long-Term Debt........................................... 1,830,400 1,935,271
---------- ----------
Unamortized premium and discount, net ................................. (9,422) (8,880)
---------- ----------
Total Long-Term Debt.................................................. 4,112,528 4,464,110
Less amounts due within one year...................................... 170,523 418,642
---------- ----------
Long-Term Debt, Net .................................................. 3,942,005 4,045,468
---------- ----------
TOTAL CAPITALIZATION..................................................... $6,861,041 $6,889,756
========== ==========
The accompanying notes are an integral part of these financial statements.
<FN>NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
<FA>(a) Each of these series is subject to certain refunding limitations for
the first five years after they were issued. Redemption prices reduce
in future years.
<FB>(b) Changes in Preferred Stock Subject to Mandatory Redemption:
(Thousands of Dollars)
Balance at January 1, 1992....... $ 170,394
Issues........................ 75,000
PSNH stock transferred........ 125,000
Reacquisitions and Retirements (16,894)
-------
Balance at December 31, 1992..... 353,500
Issues........................ 80,000
Reacquisitions and Retirements (51,500)
-------
Balance at December 31, 1993..... 382,000
Reacquisitions and Retirements (2,325)
-------
Balance at December 31, 1994..... $379,675
========
The minimum sinking-fund provisions of the series subject to
mandatory redemption aggregate approximately $5,300,000 in 1995 and
1996, $30,300,000 in 1997, $34,000,000 in 1998, and $50,000,000 in 1999.
In case of default on sinking-fund payments, no payments may be made on
any junior stock by way of dividends or otherwise (other than in shares
of junior stock) so long as the default continues. If a subsidiary is in
arrears in the payment of dividends on any outstanding shares of
preferred stock, the subsidiary would be prohibited from redemption or
purchase of less than all of the preferred stock outstanding.
<FC>(c) Long-term debt maturities and cash sinking-fund requirements,
excluding fees and interest due for spent fuel disposal costs, on debt
outstanding at December 31, 1994 for the years 1995 through 1999 are
approximately $170,500,000, $265,200,000, $264,200,000, $239,600,000,
and $371,900,000, respectively. In addition, there are annual 1 percent
sinking- and improvement-fund requirements of approximately $16,000,000
for 1995, $15,600,000 for 1996 and 1997, $13,450,000 for 1998, and
$13,150,000 for 1999. Such sinking- and improvement-fund requirements
may be satisfied by the deposit of cash or bonds or by certification of
property additions. Essentially all utility plant of The Connecticut
Light and Power Company (CL&P), Public Service Company of New Hampshire
(PSNH), Western Massachusetts Electric Company (WMECO), and North
Atlantic Energy Corporation (NAEC), wholly owned subsidiaries of NU, is
subject to the liens of their respective first mortgage bond indentures.
In addition, CL&P and WMECO have secured $369,300,000 of pollution
control notes with second mortgage liens on Millstone 1, junior to the
liens of their respective first mortgage bond indentures. PSNH's two
bank facilities, the Term Loan and the Revolving Credit Facility, have a
second lien, junior to the lien of its first mortgage bond indenture, on
all PSNH property located in New Hampshire. At December 31, 1994, the
principal amount outstanding under the Term Loan was $141,000,000. At
December 31, 1994, there were no borrowings under the Revolving
Credit Facility.
Concurrent with the issuance of PSNH's Series A and B First
Mortgage Bonds, PSNH entered into financing arrangements with the
Business Finance Authority (BFA) of the state of New Hampshire. Pursuant
to these arrangements, the BFA issued five series of Pollution Control
Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1994,
$516,485,000 of the PCRBs were outstanding. PSNH's obligation to repay each
series of PCRBs is secured by a series of First Mortgage Bonds that was
issued under its indenture. Each such series of First Mortgage Bonds contains
terms and provisions with respect to maturity, principal payment, interest
rate, and redemption that correspond to those of the applicable series of
PCRBs. For financial reporting purposes, these bonds would not be considered
outstanding unless PSNH fails to meet its obligations under the PCRBs.
<FD>(d) The average effective interest rates on the variable-rate
pollution control notes ranged from 2.5 percent to 4.3 percent for 1994
and from 2.2 percent to 3.4 percent for 1993. The average effective
interest rates for the PSNH Term Loan for 1994 and 1993 were
approximately 5.2 percent and 4.3 percent, respectively.
<FE>(e) On January 23, 1995, CL&P Capital, L.P., a subsidiary of CL&P,
issued $100 million of 9.3 percent cumulative Monthly Income Preferred
Securities to help finance the retirement of $125 million of CL&P preferred
stock.
</TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
Consolidated Statements Of Common Shareholders' Equity
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
Deferred
Benefit
Capital Plan--
Common Surplus, ESOP Retained
Shares(a) Paid In (Note 6)<F6> Earnings(b) Total
--------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1992....... $596,271 $640,119 $ (175,000) $ 814,684 $1,876,074
Net income for 1992............ 256,054 256,054
Tax benefit of ESOP dividends.. 7,348 7,348
Cash dividends on common
shares--$1.76 per share...... (229,074) (229,074)
Loss on the retirement of
preferred stock.............. (1,268) (1,268)
Issuance of 11,417,305 common
shares, $5 par value......... 57,087 204,440 261,527
Issuance of 3,191,489 common
shares, $5 par value,
to ESOP Trust................ 15,957 59,043 (75,000) -
Allocation of benefits--ESOP... 9,601 9,601
Capital stock expenses, net.... (6,285) (6,285)
--------- --------- ------------- ------------ -----------
Balance at December 31, 1992..... 669,315 897,317 (240,399) 847,744 2,173,977
Net income for 1993............ 249,953 249,953
Cash dividends on common
shares--$1.76 per share...... (218,179) (218,179)
Issuance of 344,106 common
shares, $5 par value......... 1,720 6,538 8,258
Allocation of benefits--ESOP... 1,800 12,194 13,994
Capital stock expenses, net.... (3,915) (3,915)
--------- --------- ------------- ------------ -----------
Balance at December 31, 1993..... 671,035 901,740 (228,205) 879,518 2,224,088
Net income for 1994............ 286,874 286,874
Cash dividends on common
shares--$1.76 per share...... (219,317) (219,317)
Loss on retirement of
preferred stock.............. (87) (87)
Issuance of 3,201 common
shares, $5 par value......... 16 61 77
Allocation of benefits--ESOP... (406) 14,881 14,475
Capital stock expenses, net.... 2,976 2,976
--------- --------- ------------- ------------ -----------
Balance at December 31, 1994..... $671,051 $904,371 $ (213,324) $ 946,988 $2,309,086
========= ========= ============= ============ ===========
<FN>
<F1>(a) As part of its acquistion of PSNH, NU issued 8,430,910 warrants to former PSNH Equity
security holders. Each warrant, which will expire on June 5, 1997, entitles the
holder to purchase one share of NU common at an exercise price of $24 per share. As
of Decemer 31, 1994, 458,595 shares had been purchased through the exercise of
warrants.
<F2>(b) Certain consolidated subsidiaries have dividend restrictions imposed by their
long-term debt agreements. These restrictions also limit the amount of retained
earnings available for NU common dividends. At December 31, 1994, these restrictions
totaled approximately $559.6 million.
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A>A. Principles of Consolidation
Northeast Utilities (NU) is the parent company of the Northeast Utilities
system (the system). The consolidated financial statements of the company
include the accounts of all wholly owned subsidiaries. Significant
intercompany transactions have been eliminated in consolidation.
On June 5, 1992 (Acquisition Date), NU acquired PSNH. As part of this
transaction, PSNH transferred its 35.6 percent ownership interest in the
Seabrook nuclear power plant to NAEC. Effective with the Acquisition Date,
the consolidated financial statements of the company include, on a
prospective basis, the financial position, the results of operations, and the
cash flows for PSNH and NAEC. For the 12 months ended December 31, 1994, 1993,
and 1992, PSNH and NAEC increased NU's consolidated operating revenues by
$869.8 million, $805.5 million, and $438.4 million, respectively. For the same
periods, PSNH and NAEC increased NU's consolidated earnings for common shares
by $94.7 million, $65.0 million, and $34.6 million, respectively.
<F1B>B. Change in Accounting for Property Taxes
Certain subsidiaries of NU, including CL&P and WMECO, adopted a one-time
change in the method of accounting for municipal property tax expense for
their Connecticut properties. Most municipalities in Connecticut assess
property values as of October 1. Before January 1, 1993, the system accrued
Connecticut property tax expense over the period October 1 through September
30 based on the lien-date method. In the first quarter of 1993, these
subsidiaries changed their method of accounting for Connecticut municipal
property taxes to recognize the expense from July 1 through June 30, to match
the payments and the services provided by the municipalities. This one-time
change increased earnings for common shares and earnings per common share by
approximately $51.7 million and $0.42, respectively, in 1993.
<F1C>C. Reclassifications
Certain reclassifications of prior years' data have been made to conform with
the current year's presentation.
<F1D>D. Investments and Jointly Owned Electric Utility Plant
Regional Nuclear Generating Companies: CL&P, PSNH, and WMECO own common
stock of four regional nuclear generating companies (Yankee companies). The
system holds a 49.0 percent ownership interest in Connecticut Yankee Atomic
Power Company (CY), a 38.5 percent ownership interest in Yankee Atomic
Electric Company (YAEC), a 20.0 percent ownership interest in Maine Yankee
Atomic Power Company (MY), and a 16.0 percent ownership interest in Vermont
Yankee Nuclear Power Corporation (VY). The system's investments in the Yankee
companies are accounted for on the equity basis due to NU's ability to
exercise significant influence over their operating and financial policies.
The electricity produced by the facilities that are operating is committed to
the participants substantially on the basis of their ownership interests and
is billed pursuant to contractual agreements. Under ownership agreements with
the Yankee companies, CL&P, PSNH, and 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 7F, "Commitments and Contingencies-
Purchased Power Arrangements."
The YAEC nuclear power plant was shut down permanently on February 26, 1992.
For more information on the Yankee companies, see Note 3, "Nuclear
Decommissioning."
Millstone 3: CL&P, PSNH, and WMECO have a 68.02 percent joint-ownership
interest in Millstone 3, a 1,154-megawatt (MW) nuclear generating unit. As of
December 31, 1994 and 1993, plant-in-service included approximately $2.4
billion, and the accumulated provision for depreciation included approximately
$525.9 million and $460.6 million, respectively, for the system's share of
Millstone 3. The system's share of Millstone 3 expenses is included in the
corresponding operating expenses on the accompanying Consolidated Statements
Of Income.
Seabrook: CL&P and NAEC have a 40.04 percent joint-ownership interest in
Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells all of its share
of the power generated by Seabrook 1 to PSNH under two long-term contracts.
As of December 31, 1994 and 1993, plant-in-service included approximately
$881.0 million and $877.3 million, respectively, and the accumulated provision
for depreciation included approximately $83.2 million and $66.4 million,
respectively, for the system's share of Seabrook 1. The system's share of
Seabrook 1 expenses is included in the corresponding operating expenses on
the accompanying Consolidated Statements Of Income.
Hydro-Quebec: NU has a 22.66 percent equity-ownership interest,
approximating $26.1 million, in two companies that transmit electricity
imported from the Hydro-Quebec system in Canada. The two companies own and
operate transmission and terminal facilities, which have the capability of
importing up to 2,000 MW from the Hydro-Quebec system. See Note 7G,
"Commitments and Contingencies-Hydro-Quebec," for additional information.
<F1E>E. 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 factors 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. For
nuclear production plants, the costs of removal, less salvage, that have been
funded through external decommissioning trusts will be paid with funds from
the trusts and charged to the accumulated reserve for decommissioning
included in the accumulated provision for depreciation over the expected
service life of the plants. See Note 3, "Nuclear Decommissioning," for
additional information.
The depreciation rates for the several classes of electric plant-in-service
are equivalent to a composite rate of 3.7 percent in 1994, 3.6 percent in
1993, and 3.5 percent in 1992.
<F1F>F. 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 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 operating subsidiaries are subject to
further regulation for rates, accounting, and other matters by the FERC and/or
applicable state regulatory commissions.
<F1G>G. Revenues
Other than 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. Rates can be
changed only through a formal proceeding before the appropriate regulatory
commission. At the end of each accounting period, CL&P, PSNH, and WMECO accrue
an estimate for the amount of energy delivered but unbilled.
<F1H>H. Regulatory Accounting
The operating companies of the system follow accounting policies that reflect
the impact of the rate treatment of certain events or transactions that
differ from generally accepted accounting principles for those events or
transactions followed by nonregulated enterprises. Under regulatory
accounting, assuming that future revenues are expected to be sufficient to
provide recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an asset, or
create a liability. If the economic entity no longer comes under the
jurisdiction of a regulator or external forces, such as a move to a
competitive environment, effectively limiting the influence of
cost-of-service based rate regulation, the entity may be forced to abandon
regulatory accounting, requiring a reexamination and potential write-off of
net regulatory assets. The system operating companies continue to be subject
to cost-of-service based rate regulation. Based on current regulation and
recent regulatory decisions regarding competition in the system's markets,
the company believes that its use of regulatory accounting is still appropriate.
The components of regulatory assets are as follows:
--------------------------------------------------------------------
At December 31, 1994 1993
--------------------------------------------------------------------
(Thousands of Dollars)
Income taxes, net (Note 1I). . . $1,124,119 $1,183,716
Regulatory asset-PSNH
(Note 1J). . . . . . . . . . . 678,974 769,498
Recoverable energy costs, net
(Note 1K). . . . . . . . . . . 268,982 202,264
Deferred costs-nuclear plants
(Note 1L). . . . . . . . . . . 233,145 271,337
Unrecovered contract obligation-
YAEC (Note 3). . . . . . . . . 157,147 132,826
Deferred demand-side-
management costs (Note 1M) . . 116,133 111,442
Other. . . . . . . . . . . . . . 145,864 130,200
---------- ----------
$2,724,364 $2,801,283
========== ==========
<F1I>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 income subject to tax) is accounted
for in accordance with the ratemaking treatment of the applicable regulatory
commissions. See Consolidated Statements Of Income Taxes on page 27 for the
components of income tax expense.
In 1992, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109).
SFAS 109 supersedes previously issued income tax accounting standards. NU
adopted SFAS 109, on a prospective basis, during the first quarter of 1993 and
increased the net deferred tax obligation by $1.2 billion at that time. As it
is probable that the increase in deferred tax liabilities will be recovered from
customers through rates, NU also established a regulatory asset.
The tax effect of temporary differences which give rise to the accumulated
deferred tax obligation is as follows:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and
other plant-related differences . $1,495,323 $1,472,509
Net operating loss carryforwards. . (247,440) (270,612)
Regulatory assets-income tax
gross up. . . . . . . . . . . . . 393,117 424,997
Other . . . . . . . . . . . . . . . 327,230 285,087
----------- ----------
$1,968,230 $1,911,981
=========== ==========
At December 31, 1994, PSNH had a regular tax net operating loss (NOL)
carryforward of approximately $726 million, and an Alternative Minimum Tax
(AMT) NOL carryforward of $529 million, both to be used against PSNH's
federal taxable income and expiring between the years 2000 and 2006. PSNH
also had Investment Tax Credit (ITC) carryforwards of $54 million, which
expire between the years 1995 and 2004. For a portion of the carryforward
amounts indicated above, the reorganization of PSNH under Chapter 11 of the
United States Bankruptcy Code limits the annual amount of NOL and ITC
carryforwards that may be used. Approximately $249 million of the NOL, $189
million of the AMT NOL, and $23 million of the ITC carryforwards are subject
to this limitation.
<F1J>J. Regulatory Asset-PSNH
The regulatory asset-PSNH represents the aggregate value placed by the rate
agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets
in excess of the net book value of PSNH's non-Seabrook assets and the
$700-million value assigned to Seabrook by the Rate Agreement. The regulatory
asset-PSNH was valued at approximately $920.6 million on the Acquisition
Date. The Rate Agreement provides for the recovery, through rates, of the
amortization of the regulatory asset-PSNH with a return each year on the
unamortized portion of the asset. The Rate Agreement provides that $425
million of the regulatory asset-PSNH be amortized over the first seven years
after PSNH's May 16, 1991 reorganization from bankruptcy (Reorganization Date),
with the remaining amount to be amortized over the 20-year period after the
Reorganization Date.
<F1K>K. Recoverable Energy Costs
Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC
are assessed for their proportionate shares of the costs of decontaminating
and decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that regulators
treat D&D assessments as a reasonable and necessary current cost of fuel, to be
fully recovered in rates, like any other fuel cost. CL&P, PSNH, WMECO, and NAEC
have begun to recover these costs.
CL&P: Retail electric rates include a fuel adjustment clause (FAC) under
which fossil-fuel prices above or below base-rate levels are charged or
credited to customers. Monthly FAC rates are also subject to retroactive
review and appropriate adjustment. CL&P also utilizes a generation utilization
adjustment clause (GUAC), which defers the effect on fuel costs caused by
variations from a specified composite nuclear generation capacity factor
embedded in base rates.
In the past two GUAC proceedings before the Connecticut Department of Public
Utility Control (DPUC), the DPUC determined that CL&P overrecovered its fuel
costs and offset the amount of the overrecovery against the GUAC balance. This
has resulted in disallowances of GUAC recovery of $7.9 million for the 1992-1993
GUAC period and $7.8 million for the 1993-1994 GUAC period. CL&P has appealed
the first decision and will appeal the second decision.
At December 31, 1994, CL&P's recoverable energy costs were $61.0 million,
including the D&D assessments of $37.4 million.
PSNH: The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail customers,
for a ten-year period, the retail portion of differences between the fuel and
purchase power costs assumed in the Rate Agreement and PSNH's actual costs,
which include the costs under the Seabrook Power Contract. The cost components
of the FPPAC are subject to a prudence review by the New Hampshire Public
Utilities Commission (NHPUC).
The costs associated with purchases from certain nonutility generators (NUGs)
over the level assumed in the Rate Agreement are deferred and recovered
through the FPPAC. PSNH has been attempting to negotiate the rate orders
mandating the purchase of high-cost NUG power. In September 1994, the NHPUC
approved an amendment to the Rate Agreement allowing settlement agreements to
be implemented with two NUGs. The two NUGs have given up their right to sell
their output to PSNH in exchange for lump-sum cash payments of approximately
$40 million. The deferred buyout payments are included as part of PSNH's
recoverable energy costs. During the Rate Agreement's fixed-rate period, all
the savings from the buyout will be used to reduce PSNH's recoverable energy
costs. At the end of the fixed-rate period, 50 percent of the savings will be
used to reduce the recoverable energy costs, with the remainder reducing
current rates. At December 31, 1994, PSNH's recoverable energy costs included
fuel and purchase power deferrals ($154.9 million), the deferred buyout
($39.8 million), and the D&D assessments ($0.3 million).
For additional information, see Note 7B, "Commitments and Contingencies -
Nuclear Performance."
<F1L>L. Deferred Costs-Nuclear Plants
The system's operating companies are phasing into rates the recoverable
portions of their investments in Millstone 3 and Seabrook 1 and are deferring
costs as part of these phase-in plans. All plans are in compliance with SFAS
No. 92, Regulated Enterprises-Accounting for Phase-in Plans.
CL&P: As allowed by the DPUC, effective January 1, 1995, CL&P has placed
into rate base its allowed investments in Millstone 3 and Seabrook 1 and is
recovering deferrals and carrying charges on these units. As of December 31,
1994, $448.5 million of the deferred return, including carrying charges, has
been recovered, and $101.6 million of the deferred return to date, plus
carrying charges, remains to be recovered. Recovery will be completed by
December 31, 1995 and August 31, 1996 for Millstone 3 and Seabrook 1,
respectively.
NAEC: As prescribed by the Rate Agreement, NAEC is phasing in its investment
in Seabrook 1. As of December 31, 1994, the portion of the investment on
which NAEC is entitled to earn a cash return was 70 percent and will increase
by 15 percent in each of the next two years beginning May 1, 1995. From the
Acquisition Date through December 31, 1994, NAEC recorded $131.5 million of
deferred return on the excluded portion of its investment in Seabrook 1,
which has been recorded in "Regulatory assets" on the Consolidated Balance
Sheets. The deferred return on the excluded portion of NAEC's investment in
Seabrook 1 will be recovered with carrying charges beginning six months after
the end of PSNH's fixed-rate period (which continues through May 1997) and
will be fully recovered by May 2001.
<F1M>M. Demand-side Management (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). These costs are being recovered over periods
ranging from four to eight years. On October 31, 1994, CL&P filed its 1995
CAM for 1995 DSM costs and programs. The filing proposes expenditures
of $36.7 million with recovery over four years and a zero CAM rate.
<F1N>N. Spent Nuclear Fuel Disposal Costs
Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC 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 may be made anytime prior to
the first delivery of spent fuel to the DOE, which may be as early as 1998.
Until such payment is made, the outstanding balance will continue to accrue
interest at the three-month Treasury Bill Yield Rate. At December 31, 1994,
fees due to the DOE for the disposal of prior-period fuel were approximately
$174.9 million, including interest costs of $92.8 million. As of December 31,
1994, all fees had been collected through rates.
<F1O>O. Derivative Financial Instruments
The company utilizes interest-rate caps and fuel swaps to manage well-defined
interest-rate and fuel-price risks. Premiums paid for purchased
interest-rate-cap agreements are amortized to interest expense over the terms
of the caps. Unamortized premiums are included in deferred charges. Amounts
receivable under cap agreements are accrued as a reduction of interest expense.
Amounts receivable or payable under fuel-swap agreements are recognized in
income when realized. Any material unrealized gains or losses on fuel swaps or
interest-rate caps will be deferred until realized. For further information on
derivatives, see Note 8, "Derivative Financial Instruments."
<F2>2. LEASES
CL&P and WMECO have entered into the Niantic Bay Fuel Trust (NBFT) capital
lease agreement to finance up to $530 million of nuclear fuel for Millstone 1
and 2 and their shares of the nuclear fuel for Millstone 3. CL&P and WMECO
make quarterly lease payments for the cost of nuclear fuel consumed in the
reactors (based on a units-of-production method at rates which reflect
estimated kilowatt-hours of energy provided) plus financing costs associated
with the fuel in the reactors. Upon permanent discharge from the reactors,
ownership of the nuclear fuel transfers to CL&P and WMECO. The system
companies have also entered into lease agreements, some of which are capital
leases, for the use of data processing and office equipment, vehicles,
nuclear control room simulators, and office space. The provisions of these
lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $81,952,000
in 1994, $100,911,000 in 1993, and $81,376,000 in 1992. Interest included in
capital lease rental payments was $14,881,000 in 1994, $16,525,000 in 1993,
and $20,581,000 in 1992. Operating lease rental payments charged to operating
expense were $20,118,000 in 1994, $22,630,000 in 1993, and $27,451,000 in 1992.
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. 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, 1994, are provided on the
next page.
Capital Operating
Year Leases Leases
-------- ---------
(Thousands of Dollars)
1995. . . . . . . . . . . . . $ 9,600 $ 23,300
1996. . . . . . . . . . . . . 8,700 20,600
1997. . . . . . . . . . . . . 8,000 18,000
1998. . . . . . . . . . . . . 7,900 10,400
1999. . . . . . . . . . . . . 7,500 7,900
After 1999. . . . . . . . . . 49,400 36,500
-------- --------
Future minimum lease
payments . . . . . . . . . 91,100 $116,700
========
Less amount representing
interest . . . . . . . . . 44,800
--------
Present value of future
minimum lease payments
for other than nuclear fuel 46,300
Present value of future nuclear
fuel lease payments. . . . 192,800
--------
Total. . . . . . . $239,100
========
<F3>3. NUCLEAR DECOMMISSIONING
The company's 1992 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. A 1994 Seabrook
decommissioning study, which is currently under review by the New Hampshire
Decommissioning Finance Committee, also confirmed that complete and immediate
dismantlement at retirement is the most viable and economic method of
decommissioning Seabrook 1. Decommissioning studies are reviewed and updated
periodically to reflect changes in decommissioning requirements, technology,
and inflation.
The estimated cost of decommissioning Millstone 1 and 2, in year-end 1994
dollars, is $410.9 million and $330.0 million, respectively. The system's
ownership share of the estimated cost of decommissioning Millstone 3 and
Seabrook 1 (utilizing the currently approved decommissioning study), in
year-end 1994 dollars, is $305.2 million and $152.8 million, respectively.
These estimated costs have been levelized and assume after-tax earnings
on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1
percent, respectively. Future escalation rates in decommissioning costs for
the Millstone units and for Seabrook 1 are assumed. Nuclear decommissioning
costs are accrued over the expected service life of the units and are included
in depreciation expense on the Consolidated Statements Of Income. Nuclear
decommissioning costs amounted to $33.5 million in 1994, $29.4 million in 1993,
and $28.1 million in 1992. Nuclear decommissioning, as a cost of removal, is
included in the accumulated provision for depreciation on the Consolidated
Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for
decommissioning amounted to $278.0 million. See "Nuclear Decommissioning" in the
Management's Discussion And Analysis for a discussion of changes being
considered by the FASB related to accounting for decommissioning costs.
CL&P and WMECO have established independent decommissioning trusts for their
portions of the costs of decommissioning Millstone 1, 2, and 3. PSNH makes
payments to an independent decommissioning trust for its portion of the costs
of decommissioning Millstone 3. CL&P's and NAEC's portions of the cost of
decommissioning Seabrook 1 are paid to an independent decommissioning
financing fund managed by the state of New Hampshire.
As of December 31, 1994, CL&P, PSNH, and WMECO have collected, through rates,
$173.4 million, $1.5 million, and $42.4 million, respectively, toward the
future decommissioning costs of their share of the Millstone units, of which
$179.7 million has been transferred to external decommissioning trusts. As of
December 31, 1994, CL&P and NAEC (including pre-Acquisition Date payments made
by PSNH) have paid approximately $1.2 million and $10.1 million, respectively,
into Seabrook 1's decommissioning financing fund. Earnings on the
decommissioning trusts and financing fund increase the decommissioning trust
balance and the accumulated reserve for decommissioning. Due to NU's adoption,
effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in
Debt and Equity Securities, unrealized gains and losses associated with the
decommissioning trusts also impact the balance of the trusts and the
accumulated reserve for decommissioning.
Changes in requirements or technology, the timing of funding or dismantling,
or adoption of a decommissioning method other than immediate dismantlement,
would change decommissioning cost estimates. CL&P, PSNH, and WMECO attempt to
recover sufficient amounts through their allowed rates to cover their 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 system companies. Because allowances for
decommissioning have increased significantly in recent years, customers in
future years may need to increase their payments to offset the effects of any
insufficient rate recoveries in previous years.
CL&P, PSNH, and WMECO, along with other New England utilities, have equity
investments in the four Yankee companies. Each Yankee company owns a single
nuclear generating unit. The system's ownership share of estimated costs, in
year-end 1994 dollars, of decommissioning CY, MY, and VY are $177.4 million,
$67.6 million, and $52.7 million, respectively. Under the terms of the contracts
with the Yankee companies, the shareholders-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 by CL&P, PSNH, and WMECO.
YAEC has begun component removal activities related to the decommissioning of
its nuclear facility. In June 1992, YAEC filed a rate filing to obtain FERC
authorization to collect the closing and decommissioning costs and to recover
the remaining investment in the YAEC nuclear power plant over the remaining
period of the plant's Nuclear Regulatory Commission (NRC) operating license.
The bulk of these costs has been agreed to by the YAEC joint owners and
approved as a settlement by FERC. In October 1994, YAEC submitted a revised
decommissioning cost estimate as part of its decommissioning plan with the
NRC. Following the receipt of NRC approval, this estimate will be filed with
the FERC. The revised estimate increased the system's ownership share of
decommissioning YAEC's nuclear facility by approximately $36 million in
January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs,
including decommissioning, amounted to $408.2 million, of which the system's
share was approximately $157.1 million. Management expects that CL&P, PSNH,
and WMECO will continue to be allowed to recover such FERC-approved costs from
their customers. Accordingly, NU has recognized these costs as regulatory
assets, with corresponding obligations, on its Consolidated Balance Sheets.
<F4>4. SHORT-TERM DEBT
The system companies have various revolving credit lines, totaling $485
million. NU, CL&P, WMECO, Holyoke Water Power Company (HWP), Northeast
Nuclear Energy Company (NNECO), and The Rocky River Realty Company (RRR) have
established a revolving-credit facility with a group of 16 banks. Under this
facility, the participating companies may borrow up to an aggregate of $360
million. Individual borrowing limits as of January 1, 1995 were $150 million
for NU, $325 million for CL&P, $60 million for WMECO, $5 million for HWP, $50
million for NNECO, and $22 million for RRR. The system companies may borrow
funds on a short-term revolving basis, using either fixed-rate loans or
standby loans. Fixed rates are set using competitive bidding. Standby-loan
rates are based upon several alternative variable rates. The system companies
are obligated to pay a facility fee of 0.20 percent per annum of each bank's
total commitment under the three-year portion of the facility, representing
75 percent of the total facility, plus 0.135 percent per annum of each bank's
total commitment under the 364-day portion of the facility, representing 25
percent of the total facility. At December 31, 1994 and 1993, there were
$30.0 million and $22.5 million in borrowings, respectively, under the
facility.
PSNH has credit lines totaling $125 million available through a
revolving-credit agreement with a group of 19 banks. PSNH may borrow funds on
a short-term revolving basis using either fixed-rate or standby loans. Fixed
rates are set using competitive bidding. Standby-loan rates are based upon
several alternative variable rates. PSNH is obligated to pay a facility fee
of 0.25 percent per annum on the total commitment. At December 31, 1994 and
1993, there were no borrowings under the agreement.
The weighted average interest rates on notes payable to banks and commercial
paper outstanding on December 31, 1994 were 6.2 percent and 6.4 percent,
respectively. The weighted average interest rate on notes payable to banks
outstanding on December 31, 1993 was 3.3 percent. Maturities of the
short-term debt obligations were for periods of three months or less.
The amount of short-term borrowings that may be incurred by the system
companies is subject to periodic approval by the SEC under the 1935 Act. In
addition, the charters of CL&P and WMECO contain provisions restricting the
amount of short-term borrowings. Under the SEC and/or charter restrictions,
NU, CL&P, PSNH, WMECO, and NAEC were authorized, as of January 1, 1995, to
incur short-term borrowings up to a maximum of $150 million, $325 million,
$175 million, $60 million, and $50 million, respectively.
5. EMPLOYEE BENEFITS
<F5A>A. Pension Benefits
The system's subsidiaries participate in a uniform noncontributory-defined
benefit retirement plan covering all regular system employees. Benefits are
based on years of service and employees' highest eligible compensation during
five consecutive years of employment. Total pension cost, part of which was
charged to utility plant, approximated $7.7 million in 1994, $29.2 million in
1993, and $9.7 million in 1992. Pension costs for 1994 and 1993 included
approximately $9.2 million and $27.7 million, respectively, related to work
force-reduction programs.
Currently, the subsidiaries fund 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 are:
----------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . $ 39,317 $ 59,068 $ 32,662
Interest cost. . . . . . . . 84,284 81,456 78,092
Return on plan assets. . . . 2,268 (176,798) (83,371)
Net amortization . . . . . . (118,188) 65,447 (17,702)
--------- --------- ---------
Net pension cost.. . . . . . $ 7,681 $ 29,173 $ 9,681
========= ========= =========
For calculating pension cost, the following assumptions were used:
----------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------------
Discount rate . . . . . . . . . . 7.75% 8.00% 8.41%
Expected long-term rate
of return. . . . . . . . . . . 8.50 8.50 9.00
Compensation/progression
rate . . . . . . . . . . . . . 4.75 5.00 6.56
The following table represents the plan's funded status reconciled to the
Consolidated Balance Sheets:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including vested benefits at
December 31,1994 and 1993
of $815,646,000 and
$817,421,000, respectively .. $ 893,653 $ 898,788
========== ==========
Projected benefit obligation. . . . $1,112,993 $1,141,271
Market value of plan assets . . . . 1,266,239 1,340,249
---------- ----------
Market value in excess of projected
benefit obligation. . . . . . . 153,246 198,978
Unrecognized transition amount. . . (15,191) (16,735)
Unrecognized prior service costs. . 10,373 10,287
Unrecognized net gain . . . . . . . (238,622) (275,043)
---------- ----------
Accrued pension liability. . . . $ (90,194) $ (82,513)
========== ==========
The following actuarial assumptions were used in calculating
the plan's year-end funded status:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
Discount rate . . . . . . . . . . . 8.25% 7.75%
Compensation/progression rate . . . 5.00 4.75
<F5B>B. Postretirement Benefits Other Than Pensions
The system's subsidiaries provide certain health care benefits, primarily
medical and dental, and life insurance benefits through a benefit plan to
retired employees. These benefits are available for employees leaving the
system who are otherwise eligible to retire and have met specified service
requirements. Effective January 1, 1993, the system adopted SFAS 106,
Employer's Accounting for Postretirement Benefits Other Than Pensions on a
prospective basis. Total health care and life insurance costs, part of which
were deferred or charged to utility plant, approximated $47.6 million in 1994,
$50.1 million in 1993, and $15.6 million in 1992.
On January 1, 1993, the accumulated postretirement benefit obligation
represented the system's transition obligation upon the adoption of SFAS 106.
As allowed by SFAS 106, the system is amortizing its transition obligation of
approximately $306 million over a 20-year period. 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.
Certain subsidiaries of NU are funding SFAS 106 postretirement costs through
external trusts. The subsidiaries are funding annually amounts that have been
rate recovered and which also are tax-deductible under the Internal Revenue
Code. The trust assets are invested primarily in equity securities and bonds.
The following table represents the plan's funded status
reconciled to the Consolidated Balance Sheets:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees. . . . . . . . . . . . . $ 251,448 $ 242,889
Fully eligible active employees 416 540
Active employees not eligible
to retire. . . . . . . . . . . . 69,556 67,955
---------- ----------
Total accumulated postretirement
benefit obligation . . . . . . . . . 321,420 311,384
Market value of plan assets. . . . . . 26,406 12,642
---------- ----------
Accumulated postretirement benefit
obligation in excess of
plan assets. . . . . . . . . . . . . (295,014) (298,742)
Unrecognized transition
amount. . . . . . . . . . . . . . . 272,417 287,551
Unrecognized net gain . . . . . . . . (4,772) (5,150)
---------- ----------
Accrued postretirement
benefit liability . . . . . . . . . $(27,369) $ (16,341)
========== ==========
The components of health care and life insurance costs are:
----------------------------------------------------------------------
For the Years Ended December 31, 1994 1993
----------------------------------------------------------------------
(Thousands of Dollars)
Service cost . . . . . . . . . . . . $ 7,418 $ 9,175
Interest cost. . . . . . . . . . . . 25,319 25,330
Return on plan assets. . . . . . . . 236 (220)
Net amortization . . . . . . . . . . 14,581 15,855
------- -------
Net health care and life
insurance costs. . . . . . . . . . $47,554 $50,140
======= =======
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
----------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------
Discount rate . . . . . . . . . . . . . . 8.00% 7.75%
Long-term rate of return-health assets,
net of tax. . . . . . . . . . . . . . . 5.00 5.00
Long-term rate of return-life assets. . . 8.50 8.50
Health care cost trend rate (a). . . . . 10.20 11.10
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 5.4 percent by 2002.
The effect of increasing the assumed health care cost trend rates by one
percentage point in each year would increase the accumulated postretirement
benefit obligation as of December 31, 1994 by $17.2 million and the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for the year then ended by $1.7 million. The trust holding the plan assets
is subject to federal income taxes at a 35-percent tax rate.
PSNH and WMECO are currently recovering SFAS 106 costs, including previously
deferred costs. CL&P has received regulatory approval to defer SFAS 106 costs
in excess of costs incurred on a pay-as-you-go basis. Deferral of such costs
is permitted since it is expected that the period of recovery of deferred
costs will be within the time frame established by the applicable accounting
requirements.
<F5C>C. 401(k) Savings Plan
The company also maintains a 401(k) Savings Plan for substantially all
employees. This savings plan provides for employee contributions up to
specified limits. The company's savings plan provides up to 3 percent of
matching contributions. The matching contributions for the company for 1994,
1993, and 1992 were $12.1 million, $12.2 million, and $8.6 million,respectively.
For further information on the 401(k) Savings Plan, see Note 6, "Employee Stock
Ownership Plan."
<F6>6. EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)
NU maintains an ESOP for purposes of allocating shares to employees
participating in the system's 401(k) plan. Under this arrangement, NU issued in
1991 and 1992 a total of $250 million principal amount of unsecured and
amortizing notes, the proceeds of which were lent to the ESOP trust for purchase
of approximately 10.8 million newly issued NU common shares from the company.
NU makes principal and interest payments on the ESOP notes at the same rate that
ESOP shares are allocated to employees.
In 1994 and 1993, the ESOP trust issued approximately 664,000 and 530,000,
respectively, of NU common shares, with costs of approximately $15.5 million
and $14.0 million, respectively, to the 401(k) plan. As of December 31, 1994
and 1993, the total allocated ESOP shares were 1,547,219 and 899,284,
respectively, and total unallocated ESOP shares were 9,215,904 and 9,880,189,
respectively. The fair market value of unallocated ESOP shares as of December
31, 1994 and 1993 was approximately $199.3 million and $234.7 million,
respectively.
During 1994, the ESOP trust used approximately $23.3 million in dividends
paid on NU common shares and $13.1 million in contributions from NU to meet
principal and interest payments on ESOP notes. During the 12-month periods
ending December 31, 1994 and 1993, the ESOP trust incurred approximately
$20.0 million and $20.9 million, respectively, in interest expense.
NU adopted the American Institute of Certified Public Accountant's Statement
of Position 93-6, Employers' Accounting for Employee Stock Ownership Plans
(SOP 93-6) in 1993. This new standard requires: (1) offsetting of ESOP tax
benefits against income tax expense, (2) charging allocated ESOP dividends
directly to retained earnings, (3) exclusion of unallocated ESOP dividends for
financial reporting purposes, and (4) exclusion of unallocated ESOP shares from
earnings-per-common share (EPS) calculations. The adoption of SOP 93-6 did not
have a material impact on 1993 EPS; however, 1993 earnings for common shares
decreased by approximately $19.9 million. Had the provisions of SOP 93-6 been
applied to 1992 results of operations, the impact on EPS would not have been
material; however, earnings for common shares would have decreased by $16.0
million.
7. COMMITMENTS AND CONTINGENCIES
<F7A>A. Construction Program
The construction program is subject to periodic review and revision. Actual
construction expenditures may vary from estimates due to factors such as
revised load estimates, inflation, revised nuclear safety regulations,
delays, difficulties in the licensing process, the availability and cost of
capital, and the granting of timely and adequate rate relief by regulatory
commissions, as well as actions by other regulatory bodies.
The system companies currently forecast construction expenditures (including
the allowance for funds used during construction) of approximately $1.2 billion
for the years 1995-1999, including $253.7 million for 1995. In addition, the
system companies estimate that nuclear fuel requirements, including nuclear
fuel financed through the NBFT, will be $366.7 million for the years 1995-1999,
including $67.9 million for 1995. See Note 2, "Leases," for additional
information about the financing of nuclear fuel.
<F7B>B. Nuclear Performance
Outages that occurred over the period October 1990 through February 1992 at
the Millstone nuclear units have been the subject of five ongoing prudence
reviews in Connecticut. CL&P has received final decisions on each of the
reviews. The Office of Consumer Counsel (OCC) appealed decisions favorable to
the company in two dockets. For the one appeal decided, which related to a
procedural issue, the OCC prevailed and the case has been remanded to the
DPUC for further proceedings. The exposure under these two dockets is
approximately $66 million. The DPUC has suspended a third docket, pending the
outcome of one of the appeals. The exposure under this remaining docket is
$26 million. Management believes that its actions with respect to these
outages have been prudent, and it does not expect the outcome of the appeals
to result in material disallowances.
In October 1994, Millstone 2 began a planned refueling and maintenance outage
that was originally scheduled for 63 days. The outage has encountered several
unexpected difficulties which have lengthened the duration of the outage. The
magnitude of the schedule impact is currently under review, but the unit is
not expected to return to service before April 1995. CL&P and WMECO expect
that replacement power costs in the range of $7 million and $1 million per
month, respectively, will be attributable to the extension of the outage.
Recovery of the costs related to this outage is subject to scrutiny by the DPUC
and the Massachusetts Department of Public Utilities (DPU).
<F7C>C. PSNH Rate Agreement
The Rate Agreement provided the financial basis for PSNH's Plan of
Reorganization (the Plan). The Rate Agreement calls for seven successive 5.5
percent annual increases in PSNH's base rates for its charges to retail
customers (the Fixed-Rate Period). The first increase was put into effect on
January 1, 1990 and the remaining two increases are scheduled to be put into
effect annually beginning on June 1, 1995. As discussed in Note 1K, "Summary
of Significant Accounting Policies-Recoverable Energy Costs-PSNH," the FPPAC
protects PSNH from changes in fuel and purchased power costs. Although the
Rate Agreement provides an unusually high degree of certainty as to PSNH's
retail rates for the next two years, it also entails a risk when sales are
lower than anticipated or if PSNH should experience unexpected increases in
its costs other than those for fuel and purchased power, since PSNH has
agreed that it will not seek additional rate relief during the Fixed-Rate
Period, except in limited circumstances. However, in order to provide protection
from significant variations from the costs assumed in base rates over the
Fixed-Rate Period, the Rate Agreement establishes a return on equity (ROE)
collar to prevent PSNH from earning a ROE in excess of an upper limit or below a
lower limit. To date, PSNH's ROE has been within the limits of the ROE collar.
<F7D>D. Environmental Matters
The system is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the disposal of toxic
substances and hazardous and solid wastes, and the handling and use of chemical
products. The system has an active environmental auditing and training program
and believes that it is in substantial compliance with current environmental
laws and regulations.
Changing environmental requirements could hinder the construction of new
generating units, transmission and distribution lines, substations, and other
facilities. The cumulative long-term, economic cost impact of increasingly
stringent environmental requirements cannot accurately be estimated. Changing
environmental requirements could also require extensive and costly
modifications to the system's existing generating units, and transmission and
distribution systems, and could raise operating costs significantly. As a
result, the system 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. The system may
also encounter significantly increased costs to remedy the environmental effects
of prior waste handling activities.
The system has recorded a liability for what it believes, based upon
information currently available, are its estimated environmental remediation
costs for waste disposal sites for which the system's subsidiaries expect to
bear legal liability. In most cases, the extent of additional future
environmental cleanup costs is 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, 1994, the liability recorded by the system for its estimated environmental
remediation costs, excluding any possible insurance recoveries or recoveries
from third parties, amounted to approximately $11 million. However, in the event
that it becomes necessary to effect environmental remedies that are currently
not considered probable, it is reasonably possible that the upper limit of the
system's environmental liability range could increase to approximately $16
million.
The system cannot estimate the potential liability for future claims 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 the system's financial position or future results
of operations.
<F7E>E. Nuclear Insurance Contingencies
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first $200 million of
liability would be provided by purchasing the maximum amount of commercially
available insurance. Additional coverage of up to a total of $8.3 billion
would be provided by an assessment of $75.5 million per incident, levied on
each of the 110 nuclear units that are currently subject to the Secondary
Financial Protection Program in the United States, subject to a maximum
assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs arising
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5 percent, up to $3.8
million, or $415.3 million in total, for all 110 nuclear units. The maximum
assessment is to be adjusted at least every five years to reflect
inflationary changes. Based on the ownership interests in Millstone 1, 2, and
3 and in Seabrook 1, the system's maximum liability would be $244.2 million
per incident. In addition, through power purchase contracts with the three
operating Yankee regional nuclear generating companies, the system would be
responsible for up to an additional $67.4 million per incident. Payments for
the system's ownership interest in nuclear generating facilities would be
limited to a maximum of $39.3 million per incident per year.
Effective January 1, 1995, insurance was purchased from Nuclear Mutual
Limited (NML) to cover the primary cost of repair, replacement, or
decontamination of utility property resulting from insured occurrences with
respect to the system's ownership interest in Millstone 1, 2, and 3 and in
CY. All companies insured with NML are subject to retroactive assessments if
losses exceed the accumulated funds available to NML. The maximum potential
assessment against the system with respect to losses arising during the
current policy year is approximately $16.6 million under the NML primary
property insurance program.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL)
to cover: (1) certain extra costs incurred in obtaining replacement power
during prolonged accidental outages with respect to the system's ownership
interests in Millstone 1, 2, and 3, Seabrook 1, and CY, and PSNH's Seabrook
Power Contract with NAEC; and (2) the excess cost of repair, replacement, or
decontamination or premature decommissioning of utility property resulting
from insured occurrences with respect to the system's ownership interests in
Millstone 1, 2, and 3, Seabrook 1, CY, MY, and VY. All companies insured with
NEIL are subject to retroactive assessments if losses exceed the accumulated
funds available to NEIL. The maximum potential assessments against the system
with respect to losses arising during current policy years are approximately
$10.8 million under the replacement power policies and $51.7 million
under the excess property damage, decontamination, and decommissioning
policies. Although the system has purchased the limits of coverage currently
available from the conventional nuclear insurance pools, the cost of a
nuclear incident could exceed available insurance proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual Atomic
Energy Liability Underwriters, 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 $3.1 million
per reactor. The maximum potential assessments against the system with
respect to losses arising during the current policy period are approximately
$13.3 million.
<F7F>F. Purchased Power Arrangements
CL&P, PSNH, and WMECO purchase approximately 10 percent of their electricity
requirements pursuant to long-term contracts with the Yankee companies. Under
the terms of their agreements, the companies pay their ownership shares (or
entitlement shares) of generating costs, which include depreciation, operation
and maintenance 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 companies' rates. The total cost of
purchases under these contracts for the units that are operating amounted to
$154.3 million in 1994, $169.0 million in 1993, and $145.4 million in 1992.
See Note 1D, "Summary of Significant Accounting Policies-Investments and
Jointly Owned Electric Utility Plant," and Note 3, "Nuclear Decommissioning,"
for more information on the Yankee companies.
CL&P, PSNH, and WMECO have entered into various arrangements for the purchase
of capacity and energy from nonutility generators. Some of these arrangements
have terms from 10 to 30 years and require the companies to purchase
the energy at specified prices or formula rates. For the 12 months ended
December 31, 1994, approximately 14 percent of system electricity requirements
was met by nonutility generators. The total cost of purchases under these
arrangements amounted to $435.0 million in 1994, $426.8 million in 1993, and
$323.8 million in 1992. These costs are eventually recovered through the
companies' rates. For additional information, see Note 1K, "Summary of
Significant Accounting Policies-Recoverable Energy Costs-PSNH."
PSNH entered into a buy-back agreement to purchase the capacity and energy of
the New Hampshire Electric Cooperative, Inc.'s (NHEC) Seabrook share and to
pay all of NHEC's Seabrook costs for a ten-year period, which began July 1,
1990. The total cost of purchases under this agreement was $15.7 million in
1994, $14.4 million in 1993, and $13.8 million in 1992. Part of these costs
is collected currently though the FPPAC and part is deferred for future
collection in accordance with the Rate Agreement. In connection with the
agreement, NHEC agreed to continue as a firm-requirements customer of PSNH
for 15 years.
The estimated annual costs of the system's significant purchase power
arrangements are as follows:
----------------------------------------------------------------------
1995 1996 1997 1998 1999
----------------------------------------------------------------------
(Millions of Dollars)
Yankee
Companies . . . . . . $168.5 $177.1 $158.4 $188.0 $180.5
Nonutility
Generators . . . . . . $447.1 468.4 478.9 489.3 493.1
NHEC . . . . . . . . . $ 16.5 16.5 25.1 33.2 32.8
<F7G>G. Hydro-Quebec
Along with other New England utilities, CL&P, PSNH, WMECO, and HWP entered
into agreements to support transmission and terminal facilities to import
electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and
HWP, in the aggregate, are obligated to pay, over a 30-year period, their
proportionate shares of the annual operation, maintenance, and capital costs
of these facilities, which are currently forecast to be $171.9 million for
the years 1995-1999, including $38.4 million for 1995.
<F8>8. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes derivative financial instruments to manage well-defined
interest-rate and fuel-price risks. The company does not use them for trading
purposes.
Interest-Rate-Cap Contracts: CL&P, PSNH, and WMECO have entered into
interest-rate-cap contracts with financial institutions in order to reduce a
portion of the interest-rate risk associated with certain variable-rate
tax-exempt pollution control revenue bonds, as well as a portion of the PSNH
Variable-Rate Term Loan. During 1994, there were five outstanding contracts
held by CL&P, PSNH, and WMECO covering $617 million of variable-rate debt,
with terms ranging from one to three years. Two of the five contracts expired
in 1994. The contracts entitle CL&P, PSNH, and WMECO to receive from
counterparties the amounts, if any, by which the interest payments on a
portion of its variable-rate tax-exempt pollution control revenue bonds
exceed the J.J. Kenny High Grade Index, and the PSNH Variable-Rate Term Loan
exceed the three-month LIBOR rate. These contracts are settled on a quarterly
basis. As of December 31, 1994, CL&P, PSNH, and WMECO had a total of $467
million in caps with maturities of one year, with a positive mark-to-market
position of approximately $5.0 million.
Fuel Swaps: CL&P also uses fuel-swap agreements with financial institutions
to hedge against fuel-price risk created by long-term negotiated energy
contracts. These fuel swaps minimize exposure associated with rising fuel
prices and effectively fix CL&P's cost of fuel for these negotiated energy
contracts. Under the swap agreements, CL&P exchanges monthly payments based
on the differential between a fixed and variable price for the associated
fuel. As of December 31, 1994, CL&P had five outstanding agreements with a
total notional value of approximately $126 million, and a positive
mark-to-market position of approximately $3.1 million. These swap agreements
have been made with various financial institutions, each of which are rated
"A" or better by Standard & Poor's rating group.
The system companies are exposed to credit risk on both the interest-rate
caps and fuel swaps if the counterparties fail to perform their obligations.
However, the system companies anticipate that the counterparties will be able
to fully satisfy their obligations under the contracts.
<F9>9. 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 requires investments in debt and equity securities to be presented
at fair value and was adopted by the company on a prospective basis as of
January 1, 1994. As a result of the adoption of SFAS 115, the investments
held in the company's nuclear decommissioning trusts decreased by approximately
$5.5 million as of December 31, 1994, with a corresponding offset to the
accumulated provision for depreciation. The $5.5 million decrease represents
cumulative gross unrealized holding gains of $1.9 million, offset by cumulative
gross unrealized holding losses of $7.4 million. There was no change in funding
requirements of the trusts nor any impact on earnings as a result of the
adoption of SFAS 115.
Preferred stock and long-term debt: The fair value of the system's fixed-rate
securities is based upon the quoted market price for those issues or similar
issues. Adjustable rate securities are assumed to have a fair value equal to
their carrying value.
The carrying amounts of the system's financial instruments and the estimated
fair values are as follows:
----------------------------------------------------------------------
Carrying Fair
At December 31, 1994 Amount Value
----------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption. . . . . . $ 234,700 $ 179,875
Preferred stock subject to
mandatory redemption. . . . . . 379,675 370,250
Long-term debt -
First Mortgage Bonds. . . . . . 2,291,550 2,151,744
Other long-term debt. . . . . . 1,830,400 1,811,627
----------------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
----------------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption . . . . . $ 239,700 $ 202,826
Preferred stock subject to
mandatory redemption . . . . . 382,000 407,990
Long-term debt -
First Mortgage Bonds . . . . . 2,537,719 2,632,983
Other long-term debt . . . . . 1,935,271 2,055,433
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
<CAPTION>
QUARTER ENDED
1994 March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
(Thousands of Dollars, except per share data)
<S> <C> <C> <C> <C>
Operating Revenues .............. $966,174 $854,627 $923,708 $898,233
======== ======== ======== ========
Operating Income................. $159,559 $123,688 $135,882 $129,103
======== ======== ======== ========
Net Income ...................... $ 95,888 $ 61,145 $ 65,029 $ 64,812
======== ======== ======== ========
Earnings Per Common Share........ $ 0.77 $ 0.49 $ 0.52 $ 0.52
======== ======== ======== ========
1993
Operating Revenues .............. $958,192 $853,769 $915,239 $901,893
======== ======== ======== ========
Operating Income................. $129,745 $ 94,059 $l07,772 $139,275
======== ======== ======== ========
Net Income....................... $112,447 $ 14,759 $ 46,421 $ 76,326
======== ======== ======== ========
Earnings Per Common Share ....... $ 0.91 $ 0.12 $ 0.37 $ 0.62
======== ======== ======== ========
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED GENERAL OPERATING STATISTICS
<CAPTION>
1994 1993 1992<F1>(a) 1991 1990
---- ---- ----------- ---- ----
<S> <C> <C> <C> <C> <C>
System Capability-MW (b)<F2>... 8,494.8 7,795.3 7,823.2 5,916.2 5,909.6
System Peak Demand-MW.......... 6,338.5 6,191.0 5,781.0 4,999.8 4,753.9
Nuclear Capacity-MW(b)<F2>..... 3,272.6 3,110.0 2,981.1 2,380.0 2,459.5
Nuclear Capacity
Factor(c)<F3>................ 67.5 80.8 63.7 50.6 69.4
Nuclear Contribution to Total
Energy Requirements (%) (b)<F2> 54.0 62.1 48.5 43.5 57.5
<FN>
<F1>(a) Effective with the June 5, 1992 acquisition of PSNH, the consolidated financial and
statistical information of NU includes, on a prospective basis, the operations of PSNH and
NAEC.
<F2>(b) Includes the system's entitlements in regional nuclear generating companies, net of capacity
sales and purchases.
<F3>(c) Represents the average capacity factor for the nuclear units operated by the NU system.
</TABLE>
<TABLE>
NORTHEAST UTILITIES AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
1994 1993 1992<F1>(a) 1991
---- ---- ------------ ----
(Thousands of Dollars, except percentages and share data)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Net Utility Plant-
Continuing Operations ............... $ 6,603,447 $ 6,669,661 $ 6,719,652 $ 5,257,567
Discontinued Gas Plant............... -- -- -- --
Total Assets ......................... 10,584,880 10,668,164 9,724,340 6,781,746
Total Capitalization <F2>(b).......... 7,035,989 7,309,898 7,421,592 5,138,426
Obligations Under Capital Leases <F2>(b) 239,121 243,760 266,100 279,729
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 3,642,742 $ 3,629,093 $ 3,216,874 $ 2,753,803
Net Income.......................<F3> 286,874 249,953(c) 256,054 236,709
Earnings per Common Share........<F3> $2.30 $2.02(c) $2.02 $2.12
Discontinued Gas Operations:
Operating Revenues................... $ -- $ -- $ -- $ --
Net Income........................... -- -- -- --
Earnings per Common Share ........... $ -- $ -- $ -- $ --
COMMON SHARE DATA:
Earnings per Share...............<F3> $2.30 $2.02(c) $2.02 $2.12
Dividends per Share ................. $1.76 $1.76 $1.76 $1.76
Payout Ratio (%)..................... 76.5 87.1 87.1 83.0
Number of Shares
Outstanding--Average............<F4> 124,678,192 123,947,631(d)130,403,488 111,453,550
Market Price--High................... $25 3/4 $28 7/8 $26 3/4 $24 3/8
Market Price--Low.................... $20 3/8 $22 $22 1/2 $19
Market Price--Closing Price
(end of year) ..................... $21 5/8 $23 3/4 $26 l/2 $23 5/8
Book Value per Share(end of year).... $18.47 $17.89 $16.24 $15.73
Rate of Return Earned on Average
Common Equity (%) ................. 12.7 11.4 12.7 13.0
Dividend Yield (end of year) (%) .... 8.1 7.4 6.6 7.4
Market-to-Book Ratio (end of year)... 1.2 1.3 1.6 1.5
Price-Earnings Ratio (end of year)... 9.4 11.8 13.1 11.1
CAPITALIZATION: <F2> (b)
Common Shareholders' Equity......... $ 2,309,086 2,224,088 $ 2,173,977 $ 1,876,074
Preferred Stock Not Subject
to Mandatory Redemption........... 234,700 239,700 304,696 394,695
Preferred Stock Subject to
Mandatory Redemption ............. 379,675 382,000 353,500 170,394
Long-Term Debt...................... 4,112,528 4,464,110 4,589,419 2,697,263
----------- ---------- ----------- -----------
Total Capitalization ............... $ 7,035,989 $7,309,898 $ 7,421,592 $ 5,138,426
=========== ========== =========== ===========
<FN>
<F1>(a) Effective with the June 5, 1992 acquisition of PSNH, the consolidated financial and
statistical information of NU includes, on a prospective basis, the operations of PSNH and
NAEC.
<F2>(b) Includes portions due within one year.
<F3>(c) Includes the cumulative effect of change in accounting for municipal property tax expense,
which increased earnings for common shares and earnings per common share by $51.7 million and
$0.42, respectively.
<F4>(d) Decrease in the number of shares results from a change in accounting for Employee Stock
Ownership Plan shares.
</TABLE>
<TABLE>
<CAPTION> 1990 1989 1988 1987
---- ---- ---- ----
(Thousands of Dollars, except percentages and share data)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 5,265,168 $ 5,237,805 $ 5,267,629 $ 5,229,242
Discontinued Gas Plant .............. -- -- 254,587 237,903
Total Assets ........................ 6,601,371 6,523,202 6,764,608 6,663,794
Total Capitalization <F2>(b).......... 4,965,859 4,954,083 5,123,504 4,956,080
Obligations Under Capital Leases <F2>(b) 319,548 341,246 410,352 432,714
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 2,616,319 $ 2,473,571 $ 2,268,607 $ 2,038,554
Net Income........................... 211,007 203,225 224,844 214,529
Earnings per Common Share............ $1.94 $1.87 $2.07 $1.97
Discontinued Gas Operations:
Operating Revenues................... $ -- $ 124,229 $ 200,243 $ 202,816
Net Income........................... -- 5,858 9,078 14,616
Earnings per Common Share ........... $ -- $0.05 $0.08 $0.14
COMMON SHARE DATA:
Earnings per Share................... $1.94 $1.92 $2.15 $2.11
Dividends per Share ................. $1.76 $1.76 $1.76 $1.76
Payout Ratio (%)..................... 90.7 91.7 81.9 83.4
Number of Shares
Outstanding--Average................ 109,003,818 108,669,106 108,669,106 108,669,106
Market Price--High................... $22 5/8 $23 $23 1/8 $28
Market Price--Low.................... $17 7/8 $18 1/2 $18 1/4 $18
Market Price--Closing Price
(end of year) ..................... $20 $22 1/2 $19 7/8 $20 1/4
Book Value per Share(end of year).... $16.34 $16.13 $16.90 $16.53
Rate of Return Earned on Average
Common Equity (%) ................. 12.0 11.8 13.0 12.8
Dividend Yield (end of year) (%) .... 8.8 7.8 8.9 8.7
Market-to-Book Ratio (end of year)... 1.2 1.4 1.2 1.2
Price-Earnings Ratio (end of year)... 10.3 11.7 9.2 9.6
CAPITALIZATION: <F2>(b)
Common Shareholders' Equity......... $ 1,790,758 $ 1,752,395 $ 1,837,034 $ 1,796,293
Preferred Stock Not Subject
to Mandatory Redemption........... 394,695 394,695 344,695 291,195
Preferred Stock Subject to
Mandatory Redemption ............. 176,892 181,892 111,832 205,832
Long-Term Debt...................... 2,603,514 2,625,101 2,829,943 2,662,760
----------- ----------- ------------ ------------
Total Capitalization ............... $ 4,965,859 $ 4,954,083 $ 5,123,504 $ 4,956,080
=========== =========== ============ ============
</TABLE>
<TABLE>
<CAPTION>
1986 1985
---- ----
(Thousands of Dollars, except percentages and share data)
<S> <C> <C>
BALANCE SHEET DATA:
Net Utility Plant--
Continuing Operations................ $ 5,120,812 $ 5,204,687
Discontinued Gas Plant .............. 224,581 214,115
Total Assets ......................... 6,299,755 6,147,720
Total Capitalization ................. 4,743,914 4,681,995
Obligations Under Capital Leases<F2>(b) 441,183 440,587
INCOME DATA:
Continuing Operations:
Operating Revenues................... $ 2,006,842 $ 1,969,225
Net Income........................... 171,234 277,768
Earnings per Common Share............ $1.58 $2.62
Discontinued Gas Operations:
Operating Revenues................... $ 203,814 $ 220,010
Net Income........................... 10,705 10,773
Earnings per Common Share ........... $0.10 $0.10
COMMON SHARE DATA:
Earnings per Share................... $1.68 $2.72
Dividends per Share ................. $1.68 $1.58
Payout Ratio (%)..................... 100.0 58.1
Number of Shares
Outstanding--Average............... 108,352,517 106,221,131
Market Price--High.................. $28 1/4 $18 3/4
Market Price--Low.................... $17 3/8 $13 3/4
Market Price--Closing Price
(end of year) ..................... $24 1/4 $17 3/4
Book Value per Share(end of year).... $16.24 $16.21
Rate of Return Earned on Average
Common Equity (%) ................. 10.4 17.4
Dividend Yield (end of year) (%) .... 6.9 8.9
Market-to-Book Ratio (end of year)... 1.5 1.1
Price-Earnings Ratio (end of year)... 14.4 6.5
CAPITALIZATION: <F2>(b)
Common Shareholders' Equity......... $ 1,765,090 $ 1,738,871
Preferred Stock Not Subject
to Mandatory Redemption........... 291,195 291,195
Preferred Stock Subject to
Mandatory Redemption ............. 166,832 185,833
Long-Term Debt...................... 2,520,797 2,466,096
------------ -----------
Total Capitalization ............... $ 4,743,914 $ 4,681,995
============ ===========
</TABLE>
<TABLE>CONSOLIDATED ELECTRIC OPERATING STATISTICS
<CAPTION>
1994 1993 1992<F1>(a) 1991
---- ---- ----------- ----
<S> <C> <C> <C> <C>
SOURCE OF ELECTRIC ENERGY:
(kWh-millions) <F2>(b)
Nuclear--Steam........................ 19,444 22,965 15,520 11,062
Fossil--Steam......................... 8,292 7,676 6,784 6,179
Hydro--Conventional................... 1,239 1,140 1,076 994
Hydro--Pumped Storage................. 1,195 1,269 1,221 1,173
Internal Combustion................... 13 8 9 25
Energy Used for Pumping .............. (1,629) (1,749) (1,671) (1,605)
------ ------ ------ ------
Net Generation..................... 28,554 31,309 22,939 17,828
Purchased and Net Interchange......... 14,027 10,499 14,165 13,430
Company Use and Unaccounted for ...... (2,422) (2,591) (2,028) (1,958)
------ ------ ------ ------
Net Energy Sold.................... 40,159 39,217 35,076 29,300
====== ====== ====== ======
REVENUE: (thousands)
Residential........................... $1,437,764 $1,385,818 $1,213,140 $ 995,098
Commercial........................<F3> 1,174,658(c) 1,043,125 943,832 828,117
Industrial........................<F3> 560,086(c) 649,876 554,587 419,003
Other Utilities ...................... 330,511 383,129 346,791 366,231
Streetlighting and Railroads.......... 45,579 45,480 43,296 38,656
Miscellaneous......................... 36,134 60,008 59,465 49,539
---------- ---------- ---------- ----------
Total Electric ................... 3,584,732 3,567,436 3,161,111 2,696,644
Other............................. 58,010 61,657 55,763 57,159
---------- ---------- ---------- ----------
Total............................. $3,642,742 $3,629,093 $3,216,874 $2,753,803
========== ========== ========== ==========
SALES: (kWh-millions)
Residential.......................... 12,322 11,988 10,839 9,518
Commercial.......................<F3> 11,666(c) 10,304 9,608 8,900
Industrial.......................<F3> 6,738(c) 7,572 6,593 5,208
Other Utilities ..................... 9,121 9,046 7,733 5,388
Streetlighting and Railroads......... 312 307 303 286
------ ------ ------ ------
Total............................ 40,159 39,217 35,076 29,300
====== ====== ====== ======
CUSTOMERS: (average)
Residential......................... 1,513,987 1,503,182 1,351,019 1,150,357
Commercial......................<F3> 154,703(c) 155,487 132,680 102,867
Industrial......................<F3> 7,813(c) 6,272 5,774 5,067
Other............................... 3,818 3,793 3,581 3,305
--------- --------- --------- ---------
Total............................ 1,680,321 1,668,734 1,493,054 1,261,596
========= ========= ========= =========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 8,152 7,987 8,129 8,285
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $951.19 $923.32 $909.80 $866.20
AVERAGE REVENUE PER kWh:
Residential......................... 11.67 cents 11.56 cents 11.19 cents 10.45 cents
Commercial.......................... 10.07 10.12 9.82 9.30
Industrial.......................... 8.31 8.58 8.41 8.05
<FN><F1>(a) Effective with the June 5, 1992 acquisition of PSNH, the consolidated financial and
statistical information of NU includes, on a prospective basis, the operations of PSNH and
NAEC.
<F2>(b) Generated in system and regional nuclear generating plants.
<F3>(c) Effective January 1, 1994, approximately 1,300 former commercial customers were reclassified
as industrial customers.
</TABLE>
<TABLE>
<CAPTION>
1990
----
<S> <C>
SOURCE OF ELECTRIC ENERGY:
(kWh-millions)<F2> (b)
Nuclear--Steam........................ 17,724
Fossil--Steam......................... 6,829
Hydro--Conventional................... 1,174
Hydro--Pumped Storage................. 1,250
Internal Combustion................... 11
Energy Used for Pumping .............. (1,688)
------
Net Generation..................... 25,300
Purchased and Net Interchange......... 6,249
Company Use and Unaccounted for ...... (1,938)
------
Net Energy Sold.................... 29,611
======
REVENUE: (thousands)
Residential........................... $ 938,032
Commercial............................ 788,478
Industrial............................ 410,125
Other Utilities ...................... 346,087
Streetlighting and Railroads.......... 37,195
Miscellaneous......................... 42,882
----------
Total Electric ................... 2,562,799
Other................................. 53,520
----------
Total............................. $2,616,319
==========
SALES: (kWh-millions)
Residential.......................... 9,500
Commercial........................... 8,981
Industrial........................... 5,448
Other Utilities ..................... 5,394
Streetlighting and Railroads......... 288
------
Total............................ 29,611
======
CUSTOMERS: (average)
Residential......................... 1,145,142
Commercial.......................... 102,900
Industrial.......................... 5,114
Other............................... 3,283
---------
Total............................ 1,256,439
=========
AVERAGE ANNUAL USE PER RESIDENTIAL
CUSTOMER (kWh)...................... 8,304
AVERAGE ANNUAL BILL PER RESIDENTIAL
CUSTOMER............................ $819.94
AVERAGE REVENUE PER kWh:
Residential......................... 9.87 cents
Commercial.......................... 8.78
Industrial.......................... 7.53
</TABLE>
Exhibit 13.2
1994
ANNUAL REPORT
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
--------------------------------------------------------
1994 Annual Report
The Connecticut Light and Power Company and Subsidiaries
Index
Contents Page
-------- ----
Consolidated Balance Sheets.......................... 1-2
Consolidated Statements of Income.................... 3
Consolidated Statements of Cash Flows................ 4
Consolidated Statements of Common Stockholder's Equity 5
Notes to Consolidated Financial Statements........... 6-30
Report of Independent Public Accountants............. 31
Management's Discussion and Analysis of Financial
Condition and Results of Operations................ 32-39
Selected Financial Data.............................. 40
Statements of Quarterly Financial Data............... 40
Statistics........................................... 41
Preferred Stockholder and Bondholder Information..... Back Cover
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
At December 31, 1994 1993
------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
------
Utility Plant, at original cost:
Electric................................................ $6,063,179 $5,936,346
Less: Accumulated provision for depreciation......... 2,194,314 2,010,962
----------- -----------
3,868,865 3,925,384
Construction work in progress........................... 99,993 121,177
Nuclear fuel, net....................................... 164,795 156,878
----------- -----------
Total net utility plant............................. 4,133,653 4,203,439
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994 and
at cost in 1993 (Note 12)<F12>......................... 171,950 147,657
Investments in regional nuclear generating
companies, at equity................................... 54,952 53,910
Other, at cost.......................................... 14,742 14,191
----------- -----------
241,644 215,758
----------- -----------
Current Assets:
Cash.................................................... 2,017 2,340
Receivables, less accumulated provision for
uncollectible accounts of $12,778,000 in 1994
and $10,816,000 in 1993................................ 192,926 210,805
Accounts receivable from affiliated companies........... 9,367 29,687
Accrued utility revenues................................ 90,475 97,662
Fuel, materials, and supplies, at average cost.......... 64,003 60,247
Prepayments and other................................... 54,215 43,682
----------- -----------
413,003 444,423
----------- -----------
Deferred Charges:
Regulatory assets (Note 1H)<F1H>........................ 1,410,334 1,517,943
Unamortized debt expense................................ 8,396 8,971
Other................................................... 10,427 6,871
----------- -----------
1,429,157 1,533,785
----------- -----------
Total Assets........................................ $6,217,457 $6,397,405
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------
At December 31, 1994 1993
----------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock--$10 par value. Authorized
24,500,000 shares; outstanding 12,222,930
shares in 1994 and 1993.............................. $ 122,229 $ 122,229
Capital surplus, paid in.............................. 632,117 630,271
Retained earnings..................................... 765,724 750,719
----------- -----------
Total common stockholder's equity............ 1,520,070 1,503,219
Cumulative preferred stock--
$50 par value - authorized 9,000,000 shares;
outstanding 5,424,000 shares in 1994 and in 1993
$25 par value - authorized 8,000,000 shares;
outstanding 5,000,000 shares in 1994 and in 1993
Not subject to mandatory redemption (Note 5)<F5>.... 166,200 166,200
Subject to mandatory redemption (Note 6)<F6>........ 226,250 230,000
Long-term debt (Note 7)<F7>........................... 1,815,579 1,743,260
----------- -----------
Total capitalization......................... 3,728,099 3,642,679
----------- -----------
Obligations Under Capital Leases........................ 120,268 121,892
----------- -----------
Current Liabilities:
Notes payable to banks................................ 76,000 95,000
Notes payable to affiliated company................... 92,750 1,250
Commercial paper...................................... 10,000 -
Long-term debt and preferred stock--current
portion.............................................. 11,861 314,020
Obligations under capital leases--current
portion.............................................. 55,701 55,526
Accounts payable...................................... 102,837 117,858
Accounts payable to affiliated companies.............. 43,033 52,179
Accrued taxes......................................... 26,413 36,139
Accrued interest...................................... 30,682 29,669
Other................................................. 22,828 32,287
----------- -----------
472,105 733,928
----------- -----------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)<F1I>...... 1,544,021 1,575,965
Accumulated deferred investment tax credits........... 150,087 154,701
Deferred contract obligation--YAEC (Note 3)<F3>....... 100,003 84,526
Other................................................. 102,874 83,714
----------- -----------
1,896,985 1,898,906
----------- -----------
Commitments and Contingencies (Note 10)<F10>
Total Capitalization and Liabilities......... $6,217,457 $6,397,405
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues................................ $2,328,052 $2,366,050 $2,316,451
----------- ----------- -----------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power.... 568,394 657,121 598,287
Other........................................ 593,851 641,402 605,675
Maintenance..................................... 207,003 180,403 197,460
Depreciation.................................... 231,155 219,776 209,884
Amortization of regulatory assets, net.......... 77,384 112,353 73,456
Federal and state income taxes (Note 8)<F8>..... 195,038 144,547 172,236
Taxes other than income taxes................... 173,068 170,353 171,642
----------- ----------- -----------
Total operating expenses.................. 2,045,893 2,125,955 2,028,640
----------- ----------- -----------
Operating Income.................................. 282,159 240,095 287,811
----------- ----------- -----------
Other Income:
Deferred nuclear plants return--other
funds (Note 1K)<F1K>.......................... 13,373 23,537 35,396
Equity in earnings of regional nuclear
generating companies.......................... 7,453 6,193 8,014
Other, net...................................... 5,136 (1,044) 6,964
Income taxes--credit............................ 9,037 4,859 11,171
----------- ----------- -----------
Other income, net......................... 34,999 33,545 61,545
----------- ----------- -----------
Income before interest charges............ 317,158 273,640 349,356
----------- ----------- -----------
Interest Charges:
Interest on long-term debt...................... 119,927 134,263 151,314
Other interest.................................. 6,378 9,654 4,205
Deferred nuclear plants return--borrowed
funds (Note 1K)<F1K>.......................... (7,435) (13,979) (12,877)
----------- ----------- -----------
Interest charges, net..................... 118,870 129,938 142,642
----------- ----------- -----------
Income before cumulative effect of
accounting change............................... 198,288 143,702 206,714
Cumulative effect of accounting change
(Note 1B)<F1B>.................................. - 47,747 -
----------- ----------- -----------
Net Income........................................ $ 198,288 $ 191,449 $ 206,714
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net Income................................................ $ 198,288 $ 191,449 $ 206,714
Adjustments to reconcile to net cash
from operating activities:
Depreciation............................................ 231,155 219,776 209,884
Deferred income taxes and investment tax credits, net... 37,664 (20,188) 72,138
Deferred nuclear plants return, net of amortization..... 82,651 58,740 10,071
Recoverable energy costs, net of amortization........... 3,975 125,579 (64,138)
Deferred demand-side management, net of amortization.... (4,691) (23,955) (31,989)
Other sources of cash................................... 35,464 80,831 26,430
Other uses of cash...................................... (41,518) (23,544) (34,589)
Changes in working capital:
Receivables and accrued utility revenues................ 45,386 (9,370) 245
Fuel, materials, and supplies........................... (3,756) 11,951 1,296
Accounts payable........................................ (24,167) 5,433 (18,067)
Accrued taxes........................................... (9,726) (82,018) 15,344
Other working capital (excludes cash)................... (18,403) 9,754 7,154
----------- ----------- -----------
Net cash flows from operating activities.................... 532,322 544,438 400,493
----------- ----------- -----------
Cash Flows From Financing Activities:
Issuance of long-term debt................................ 535,000 740,500 491,000
Issuance of preferred stock............................... - 80,000 75,000
Net increase (decrease) in short-term debt................ 82,500 (109,490) 15,240
Reacquisitions and retirements of long-term debt.......... (774,020) (771,973) (431,232)
Reacquisitions and retirements of preferred stock......... - (114,996) (91,891)
Cash dividends on preferred stock......................... (23,895) (29,182) (31,977)
Cash dividends on common stock............................ (159,388) (160,365) (164,277)
----------- ----------- -----------
Net cash flows used for financing activities................ (339,803) (365,506) (138,137)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................. (149,889) (149,308) (225,901)
Nuclear fuel............................................ (20,905) (13,658) 3,139
----------- ----------- -----------
Net cash flows used for investments in plant.............. (170,794) (162,966) (222,762)
Other investment activities, net.......................... (22,048) (25,787) (32,181)
----------- ----------- -----------
Net cash flows used for investments......................... (192,842) (188,753) (254,943)
----------- ----------- -----------
Net (Decrease) Increase In Cash For The Period.............. (323) (9,821) 7,413
Cash - beginning of period.................................. 2,340 12,161 4,748
----------- ----------- -----------
Cash - end of period........................................ $ 2,017 $ 2,340 $ 12,161
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized during construction.. $ 115,120 $ 130,592 $ 143,957
=========== =========== ===========
Income taxes.............................................. $ 161,513 $ 149,056 $ 95,199
=========== =========== ===========
Increase in obligations:
Niantic Bay Fuel Trust.................................... $ 52,353 $ 40,140 $ 30,948
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
Capital Retained
Common Surplus, Earnings
Stock Paid In (a) Total
------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1992.......... $122,229 $637,202 $ 738,993 $1,498,424
Net income for 1992............. 206,714 206,714
Cash dividends on preferred
stock......................... (31,977) (31,977)
Cash dividends on common stock.. (164,277) (164,277)
Loss on the retirement of
preferred stock............... (636) (636)
Capital stock expenses, net..... (2,351) (2,351)
--------- --------- ---------- -----------
Balance at December 31, 1992........ 122,229 634,851 748,817 1,505,897
Net income for 1993............. 191,449 191,449
Cash dividends on preferred
stock......................... (29,182) (29,182)
Cash dividends on common stock.. (160,365) (160,365)
Capital stock expenses, net..... (4,580) (4,580)
--------- --------- ---------- -----------
Balance at December 31, 1993........ 122,229 630,271 750,719 1,503,219
Net income for 1994............. 198,288 198,288
Cash dividends on preferred
stock......................... (23,895) (23,895)
Cash dividends on common stock.. (159,388) (159,388)
Capital stock expenses, net..... 1,846 1,846
--------- --------- ---------- -----------
Balance at December 31, 1994........ $122,229 $632,117 $ 765,724 $1,520,070
========= ========= ========== ===========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements.
At December 31, 1994, these restrictions totaled approximately $540 million.
The accompanying notes are an integral part of these financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A>A. PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of The Connecticut Light and
Power Company and subsidiaries (the company or CL&P) include the
accounts of all wholly owned subsidiaries. Significant intercompany
transactions have been eliminated in consolidation.
CL&P, Western Massachusetts Electric Company (WMECO), Holyoke Water
Power Company (HWP), Public Service Company of New Hampshire (PSNH),
and North Atlantic Energy Corporation (NAEC) are the operating
subsidiaries comprising the Northeast Utilities system (the system)
and are wholly owned by Northeast Utilities (NU).
Other wholly owned subsidiaries of NU provide substantial support
services to the system. Northeast Utilities Service Company (NUSCO)
supplies centralized accounting, administrative, data processing,
engineering, financial, legal, operational, planning, purchasing, and
other services to the system companies. Northeast Nuclear Energy
Company (NNECO) acts as agent for system companies in operating the
Millstone nuclear generating facilities. Commencing June 29, 1992,
North Atlantic Energy Service Corporation (NAESCO) began acting as
agent for CL&P and NAEC in operating the Seabrook 1 nuclear facility.
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.
<F1B>B. CHANGE IN ACCOUNTING FOR PROPERTY TAXES
CL&P adopted a one-time change in the method of accounting for
municipal property tax expense for its Connecticut properties. Most
municipalities in Connecticut assess property values as of October 1.
Before January 1, 1993, CL&P accrued Connecticut property tax expense
over the period October 1 through September 30 based on the lien-date
method. In the first quarter of 1993, CL&P changed its method of
accounting for Connecticut municipal property taxes to recognize the
expense from July 1 through June 30, to match the payments and the
services provided by the municipalities. This one-time change
increased earnings for common shares by approximately $47.7 million in
1993.
<F1C>C. RECLASSIFICATIONS
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
<F1D>D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: CL&P owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with the company's ownership interests, are:
Connecticut Yankee Atomic Power Company (CY) ....34.5%
Yankee Atomic Electric Company (YAEC) ...........24.5
Maine Yankee Atomic Power Company (MY) ..........12.0
Vermont Yankee Nuclear Power Corporation (VY) ... 9.5
CL&P's investments in the Yankee companies are accounted for on the
equity basis due to the company's ability to exercise significant
influence over their operating and financial policies. The electricity
produced by the facilities that are operating is committed to the
participants substantially on the basis of their ownership interests
and is billed pursuant to contractual agreements. Under ownership
agreements with the Yankee companies, CL&P may be asked to provide
direct or indirect financial support for one or more of the companies.
For more information on these agreements, see Note 10E, "Commitments
and Contingencies - Purchased Power Arrangements."
The YAEC nuclear power plant was shut down permanently on February 26,
1992. For more information on the Yankee companies, see Note 3,
"Nuclear Decommissioning."
Millstone 1: CL&P has an 81 percent joint-ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of
December 31, 1994 and 1993, plant-in-service included approximately
$370.9 million and $332 million, respectively, and the accumulated
provision for depreciation included approximately $135.0 million and
$130.8 million, respectively, for CL&P's share of Millstone 1. CL&P's
share of Millstone 1 expenses is included in the corresponding
operating expenses on the accompanying Consolidated Statements of
Income.
Millstone 2: CL&P has an 81 percent joint-ownership interest in
Millstone 2, an 870-MW nuclear generating unit. As of December 31,
1994 and 1993, plant-in-service included approximately $680.5 million
and $676 million, respectively, and the accumulated provision for
depreciation included approximately $175.2 million and $151.5 million,
respectively, for CL&P's share of Millstone 2. CL&P's share of
Millstone 2 expenses is included in the corresponding operating
expenses on the accompanying Consolidated Statements of Income.
Millstone 3: CL&P has a 52.93 percent joint-ownership interest in
Millstone 3, a 1,154-MW nuclear generating unit. As of December 31,
1994 and 1993, plant-in-service included approximately $1.9 billion and
the accumulated provision for depreciation included approximately
$418.5 million and $366.6 million, respectively, for CL&P's share of
Millstone 3. CL&P's share of Millstone 3 expenses is included in the
corresponding operating expenses on the accompanying Consolidated
Statements of Income.
Seabrook: CL&P has a 4.06 percent joint-ownership interest in
Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31,
1994 and 1993, plant-in-service included approximately $173.2 million
and $173.4 million, respectively, and the accumulated provision for
depreciation included approximately $20.1 million and $17.7 million,
respectively, for CL&P's share of Seabrook 1. CL&P's share of
Seabrook 1 expenses is included in the corresponding operating expenses
on the accompanying Consolidated Statements of Income.
<F1E>E. 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 factors 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. For
nuclear production plants, the costs of removal, less salvage, that
have been funded through external decommissioning trusts will be paid
with funds from the trusts and charged to the accumulated reserve for
decommissioning included in the accumulated provision for depreciation
over the expected service life of the plants. See Note 3, "Nuclear
Decommissioning," for additional information.
The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.9 percent in
1994, 3.8 percent in 1993, and 3.7 percent in 1992.
<F1F>F. PUBLIC UTILITY REGULATION
NU is registered with the Securities and Exchange Commission (SEC) as a
holding company under the Public Utility Holding Company Act of 1935
(1935 Act), and it and its subsidiaries, including the company, are
subject to the provisions of the 1935 Act. Arrangements among the
system companies, outside agencies, and other utilities covering
interconnections, interchange of electric power, and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. The company is subject to further
regulation for rates, accounting, and other matters by the FERC and/or
the Connecticut Department of Public Utility Control (DPUC).
<F1G>G. REVENUES
Other than 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. Rates
can be changed only through a formal proceeding before the appropriate
regulatory commission. At the end of each accounting period, CL&P
accrues an estimate for the amount of energy delivered but unbilled.
<F1H>H. REGULATORY ACCOUNTING
CL&P follows accounting policies that reflect the impact of the rate
treatment of certain events or transactions that differ from generally
accepted accounting principles for those events or transactions
followed by nonregulated enterprises. Under regulatory accounting,
assuming that future revenues are expected to be sufficient to provide
recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an
asset, or create a liability. If the economic entity no longer comes
under the jurisdiction of a regulator or external forces, such as a
move to a competitive environment, effectively limiting the influence
of cost-of-service based rate regulation, the entity may be forced to
abandon regulatory accounting, requiring a reexamination and potential
write-off of net regulatory assets. CL&P continues to be subject to
cost-of-service based rate regulation. Based on current regulation,
and recent regulatory decisions regarding competition in the company's
market, CL&P believes that its use of regulatory accounting is still
appropriate.
The components of regulatory assets are as follows:
At December 31, 1994 1993
----------------------------------------------------------------------------
(Thousands of Dollars)
Income taxes, net (Note 1I) $ 949,134 $1,026,046
Deferred demand-side-management costs (Note 1J) 116,133 111,442
Deferred costs-nuclear plants (Note 1K) 101,632 185,909
Unrecovered contract obligation-YAEC (Note 3) 100,003 84,526
Recoverable energy costs, net (Note 1L) 61,040 65,591
Cogeneration costs (Note 1N) 36,821 -
Other 45,571 44,429
-------- --------
$1,410,334 $1,517,943
========== ==========
<F1I>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 income
subject to tax) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 8,
"Income Tax Expense," for the components of income tax expenses.
In 1992, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income
tax accounting standards. The company adopted SFAS 109, on a
prospective basis, during the first quarter of 1993, and increased the
net deferred tax obligation by $1.0 billion at that time. As it is
probable that the increase in deferred tax liabilities will be
recovered from customers through rates, CL&P also established a
regulatory asset.
The tax effect of temporary differences which give rise to the
accumulated deferred tax obligation are as follows:
At December 31, 1994 1993
----------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences ........ $1,063,823 $1,049,849
Regulatory assets - income tax gross up 402,685 434,894
Other ................................ 77,513 91,222
---------- ----------
$1,544,021 $1,575,965
========== ==========
<F1J>J. DEMAND-SIDE-MANAGEMENT COSTS (DSM)
CL&P's DSM costs are recovered in base rates through a Conservation
Adjustment Mechanism (CAM). These costs are being recovered over
periods ranging from four to eight years. On October 31, 1994, CL&P
filed its 1995 CAM for 1995 DSM costs and programs. The filing
proposes expenditures of $36.7 million with recovery over four years
and a zero CAM rate.
<F1K>K. DEFERRED COSTS - NUCLEAR PLANTS
CL&P is phasing into rates the recoverable portions of its investments
in Millstone 3 and Seabrook 1. CL&P is deferring costs as part of its
phase-in plans. Both plans are in compliance with SFAS No. 92,
Regulated Enterprises - Accounting for Phase-in Plans.
As allowed by the DPUC, effective January 1, 1995, CL&P placed into
rate base its allowed investments in Millstone 3 and Seabrook 1 and is
recovering deferrals and carrying charges on these units. As of
December 31, 1994, $448.5 million of the deferred return, including
carrying charges, has been recovered, and $101.6 million of the
deferred return to date, plus carrying charges, remains to be
recovered. Recovery will be completed by December 31, 1995 and
August 31, 1996 for Millstone 3 and Seabrook 1, respectively.
<F1L>L. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for
its proportionate share of the costs of decontaminating and
decommissioning uranium enrichment plants owned by the United States
Department of Energy (D&D assessment). The Energy Act requires that
regulators treat D&D assessments as a reasonable and necessary current
cost of fuel, to be fully recovered in rates, like any other fuel cost.
CL&P has begun to recover these costs.
Retail electric rates include a fuel adjustment clause (FAC) under
which fossil-fuel prices above or below base-rate levels are charged or
credited to customers. Monthly FAC rates are also subject to
retroactive review and appropriate adjustment. CL&P also utilizes a
generation utilization adjustment clause (GUAC), which defers the
effect on fuel costs caused by variations from a specified composite
nuclear generation capacity factor embedded in base rates.
In the past two GUAC proceedings before the DPUC, the DPUC determined
that CL&P overrecovered its fuel costs and offset the amount of the
overrecovery against the GUAC balance. This has resulted in
disallowances of GUAC recovery of $7.9 million for the 1992-1993 GUAC
period and $7.8 million for the 1993-1994 GUAC period. CL&P has
appealed the first decision and will appeal the second decision.
At December 31, 1994, CL&P's recoverable energy costs were $61.0
million, including D&D assessments of $37.4 million.
For additional information see Note 10B, "Commitments and
Contingencies-Nuclear Performance."
<F1M>M. SPENT NUCLEAR FUEL DISPOSAL COSTS
Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United
States Department of Energy (DOE) for the disposal of spent nuclear
fuel and high-level radioactive waste. Fees for nuclear fuel burned on
or after April 7, 1983 are billed currently to customers and paid to
the DOE on a quarterly basis. For nuclear fuel used to generate
electricity prior to April 7, 1983 (prior-period fuel), payment may be
made anytime prior to the first delivery of spent fuel to the DOE,
which may be as early as 1998. Until such payment is made, the
outstanding balance will continue to accrue interest at the three-month
Treasury Bill Yield Rate. At December 31, 1994, fees due to the DOE
for the disposal of prior-period fuel were approximately $141.7
million, including interest costs of $75.2 million. As of December 31,
1994, all fees had been collected through rates.
<F1N>N. COGENERATION COSTS
CL&P, with the approval of the DPUC, began deferring certain
cogeneration costs for future recovery beginning in 1994. At December
31, 1994, CL&P had deferred approximately $36.8 million in cogeneration
costs. CL&P will begin recovery of these deferrals over five years
beginning July 1, 1996.
<F1O>O. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes interest-rate caps and fuel swaps to manage well-
defined interest rate and fuel-price risks. Premiums paid for
purchased interest-rate cap agreements are amortized to interest
expense over the terms of the caps. Unamortized premiums are included
in deferred charges. Amounts receivable under cap agreements are
accrued as a reduction of interest expense. Amounts receivable or
payable under fuel-swap agreements are recognized in income when
realized. Any material unrealized gains or losses on fuel swaps or
interest-rate caps will be deferred until realized. For further
information on derivatives, see Note 11, "Derivative Financial
Instruments."
<F2>2. LEASES
CL&P and WMECO have entered into the Niantic Bay Fuel Trust (NBFT) capital
lease agreement to finance up to $530 million of nuclear fuel for
Millstone 1 and 2 and their shares of the nuclear fuel for Millstone 3.
CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel
consumed in the reactors (based on a units-of-production method at rates
which reflect estimated kilowatt-hours of energy provided) plus financing
costs associated with the fuel in the reactors. Upon permanent discharge
from the reactors, ownership of the nuclear fuel transfers to CL&P and
WMECO.
CL&P has also entered into lease agreements, some of which are capital
leases, for the use of data processing and office equipment, vehicles,
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 operating expense:
Capital Operating
Year Leases Leases
---- ------------ ----------
1994 ............ $60,975,000 $24,192,000
1993 ............ 76,606,000 24,355,000
1992 ............ 61,795,000 26,919,000
Interest included in capital lease rental payments was $10,228,000 in 1994,
$11,298,000 in 1993, and $14,782,000 in 1992.
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.
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, 1994, are as follows:
Capital Operating
Year Leases Leases
---- ------------ ----------
(Thousands of Dollars)
1995 $ 2,700 .....$ 19,500
1996 2,700 ........18,000
1997 2,700 ........16,500
1998 2,700 ........12,100
1999 2,700 ........10,400
After 1999 42,100 .... 61,900
---------- ---------
Future minimum lease payments 55,600 ......$138,400
========
Less amount representing interest 35,900
--------
Present value of future minimum
lease payments for other than
nuclear fuel................. 19,700
Present value of future nuclear
fuel lease payments.......... 156,300
---------
Total .............. $176,000
========
<F3>3. NUCLEAR DECOMMISSIONING
The company's 1992 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. A 1994
Seabrook decommissioning study, which is currently under review by the New
Hampshire Decommissioning Finance Committee, also confirmed that complete
and immediate dismantlement at retirement is the most viable and economic
method of decommissioning Seabrook 1. Decommissioning studies are reviewed
and updated periodically to reflect changes in decommissioning
requirements, technology, and inflation.
The estimated cost of decommissioning CL&P's ownership share of Millstone 1
and 2, in year-end 1994 dollars, is $332.8 million and $267.3 million,
respectively. CL&P's ownership share of the estimated cost of
decommissioning Millstone 3 and Seabrook 1 (utilizing the currently
approved decommissioning study), in year-end 1994 dollars, is $237.5
million and $15.5 million, respectively. These estimated costs have been
levelized and assume after-tax earnings on the Millstone and Seabrook 1
decommissioning funds of 6.5 percent and 6.1 percent, respectively. Future
escalation rates in decommissioning costs for the Millstone units and for
Seabrook 1 are assumed. Nuclear decommissioning costs are accrued over the
expected service life of the units and are included in depreciation expense
on the Consolidated Statements of Income. Nuclear decommissioning costs
amounted to $25.6 million in 1994 and $21.9 million in 1993 and 1992.
Nuclear decommissioning, as a cost of removal, is included in the
accumulated provision for depreciation on the Consolidated Balance Sheets.
At December 31, 1994, the balance in the accumulated reserve for
decommissioning amounted to $209.7 million. See "Nuclear Decommissioning"
in Management's Discussion and Analysis for a discussion of changes being
considered by the FASB related to accounting for decommissioning costs.
CL&P has established independent decommissioning trusts for its portion of
the costs of decommissioning Millstone 1, 2, and 3. CL&P's portion of the
cost of decommissioning Seabrook 1 is paid to an independent
decommissioning financing fund managed by the state of New Hampshire.
As of December 31, 1994, CL&P has collected, through rates, $173.4 million,
toward the future decommissioning costs of its share of the Millstone
units, of which $135.9 million has been transferred to external
decommissioning trusts. As of December 31, 1994, CL&P has paid
approximately $1.2 million into Seabrook 1's decommissioning trust.
Earnings on the decommissioning trusts increase the decommissioning trust
balance and the accumulated reserve for decommissioning. Due to CL&P's
adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain
Investments in Debt and Equity Securities, unrealized gains and losses
associated with the decommissioning trusts also impact the balance of the
trusts and the accumulated reserve for decommissioning.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement, would change decommissioning cost estimates. CL&P attempts
to recover sufficient amounts through its allowed rates to cover its
expected decommissioning costs. Only the portion of currently estimated
total decommissioning costs that has been accepted by the regulatory
agencies is reflected in CL&P's rates. Because allowances for
decommissioning have increased significantly in recent years, customers in
future years may need to increase their payments to offset the effects of
any insufficient rate recoveries in previous years.
CL&P, along with other New England utilities, has equity investments in the
four Yankee companies. Each Yankee company owns a single nuclear
generating unit. The estimated costs, in year-end 1994 dollars, of
decommissioning CL&P's ownership share of CY, MY, and VY are $124.9
million, $40.6 million, and $31.3 million, respectively. Under the terms
of the contracts with the Yankee companies, the shareholders-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 CL&P's cost of power.
YAEC has begun component removal activities related to the decommissioning
of its nuclear facility. In June 1992, YAEC filed a rate filing to obtain
FERC authorization to collect the closing and decommissioning costs and to
recover the remaining investment in the YAEC nuclear power plant, over the
remaining period of the plant's Nuclear Regulatory Commission (NRC)
operating license. The bulk of these costs has been agreed to by the YAEC
joint owners and approved as a settlement, by FERC. In October 1994, YAEC
submitted a revised decommissioning cost estimate as part of its
decommissioning plan with the NRC. Following the receipt of NRC approval,
this estimate will be filed with the FERC. The revised estimate increased
CL&P's ownership share of decommissioning YAEC's nuclear facility by
approximately $23.1 million in January 1, 1994 dollars. At December 31,
1994, the estimated remaining costs including decommissioning, amounted to
$408.2 million, of which CL&P's share was approximately $100 million.
Management expects that CL&P will continue to be allowed to recover such
FERC-approved costs from its customers. Accordingly, CL&P has recognized
these costs as a regulatory asset, with a corresponding obligation, on its
Consolidated Balance Sheets.
<F4>4. SHORT-TERM DEBT
The system companies have various revolving credit lines, totalling $485
million. NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company
(RRR) have established a revolving-credit facility with a group of
16 banks. Under this facility, the participating companies may borrow up
to an aggregate of $360 million. Individual borrowing limits as of January
1, 1995 were $150 million for NU, $325 million for CL&P, $60 million for
WMECO, $5 million for HWP, $50 million for NNECO, and $22 million for RRR.
The system companies may borrow funds on a short-term revolving basis
using either fixed-rate loans or standby loans. Fixed rates are set using
competitive bidding. Standby-loan rates are based upon several alternative
variable rates. The system companies are obligated to pay a facility fee
of 0.20 percent per annum of each bank's total commitment under the three-
year portion of the facility, representing 75 percent of the total
facility, plus 0.135 percent per annum of each bank's total commitment
under the 364-day portion of the facility, representing 25 percent of the
total facility. At December 31, 1994 and 1993, there were $30.0 million
and $22.5 million of borrowings, respectively, under the facility, all of
which had been borrowed by other system companies. At December 31, 1993,
CL&P had $5 million in borrowings outstanding under this facility.
The weighted average interest rates on notes payable to banks and
commercial paper outstanding on December 31, 1994 were 6.2 percent and 6.4
percent, respectively. The weighted average interest rate on notes payable
to banks outstanding on December 31, 1993 was 3.3 percent.
Certain subsidiaries of NU, including CL&P, are members of the Northeast
Utilities System Money Pool (Pool). The Pool provides a more efficient use
of the cash resources of the system, and reduces outside short-term
borrowings. NUSCO administers the Pool as agent for the member companies.
Short-term borrowing needs of the member companies are first met with
available funds of other member companies, including funds borrowed by NU
parent. NU parent may lend to the Pool but may not borrow. Funds may be
withdrawn from or repaid to the Pool at any time without prior notice.
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. Investing and borrowing subsidiaries receive or pay
interest based on the average daily Federal Funds rate. At December 31,
1994 and 1993, CL&P had $92.8 million and $1.3 million, respectively, of
borrowings outstanding from the Pool. The interest rate on borrowings from
the Pool on December 31, 1994 and 1993 were 4.9 percent and 2.9 percent,
respectively.
Maturities of CL&P's short-term debt obligations are for periods of three
months or less.
The amount of short-term borrowings that may be incurred by the company is
subject to periodic approval by the SEC under the 1935 Act. In addition,
the charter of CL&P contains provisions restricting the amount of short-
term borrowings. Under the SEC and/or charter restrictions, the company
was authorized, as of January 1, 1995, to incur short-term borrowings up to
a maximum of $325 million.
<F5>5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
<TABLE>
<CAPTION>
December 31, Shares
1994 Outstanding
Redemption December 31, December
31,
-----------------------------
Description Price 1994 1994 1993 1992
-------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
$1.90 Series of 1947 $52.50 163,912 $8,196 $8,196 $8,196
$2.00 Series of 1947 $54.00 336,088 16,804 16,804 16,804
$2.04 Series of 1949 $52.00 100,000 5,000 5,000 5,000
$2.06 Series E of 1954 $51.00 200,000 10,000 10,000 10,000
$2.09 Series F of 1955 $51.00 100,000 5,000 5,000 5,000
$2.20 Series of 1949 $52.50 200,000 10,000 10,000 10,000
$3.24 Series G of 1968 $51.84 300,000 15,000 15,000 15,000
$3.80 Series J of 1971 - - - - 20,000
$4.48 Series H of 1970 - - - - 15,000
$4.48 Series I of 1970 - - - - 20,000
3.90% Series of 1949 $50.50 160,000 8,000 8,000 8,000
4.50% Series of 1956 $50.75 104,000 5,200 5,200 5,200
4.50% Series of 1963 $50.50 160,000 8,000 8,000 8,000
4.96% Series of 1958 $50.50 100,000 5,000 5,000 5,000
5.28% Series of 1967 $51.43 200,000 10,000 10,000 10,000
6.56% Series of 1968 $51.44 200,000 10,000 10,000 10,000
7.60% Series of 1971 - - - - 9,996
1989 Adjustable Rate
DARTS $25.00 2,000,000 50,000 50,000 50,000
------ ------ ------
Total preferred stock
not subject to
mandatory redemption $166,200 $166,200 $231,196
======== ======== ========
</TABLE>
All or any part of each outstanding series of such preferred stock may be
redeemed by the company at any time at established redemption prices plus
accrued dividends to the date of redemption.
As of January 23, 1995, CL&P Capital, L.P., a subsidiary of CL&P, issued
$100 million of 9.3 percent cumulative Monthly Income Preferred Securities
to help finance the expected retirement of $125 million of CL&P preferred
stock.
<F6>6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
<TABLE>
<CAPTION>
December 31, Shares
1994 Outstanding December 31,
Redemption December 31, ----------------------------
Description Price* 1994 1994 1993 1992
-------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
9.10% Series of 1987 - - $ - $ - $ 50,000
9.00% Series of 1989 $26.50 3,000,000 75,000 75,000 75,000
7.23% Series of 1992 $52.41 1,500,000 75,000 75,000 75,000
5.30% Series of 1993 $51.00 1,600,000 80,000 80,000 -
-------- -------- --------
230,000 230,000 200,000
Less preferred stock to be
redeemed within one year 3,750 - 2,500
-------- -------- --------
Total preferred stock subject
to mandatory redemption $226,250 $230,000 $197,500
======== ======== ========
</TABLE>
*Each of these series is subject to certain refunding limitations for the first
five years after they were issued. Redemption prices reduce in future years.
The following table details redemption and sinking fund activity for
preferred stock subject to mandatory redemption:
<TABLE>
<CAPTION>
Minimum
Annual Shares Reacquired
Sinking-Fund ------------------------------
Series Requirement 1994 1993 1992
------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
$5.52 Series L of 1975 $ - - - 38,524
11.52% Series of 1975 - - - 19,318
10.48% Series of 1980 - - - 280,000
9.10% Series of 1987 - - 2,000,000 -
9.00% Series of 1989 (1) 3,750 - - -
7.23% Series of 1992 (2) 3,750 - - -
5.30% Series of 1993 (3) 16,000 - - -
</TABLE>
(1)Sinking fund requirements commence October 1, 1995.
(2)Sinking fund requirements commence September 1, 1998.
(3)Sinking fund requirements commence October 1, 1999.
The minimum sinking-fund provisions of the series subject to mandatory
redemption, for the years 1995 through 1999, aggregate approximately $3,750,000
in 1995, 1996, and 1997, $7,500,000 in 1998, and $23,500,000 in 1999. In case
of default on sinking-fund payments or the payment of dividends, no payments may
be made on any junior stock by way of dividends or otherwise (other than in
shares of junior stock) so long as the default continues. If the company is in
arrears in the payment of dividends on any outstanding shares of preferred
stock, the company would be prohibited from redemption or purchase of less than
all of the preferred stock outstanding. All or part of each of the series named
above may be redeemed by the company at any time at established redemption
prices plus accrued dividends to the date of redemption, subject to certain
refunding limitations.
<F7>7. LONG-TERM DEBT
Details of long-term debt outstanding are: December 31,
------------------------
1994 1993
---------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
Series 1964 due 1994 $ - 12,000
Series WW due 1994 - 170,000
Series 1967 due 1997 - 20,000
Series S due 1997 - 30,000
Series UU due 1997 200,000 200,000
Series U due 1998 - 40,000
Series 1968 due 1998 - 25,000
Series T due 1998 20,000 20,000
Series 1968 due 1998 - 10,000
Series VV due 1999 100,000 100,000
Series A due 1999 140,000 -
Series XX due 2000 200,000 200,000
Series X due 2001 - 30,000
Series 1971 due 2001 - 30,000
Series 1972 due 2002 - 35,000
Series Y due 2002 - 50,000
Series Z due 2003 - 50,000
Series 1973 due 2003 - 40,000
Series B due 2004 140,000 -
Series QQ due 2018 - 75,000
Series RR due 2019 - 75,000
Series SS due 2019 - 75,000
Series TT due 2019 20,000 20,000
Series YY due 2023 100,000 100,000
Series C due 2024 115,000 -
Series D due 2024 140,000 -
Series ZZ due 2025 125,000 125,000
---------- ----------
Total First Mortgage Bonds 1,300,000 1,532,000
Pollution Control Notes:
Variable rate, due 2016-2022 46,400 46,400
Tax exempt, due 2028 315,500 315,500
Fees and interest due for spent fuel
disposal costs (Note 1M) 141,694 136,125
Other 28,398 35,417
Less amounts due within one year 8,111 314,020
Unamortized premium and discount, net (8,302) (8,162)
---------- ----------
Long-term debt, net $1,815,579 $1,743,260
========== ==========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1994 for the years 1995 through 1999 are
approximately: $8,111,000, $9,372,000, $210,828,000, $20,011,000, and
$240,005,000, respectively. In addition, there are annual one-percent
sinking-and improvement-fund requirements, currently amounting to
$13,000,000 for 1995, 1996 and 1997, $11,000,000 for 1998, and $10,800,000
for 1999. Such sinking- and improvement-fund requirements may be satisfied
by the deposit of cash or bonds or by certification of property additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by the company at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which are
subject to certain refunding limitations during their respective initial
five-year redemption periods.
Essentially all of the company's utility plant is subject to the lien of
its first mortgage bond indenture. As of December 31, 1994 and 1993, the
company has secured $315.5 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 rates on the variable-rate
pollution control notes ranged from 2.7 percent to 3.3 percent for 1994 and
2.4 percent to 2.7 percent for 1993.
<F8>8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
<TABLE>
<CAPTION>
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
-----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Current income taxes:
Federal $108,371 $115,403 $ 61,773
State 39,966 44,473 27,153
-------- -------- --------
Total current 148,337 159,876 88,926
-------- -------- --------
Deferred income taxes, net:
Federal 44,180 3,808 60,788
State 842 (12,987) 11,833
-------- -------- --------
Total deferred 45,022 (9,179) 72,621
-------- -------- --------
Investment tax credits, net (7,358) (11,009) (6,230)
-------- -------- --------
Total income tax expense $186,001 $139,688 $155,317
======== ======== ========
The components of total income tax expense are classified as follows:
Income taxes charged to operating expenses $195,038 $144,547 $172,236
Income taxes associated with the
amortization of deferred nuclear plants
return - borrowed funds - - (15,157)
Income taxes associated with allowance for
funds used during construction (AFUDC) and
deferred nuclear plants return -
borrowed funds - - 9,409
Other income taxes - credit (9,037) (4,859) (11,171)
-------- -------- --------
Total income tax expense $186,001 $139,688 $155,317
======== ======== ========
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
-----------------------------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation, leased nuclear fuel, settlement
credits, and disposal costs $38,874 $42,663 $43,715
Demand-side management 203 9,156 13,506
Postretirement benefits accrual (1,019) (2,579) -
Energy adjustment clauses 14,465 (52,189) 12,627
AFUDC and deferred nuclear plants return, net (18,483) (13,741) (5,748)
Early retirement program 671 (3,355) 3,988
Pension accrual 742 3,553 885
Settlement, canceled independent power plants - - 7,251
Loss on bond redemption 9,183 8,145 10
Other 386 (832) (3,613)
------- ------- --------
Deferred income taxes, net $45,022 ($9,179) $72,621
======= ======== ========
A reconciliation between income tax expense and the expected tax expense at the applicable
statutory rate is as follows:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at 35 percent of pretax
income for 1994 and 1993 and at 34 percent for 1992 $134,501 $115,898 $123,091
Tax effect of differences:
Depreciation differences 18,602 19,264 15,826
Deferred nuclear plants return - other funds (4,681) (8,294) (12,035)
Amortization of deferred nuclear plants return -
other funds 19,755 18,648 14,511
Property tax differences 5,286 (12,320) (732)
Investment tax credit amortization (7,358) (11,009) (6,230)
State income taxes, net of federal
benefit 26,526 20,466 25,730
Adjustment for prior years taxes (2,706) (2,330) (3,500)
Other, net (3,924) (635) (1,344)
-------- -------- --------
Total income tax expense $186,001 $139,688 $155,317
======== ======== ========
</TABLE>
9. EMPLOYMENT BENEFITS
<F9A>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 employees' highest eligible compensation
during five consecutive years of employment. The company's direct
portion of the system's pension (income)/cost, part of which was
charged to utility plant, approximated $(2.3) million in 1994, $7.6
million in 1993, and ($1.7) million in 1992. The company's pension
costs for 1994 and 1993 include approximately $4.8 million and $13.1
million, respectively, related to work-force reduction programs.
Currently, the company funds annually an amount at least equal to that
which will satisfy the requirements of the Employment 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 CL&P are:
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------
(Thousands of Dollars)
Service cost $13,072 $21,907 $10,614
Interest cost 36,103 35,055 36,308
Return on plan assets 1,020 (80,615) (40,377)
Net amortization (52,536) 31,254 (8,206)
------- -------- --------
Net pension (income)/cos ($2,341) $7,601 ($1,661)
======= ======= =======
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------------------
(Thousands of Dollars)
Discount rate 7.75% 8.00% 8.50%
Expected long term rate
of return 8.50 8.50 9.00
Compensation/progression rate 4.75 5.00 6.75
The following table represents the plan's funded status reconciled
to the Consolidated Balance Sheets:
At December 31, 1994 1993
-----------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $374,109,000 of vested benefits
at December 31, 1994 and $380,238,000
of vested benefits at December 31, 1993 $401,889 $409,136
======== ========
Projected benefit obligation $471,079 $484,396
Market value of plan assets 568,294 604,320
-------- --------
Market value in excess of projected
benefit obligation 97,215 119,924
Unrecognized transition amount (9,204) (10,125)
Unrecognized prior service costs 1,420 1,547
Unrecognized net (gain) (88,845) (113,100)
--------- ---------
Prepaid/(Accrued) pension liability $586 ($1,754)
========= =========
The following actuarial assumptions were used in calculating the Plan's
year-end funded status:
At December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Discount rate ............ 8.25% 7.75%
Compensation/progression rate 5.00 4.75
>F9B>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. These benefits are available for employees leaving
the company who are otherwise eligible to retire and have met specified
service requirements. Effective January 1, 1993, the company adopted
SFAS 106, Employer's Accounting for Postretirement Benefits Other Than
Pensions on a prospective basis. CL&P's direct portion of health care
and life insurance costs, part of which were deferred or charged to
utility plant, approximated $22.3 million in 1994, $23.2 million in
1993, and $8.8 million in 1992.
On January 1, 1993, the accumulated postretirement benefit obligation
represented the company's transition obligation upon the adoption of
SFAS 106. As allowed by SFAS 106, the company is amortizing its
transition obligation of approximately $148 million over a 20-year
period. 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.
During 1994, the company funded through external trusts an amount
equivalent to total SFAS 106 benefits paid for 1994. During 1993, the
company did not fund SFAS 106 postretirement costs through external
trusts. The company expects to fund, annually, total SFAS 106 costs,
including benefits paid amounts, once they have been rate recovered and
which also are tax-deductible under the Internal Revenue Code. The
trust assets are invested primarily in equity securities and bonds.
The following table represents the plan's funded status reconciled to
the Consolidated Balance Sheet:
At December 31, 1994 1993
--------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees .......................... $129,111 $119,520
Fully eligible active employees ... 241 288
Active employees not eligible to retire 25,203 29,270
--------- ---------
Total accumulated postretirement
benefit obligation 154,555 149,078
Market value of plan assets ....... 167 -
--------- ---------
Accumulated postretirement benefit obligation
in excess of plan assets ......... (154,388) (149,078)
Unrecognized transition amount ..... 132,194 139,539
Unrecognized net loss (gain) ...... 192 (2,591)
---------- ---------
Accrued postretirement benefit liability $(22,002) $(12,130)
======== ========
-------------------------------------------------------------
The components of health care and life insurance costs are:
For the Years Ended December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Service cost ....................... $ 2,371 $ 3,397
Interest cost ...................... 12,157 12,091
Return on plan assets ............. 2 -
Net amortization ................... 7,774 7,682
------- -------
Net health care and life insurance costs $22,304 $23,170
======= =======
The following actuarial assumptions were used in calculating the plan's
year end funded status:
At December 31, 1994 1993
------------------------------------------------------------
Discount rate ...................... 8.00% 7.75%
Long-term rate of return - health
assets, net of tax................ 5.00 5.00
Long-term rate of return - life assets 8.50 8.50
Health care cost trend rate (a) .... 10.20 11.10
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 5.4 percent by 2002.
The effect of increasing the assumed health care cost trend rates by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1994 by $8.6
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$763,000. The trust holding the plan assets is subject to federal
income taxes at a 35-percent tax rate.
CL&P has received regulatory approval to defer SFAS 106 costs in excess
of costs incurred on a pay-as-you-go basis. Deferral of such costs is
permitted since it is expected that the period of recovery of deferred
costs will be within the time frame established by the applicable
accounting requirements.
10. COMMITMENTS AND CONTINGENCIES
<F10A>A.CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision.
Actual construction expenditures may vary from estimates due to factors
such as revised load estimates, inflation, revised nuclear safety
regulations, delays, difficulties in the licensing process, the
availability and cost of capital, and the granting of timely and
adequate rate relief by regulatory commissions, as well as actions by
other regulatory bodies.
CL&P currently forecasts construction expenditures (including AFUDC) of
approximately $716.9 million for the years 1995-1999, including $147.7
million for 1995. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
approximately $257.4 million for the years 1995-1999, including $46.8
million for 1995. See Note 2, "Leases," for additional information
about the financing of nuclear fuel.
<F10B>B.NUCLEAR PERFORMANCE
Outages that occurred over the period October 1990 through February
1992 at the Millstone nuclear units have been the subject of five
ongoing prudence reviews in Connecticut. CL&P has received final
decisions on each of the reviews. The Office of Consumer Counsel (OCC)
appealed decisions favorable to the company in two dockets. For the
one appeal decided, which related to a procedural issue, the OCC
prevailed and the case has been remanded to the DPUC for further
proceedings. The exposure under these two dockets is approximately $66
million. The DPUC has suspended a third docket, pending the outcome of
one of the appeals. The exposure under this remaining docket is $26
million. Management believes that its actions with respect to these
outages have been prudent, and it does not expect the outcome of the
appeals to result in material disallowances.
In October 1994, Millstone 2 began a planned refueling and maintenance
outage that was originally scheduled for 63 days. The outage has
encountered several unexpected difficulties which have lengthened the
duration of the outage. The magnitude of the schedule impact is
currently under review, but the unit is not expected to return to
service before April 1995. CL&P expects that replacement power costs
in the range of $7 million per month will be attributable to the
extension of the outage. Recovery of the costs related to this outage
is subject to scrutiny by the DPUC.
<F10C>C.ENVIRONMENTAL MATTERS
CL&P is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the disposal of toxic
substances and hazardous and solid wastes, and the handling and use of
chemical products. CL&P has an active environmental auditing and
training program and believes that it is in substantial compliance with
current environmental laws and regulations.
Changing environmental requirements could hinder the construction of
new generating units, transmission and distribution lines, substations,
and other facilities. The cumulative long-term, economic cost impact
of increasingly stringent environmental requirements cannot accurately
be estimated. Changing environmental requirements could also require
extensive and costly modifications to CL&P's existing generating units,
and transmission and distribution systems, and could raise operating
costs significantly. As a result, CL&P may incur significant
additional environmental costs, greater than amounts included in cost
of removal and other reserves, in connection with the generation and
transmission of electricity and the storage, transportation, and
disposal of by-products and wastes. CL&P may also encounter
significantly increased costs to remedy the environmental effects of
prior waste handling activities.
CL&P has recorded a liability for what it believes is, based upon
information currently available, its estimated environmental
remediation costs for waste disposal sites for which it's expected to
bear legal liability. In most cases, the extent of additional future
environmental cleanup costs is 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, 1994, the liability recorded by CL&P for its
estimated environmental remediation costs, excluding any possible
insurance recoveries or recoveries from third parties, amounted to
approximately $7 million. However, in the event that it becomes
necessary to effect environmental remedies that are currently not
considered probable, it is reasonably possible that the upper limit of
CL&P's environmental liability range could increase to approximately
$10 million.
CL&P cannot estimate the potential liability for future claims that may
be brought against it. However, considering known facts, existing
laws, and regulatory practices, management does not believe the matters
disclosed above will have a material effect on CL&P's financial
position or future results of operations.
<F10D>D.NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first
$200 million of liability would be provided by purchasing the maximum
amount of commercially available insurance. Additional coverage of up
to a total of $8.3 billion would be provided by an assessment of
$75.5 million per incident, levied on each of the 110 nuclear units
that are currently subject to the Secondary Financial Protection
Program in the United States, subject to a maximum assessment of
$10 million per incident per nuclear unit in any year. In addition, if
the sum of all public liability claims and legal costs arising from any
nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5 percent, up to
$3.8 million, or $415.3 million in total, for all 110 nuclear units.
The maximum assessment is to be adjusted at least every five years to
reflect inflationary changes. Based on CL&P's ownership interests in
Millstone 1, 2, and 3, and Seabrook 1, CL&P's maximum liability would
be $173.6 million per incident. In addition, through CL&P's power
purchase contracts with the three operating Yankee regional nuclear
generating companies, CL&P would be responsible for up to an additional
$44.4 million per incident. Payments for CL&P's ownership interest in
nuclear generating facilities would be limited to a maximum of
$27.5 million per incident per year.
Effective January 1, 1995, insurance was purchased from Nuclear Mutual
Limited (NML) to cover the primary cost of repair, replacement, or
decontamination of utility property resulting from insured occurrences
with respect to CL&P's ownership interest in Millstone 1, 2, 3, and CY.
All companies insured with NML are subject to retroactive assessments
if losses exceed the accumulated funds available to NML. The maximum
potential assessment against CL&P with respect to losses arising during
the current policy year is approximately $13 million under the NML
primary property insurance program.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL) to cover: (1) certain extra costs incurred in obtaining
replacement power during prolonged accidental outages with respect to
CL&P's ownership interests in Millstone 1, 2, and 3, Seabrook 1, and
CY; and (2) the excess cost of repair, replacement, or decontamination
or premature decommissioning of utility property resulting from insured
occurrences with respect to CL&P's ownership interests in Millstone 1,
2, and 3, Seabrook 1, CY, MY, and VY. All companies insured with NEIL
are subject to retroactive assessments if losses exceed the accumulated
funds available to NEIL. The maximum potential assessments against
CL&P, with respect to losses arising during current policy years are
approximately $7.5 million under the replacement power policies and
$32.2 million under the excess property damage, decontamination, and
decommissioning policies. Although CL&P has purchased the limits of
coverage currently available from the conventional nuclear insurance
pools, the cost of a nuclear incident could exceed available insurance
proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual
Atomic Energy Liability Underwriters, 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 $3.1 million per reactor. The maximum
potential assessments against CL&P with respect to losses arising
during the current policy period are approximately $9.2 million.
<F10E>E.PURCHASED POWER ARRANGEMENTS
CL&P along with PSNH and WMECO purchase approximately 10 percent of
their electricity requirements pursuant to long-term contracts with the
Yankee companies. Under the terms of its agreements, CL&P pays its
ownership share (or entitlement share) of generating costs, which
include depreciation, operation and maintenance expenses, taxes, the
estimated cost of decommissioning, and a return on invested capital.
These costs are recorded as purchased power expense, and are recovered
through the company's rates. CL&P's total cost of purchases under
these contracts for the units that are operating amounted to $102.1
million in 1994, $112.3 million in 1993, and $103.2 million in 1992.
See Note 1D, "Summary Of Significant Accounting Policies - Investments
and Jointly Owned Electric Utility Plant" and Note 3, "Nuclear
Decommissioning" for more information on the Yankee companies.
CL&P has entered into various arrangements for the purchase of capacity
and energy from nonutility generators. These arrangements generally
have terms from 10 to 30 years, and require the company to purchase the
energy at specified prices or formula rates. For the 12 months ended
December 31, 1994, approximately 14 percent of system electricity
requirements was met by nonutility generators. The total cost of the
company's purchases under these arrangements amounted to $277.4 million
in 1994, $279.8 million in 1993, and $267.3 million in 1992. These
costs are eventually recovered through the company's rates.
The estimated annual costs of CL&P's significant purchase power
arrangements are as follows:
1995 1996 1997 1998 1999
-------------------------------------------------------------
(Millions of Dollars)
Yankee companies ...... $110.2 $116.0 $103.7 $123.6 $118.1
Nonutility generators . 301.1 315.9 322.5 329.3 329.2
<F10F>F.HYDRO-QUEBEC
Along with other New England utilities, CL&P, PSNH, WMECO, and HWP
entered into agreements to support transmission and terminal facilities
to import electricity from the Hydro-Quebec system in Canada. CL&P is
obligated to pay, over a 30-year period, its proportionate share of the
annual operation, maintenance, and capital costs of these facilities,
which are currently forecast to be $97.7 million for the years 1995-
1999, including $21.8 million for 1995.
<F11>11.DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes derivative financial instruments to manage well-
defined interest-rate and fuel- price risks. The company does not use them
for trading purposes.
Interest-Rate Cap Contracts: CL&P has entered into interest-rate cap
contracts with financial institutions in order to reduce a portion of the
interest-rate risk associated with certain variable-rate tax-exempt
pollution control revenue bonds. During 1994, there was one outstanding
contract held by CL&P covering $340 million of variable-rate debt, with a
term of three years. The contract entitles CL&P to receive from a
counterparty the amounts, if any, by which the interest payments on a
portion of its variable-rate tax-exempt pollution control revenue bonds
exceed the J. J. Kenny High Grade Index. This contract is settled on a
quarterly basis. As of December 31, 1994, CL&P had a total of $340 million
in caps outstanding, with a positive mark-to-market position of
approximately $3.7 million.
Fuel Swaps: CL&P also uses fuel-swap agreements with financial
institutions to hedge against fuel-price risk created by long-term
negotiated energy contracts. These fuel swaps minimize exposure associated
with rising fuel prices, and effectively fix CL&P's cost of fuel for these
negotiated energy contracts. Under the swap agreements, CL&P exchanges
monthly payments based on the differential between a fixed and variable
price for the associated fuel. As of December 31, 1994, CL&P had five
outstanding agreements with a total notional value of approximately $126
million, and a positive mark-to-market position of approximately $3.1
million. These swap agreements have been made with various financial
institutions, each of which are rated "A" or better by Standard and Poor's
rating group.
CL&P is exposed to credit risk on both the interest-rate caps and fuel
swaps if the counterparties fail to perform their obligations. However,
CL&P anticipates that the counterparties will be able to fully satisfy
their obligations under the contracts.
<F12>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 requires investments in debt and equity securities to be presented
at fair value and was adopted by the company on a prospective basis as of
January 1, 1994. As a result of the adoption of SFAS 115, the investments
held in the company's nuclear decommissioning trusts decreased by
approximately $3.8 million as of December 31, 1994, with a corresponding
offset to the accumulated provision for depreciation. The $3.8 million
decrease represents cumulative gross unrealized holding gains of $1.6
million, offset by cumulative gross unrealized holding losses of $5.4
million. There was no change in funding requirements of the trusts nor any
impact on earnings as a result of the adoption of SFAS 115.
Preferred stock and long-term debt: The fair value of CL&P's fixed rate
securities is based upon the quoted market price for those issues or
similar issues. Adjustable rate securities are assumed to have a fair
value equal to their carrying value.
The carrying amounts of CL&P's financial instruments and the estimated fair
values are as follows:
Carrying Fair
At December 31, 1994 Amount Value
----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption ........ $ 166,200 $ 113,825
Preferred stock subject to
mandatory redemption ........ 230,000 218,075
Long-term debt -
First Mortgage Bonds ....... 1,300,000 1,182,894
Other long-term debt ....... 531,992 531,992
-----------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption ........ $ 166,200 $ 128,826
Preferred stock subject to
mandatory redemption ........ 230,000 240,400
Long-term debt -
First Mortgage Bonds ....... 1,532,000 1,580,396
Other long-term debt ....... 533,442 539,518
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
---------------------------------------------------------------------
To the Board of Directors
of The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The
Connecticut Light and Power Company and Subsidiaries (a Connecticut corporation
and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1994
and 1993, and the related consolidated statements of income, common
stockholder's equity and cash flows for each of the three years in the period
ended December 31, 1994. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of The
Connecticut Light and Power Company and Subsidiaries as of December 31, 1994 and
1993, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
As explained in Note 1B and 9B to the financial statements, effective
January 1, 1993, The Connecticut Light and Power Company and Subsidiaries
changed its methods of accounting for property taxes and postretirement benefits
other than pensions.
/s/Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
---------------------------------------------------------------------
This section contains management's assessment of CL&P's ( the company) financial
condition and the principal factors having an impact on the results of
operations. The company is a wholly owned subsidiary of Northeast Utilities
(NU). This discussion should be read in conjunction with the company's
financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
Net income was approximately $198 million in 1994, as compared to approximately
$191 million in 1993. The 1994 net income is higher as a result of higher
retail kilowatt-hour sales, retail rate increases in 1993 and 1994, the deferral
of cogeneration expenses, and reduced operation and interest costs. These
increases were partially offset by lower revenues from wholesale sales. The
1993 net income was impacted by a number of one-time items, including the
cumulative effect of a one-time change in the accounting for municipal property
taxes, which resulted in an increase in 1993 net income of approximately
$48 million. In addition, 1993 net income reflected a decrease of approximately
$10 million for the costs of the company's employee-reduction program and a
decrease of approximately $15 million for disallowances in 1993 ordered in the
company's retail rate case. Net income before the effects of the change in
accounting for property taxes and other one-time items was approximately
$169 million in 1993.
In 1994, the company experienced its most significant retail kilowatt-hour sales
growth in six years, due in large part to the beginning of an economic recovery
in New England. Employment levels have risen, unemployment rates have fallen,
and personal income has increased. The company's 1994 retail sales rose by
3.4 percent over 1993. Overall, weather had little effect on sales volume, with
mild weather after mid-August offsetting unusually cold weather in January and
hot weather in late June and July.
In 1995, the company expects little retail sales growth over 1994, primarily
because of the effects of higher interest rates on the regional economy and
further cutbacks in defense-related industries in Connecticut. The company
estimates compounded annual sales growth of 1.4 percent from 1994 through 1999.
Competitive forces within the electric utility industry are continuing to
increase due to a variety of influences, including legislative and regulatory
actions, technological advances, and changes in consumer demand. The company
has developed, and is continuing to develop, a number of initiatives to retain
and continue to serve its existing customers and to expand its retail and
wholesale customer base.
The company believes the steps it is taking including a companywide process
reengineering effort, will have significant, positive effects, including reduced
operating costs and improved customer service, in the next few years. The
company also benefits from a diverse retail base with no significant dependence
on any one retail customer or industry.
CL&P continues to operate predominantly in a state-approved franchise territory
under traditional cost-of-service regulation. Retail wheeling, under which a
retail customer would be permitted to select an electricity supplier and require
the local electric utility to transmit the power to the customer's site, is not
required in Connecticut. In 1994, Connecticut regulators reviewed the
desirability of retail wheeling and determined that it was not in the best
interest of the state until new generating capacity is needed, which the NU
system projects to be in the year 2009. Connecticut regulators are presently
studying the potential restructuring of the electric utility industry. To date,
this regulatory proceeding has not progressed to the point where management can
assess the impact of any potential outcome on the company.
While retail competition is not required in the company's retail service
territory, competitive forces are nonetheless influencing retail pricing. These
forces include competition from alternate fuels such as natural gas, competition
from customer-owned generation, and regional competition for business retention
and expansion. The company's retail business group continues to work with
customers to address their concerns. The company has reached long-term rate
agreements with many new and existing customers to gain or retain their
business. In general, these rate agreements have terms of about five years.
Negotiated retail rate reductions for customers under rate agreements in effect
for 1994 amounted to approximately $11 million. Management believes that the
aggregate amount of negotiated retail rate reductions will increase in 1995 but
that the related agreements will continue to provide significant benefits to the
system, including the preservation of approximately 3 percent of retail
revenues.
The company is also working with its regulators to address the needs of
customers more widely. The company has a three-year rate agreement in effect
through June 1996. Management will continue to evaluate the use of agreements
of this type to keep retail rates competitive.
The company acts as both a buyer and a seller of electricity in the highly
competitive wholesale electricity market in the Northeastern United States
(Northeast). Many of the contracts signed in the late 1980s have or will expire
in the mid-1990s. Much of the revenue produced by such contracts has not been
replaced through new wholesale power arrangements. As a result, wholesale power
revenues fell to approximately $215 million in 1994 from approximately $268 mil-
lion in 1993. Unless prices on the wholesale market improve, revenues are
expected to fall still further in 1995 before stabilizing in late 1996 and 1997.
Wholesale sales are made primarily to investor-owned utilities and municipal or
cooperative electric systems in the Northeast. The company will be increasing
its efforts to increase wholesale sales through intensified marketing efforts.
The company's wholesale power marketing efforts benefit from the interconnection
of the NU system's transmission system with all of the major utilities in New
England, as well as with the three largest electric utilities in New York state.
RATE MATTERS
The company follows accounting principles that allow the rate treatment for
certain events or transactions to be reflected. These principles may differ
from the accounting principles followed by nonregulated enterprises. Regulators
may permit incurred costs, which would normally be treated as expenses by
nonregulated enterprises, to be deferred as regulatory assets and recovered in
revenues at a later date. Regulatory assets at December 31, 1994 were
approximately $1.4 billion. Based on current regulation, the company believes
that its use of regulatory accounting is still appropriate.
See the "Notes to Consolidated Financial Statements," Note 1H, for further
details on regulatory accounting.
CL&P's retail rates increased by approximately $47 million, or 2.04 percent, in
July 1994, representing the second step of a three-year rate plan approved by
the Department of Public Utility Control (DPUC) in 1993. The third step of an
approximately $48 million, or 2.06 percent, increase will become effective in
July 1995. CL&P's 1993 rate decision has been appealed by the Connecticut
Office of Consumer Counsel and the city of Hartford. If this appeal prevails
there may be revenues subject to refund, however, management believes that the
possibility of the appeal prevailing is unlikely.
CL&P recovers from or refunds to customers certain fuel costs if the nuclear
units do not operate at a predetermined capacity factor (currently 72 percent)
through a Generation Utilization Adjustment Clause (GUAC). For the GUAC year
ended July 31, 1994, the DPUC found that CL&P overrecovered its fuel costs and
reduced by approximately $8 million CL&P's overall request to recover
approximately $24 million of deferred GUAC costs. The company plans to appeal
the decision in court as it did for a similar DPUC decision on the 1992-1993
GUAC period, which also disallowed approximately $8 million of GUAC costs.
For the GUAC year ended July 31, 1995, CL&P expects to defer in excess of
$50 million of GUAC fuel costs for projected nuclear performance below
72 percent. As of December 31, 1994, CL&P has reserved approximately
$13 million against this amount based on the methodology applied by the DPUC in
the previous GUAC decisions.
NUCLEAR PERFORMANCE
The composite capacity factor of the five nuclear generating units that the NU
system operates - including the Connecticut Yankee (CY) nuclear unit was
67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national
average of 73.2 percent. The lower 1994 capacity factor was primarily the
result of extended refueling and maintenance outages for Millstone 1,
Millstone 2, and Seabrook. CY, Seabrook, and Millstone 2 were also out of
service for varying lengths of time in 1994 because of unexpected technical and
operating difficulties. These difficulties included a manual shutdown of CY
when both service water headers were declared inoperable, an automatic trip from
100 percent power for Seabrook when a main steam isolation valve closed during
quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded
lower seal on a reactor coolant pump.
On October 1, 1994, Millstone 2 was shut down for a planned 63-day refueling and
maintenance outage. The outage has encountered several unexpected difficulties,
which will lengthen the duration of the outage. The outage extensions were
caused by a significant scope increase in service water system repairs as
identified through a comprehensive inspection plan and by a need for management
to exercise a deliberate approach to the conduct of work during the early
portions of the outage. The outage schedule is currently under review, but the
unit is not expected to return to service before April 1995. Replacement-power
costs attributable to the extension of the outage for CL&P are expected to be in
the range of approximately $7 million per month. These costs are deferred for
future recovery through the GUAC. (See rate matters above for further
discussion of the GUAC.) In addition, CL&P's operation and maintenance costs to
be incurred during the outage are estimated to be $42 million, an increase of
$15 million as a result of the extension. The recovery of these costs is
subject to prudence review in Connecticut.
The Nuclear Regulatory Commission's (NRC's) latest report for the Millstone
Station noted significant weaknesses in Millstone 2's operations and
maintenance. In a recent public statement in late 1994, a senior NRC official
expressed disappointment with the continued weaknesses in Millstone 2's
performance. The primary cause of the NRC's disappointment with Millstone 2's
performance appears to be that, despite significant management attention and
action over a period of years, the NRC does not believe it has seen enough
objective evidence of improvement in reducing procedural noncompliance and other
human errors. Management has acknowledged the basis for the NRC's concern with
Millstone 2 and has been devoting increased attention to resolving these issues.
Management and the NRC expect to continue to monitor closely the developments
at Millstone 2.
ENVIRONMENTAL MATTERS
NU devotes substantial resources to identify and then to meet the multitude of
environmental requirements it faces. NU has active auditing programs
addressing a variety of different regulatory requirements, including an
environmental auditing program to detect and remedy noncompliance with
environmental laws or regulations.
The company is potentially liable for environmental cleanup costs at a number of
sites both inside and outside its service territories. To date, the future
estimated environmental remediation liability has not been material with respect
to the earnings or financial position of the company. At December 31, 1994, the
liability recorded by the company, amounted to approximately $7 million. These
costs could rise to as much as $10 million if alternate remedies become
necessary.
The company expects that the implementation of the Clean Air Act Amendments of
1990 (CAAA) as they relate to sulfur dioxide emissions will require only modest
emissions reductions for the company. CL&P's exposure is minimal because of
the company's investment in nuclear energy in the 1970s and 1980s and the
burning of low-sulfur fuels. The CAAA requirements for emission limits for
nitrogen oxides will initially be met by capital expenditures of approximately
$10 million.
NUCLEAR DECOMMISSIONING
The company's estimated cost to decommission its shares of Millstone units 1, 2,
and 3 and Seabrook is approximately $853 million in year-end 1994 dollars. In
addition, the company's estimated cost to decommission its shares of the
regional nuclear generating units is approximately $197 million. These costs
are being recognized over the lives of the respective units and a portion of the
costs is being recovered through rates. Yankee Atomic Electric Company (YAEC)
has begun component removal activities related to the decommissioning of its
nuclear facility. The company's estimated obligation to YAEC has been recorded
on its Consolidated Balance Sheets. Management expects that the company will
continue to be allowed to recover these costs.
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
this company, regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. The Financial Accounting Standards Board is
currently reviewing the accounting for removal costs, including decommissioning.
If current electric utility industry accounting practices for such decom-
missioning costs are changed: (1) annual provisions for decommissioning could
increase, (2) the estimated costs for decommissioning could be recorded as a
liability rather than as accumulated depreciation, and (3) trust fund income
from the external decommissioning trust could be reported as investment income
rather than as a reduction to decommissioning expense.
See the "Notes to The Consolidated Financial Statements, " Note 3, for further
information on nuclear decommissioning.
PROPERTY TAXES
CY has a significant court appeal for municipal property tax assessments in the
town of Haddam, Connecticut. The central issue in this case is the fair market
value of utility property. CY believes that the assessments should be based on
a fair market value that approximates net book cost. This is the assessment
level that taxing authorities are predominantly using throughout Connecticut.
However, towns such Haddam advocate a method that approximates reproduction
costs.
CY's appeal is still pending. The company estimates that, for assessments in
towns such as Haddam, the change to the reproduction cost methodology could
result in property valuations approximately three times greater than values
approximating net book cost. If other towns in Connecticut adopt this
methodology, there could be a significant adverse impact on the company's future
results of operations and financial condition. However, the extent to which
other towns successfully adopt this methodology and any subsequent increase in
the company's property tax liability cannot be determined at this time.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $12 million in 1994, as
compared with 1993, primarily due to lower recovery of replacement-power costs
under the GUAC in 1994, partially offset by higher revenues from rate increases
and sales combined with lower cash operating expenses. Cash used for financing
activities was approximately $26 million lower in 1994, as compared with 1993,
primarily due to an increase in short-term debt, partially offset by higher net
reacquisitions and retirements of long-term debt. Cash used for investments
increased $4 million in 1994, as compared with 1993.
In 1994, the company refinanced approximately $535 million of debt. With
interest rates rising in mid-1994, much refinancing completed, and construction
needs remaining modest, the focus of CL&P's financing activities will shift
toward using the significant amount of cash generated by the company to retire
debt and to prepare the company for an increasingly competitive business
environment.
The company is obligated to meet approximately $531 million of long-term debt
and preferred stock maturities and cash sinking-fund requirements during the
1995 through 1999 period, including approximately $12 million for 1995.
The company's construction program expenditures, including allowance for funds
used during construction, for the period 1995 through 1999 are estimated to be
approximately $717 million, including approximately $148 million for 1995. The
construction program's main focus is maintaining and upgrading the existing
transmission and distribution system, as well as nuclear and fossil-generating
facilities. NU does not foresee the need for new major generating facilities,
at least until the year 2009. Construction expenditures and debt sinking fund
requirements will continue to be met through internal cash generation.
CL&P entered into interest rate cap contracts to reduce a portion of the
interest rate risk on certain variable-rate tax-exempt pollution control revenue
bonds. CL&P also uses fossil fuel-swap agreements to hedge against fuel-price
risk on certain long-term, negotiated energy contracts. Any premiums paid on
these contracts are deferred and amortized over the life of the contracts. The
differential paid or received as interest rates or fuel prices change is
recognized in income when realized.
See the "Notes To Consolidated Financial Statements," Note 8, for further
information on derivative financial instruments.
RESULTS OF OPERATIONS
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table below.
CHANGE IN OPERATING REVENUES
INCREASE/(DECREASE)
1994 VS. 1993 1993 VS. 1992
--------------------------------------------------------------------
(MILLIONS OF DOLLARS)
Regulatory decisions $ 38 $34
Fuel and purchased power
cost recoveries (45) 2
Sales volume 40 3
Wholesale revenues (63) 7
Other revenues (8) 4
----- ----
Total revenue change $(38) $50
==== ===
Operating revenues decreased approximately $38 million in 1994 from 1993. Reve-
nues related to regulatory decisions increased, primarily because of the effects
of the July 1993 and 1994 retail rate increases, partially offset by lower
recoveries for demand-side-management costs. Fuel and purchased power cost
recoveries decreased primarily due to lower GUAC recoveries. Sales volume
increased as a result of higher retail sales from an improving economy. Retail
sales increased 3.4 percent in 1994 from 1993 sales levels. Wholesale revenues
decreased primarily due to the expiration in late 1993 and 1994 of some
significant capacity sales contracts.
Operating revenues increased approximately $50 million in 1993 from 1992.
Revenues related to regulatory decisions increased, primarily because of the
effects of the June 1993 retail rate increase for CL&P and higher recoveries for
demand-side-management costs. Retail sales were essentially flat in 1993.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power decreased approximately $89 million in
1994, as compared with 1993, primarily due to lower recognition of replacement-
power fuel costs in 1994, partially offset by a higher level of outside energy
purchases from other utilities in 1994.
Fuel, purchased and net interchange power increased approximately $59 million in
1993, as compared with 1992, primarily due to the timing in the recognition of
fuel expenses under the provisions of CL&P's fuel adjustment clauses, and 1993
disallowances of replacement-power costs as a result of regulatory reviews in
Connecticut, partially offset by lower outside purchases due to better nuclear
performance in 1993.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses decreased approximately $21 million in
1994, as compared with 1993, primarily due to higher costs in 1993 associated
with early retirement programs, lower 1994 payroll and benefit costs, lower
fossil-unit costs and lower capacity charges from the regional nuclear
generating units, partially offset by higher 1994 costs associated with the
operation and maintenance activities of the nuclear units and higher reserves
for excess/obsolete inventory at the nuclear and fossil units in 1994.
Other operation and maintenance expenses increased approximately $19 million in
1993, as compared with 1992, primarily due to the 1993 costs associated with an
employee-reduction program ($24 million) and higher 1993 postretirement benefit
costs, partially offset by lower costs associated with the operation and
maintenance activities of the nuclear units.
DEPRECIATION EXPENSES
Depreciation expenses increased approximately $11 million in 1994, as compared
to 1993, primarily as a result of higher depreciable plant balances, higher
average depreciation rates, and higher decommissioning collections.
Depreciation expenses increased $10 million in 1993, as compared to 1992,
primarily as a result of higher depreciation rates and higher depreciable plant
balances.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased approximately $35 million in
1994, as compared with 1993, primarily because of the deferral of cogeneration
expenses beginning in July 1994 as allowed under the 1993 retail rate decision
and lower 1994 expenses associated with the recovery of Hydro-Quebec support
payments, partially offset by higher 1994 amortization of Millstone 3 and
Seabrook phase-in costs.
Amortization of regulatory assets, net increased approximately $39 million in
1993, as compared to 1992, primarily because of higher amortization of
Millstone 3 and Seabrook phase-in costs, the gross-up of taxes due to a required
change in the accounting for income taxes, and the amortization of costs paid to
the developers of two wood-to-energy plants as allowed in the 1993 rate
decision.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased approximately $46 million in 1994, as
compared with 1993, primarily because of higher taxable income.
Federal and state income taxes decreased approximately $21 million in 1993, as
compared with 1992, primarily because of lower taxable income and higher
investment tax credits, partially offset by an increase in flow-through
depreciation.
DEFERRED NUCLEAR PLANTS RETURN
Deferred nuclear plants return decreased approximately $17 million in 1994, as
compared with 1993, primarily because additional Millstone 3 investment was
phased into rates in 1994.
Deferred nuclear plants return decreased approximately $11 million in 1993, as
compared with 1992, primarily because additional Millstone 3 investment was
phased into rates in 1993.
OTHER INCOME, NET
Other income, net increased approximately $6 million in 1994, as compared with
1993, and decreased approximately $8 million in 1993, as compared with 1992,
primarily because of the 1993 allocation to customers of a portion of the
property tax accounting change as ordered in the 1993 CL&P rate decision.
INTEREST CHARGES
Interest on long-term debt decreased approximately $14 million in 1994, as
compared with 1993, primarily because of lower average interest rates as a
result of refinancing activities and lower 1994 debt levels.
Interest on long-term debt decreased approximately $17 million in 1993, as
compared with 1992, primarily because of lower average interest rates as a
result of substantial refinancing activities.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
The cumulative effect of the accounting change of approximately $48 million in
1993 represents the one-time change in the method of accounting for municipal
property tax expense recognized in the first quarter of 1993.
THE CONNECTICUT LIGHT AND POWER COMPANY
------------------------------------------------------------------------------
SELECTED FINANCIAL DATA
------------------------------------------------------------------------------
1994 1993 1992 1991 1990
------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $2,328,052 $2,366,050 $2,316,451 $2,275,737 $2,170,087
Operating Income.... 282,159 240,095 287,811 323,835 320,641
Net Income.......... 198,288 191,449(a) 206,714 240,818 224,783
Cash Dividends on
Common Stock...... 159,388 160,365 164,277 172,587 179,921
Total Assets........ 6,217,457 6,397,405 5,582,831 5,338,466 5,176,809
Long-Term Debt*..... 1,823,690 2,057,280 2,087,936 2,023,268 2,101,334
Preferred Stock Not
Subject to Mandatory
Redemption......... 166,200 166,200 231,196 306,195 306,195
Preferred Stock
Subject to Mandatory
Redemption*........ 230,000 230,000 200,000 141,892 146,892
Obligations Under
Capital Leases*.... 175,969 177,418 197,404 208,924 233,919
* Includes portions due within one year.
(a) Includes the cumulative effect of a change in accounting for municipal
property tax expense, which increased earnings for common shares by $47.7
million.
------------------------------------------------------------------------
STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
------------------------------------------------------------------------
Quarter Ended
-------------------------------------------------
1994 March 31 June 30 September 30December 31
---------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.. $619,815 $551,135 $598,706 $558,396
======== ======== ======== ========
Operating Income.... $ 88,796 $ 58,190 $ 73,640 $ 61,533
========= ========= ========= =========
Net Income.......... $ 68,590 $ 39,162 $ 50,191 $ 40,345
========= ========= ========= =========
1993
------------------------------------------------------------------------
Operating Revenues.. $627,134 $559,894 $604,343 $574,679
======== ======== ======== ========
Operating Income.... $ 67,201 $ 47,775 $ 58,321 $ 66,798
========= ========= ========= =========
Net Income.......... $ 91,596 $ 13,775 $ 39,068 $ 47,010
========= ========= ========= =========
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
------------------------------------------------------------------------
STATISTICS
------------------------------------------------------------------------
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer(kWh) (Average) (December 31,)
--------------------------------------------------------------------------
1994 $6,327,967 26,975 8,775 1,086,400 2,587
1993 6,214,401 26,107 8,519 1,078,925 2,676
1992 6,100,682 25,809 8,501 1,075,425 3,028
1991 5,986,271 24,992 8,435 1,069,912 3,364
1990 5,881,500 25,039 8,434 1,064,695 3,517
Exhibit 13.3
1994
ANNUAL REPORT TO STOCKHOLDERS
WESTERN MASSACHUSETTS ELECTRIC COMPANY
--------------------------------------
1994 Annual Report
Western Massachusetts Electric Company
Index
Contents Page
-------- ----
Balance Sheets..................................... 1-2
Statements of Income............................... 3
Statements of Cash Flows........................... 4
Statements of Common Stockholder's Equity.......... 5
Notes to Financial Statements...................... 6-25
Report of Independent Public Accountants........... 26
Management's Discussion and Analysis of Financial
Condition and Results of Operations............... 27-32
Selected Financial Data............................ 33
Statements of Quarterly Financial Data............. 33
Statistics......................................... 34
Preferred Stockholder and Bondholder Information... Back Cover
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
At December 31, 1994 1993
------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
------
Utility Plant, at original cost:
Electric................................................ $1,214,326 $1,183,410
Less: Accumulated provision for depreciation......... 425,019 395,190
----------- -----------
789,307 788,220
Construction work in progress........................... 19,187 23,790
Nuclear fuel, net....................................... 38,000 35,727
----------- -----------
Total net utility plant............................. 846,494 847,737
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994 and
at cost in 1993 (Note 12)<F12>......................... 56,123 49,155
Investments in regional nuclear generating
companies, at equity................................... 14,927 14,633
Other, at cost.......................................... 3,941 3,840
----------- -----------
74,991 67,628
----------- -----------
Current Assets:
Cash.................................................... 105 185
Notes receivable from affiliated companies.............. 8,750 -
Receivables, less accumulated provision for
uncollectible accounts of $2,032,000 in 1994
and $1,997,000 in 1993................................ 35,427 36,437
Accounts receivable from affiliated companies........... 1,108 4,972
Accrued utility revenues................................ 15,766 17,362
Fuel, materials, and supplies, at average cost.......... 4,829 7,057
Prepayments and other................................... 9,215 9,613
----------- -----------
75,200 75,626
----------- -----------
Deferred Charges:
Regulatory assets (Note 1H)<F1H>........................ 184,226 210,647
Unamortized debt expense................................ 1,733 1,842
Other................................................... 974 1,162
----------- -----------
186,933 213,651
----------- -----------
Total Assets........................................ $1,183,618 $1,204,642
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
BALANCE SHEETS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------
At December 31, 1994 1993
------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock--$25 par value. Authorized and
outstanding 1,072,471 shares in 1994 and 1993........ $ 26,812 $ 26,812
Capital surplus, paid in................................ 149,683 149,319
Retained earnings....................................... 111,586 97,627
----------- -----------
Total common stockholder's equity.............. 288,081 273,758
Cumulative preferred stock--
$100 par value--authorized 1,000,000 shares;
outstanding 200,000 shares in 1994 and 1993;
$25 par value--authorized 3,600,000 shares;
outstanding 2,927,000 shares in 1994
3,220,000 shares in 1993
Not subject to mandatory redemption (Note 5)<F5>...... 68,500 73,500
Subject to mandatory redemption (Note 6)<F6>.......... 24,000 25,500
Long-term debt (Note 7)<F7>............................. 345,669 393,232
----------- -----------
Total capitalization........................... 726,250 765,990
----------- -----------
Obligations Under Capital Leases.......................... 23,852 24,014
----------- -----------
Current Liabilities:
Notes payable to banks.................................. - 6,000
Long-term debt and preferred stock--current
portion................................................ 34,975 1,500
Obligations under capital leases--current
portion................................................ 12,945 12,888
Accounts payable........................................ 20,396 17,493
Accounts payable to affiliated companies................ 17,352 12,016
Accrued taxes........................................... 5,160 7,022
Accrued interest........................................ 6,702 6,478
Refundable energy costs................................. - 8,676
Other................................................... 7,584 11,727
----------- -----------
105,114 83,800
----------- -----------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)<F1I>........ 253,821 253,547
Accumulated deferred investment tax credits............. 27,822 36,083
Deferred contract obligation--YAEC (Note 3)<F3>......... 28,572 24,150
Other................................................... 18,187 17,058
----------- -----------
328,402 330,838
----------- -----------
Commitments and Contingencies (Note 10)<F10>
Total Capitalization and Liabilities........... $1,183,618 $1,204,642
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
------------------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues.............................. $421,477 $415,055 $410,720
--------- --------- ---------
Operating Expenses:
Operation --
Fuel, purchased and net interchange power.. 67,365 67,781 86,356
Other...................................... 130,683 142,273 126,060
Maintenance................................... 35,430 34,259 39,303
Depreciation.................................. 36,885 35,751 34,257
Amortization of regulatory assets............. 29,118 29,700 26,321
Federal and state income taxes (Note 8)<F8>... 33,540 28,173 20,926
Taxes other than income taxes................. 18,403 17,051 16,984
--------- --------- ---------
Total operating expenses................ 351,424 354,988 350,207
--------- --------- ---------
Operating Income................................ 70,053 60,067 60,513
--------- --------- ---------
Other Income:
Deferred Millstone 3 return--other
funds (Note 1K)<F1K>........................ 761 1,439 2,119
Equity in earnings of regional nuclear
generating companies........................ 2,031 1,680 2,170
Other, net.................................... 2,926 2,966 2,628
Income taxes--credit.......................... 816 304 810
--------- --------- ---------
Other income, net....................... 6,534 6,389 7,727
--------- --------- ---------
Income before interest charges.......... 76,587 66,456 68,240
--------- --------- ---------
Interest Charges:
Interest on long-term debt.................... 27,678 29,979 31,694
Other interest................................ 21 881 469
Deferred Millstone 3 return--borrowed
funds (Note 1K)<F1K>........................ (569) (1,076) (945)
--------- --------- ---------
Interest charges, net................... 27,130 29,784 31,218
--------- --------- ---------
Income before cumulative effect of
accounting change............................. 49,457 36,672 37,022
Cumulative effect of accounting change
(Note 1B)<F1B>................................ - 3,922 -
--------- --------- ---------
Net Income...................................... $ 49,457 $ 40,594 $ 37,022
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1994 1993 1992
-------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net Income................................................ $ 49,457 $ 40,594 $ 37,022
Adjustments to reconcile to net cash
from operating activities:
Depreciation............................................ 36,885 35,751 34,257
Deferred income taxes and investment tax credits, net... 10,256 918 (785)
Deferred return - Millstone 3, net of amortization...... 13,427 12,252 9,110
Recoverable energy costs, net of amortization........... (8,622) 7,316 2,999
Other sources of cash................................... 25,967 26,765 26,591
Other uses of cash...................................... (23,701) (2,698) (1,654)
Changes in working capital:
Receivables and accrued utility revenues................ 6,470 (3,728) 12,288
Fuel, materials, and supplies........................... 2,228 1,944 490
Accounts payable........................................ 8,239 (2,078) (5,355)
Accrued taxes........................................... (1,862) (3,248) (295)
Other working capital (excludes cash)................... (2,991) 2,433 1,932
----------- ----------- -----------
Net cash flows from operating activities.................... 115,753 116,221 116,600
----------- ----------- -----------
Cash Flows From Financing Activities:
Issuance of long-term debt................................ 90,000 113,800 85,000
Net decrease in short-term debt........................... (6,000) (35,500) (3,250)
Reacquisitions and retirements of long-term debt.......... (104,169) (114,270) (94,167)
Reacquisitions and retirements of preferred stock......... (7,325) (1,500) (15,002)
Cash dividends on preferred stock......................... (5,897) (5,259) (7,485)
Cash dividends on common stock............................ (29,514) (28,785) (29,536)
----------- ----------- -----------
Net cash flows used for financing activities................ (62,905) (71,514) (64,440)
----------- ----------- -----------
Investment Activities:
Investment in plant:
Electric utility plant.................................. (32,680) (34,592) (46,061)
Nuclear fuel............................................ (4,928) (2,926) 1,003
----------- ----------- -----------
Net cash flows used for investments in plant.............. (37,608) (37,518) (45,058)
NU System Money Pool...................................... (8,750) - -
Other investment activities, net.......................... (6,570) (7,169) (7,101)
----------- ----------- -----------
Net cash flows used for investments......................... (52,928) (44,687) (52,159)
----------- ----------- -----------
Net (Decrease) Increase In Cash For The Period.............. (80) 20 1
Cash - beginning of period.................................. 185 165 164
----------- ----------- -----------
Cash - end of period........................................ $ 105 $ 185 $ 165
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized during construction.. $ 25,174 $ 27,277 $ 30,758
=========== =========== ===========
Income taxes.............................................. $ 30,040 $ 21,200 $ 17,711
=========== =========== ===========
Increase in obligations:
Niantic Bay Fuel Trust.................................... $ 12,237 $ 9,369 $ 7,224
=========== =========== ===========
</TABLE>
TThe accompanying notes are an integral part of these financial statements.
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, 1992............... $26,812 $148,696 $ 91,708 $267,216
Net income for 1992.................. 37,022 37,022
Cash dividends on preferred
stock.............................. (7,485) (7,485)
Cash dividends on common stock....... (29,536) (29,536)
Loss on the retirement of preferred
stock.............................. (632) (632)
Capital stock expenses, net.......... 330 330
-------- --------- --------- ---------
Balance at December 31, 1992............. 26,812 149,026 91,077 266,915
Net income for 1993.................. 40,594 40,594
Cash dividends on preferred
stock.............................. (5,259) (5,259)
Cash dividends on common stock....... (28,785) (28,785)
Capital stock expenses, net.......... 293 293
-------- --------- --------- ---------
Balance at December 31, 1993............. 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 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
======== ========= ========= =========
</TABLE>
(a) The company has dividend restrictions imposed by its long-term debt
agreements. At December 31, 1994, these restrictions totaled
approximately $21.5 million.
The accompanying notes are an integral part of these financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A> A. GENERAL
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).
Other wholly owned subsidiaries of NU provide substantial support
services to the system. Northeast Utilities Service Company (NUSCO)
supplies centralized accounting, administrative, data processing,
engineering, financial, legal, operational, planning, purchasing, and
other services to the system companies. Northeast Nuclear Energy
Company (NNECO) acts as agent for system companies in operating the
Millstone nuclear generating facilities.
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.
<F1B> B. CHANGE IN ACCOUNTING FOR PROPERTY TAXES
WMECO adopted a one-time change in the method of accounting for
municipal property tax expense for its Connecticut properties. Most
municipalities in Connecticut assess property values as of October 1.
Before January 1, 1993, WMECO accrued Connecticut property tax expense
over the period October 1 through September 30 based on the lien-date
method. In the first quarter of 1993, WMECO changed its method of
accounting for Connecticut municipal property taxes to recognize the
expense from July 1 through June 30, to match the payments and the
services provided by the municipalities. This one-time change
increased earnings for common shares by approximately $3.9 million.
<F1C> C. RECLASSIFICATIONS
Certain classifications of prior years' data have been made to conform
with the current year's presentation.
<F1D> D. 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:
Connecticut Yankee Atomic Power Company (CY) .... 9.5%
Yankee Atomic Electric Company (YAEC) ........... 7.0
Maine Yankee Atomic Power Company (MY) .......... 3.0
Vermont Yankee Nuclear Power Corporation (VY) ... 2.5
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. The electricity
produced by the facilities is committed to the participants
substantially on the basis of their 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 10E, "Commitments and
Contingencies - Purchased Power Arrangements."
The YAEC nuclear power plant was shut down permanently on February 26,
1992. For more information on the Yankee companies, see Note 3,
"Nuclear Decommissioning."
Millstone 1: WMECO has a 19 percent joint-ownership interest in
Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of
December 31, 1994 and 1993, plant-in-service included approximately
$87.0 million and $77.6 million, respectively, and the accumulated
provision for depreciation included approximately $31.4 million and
$30.5 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,
1994 and 1993, plant-in-service included approximately $159.2 million
and $158.1 million, respectively, and the accumulated provision for
depreciation included approximately $40.4 million and $34.8 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, an 1,154-MW nuclear generating unit. As of December 31,
1994 and 1993, plant-in-service included approximately $376.1 million
and $375.5 million, respectively, and the accumulated provision for
depreciation included approximately $83.2 million and $72.9 million,
respectively, for WMECO's proportionate share of Millstone 3. WMECO's
share of Millstone 3 expenses is included in the corresponding
operating expenses on the accompanying Statements Of Income.
<F1E> E. 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 factors 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. For
nuclear production plants, the costs of removal, less salvage, that
have been funded through external decommissioning trusts will be paid
with funds from the trusts and charged to the accumulated reserve for
decommissioning included in the accumulated provision for depreciation
over the expected service life of the plants. See Note 3, "Nuclear
Decommissioning," for additional information.
The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.1 percent in
1994 and 1993, and 3.0 percent in 1992.
<F1F> F. 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 inter-
connections, interchange of electric power, and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. The company is subject to further
regulation for rates, accounting, and other matters by the FERC and the
Massachusetts Department of Public Utilities (DPU).
<F1G> G. REVENUES
Other than 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. 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.
<F1H> H. REGULATORY ACCOUNTING
WMECO follows accounting policies that reflect the impact of the rate
treatment of certain events or transactions that differ from generally
accepted accounting principles for those events or transactions
followed by nonregulated enterprises. Under regulatory accounting,
assuming that future revenues are expected to be sufficient to provide
recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an
asset, or create a liability. If the economic entity no longer comes
under the jurisdiction of a regulator or external forces, such as a
move to a competitive environment, effectively limiting the influence
of cost-of-service based rate regulation, the entity may be forced to
abandon regulatory accounting, requiring a reexamination and potential
write-off of net regulatory assets. WMECO continues to be subject to
cost-of-service based rate regulation. Based on current regulation,
WMECO believes that its use of regulatory accounting is still
appropriate.
The components of regulatory assets are as follows:
At December 31, 1994 1993
--------------------------------------------------------------
(Thousands of Dollars)
Income taxes, net (Note 1I) .......... $ 86,357 $ 94,414
Unrecovered contract obligation -
YAEC (Note 3) ...................... 28,572 24,150
Amortizable property investment -
Milstone 3( Note 1K) ............... 16,800 28,001
Recoverable energy costs (Note 1J) ... 8,324 8,908
Deferred costs - Millstone 3 (Note 1K) 7,836 22,667
Other ................................ 36,337 32,507
-------- --------
$184,226 $210,647
======== ========
<F1I> 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 income
subject to tax) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 8,
"Income Tax Expense," for the components of income tax expense.
In 1992, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income
tax accounting standards. WMECO adopted SFAS 109, on a prospective
basis during the first quarter of 1993, and increased the net deferred
tax obligation by $249.3 million at that time. As it is probable that
the increase in deferred tax liabilities will be recovered from
customers through rates, WMECO also established a regulatory asset.
The tax effect of temporary differences which give rise to the
accumulated deferred tax obligation are as follows:
At December 31, 1994 1993
-------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences ........ $214,485 $205,030
Regulatory assets - income tax gross up 34,084 37,258
Other .............................. 5,252 11,259
-------- --------
$253,821 $253,547
======== ========
<F1J> J. RECOVERABLE ENERGY COSTS
In Massachusetts, all retail fuel costs are collected on a current
basis by means of a separate fuel-charge billing rate. As permitted by
the DPU, WMECO defers the difference between forecasted and actual fuel
cost recoveries until it is recovered or refunded quarterly under a
retail fuel adjustment clause. Massachusetts law requires the
establishment of an annual performance program related to fuel
procurement and use. The program establishes performance standards for
plants owned and operated by WMECO or plants in which WMECO has a life-
of-unit contract. Therefore, revenues collected under WMECO's retail
fuel adjustment clause are subject to refund pending review by the DPU.
To date, there have been no significant adjustments as a result of
this program.
Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed for
its proportionate shares 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 has begun to recover these costs. At December 31, 1994,
WMECO's D&D assessment was $8.3 million.
<F1K> K. MILLSTONE 3
As of December 31, 1991, all of WMECO's recoverable investment in
Millstone 3 was in rate base. Beginning in 1986, the DPU has permitted
WMECO to recover the portion of its Millstone 3 investment representing
the amount currently determined to be "unuseful" by the DPU ($16.8
million at December 31, 1994), over a ten-year period, without earning
a return. On June 30, 1987, WMECO also began recovering the deferred
return, including carrying charges, on the recoverable but not yet
phased-in portion of its investment in Millstone 3. This recovery is
taking place over a nine-year period. As of December 31, 1994, $77.6
million of the deferred return, including carrying charges, has been
recovered, and $7.8 million of the deferred return, including carrying
charges, remains to be recovered over the period ending June 30, 1995.
<F1L> L. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes interest-rate caps to manage well-defined
interest-rate risks. Premiums paid for purchased interest-rate cap
agreements are amortized to interest expense over the terms of the
caps. Unamortized premiums are included in deferred charges. Amounts
receivable under cap agreements are accrued as a reduction of interest
expense. Any material unrealized gains or losses on interest-rate caps
will be deferred until realized. For further information on
derivatives, see Note 11, "Derivative Financial Instruments."
<F1M> M. 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 may be
made anytime prior to the first delivery of spent fuel to the DOE,
which may be as early as 1998. Until such payment is made, the
outstanding balance will continue to accrue interest at the three-month
Treasury Bill Yield Rate. At December 31, 1994, fees due to the DOE
for the disposal of prior-period fuel were approximately $33.2 million,
including interest costs of $17.6 million. As of December 31, 1994,
all fees had been collected through rates.
<F2>2. LEASES
WMECO and CL&P have entered into the Niantic Bay Fuel Trust (NBFT) capital
lease agreement to finance up to $530 million of nuclear fuel for
Millstone 1 and 2 and their share's of the nuclear fuel for Millstone 3.
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, some of which are capital
leases, for the use of data processing and office equipment, vehicles,
nuclear control room simulators, and office space. The provisions of these
lease agreements generally provide for renewal options. The rental
payments that have been charged to operating expense are provided on the
next page:
Capital Operating
Year Leases Leases
---- ------------ ----------
1994 ........... $13,594,000 $6,485,000
1993 ........... 17,280,000 6,367,000
1992 ........... 13,799,000 7,263,000
Interest included in capital lease rental payments was $1,845,000 in 1994,
$2,090,000 in 1993, and $2,895,000 in 1992.
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.
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, 1994, are as follows:
Year Operating Leases
---- ----------------
(Thousands of Dollars)
1995 ..................... $ 4,800
1996 ..................... 4,400
1997 ..................... 4,100
1998 ..................... 3,200
1999 ..................... 3,000
After 1999 ............... 32,000
--------
Future minimum lease payments $51,500
=======
<F3>3. NUCLEAR DECOMMISSIONING
The company's 1992 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, technology, and inflation.
The estimated cost of decommissioning WMECO's ownership share of
Millstone 1, 2, and 3, in year-end 1994 dollars, is $78.1 million, $62.7
million, and $54.9 million, respectively. These estimated costs have been
levelized and assumed after-tax earnings on the Millstone decommissioning
fund of 6.5 percent. Future escalation rates in decommissioning costs for
the Millstone units are assumed. 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 $4.8 million in 1994, $4.6 million in 1993 and 1992.
Nuclear decommissioning, as a cost of removal, is included in the
accumulated provision for depreciation on the Balance Sheets. At December
31, 1994, the balance in the accumulated reserve for decommissioning
amounted to $56.1 million. See "Nuclear Decommissioning" in the
Management's Discussion and Analysis for a discussion of changes being
considered by the FASB relating to accounting for decommissioning costs.
WMECO has established independent decommissioning trusts for its portion of
the costs of decommissioning Millstone 1, 2, and 3. As of December 31,
1994, WMECO has collected, through rates, $42.4 million 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. Due to WMECO's adoption,
effective January 1, 1994, of SFAS 115, Accounting for Certain Investments
in Debt and Equity Securities, unrealized gains and losses associated with
the decommissioning trusts also impact the balance of the trusts and the
accumulated reserve for decommissioning.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement, would change decommissioning cost estimates. WMECO attempts
to recover sufficient amounts through its allowed rates to cover their
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. Because allowances for
decommissioning have increased significantly in recent years, customers in
future years may need to increase their payments to offset the effects of
any insufficient rate recoveries in previous years.
WMECO, along with other New England utilities, has equity investments in
the four Yankee companies. Each Yankee company owns a single nuclear
generating unit. WMECO's ownership share of estimated costs, in year-end
1994 dollars, of decommissioning CY, MY, and VY are $34.4 million, $10.1
million, and $8.2 million, respectively. Under the terms of the contracts
with the Yankee companies, the shareholders-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 by WMECO.
YAEC has begun component-removal activities related to decommissioning of
its nuclear facility. In June 1992, YAEC filed a rate filing to obtain
FERC authorization to collect the closing and decommissioning costs and to
recover the remaining investment in the YAEC nuclear power plant over the
remaining period of the plant's Nuclear Regulatory Commission (NRC)
operating license. The bulk of these costs has been agreed to by the YAEC
joint owners and approved, as a settlement, by FERC. In October 1994, YAEC
submitted a revised decommissioning cost estimate as part of its
decommissioning plan with the NRC. Following the receipt of NRC approval,
this estimate will be filed with the FERC. The revised estimate increased
WMECO's ownership share of decommissioning YAEC's nuclear facility by
approximately $6.6 million in January 1, 1994 dollars. At December 31,
1994, the estimated remaining costs including decommissioning amounted to
$408.2 million, of which WMECO's share was approximately $28.6 million.
Management expects that WMECO will continue to be allowed to recover such
FERC-approved costs from its customers. Accordingly, WMECO has recognized
these costs as a regulatory asset, with a corresponding obligation, on its
Balance Sheets.
<F4>4. SHORT-TERM DEBT
The system companies have various revolving credit lines totaling $485
million. NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company
(RRR) have established a revolving-credit facility with a group of
16 banks. Under this facility, the participating companies may borrow up
to an aggregate of $360 million. Individual borrowing limits as of January
1, 1995 were $150 million for NU, $325 million for CL&P, $60 million for
WMECO, $5 million for HWP, $50 million for NNECO, and $22 million for RRR.
The system companies may borrow funds on a short-term revolving basis
using either fixed-rate loans or standby loans. Fixed rates are set using
competitive bidding. Standby-loan rates are based upon several alternative
variable rates. The system companies are obligated to pay a facility fee
of 0.20 percent per annum of each bank's total commitment under the three-
year portion of the facility, representing 75 percent of the total
facility, plus 0.135 percent per annum of each bank's total commitment
under the 364-day portion of the facility, representing 25 percent of the
total facility. At December 31, 1994, there were $30.0 million of
borrowings under the facility, all of which had been borrowed by other
system companies.
The weighted average interest rate on notes payable to banks outstanding on
December 31, 1993 was 3.3 percent.
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.
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's parent's
original borrowing. Investing and borrowing subsidiaries receive or pay
interest based on the average daily Federal Funds rate. At December 31,
1994 and 1993, WMECO had no outstanding borrowings from the Pool.
Maturities of WMECO's short-term debt obligations are for periods of three
months or less.
The amount of short-term borrowings that may be incurred by the company is
subject to periodic approval by the SEC under the 1935 Act. In addition,
the charter of WMECO contains provisions restricting the amount of short-
term borrowings. Under the SEC and/or charter restrictions, the company
was authorized, as of January 1, 1995, to incur short-term borrowings up
to a maximum of $60 million.
<F5>5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock not subject to mandatory redemption are:
December 31, Shares
1994 Outstanding
RedemptionDecember 31, December 31,
-----------------------
Description Price 1994 1994 1993 1992
--------------------------------------------------------------------
(Thousands of Dollars)
7.72% Series B of 1971 $103.51 200,000 $20,000 $20,000 $20,000
1988 Adjustable
Rate DARTS 25.00 1,940,000 48,500 53,500 53,500
------- ------ ------
Total preferred stock not
subject to mandatory
redemption ........ $68,500 $73,500 $73,500
======= ======= =======
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.
<F6>6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
December 31, Shares December 31,
1994 Outstanding ------------------------
Redemption December 31,
Description Price* 1994 1994 1993 1992
--------------------------------------------------------------------
(Thousands of Dollars)
7.60% Series of 1987 $26.02 987,000 $24,675 $27,000 $28,500
Less preferred stock to be
redeemed within one year,
net of reacquired stock 27,000 675 1,500 1,500
------- ------- -------
Total preferred stock subject
to mandatory redemption $24,000 $25,500 $27,000
======= ======= =======
*Redemption price reduces in future years.
The minimum sinking-fund provisions of the 1987 Series subject to mandatory
redemption at December 31, 1994, for the years 1995 through 1999, are $1.5
million per year. 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.
<F7>7. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31, 1994 1993
----------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
9 1/4% Series U, .......due 1995 $ 34,300 $ 34,650
5 3/4% Series F, .......due 1997 14,850 15,000
7 3/8% Series H, .......due 1998 - 15,000
6 3/4% Series G, .......due 1998 9,900 10,000
6 1/4% Series X, .......due 1999 40,000 -
6 7/8% Series W, .......due 2000 60,000 60,000
7 3/4% Series J, .......due 2002 - 30,000
7 3/4% Series V, .......due 2002 85,000 85,000
7 3/4% Series Y, .......due 2024 50,000 -
9 3/4% Series R, .......due 2016 - 24,750
10 1/8% Series T, .......due 2018 - 33,819
--------- --------
Total First Mortgage Bonds .... 294,050 308,219
Pollution Control Notes:
Tax Exempt Series A, due 2028 53,800 53,800
Fees and interest due for spent fuel
disposal costs (Note 1M) ........... 33,239 31,930
Less: Amounts due within one year ... 34,300 -
Unamortized premium and discount, net (1,120 (717)
------- --------
Long-term debt, net .................. $345,669 $393,232
======== ========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1994 for the years 1995 through 1999 are
approximately: $34,300,000 in 1995, $0 in 1996, $14,850,000 in 1997,
$9,900,000 in 1998, and $40,000,000 in 1999. In addition, there are annual
1-percent sinking- and improvement-fund requirements, currently amounting
to $2,950,000 in 1995, $2,600,000 in 1996 and 1997, $2,450,000 in 1998, and
$2,350,000 in 1999. Such sinking- and improvement-fund requirements may be
satisfied by the deposit of cash or bonds or by certification of property
additions.
All or any part of each outstanding series of first mortgage bonds may be
redeemed by the company at any time at established redemption prices plus
accrued interest to the date of redemption, except certain series which are
subject to certain refunding limitations during their respective initial
five-year redemption periods.
Essentially all of the company's utility plant is subject to the liens of
its first mortgage bond indenture. As of December 31, 1994 and 1993 , 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 indentures. The average effective interest rates on the variable-rate
pollution control notes was 2.7 percent for 1994 and 2.5 percent for 1993.
<F8>8. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
----------------------------------------------------------------
(Thousands of Dollars)
Current income taxes:
Federal ..................... $18,358 $22,239 $16,736
State ....................... 4,110 4,712 4,165
-------- -------- ---------
Total current ............. 22,468 26,951 20,901
-------- -------- --------
Deferred income taxes, net:
Federal ..................... 9,697 1,683 (1,466)
State ....................... 2,267 664 117
------- -------- --------
Total deferred ............ 11,964 2,347 (1,349)
------- -------- --------
Investment tax credits, net (1,708) (1,429) (1,251)
------ ------- -------
Total income tax expense ...... $32,724 $27,869 $18,301
======= ======= =======
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses ...................... $33,540 $28,173 $20,926
Income taxes associated with the
amortization of deferred Millstone 3
return - borrowed funds ....... - - (2,410)
Income taxes associated with
allowance for funds used during
construction (AFUDC) and deferred
Millstone 3 return - borrowed funds - - 595
Other income taxes - credit .... (816) (304) (810)
------- ------- -------
Total income tax expense ......... $32,724 $27,869 $18,301
======= ======= =======
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
For the Years Ended December 31, 1994 1993 (Note 1I)1992
----------------------------------------------------------------
(Thousands of Dollars)
Depreciation, leased nuclear fuel,
settlement credits,and disposal
costs ...................... $ 7,016 $6,852 $ 4,070
Energy adjustment clause ...... 3,598 (2,627) (4,663)
AFUDC and deferred Millstone 3
return, net................. (2,203) (2,191) (1,815)
Deferred refueling cost ....... 401 413 666
Early retirement program ...... 133 (544) (775)
Loss on bond redemption ....... 2,064 1,561 18
Demand-side management ........ 466 (712) 394
Other ......................... 489 (405) (794)
------- ------ -------
Deferred income taxes, net .... $11,964 $2,347 $(1,349)
======= ====== =======
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rates is as follows:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992
-------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at 35 percent
of pretax income for 1994 and 1993
and 34 percent for 1992 .. $28,763 $23,962 $18,810
Tax effect of differences:
Depreciation differences .... 1,740 1,784 (1,584)
Deferred Millstone 3 return -
other funds ................ (266) (504) (721)
Amortization of deferred Millstone 3
return - other funds ....... 3,347 3,341 2,856
Investment tax credit amortization (1,708) (1,429) (1,251)
State income taxes, net of
federal benefit ........... 4,144 3,494 2,829
Adjustment for prior years taxes (825) - (1,500)
Other, net .................. (2,471) (2,779) (1,138)
------- ------- -------
Total income tax expense ...... $32,724 $27,869 $18,301
======= ======= =======
9. EMPLOYMENT BENEFITS
<F9A> 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 employees' highest eligible compensation
during five consecutive years of employment. The company's direct
portion of the system's pension (income) cost, part of which was
charged to utility plant, approximated $(1.0) million in 1994, $1.2
million in 1993, and $(0.5) million in 1992. The company's pension
costs for 1994 and 1993 included approximately $0.8 million and $2.7
million, respectively, related to a work force reduction program.
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:
For the Years Ended December 31, 1994 1993 1992
----------------------------------------------------------------
(Thousands of Dollars)
Service cost .............. $ 2,720 $4,702 $2,403
Interest cost ............. 7,655 7,527 7,875
Return on plan assets ..... 221 (17,272) (8,820)
Net amortization .......... (11,635) 6,246 (1,962)
------- ------- ------
Net pension (income)/cost . $(1,039) $1,203 $ (504)
======= ====== ======
-------------------------------------------------------------
For calculating pension cost, the following assumptions were used:
For the Years Ended December 31, 1994 1993 1992
--------------------------------------------------------------
Discount rate ............. 7.75% 8.00% 8.50%
Expected long-term rate
of return ................ 8.50 8.50 9.00
Compensation/progression rate 4.75 5.00 6.75
The following table represents the Plan's funded status reconciled to
the Balance Sheets:
At December 31, 1994 1993
--------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $89,159,000 of vested
benefits at December 31, 1994 and
$82,601,000 of vested benefits at
December 31, 1993 ............ $ 85,193 $ 88,554
========= =========
Projected benefit obligation .. $ 99,667 $104,288
Market value of plan assets ... 122,813 130,803
-------- --------
Market value in excess of projected
benefit obligation ........... 23,146 26,515
Unrecognized transition amount (2,433) (2,668)
Unrecognized prior service costs (560) (581)
Unrecognized net gain ......... (22,068) (26,220)
---------- ----------
Accrued pension liability ..... $ (1,915) $ (2,954)
========== ==========
------------------------------------------------------------
The following actuarial assumptions were used in calculating the Plan's
year-end funded status:
At December 31, 1994 1993
-------------------------------------------------------------
Discount rate ................. 8.25% 7.75%
Compensation/progression rate . 5.00 4.75
-------------------------------------------------------------
<F9B> 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. These benefits are available for employees leaving
the company who are otherwise eligible to retire and have met specified
service requirements. Effective January 1, 1993, the company adopted
SFAS 106, Employer's Accounting for Postretirement Benefits Other Than
Pensions, on a prospective basis. WMECO's direct portion of health
care and life insurance costs, part of which were deferred or charged
to utility plant, approximated $5.0 million in 1994 and 1993, and $2.2
million in 1992.
On January 1, 1993, the accumulated postretirement benefit obligation
represented the company's transition obligation upon the adoption of
SFAS 106. As allowed by SFAS 106, the company is amortizing its
transition obligation of approximately $33 million over a 20-year
period. 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.
Effective July 1994, the company funded SFAS 106 postretirement costs
through external trusts. The company will fund annually amounts once
they 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. During 1993, the company did not fund
SFAS 106 costs.
The following table represents the plan's funded status reconciled to
the Balance Sheets:
At December 31, 1994 1993
--------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement
benefit obligation of:
Retirees $29,619 $27,685
Fully eligible active employees .. 28 38
Active employees not eligible to retire 4,823 5,488
--------- ---------
Total accumulated postretirement
benefit obligation ............... 34,470 33,211
Market value of plan assets ........ 2,026 -
--------- ---------
Accumulated postretirement benefit
obligation in excess of plan assets (32,444) (33,211)
Unrecognized transition amount ..... 29,542 31,183
Unrecognized net gain .............. (477) (587)
--------- ---------
Accrued postretirement benefit liability $ (3,379) $ (2,615)
======== ========
-------------------------------------------------------------
The components of health care and life insurance costs are:
For the Years Ended December 31, 1994 1993
--------------------------------------------------------------
(Thousands of Dollars)
Service cost ....................... $ 519 $ 659
Interest cost ...................... 2,703 2,676
Return on plan assets .............. 19 -
Net amortization ................... 1,717 1,703
------- -------
Net health care and life insurance costs $4,958 $5,038
====== ======
-------------------------------------------------------------
The following actuarial assumptions were used in calculating the plan's
year-end funded status:
At December 31, 1994 1993
------------------------------------------------------------
Discount rate ...................... 8.00% 7.75%
Long-term rate of return - health assets,
net of tax ....................... 5.00 5.00
Long-term rate of return - life assets 8.50 8.50
Health care cost trend rate (a) .... 10.20 11.10
(a) The annual growth in per capita cost of covered health care
benefits was assumed to decrease to 5.4 percent by 2002.
The effect of increasing the assumed health care cost trend rates by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1994 by $2.1
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$185,000. The trust holding the plan assets is subject to federal
income taxes at a 35-percent tax rate.
WMECO is currently recovering SFAS 106 costs, including previously
deferred costs. Deferral of such costs is permitted since it is
expected that the period of recovery of deferred costs will be within
the time frame established by the applicable accounting requirements.
10. COMMITMENTS AND CONTINGENCIES
<F10A>A.CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision.
Actual construction expenditures may vary from estimates due to factors
such as revised load estimates, inflation, revised nuclear safety
regulations, delays, difficulties in the licensing process, the
availability and cost of capital, and the granting of timely and
adequate rate relief by regulatory commissions, as well as actions by
other regulatory bodies.
The company currently forecasts construction expenditures (including
AFUDC) of $170.4 million for the years 1995-1999, including $36.3
million for 1995. In addition, the company estimates that nuclear fuel
requirements, including nuclear fuel financed through the NBFT, will be
$58.9 million for the years 1995-1999, including $10.7 million for
1995. See Note 2, "Leases" for additional information about the
financing of nuclear fuel.
<F10B>B.NUCLEAR PERFORMANCE
In October 1994, Millstone 2 began a planned refueling and maintenance
outage that was originally scheduled for 63 days. The outage has
encountered several unexpected difficulties which have lengthened the
duration of the outage. The magnitude of the schedule impact is
currently under review, but the unit is not expected to return to
service before April 1995. WMECO expects that replacement power costs
in the range of $1 million per month will be attributable to the
extension of the outage. Recovery of the costs related to this outage
is subject to scrutiny by the DPU.
<F10C>C.ENVIRONMENTAL MATTERS
WMECO is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the 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.
Changing environmental requirements could hinder the construction of
new generating units, transmission and distribution lines, substations,
and other facilities. The cumulative long-term, economic cost impact
of increasingly stringent environmental requirements cannot accurately
be estimated. Changing 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.
WMECO has recorded a liability for what it believes is, based upon
information currently available, its estimated environmental
remediation costs for waste disposal sites for which it expects to bear
legal liability. In most cases, the extent of additional future
environmental cleanup costs is 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, 1994, the liability recorded by WMECO for its
estimated environmental remediation costs, excluding any possible
insurance recoveries or recoveries from third parties, amounted to
approximately $700,000. However, in the event that it becomes
necessary to effect environmental remedies that are currently not
considered probable, it is reasonably possible that the upper limit of
the system's environmental liability range could increase to
approximately $2.3 million.
WMECO cannot estimate the potential liability for future claims 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.
<F10D>D.NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first $200
million of liability would be provided by purchasing the maximum amount
of commercially available insurance. Additional coverage of up to a
total of $8.3 billion would be provided by an assessment of $75.5
million per incident, levied on each of the 110 nuclear units that are
currently subject to the Secondary Financial Protection Program in the
United States, subject to a maximum assessment of $10 million per
incident per nuclear unit in any year. In addition, if the sum of all
public liability claims and legal costs arising from any nuclear
incident exceeds the maximum amount of financial protection, each
reactor operator can be assessed an additional 5 percent, up to
$3.8 million, or $415.3 million in total, for all 110 nuclear units.
The maximum assessment is to be adjusted at least every five years to
reflect inflationary changes. Based on WMECO's ownership interests in
Millstone 1, 2, and 3, WMECO's maximum liability would be $39.8 million
per incident. In addition, through WMECO's power purchase contracts
with the three operating Yankee regional nuclear generating companies,
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.
Effective January 1, 1995, insurance was purchased from Nuclear Mutual
Limited (NML) to cover the primary cost of repair, replacement, or
decontamination of utility property resulting from insured occurrences
with respect to WMECO's ownership interest in Millstone 1, 2, 3, and
CY. All companies insured with NML are subject to retroactive
assessments if losses exceed the accumulated funds available to NML.
The maximum potential assessment against WMECO with respect to losses
arising during the current policy year is approximately $3.1 million
under the NML primary property insurance program.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL) to cover: (1) certain extra costs incurred in obtaining
replacement power during prolonged accidental outages with respect to
WMECO's ownership interests in Millstone 1, 2, and 3, and CY, and (2)
the excess cost of repair, replacement, or decontamination or premature
decommissioning of utility property resulting from insured occurrences
with respect to WMECO's ownership interests in Millstone 1, 2, and 3,
CY, MY, and VY. All companies insured with NEIL are subject to
retroactive assessments if losses exceed the accumulated funds
available to NEIL. The maximum potential assessments against WMECO
with respect to losses arising during current policy years are
approximately $1.7 million under the replacement power policies and
$7.7 million under the excess property damage, decontamination, and
decommissioning policies. Although WMECO has purchased the limits of
coverage currently available from the conventional nuclear insurance
pools, the cost of a nuclear incident could exceed available insurance
proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual
Atomic Energy Liability Underwriters, 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 $3.1 million per reactor. The maximum
potential assessments against WMECO with respect to losses arising
during the current policy period are approximately $2.2 million.
<F10E>E.PURCHASED POWER ARRANGEMENTS
WMECO, along with CL&P and PSNH, purchase approximately ten percent of
their electricity requirements pursuant to long-term contracts with the
Yankee companies. Under the terms of its agreement, the company pays
its ownership share (or entitlement share) of generating costs, which
include depreciation, operation and maintenance expenses, taxes, the
estimated cost of decommissioning, and a return on invested capital.
These costs are recorded as purchased power expense, and are recovered
through the company's rates. WMECO's total cost of purchases under
these contracts for the units that are operating amounted to $28.8
million in 1994, $30.2 million in 1993, and $29.2 million in 1992. See
Note 1D, "Summary Of Significant Accounting Policies - Investments and
Jointly Owned Electric Utility Plant" and Note 3, "Nuclear
Decommissioning" for more information on the Yankee companies.
WMECO has entered into two arrangements for the purchase of capacity
and energy from nonutility generators. These arrangements have terms
of 15 and 25 years, and require the company to purchase the energy at
specified prices or formula rates. For the 12 months ended
December 31, 1994, approximately 14 percent of system electricity
requirements was met by nonutility generators. The total cost of the
company's purchases under these arrangements amounted to $27.5 million
in 1994, $13.6 million in 1993, and $4.8 million in 1992. These costs
are recovered through the company's rates.
The estimated annual costs of the significant purchase power
arrangements are as follows:
1995 1996 1997 1998 1999
-------------------------------------------------------------
(Millions of Dollars)
Yankee companies ...... $31.0 $32.6 $29.2 $34.0 $32.3
Nonutility generators . 29.7 30.9 32.5 34.1 35.8
-------------------------------------------------------------
<F10F>F.HYDRO-QUEBEC
Along with other New England utilities, WMECO, CL&P, PSNH, and HWP
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, its proportionate share of the
annual operation, maintenance, and capital costs of these facilities.
WMECO's share of Hydro-Quebec costs are currently forecast to be $19.9
million for the years 1995-1999, including $4.4 million for 1995.
<F11>11. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes derivative financial instruments to manage well-
defined interest-rate risks. The company does not use them for trading
purposes.
WMECO has entered into an interest-rate cap contract with a financial
institution in order to reduce a portion of the interest-rate risk
associated with its variable-rate tax-exempt pollution control revenue
bonds. During 1994, there was one outstanding contract held by WMECO,
covering $52 million of its pollution control bond, with a term of three
years. The contract entitles WMECO to receive from its counterparty the
amount, if any by which the interest payments on its variable-rate tax-
exempt pollution control revenue bond exceeds the J. J. Kenny High Grade
Index. This contract is settled on a quarterly basis. As of December 31,
1994, WMECO had a total notional amount of $52 million in caps outstanding,
with a positive mark-to-market position of approximately $0.6 million.
WMECO is exposed to credit risk on the interest-rate caps if the
counterparty fails to perform its obligation. However, WMECO anticipates
that the counterparty will be able to fully satisfy its obligations under
the contract.
<F12>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 amount approximates
fair value.
SFAS 115 requires investments in debt and equity securities to be presented
at fair value and was adopted by the company on a prospective basis as of
January 1, 1994. As a result of the adoption of SFAS 115, the investments
held in the company's nuclear decommissioning trusts decreased by
approximately $800,000 as of December 31, 1994, with a corresponding offset
to the accumulated provision for depreciation. The $800,000 decrease
represents cumulative gross unrealized holding gains of $300,000, offset by
cumulative gross unrealized holding losses of $1.1 million. There was no
change in funding requirements of the trusts nor any impact on earnings as
a result of the adoption of SFAS 115.
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. WMECO's adjustable rate preferred stock is assumed to have
a fair value equal to its carrying value.
The carrying amount of WMECO's financial instruments and the estimated fair
values are as follows:
----------------------------------------------------------------
Carrying Fair
At December 31, 1994 Amount Value
----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption ......... $ 68,500 $ 66,050
Preferred stock subject to
mandatory redemption ......... 24,675 24,675
Long-term debt -
First Mortgage Bonds ....... 294,050 274,469
Other long-term debt ....... 87,039 87,039
-----------------------------------------------------------------
Carrying Fair
At December 31, 1993 Amount Value
-----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock not subject to
mandatory redemption ......... $ 73,500 $ 74,000
Preferred stock subject to
mandatory redemption ......... 27,000 28,215
Long-term debt -
First Mortgage Bonds ....... 308,219 319,213
Other long-term debt ....... 85,730 85,730
-----------------------------------------------------------------
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.
WESTERN MASSACHUSETTS ELECTRIC COMPANY
------------------------------------------------------------
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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Notes 1B and 9B to the Financial Statements, effective
January 1, 1993, Western Massachusetts Electric Company changed its methods of
accounting for property taxes, and postretirement benefits other than pensions.
/s/Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
WESTERN MASSACHUSETTS ELECTRIC COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
---------------------------------------------------------------------
This section contains management's assessment of WMECO's (the company)
financial condition and the principal factors having an impact on the results of
operations. The company is a wholly owned subsidiary of Northeast Utilities
(NU). This discussion should be read in conjunction with the company's
financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
Net income increased to approximately $49 million in 1994 from approximately $41
million in 1993. The 1994 increase in net income is due primarily to reduced
operation and interest costs. The 1993 net income includes the impact of a
change in the method of accounting for Connecticut municipal property taxes
which resulted in an increase to net income of approximately $4 million. In
addition, 1993 net income reflected a decrease of approximately $2 million for
the costs of an employee reduction program. Net income before these one-time
items was approximately $39 million in 1993.
In 1994, the company experienced modest retail kilowatt-hour sales growth, due
in large part to the beginning of an economic recovery in New England.
Employment levels have risen, unemployment rates have fallen, and personal
income has increased. The company's 1994 retail kilowatt-hour sales rose by 1.4
percent over 1993. Overall, weather had little effect on sales volume, with
mild weather after mid-August offsetting unusually cold weather in January and
hot weather in late June and July.
In 1995, the company expects little retail sales growth over 1994, primarily
because of the effects of higher interest rates on the regional economy. The
company estimates compounded annual sales growth of 0.9 percent from 1994
through 1999.
Competitive forces within the electric utility industry are continuing to
increase due to a variety of influences, including legislative and regulatory
actions, technological advances, and changes in consumer demand. The company
has developed, and is continuing to develop, a number of initiatives to retain
and continue to serve its existing customers and to expand its retail and
wholesale customer base.
The company believes the steps it is taking, including a companywide process
reengineering effort, will have significant, positive effects, including reduced
operating costs and improved customer service, in the next few years. The
company also benefits from a diverse retail base with no significant dependence
on any one retail customer or industry.
WMECO continues to operate predominantly in a state-approved franchise under
traditional cost-of-service regulation. Retail wheeling, under which a retail
customer would be permitted to select an electricity supplier and require the
local electric utility to transmit the power to the customer's site, is not
required in Massachusetts. However, bills related to retail wheeling have been
introduced in the legislature. Massachusetts regulators have been studying the
potential restructuring of the electric utility industry. To date, none of these
bills have been enacted and the regulatory proceeding has not progressed to the
point where management can assess the impact of any potential outcomes on the
company.
While retail competition is not required in the company's retail service
territory, competitive forces are nonetheless influencing retail pricing. These
forces include competition from alternate fuels such as natural gas, competition
from customer-owned generation and regional competition for business retention
and expansion. The company's retail business group continues to work with
customers to address their concerns. The company has reached long-term rate
agreements with many new and existing customers to gain or retain their
business. In general, these rate agreements have terms of about five years.
Negotiated retail rate reductions for customers under rate agreements in effect
for 1994 amounted to approximately $4 million. Management believes that the
aggregate amount of retail rate reductions will increase in 1995 but that the
related agreements will continue to provide significant benefits to the company,
including the preservation of approximately 7 percent of retail revenues.
The company is also working with its regulators to address the needs of
customers more widely. The company has a 20-month rate plan in effect through
February 1996. Management will continue to evaluate the use of agreements of
this type to keep retail rates competitive.
The company acts as both a buyer and a seller of electricity in the highly
competitive wholesale electricity market in the Northeastern United States
(Northeast). Many of the contracts signed in the late 1980s have or will expire
in the mid-1990s and much of revenues produced by such contracts has not been
replaced through new wholesale power arrangements. In the last few years NU has
entered into several smaller long-term sales contracts which will continue
approximately through the year 2005. Wholesale sales are made primarily to
investor-owned utilities throughout the Northeast. The company will be increas-
ing its efforts to increase wholesale sales through intensified marketing
efforts. The company's wholesale power marketing efforts benefit from the
interconnection of the NU system's transmission system with all the major
utilities in New England.
RATE MATTERS
The company follows accounting principles that allow the rate treatment for
certain events or transactions to be reflected. These principles may differ
from the accounting principles followed by nonregulated enterprises. Regulators
may permit incurred costs, which would normally be treated as expenses by
nonregulated enterprises, to be deferred as regulatory assets and recovered in
revenues at a later date. Regulatory assets at December 31,1994 were
approximately $184 million. Based on current regulation,the company believes
that its use of regulatory accounting is still appropriate.
See "Notes to Consolidated Financial Statements," Note 1H, for further details
on regulatory accounting.
On May 26, 1994, the Massachusetts Department of Public Utilities (DPU) approved
a settlement agreement under which WMECO's customers received a base-rate
reduction of approximately $13 million over a 20-month period effective June 1,
1994 and a guarantee of no general base-rate increases before February 1996.
This agreement also terminated, without findings, all performance review
proceedings regarding the treatment of replacement-power costs incurred by WMECO
during power outages from mid-1987 through mid-1993. The DPU also approved the
amortization of previously deferred expenses for postretirement benefits
beginning in July 1994. In addition, under the agreement, WMECO's largest
customers will be offered discounts on their electric bills in return for
providing WMECO with five years' notice of any plans to self-generate or
purchase electricity from a different provider. The combined base-rate
reduction and service-extension discounts will total approximately 5 percent for
those larger customers. The settlement agreement did not have a significant
adverse impact on WMECO's earnings.
NUCLEAR PERFORMANCE
The composite capacity factor of the five nuclear generating units that the NU
system operates (including the Connecticut Yankee [CY] unit) was 67.5 percent
for 1994, compared with 80.8 percent for 1993 and a 1994 national average of
73.2 percent. The lower 1994 capacity factor was primarily the result of
extended refueling and maintenance outages for Millstone 1, Millstone 2, and
Seabrook. CY, Seabrook, and Millstone 2 were also out of service for varying
lengths of time in 1994 because of unexpected technical and operating
difficulties. These difficulties included a manual shutdown of CY when both
service water headers were declared inoperable and an automatic trip from 100
percent power for Seabrook when a main steam isolation valve closed during
quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded
lower seal on a reactor coolant pump.
On October 1, 1994, Millstone 2 was shut down for a planned 63 day refueling
and maintenance outage. The outage has encountered several unexpected
difficulties, which will lengthen the duration of the outage. The outage
extensions were caused by a significant scope increase in service water system
repairs as identified through a comprehensive inspection plan and by a need for
management to exercise a deliberate approach to the conduct of work during the
early portions of the outage. The outage schedule is currently under review,
but the unit is not expected to return to service before April 1995.
Replacement power costs attributable to the extension of the outage for WMECO
are expected to be in the range of approximately $1 million per month. These
costs are recovered through WMECO's fuel adjustment clause. In addition,
WMECO'S share of the operation and maintenance costs to be incurred during the
outage are estimated to be $10 million, an increase of approximately $4 million
as a result of the extension. The recovery of these costs is subject to
prudence reviews in Massachusetts.
The Nuclear Regulatory Commission (NRC's) latest report for the Millstone
Station noted significant weaknesses of Millstone's 2 operations and
maintenance. In a public statement in late 1994, a senior NRC official
expressed disappointment with the continued weaknesses in Millstone 2's
performance. The primary cause of the NRC's disappointment with Millstone 2's
performance appears to be that, despite significant management attention and
action over a period of years, the NRC does not believe it has seen enough
objective evidence of improvement in reducing procedural noncompliance and other
human errors. Management has acknowledged the basis for the NRC's concern with
Millstone 2 and has been devoting increased attention to resolving these issues.
Management and the NRC expect to continue to monitor closely the developments
at Millstone 2.
ENVIRONMENTAL MATTERS
NU devotes substantial resources to identify and then to meet the multitude of
environmental requirements it faces. NU has active auditing programs addressing
a variety of different regulatory requirements, including an environmental
auditing program to detect and remedy noncompliance with environmental laws or
regulations.
The company is potentially liable for environmental cleanup costs at a number of
sites both inside and outside its service territories. To date, the future
estimated environmental remediation liabilities has not been material with
respect to the earnings or financial position of the company. At December 31,
1994, the liability recorded by the company, amounted to approximately $1
million. These costs could rise to as much as approximately $2 million if
alternate remediation remedies become necessary.
The company expects that the implementation of the 1990 Clean Air Act Amendments
(CAAA) as they relate to sulfur dioxide emissions will require only modest
emission reductions for the company. WMECO's exposure is minimal because of the
companies' investment in nuclear energy in the 1970s and 1980s and the burning
of low-sulfur fuels. The CAAA requirements for emissions limits for nitrogen
oxides will initially be met by capital expenditures of approximately $1
million.
NUCLEAR DECOMMISSIONING
The company's estimated cost to decommission its shares of Millstone units 1, 2,
and 3 is approximately $196 million in year-end 1994 dollars. In addition, the
company's estimated cost to decommission its shares of the regional nuclear
generating units is approximately $53 million. These costs are being recognized
over the lives of the respective units and a portion of the costs is being
recovered through rates. Yankee Atomic Electric Company (YAEC) has begun compo-
nent removal activities related to the decommissioning of its nuclear facility.
The company's estimated obligation to YAEC has been recorded on its Balance
Sheets. Management expects that the company will continue to be allowed to
recover these costs.
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
this company, regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. The Financial Accounting Standards Board is
currently reviewing the accounting for removal costs, including decommissioning
and similar costs. If current electric utility industry accounting practices
for such decommissioning costs are changed: (1) annual provisions for decom-
missioning could increase, (2) the estimated costs for decommissioning could be
recorded as a liability rather than as accumulated depreciation, and (3) trust
fund income from the external decommissioning trust could be reported as
investment income rather than as a reduction to decommissioning expense.
See the "Notes To Financial Statements," Note 3, for further information on
nuclear decommissioning.
PROPERTY TAXES
CY has a significant court appeal for municipal property tax assessments in the
town of Haddam, Connecticut. The central issue in this case is the fair market
value of utility property. CY believes that the assessments should be based on
a fair market value that approximates net book cost. This is the assessment
level that taxing authorities are predominantly using throughout Connecticut,
Massachusetts, and some of New Hampshire. However, towns such as Haddam
advocate a method that approximates reproduction costs.
CY's appeal is still pending. The company estimates that, for assessments in
towns such as Haddam, the change to the reproduction cost methodology could
result in property valuations approximately three times greater than values
approximating net book cost. If other towns in Connecticut or Massachusetts
adopt this methodology, there could be a significant adverse impact on the
company's future results of operations and financial condition. However, the
extent to which other towns successfully adopt this methodology and any
subsequent increase in the company's property tax liability cannot be determined
at this time.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations in 1994 was relatively flat as compared with 1993.
Cash used for financing activities was approximately $9 million lower in 1994,
as compared with 1993, primarily due to lower repayment of short-term debt,
partially offset by higher net reacquisitions and retirements of long-term debt.
Cash used for investments was approximately $8 million higher in 1994, compared
with 1993, primarily due to an increase in loans to other system companies under
the NU system money pool.
In 1994, the company refinanced approximately $90 million of debt, which is
expected to reduce interest costs by approximately $2 million annually. With
interest rates rising in mid-1994, a lot of refinancing completed, and
construction needs remaining modest, the focus of the company's financing
activities will shift toward using the significant amount of cash generated by
the company to retire debt and to prepare the company for an increasingly
competitive business.
The company is obligated to meet approximately $107 million of long-term debt
and preferred stock maturities and cash sinking-fund requirements during the
1995 through 1999 period, including approximately $36 million for 1995. The
company's construction program expenditures, including allowance for funds used
during construction (AFUDC), for the period 1995 through 1999 are estimated to
be approximately $170 million, including approximately $36 million for 1995.
The construction program's main focus is maintaining and upgrading the existing
transmission and distribution system, as well as nuclear and fossil-generating
facilities. NU does not foresee the need for new major generating facilities,
at least until the year 2009. Construction expenditures and debt sinking fund
requirements will continue to be met through internal cash generation.
WMECO entered into interest rate cap contracts to reduce a portion of interest
rate risk on certain variable-rate tax-exempt pollution control revenue bonds.
Any premiums paid on these contracts are deferred and amortized over the life of
the contracts. The differential paid or received as interest rates is
recognized in income when realized.
RESULTS OF OPERATIONS
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table below.
CHANGE IN OPERATING REVENUES
Increase/(Decrease)
1994 vs. 1993 1993 vs. 1992
--------------------------------------------------------------------
(Millions of Dollars)
Regulatory decisions $(4) $12
Fuel and purchased power
cost recoveries 13 (19)
Sales volume - 4
Wholesale Revenues - 8
Other revenues (3) (1)
-- ---
Total revenue change $ 6 $ 4
=== ===
Operating revenues increased approximately $6 million in 1994 as compared with
1993. Revenues related to regulatory decision decreased in 1994, primarily
because of the June 1994 retail rate reduction and lower recoveries for demand-
side-management costs, partially offset by the July 1993 retail rate increase.
Fuel and purchased power cost recoveries increased primarily due to higher
energy interchange revenues in 1994.
Operating revenues increased approximately $4 million in 1993 as compared with
1992. Revenues related to regulatory decisions increased primarily because of
the effects of the July 1992 and July 1993 retail rate increases. Fuel and
purchased power cost recoveries decreased primarily due to lower energy costs.
Retail sales in 1993 were relatively flat. Wholesale revenues increased
primarily because of higher capacity interchange revenues.
FUEL, PURCHASED, AND NET INTERCHANGE POWER
Fuel, purchased, and net interchange power decreased approximately $19 million
in 1993, as compared to 1992, primarily due to lower outside purchases as a
result of better nuclear performance in 1993.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses decreased approximately $10 million in
1994, as compared with 1993, primarily due to higher costs in 1993 associated
with early retirement programs, lower 1994 payroll and benefit costs, lower
fossil-unit costs and lower capacity charges from the regional nuclear
generating units, partially offset by higher 1994 costs associated with the
operation and maintenance activities of the nuclear units, higher reserves for
excess/obsolete inventory at the nuclear and fossil units in 1994 and higher
outside services primarily related to companywide process reengineering.
Other operation and maintenance expenses increased approximately $11 million in
1993, as compared to 1992, primarily due to higher capacity interchange charges,
increased demand-side-management costs, and the 1993 one-time costs associated
with an employee-reduction program, partially offset by lower 1993 costs
associated with the operation and maintenance activities of the nuclear units.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased approximately $3 million in
1993, as compared to 1992, primarily because of higher amortization of Millstone
3 deferred costs.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased approximately $5 million in 1994, as
compared to 1993 due primarily to higher taxable income.
Federal and state income taxes increased approximately $8 million in 1993, as
compared to 1992, primarily because of higher taxable income and one-time
adjustments in 1992 causing 1992 taxes to be lower than would otherwise be
expected.
INTEREST CHARGES
Interest on long-term debt decreased approximately $2 million in 1994, as
compared to 1993, primarily because of lower average interest rates as a
result of refinancing activities and lower 1994 debt levels.
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
The cumulative effect of the accounting change of approximately $4 million in
1993 represents the one-time change in the method of accounting for Connecticut
municipal property tax expense recognized in the first quarter of 1993.
--------------------------------------------------------------------------
SELECTED FINANCIAL DATA
--------------------------------------------------------------------------
1994 1993 1992 1991 1990
--------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.......$ 421,477 $ 415,055 $ 410,720 $ 409,840 $ 375,456
Operating Income......... 70,053 60,067 60,513 59,723 57,448
Net Income............... 49,457 40,594(a) 37,022 34,637 35,191
Cash Dividends on
Common Stock........... 29,514 28,785 29,536 31,499 34,459
Total Assets.............1,183,618 1,204,642 1,130,684 1,119,593 1,134,986
Long-Term Debt*.......... 379,969 393,232 392,976 401,095 419,527
Preferred Stock Not Subject to
Mandatory Redemption... 68,500 73,500 73,500 88,500 88,500
Preferred Stock Subject to
Mandatory Redemption*... 24,675 27,000 28,500 28,502 30,000
Obligations Under Capital
Leases*................. 36,797 36,902 41,509 44,134 52,370
* Includes portions due within one year.
(a)Includes the cumulative effect of change in accounting for municipal property
tax expense, which increased earnings for common shares by $3.9 million.
STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
--------------------------------------------------------------------------
Quarter Ended
---------------------------------------------------
1994 March 31 June 30 September 30December 31
--------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.. $112,984 $101,188 $102,597 $104,708
======== ======== ======== ========
Operating Income.... $ 19,468 $ 21,268 $ 11,374 $ 17,943
========= ======== ========= =========
Net Income.......... $ 13,961 $ 16,035 $ 6,395 $ 13,066
========= ======== ========== =========
1993
--------------------------------------------------------------------------
Operating Revenues.. $108,950 $ 92,383 $105,510 $108,212
======== ======== ======== ========
Operating Income.... $ 17,659 $ 13,529 $ 13,045 $ 15,834
========= ======== ======== =========
Net Income.......... $ 15,350 $ 7,316 $ 7,182 $ 10,746
========= ========= ======== =========
STATISTICS
--------------------------------------------------------------------------
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions)Customer (kWh)(Average)(December 31,)
---------------------------------------------------------------------
1994 $1,271,513 4,978 7,433 193,187 617
1993 1,242,927 4,715 7,351 192,542 657
1992 1,214,386 4,155 7,433 191,920 739
1991 1,199,362 3,780 7,494 191,692 797
1990 1,184,285 3,874 7,619 191,759 826
Exhibit 13.4
1994
ANNUAL REPORT
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
---------------------------------------
1994 Annual Report
Public Service Company of New Hampshire
Index
Contents Page
-------- ----
Balance Sheets..................................... 1-2
Statements of Income............................... 3
Statements of Cash Flows........................... 4
Statements of Common Equity........................ 5
Notes to Financial Statements...................... 6-27
Report of Independent Public Accountants........... 28
Management's Discussion and Analysis of Financial
Condition and Results of Operations.............. 29-35
Selected Financial Data............................ 37-38
Statistics......................................... 39
Statements of Quarterly Financial Data............. 39
Preferred Stockholder and Bondholder Information... Back Cover
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------
At December 31, 1994 1993
-------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
------
Utility Plant, at original cost:
Electric................................................ $2,038,625 $1,980,050
Less: Accumulated provision for depreciation......... 474,129 441,076
----------- -----------
1,564,496 1,538,974
Construction work in progress........................... 17,781 8,573
Nuclear fuel, net....................................... 2,248 2,107
----------- -----------
Total net utility plant............................. 1,584,525 1,549,654
----------- -----------
Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994 and
at cost in 1993 (Note 12)<F12>......................... 1,815 1,486
Investments in regional nuclear generating
companies and subsidiary company, at equity............ 19,551 19,816
Other, at cost.......................................... 394 429
----------- -----------
21,760 21,731
----------- -----------
Current Assets:
Cash.................................................... 322 5,995
Notes receivable from affiliated companies.............. 35,000 -
Receivables, less accumulated provision for
uncollectible accounts of $2,015,000 in 1994
and of $1,816,000 in 1993............................. 76,173 76,665
Accounts receivable from affiliated companies........... 3,779 859
Accrued utility revenues................................ 36,547 35,770
Fuel, materials, and supplies, at average cost.......... 37,453 41,187
Prepayments and other................................... 20,829 10,429
----------- -----------
210,103 170,905
----------- -----------
Deferred Charges:
Regulatory assets (Note 1H)<F1H>........................ 971,505 973,353
Deferred receivable from affiliated company............. 33,284 33,284
Unamortized debt expense................................ 17,064 19,643
Other................................................... 7,726 5,941
----------- -----------
1,029,579 1,032,221
----------- -----------
Total Assets........................................ $2,845,967 $2,774,511
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
BALANCE SHEETS
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
At December 31, 1994 1993
--------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock, $1 par value--authorized
and outstanding 1,000 shares in 1994 and 1993........... $ 1 $ 1
Capital surplus, paid in................................. 421,784 421,245
Retained earnings........................................ 125,034 60,840
----------- -----------
Total common stockholder's equity............... 546,819 482,086
Cumulative preferred stock subject to mandatory
redemption--
$25 par value--authorized 25,000,000 shares;
outstanding 5,000,000 shares in 1994 and 1993
(Note 6)<F6>......................................... 125,000 125,000
Long-term debt (Note 7)<F7>.............................. 905,985 999,985
----------- -----------
Total capitalization............................ 1,577,804 1,607,071
----------- -----------
Obligations Under Seabrook Power Contract
and Other Capital Leases (Notes 2 and 3)<F2><F3>.......... 849,776 815,553
----------- -----------
Current Liabilities:
Notes payable to affiliated company...................... - 2,500
Long-term debt--current portion.......................... 94,000 94,000
Obligations under Seabrook Power Contract and other
capital leases--current portion (Notes 2 and 3)<F2><F3>. 38,191 41,006
Accounts payable......................................... 45,984 27,119
Accounts payable to affiliated companies................. 17,309 17,576
Accrued taxes............................................ 4,304 122
Accrued interest......................................... 10,496 11,142
Accrued pension benefits................................. 36,269 31,890
Other.................................................... 20,350 22,014
----------- -----------
266,903 247,369
----------- -----------
Deferred Credits:
Accumulated deferred income taxes (Note 1K)<F1K>......... 62,080 18,076
Accumulated deferred investment tax credits.............. 5,614 6,174
Deferred contract obligation--YAEC (Note 4)<F4>.......... 28,572 24,150
Deferred revenue from affiliated company
(Note 10G)<F10G>........................................ 33,284 33,284
Other.................................................... 21,934 22,834
----------- -----------
151,484 104,518
----------- -----------
Commitments and Contingencies (Note 10)<F10>
Total Capitalization and Liabilities............ $2,845,967 $2,774,511
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
January 1, January 1, June 5, January 1,
1994 1993 1992 1992
to to to to
December 31, December 31, December 31, June 4,
For the Periods 1994 1993 1992 1992
-------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating Revenues.............................. $ 922,039 $ 864,415 $ 492,559 |$ 381,769
------------- ------------- -------------|------------
Operating Expenses: |
Operation -- |
Fuel, purchased and net interchange power.. 222,801 208,023 105,346 | 123,784
Other...................................... 303,271 301,534 176,679 | 103,250
Maintenance................................... 43,725 35,427 20,535 | 22,520
Depreciation.................................. 38,703 38,580 21,526 | 25,183
Amortization of regulatory assets, net........ 55,319 67,379 51,143 | 36,528
Federal and state income taxes (Note 8)<F8>... 68,088 54,087 39,197 | 16,449
Taxes other than income taxes................. 38,046 34,675 16,927 | 19,805
------------- ------------- -------------|------------
Total operating expenses................ 769,953 739,705 431,353 | 347,519
------------- ------------- -------------|------------
Operating Income................................ 152,086 124,710 61,206 | 34,250
------------- ------------- -------------|------------
Other Income: |
|
Deferred Seabrook return--other funds......... - - - | 12,101
Equity in earnings of regional nuclear |
generating companies and subsidary company.. 2,079 1,777 1,031 | 869
Bankruptcy related expenses................... - - - | (5,084)
Gain on generating projects................... - - - | 6,498
Other, net.................................... 629 635 2,519 | 63
Income taxes--(expense) credit................ (546) 3,868 14,254 | 12,814
------------- ------------- -------------|------------
Other income, net....................... 2,162 6,280 17,804 | 27,261
------------- ------------- -------------|------------
Income before interest charges.......... 154,248 130,990 79,010 | 61,511
------------- ------------- -------------|------------
Interest Charges: |
Interest on long-term debt.................... 76,410 77,842 47,625 | 54,125
Other interest................................ 394 911 1,987 | 3,913
Deferred Seabrook return--borrowed funds, |
net of income taxes.......................... - - - | (9,305)
------------- ------------- -------------|------------
Interest charges, net................... 76,804 78,753 49,612 | 48,733
------------- ------------- -------------|------------
|
Net Income...................................... $ 77,444 $ 52,237 $ 29,398 |$ 12,778
============= ============= =============|============
</TABLE>
|
PSNH became a wholly owned subsidiary of Northeast Utilities on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------
Jan. 1, Jan. 1, Jun. 5, Jan. 1,
1994 1993 1992 1992
to to to to
Dec. 31, Dec. 31, Dec. 31, Jun. 4,
For the Periods 1994 1993 1992 1992
------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Cash Flows From Operating Activities: |
Net Income...............................................$ 77,444 $ 52,237 $ 29,398 |$ 12,778
Adjustments to reconcile to net cash |
from operating activities: |
Depreciation........................................... 38,703 38,580 21,526 | 25,183
Deferred income taxes and investment tax credits, net.. 67,047 50,027 22,543 | 3,141
Deferred return - Seabrook............................. - - - | (21,406)
Recoverable energy costs, net of amortization.......... (81,206) (39,654) (42,910)| 1,469
Amortization of regulatory asset, net.................. 55,319 67,379 51,143 | 36,528
Other sources of cash.................................. 3,213 30,001 12,816 | 15,967
Other uses of cash..................................... (4,535) (4,394) (4,435)| (4,400)
Changes in working capital: |
Receivables and accrued utility revenues............... (3,205) (3,161) (18,314)| 34,432
Fuel, materials, and supplies.......................... 3,734 3,936 459 | (4,945)
Accounts payable....................................... 18,598 (2,894) 5,083 | (8,189)
Accrued taxes.......................................... 4,182 (1,602) (17,323)| 20,409
Other working capital (excludes cash).................. 742 (2,224) 12,610 | (26,056)
|
---------- ---------- ----------|----------
Net cash flows from operating activities................... 180,036 188,231 72,596 | 84,911
---------- ---------- ----------|----------
Cash Flows Used For Financing Activities: |
Issuance of common shares................................ - - 425,000 | -
Issuance of long-term debt............................... - 44,800 75,000 | -
Net decrease in short-term debt.......................... (2,500) (41,000) (64,500)| -
Reacquisitions and retirements of long-term debt......... (94,000) (138,800) (171,000)| (27,000)
Cash dividends on preferred stock........................ (13,250) (13,250) (9,938)| (3,312)
Acquisition settlement................................... - - (841,466)| -
---------- ---------- ----------|----------
Net cash flows used for financing activities............... (109,750) (148,250) (586,904)| (30,312)
---------- ---------- ----------|----------
Investment Activities: |
Investment in plant: |
Electric utility plant................................. (39,721) (35,360) (15,352)| (25,266)
Nuclear fuel........................................... (1,249) (614) (552)| (9,990)
---------- ---------- ----------|----------
Net cash flows used for investments in plant............. (40,970) (35,974) (15,904)| (35,256)
Sale of Seabrook assets to NAEC (Note 1A)<F1A>........... - - 504,265 | -
NU System Money Pool..................................... (35,000) - - | -
Other investment activities, net......................... 11 (340) (180)| -
---------- ---------- ----------|----------
Net cash flows (used for) from investments................. (75,959) (36,314) 488,181 | (35,256)
---------- ---------- ----------|----------
Net (Decrease) Increase in Cash for the Period............. (5,673) 3,667 (26,127)| 19,343
Cash - beginning of period................................. 5,995 2,328 28,455 | 9,112
---------- ---------- ----------|----------
|
Cash - end of period.......................................$ 322 $ 5,995 $ 2,328 |$ 28,455
========== ========== ==========|==========
Supplemental Cash Flow Information: |
Cash paid during the year for: |
Interest, net of amounts capitalized during construction.$ 74,507 $ 75,609 $ 35,405 |$ 53,427
========== ========== ==========|==========
|
Income taxes.............................................$ 167 $ 2,390 $ 410 |$ 909
========== ========== ==========|==========
Increase in obligations: |
Seabrook Power Contract..................................$ 51,924 $ 84,796 $ 37,490 |$ -
========== ========== ==========|==========
Capital leases...........................................$ 1,342 $ 4,696 $ - |$ -
========== ========== ==========|==========
PSNH became a wholly owned subsidiary of Northeast Utilities on June 5, 1992.
</TABLE>
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
STATEMENTS OF COMMON EQUITY
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------
Capital
Common Surplus, Retained
Stock Paid In Earnings Total
---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Balance at January 1, 1992............... $37,494 $646,298 $ 632 $684,424
Net income........................... 12,778 12,778
Cash dividends on preferred stock.... (5,704) (5,704)
Stock dividends on common stock...... 1,962 16,456 (18,418) -
Capital stock expenses, net.......... (2) (2)
-------- --------- --------- ---------
Balance at June 4, 1992.................. $39,456 $662,752 $(10,712) $691,496
======== ========= ========= =========
Balance at June 5, 1992.................. $ - $ - $ - $ -
Net income........................... 29,398 29,398
Cash dividends on preferred stock.... (7,545) (7,545)
Issuance of 1,000 shares of common
stock, $1 par value................ 1 1
Premium on common stock.............. 424,999 424,999
Capital stock expenses, net.......... (4,237) (4,237)
-------- --------- --------- ---------
Balance at December 31, 1992............. 1 420,762 21,853 442,616
Net income........................... 52,237 52,237
Cash dividends on preferred stock.... (13,250) (13,250)
Capital stock expenses, net.......... 483 483
-------- --------- --------- ---------
Balance at December 31, 1993............. 1 421,245 60,840 482,086
Net income........................... 77,444 77,444
Cash dividends on preferred stock.... (13,250) (13,250)
Capital stock expenses, net.......... 539 539
-------- --------- --------- ---------
Balance at December 31, 1994............. $ 1 $421,784 $125,034 $546,819
======== ========= ========= =========
</TABLE>
PSNH became a wholly owned subsidiary of Northeast Utilities on June 5, 1992.
The accompanying notes are an integral part of these financial statements
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A> A. MERGER WITH NORTHEAST UTILITIES
On June 5, 1992 (Acquisition Date), Northeast Utilities (NU) acquired
Public Service Company of New Hampshire (PSNH) pursuant to a merger
agreement and the company became a wholly owned operating subsidiary of
NU. In a related transaction, PSNH's 35.6 percent share of the
Seabrook 1 nuclear power plant (Seabrook 1) and other Seabrook-related
assets were transferred to North Atlantic Energy Corporation (NAEC),
another new NU subsidiary.
In accordance with generally accepted accounting principles, the
acquisition of PSNH has been accounted for as a purchase.
On June 29, 1992, PSNH's New Hampshire Yankee Division (NHY) was
dissolved and North Atlantic Energy Service Corporation (NAESCO), a
wholly owned subsidiary of NU, with the approval of the Securities and
Exchange Commission (SEC) and the Nuclear Regulatory Commission (NRC),
began management of the Seabrook 1 power plant as agent for the
Seabrook joint owners. On June 29, 1992, all NHY employees became
employees of NAESCO.
<F1B> B. GENERAL
PSNH, The Connecticut Light and Power Company, Western Massachusetts
Electric Company, NAEC, and Holyoke Water Power Company are the
operating subsidiaries comprising the Northeast Utilities system (the
system) and are wholly owned by NU.
Other wholly owned subsidiaries of NU provide substantial support
services to the system. Northeast Utilities Service Company (NUSCO)
supplies centralized accounting, administrative, data processing,
engineering, financial, legal, operational, planning, purchasing, and
other services to the system companies. Northeast Nuclear Energy
Company acts as agent for system companies in constructing and
operating the Millstone nuclear generating facilities.
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.
<F1C> C. RECLASSIFICATIONS
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
<F1D> D. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT
Regional Nuclear Generating Companies: PSNH owns common stock of four
regional nuclear generating companies (Yankee companies). The Yankee
companies, with PSNH's ownership interests, are:
Connecticut Yankee Atomic Power Company (CY) .... 5.0%
Yankee Atomic Electric Company (YAEC) ........... 7.0
Maine Yankee Atomic Power Company (MY) .......... 5.0
Vermont Yankee Nuclear Power Corporation (VY) ... 4.0
PSNH's investments in the Yankee companies are accounted for on the
equity basis, based on PSNH's ability to exercise significant influence
over their operating and financial policies. The electricity produced
by the facilities that are operating is committed to the participants
substantially on the basis of their ownership interests and is billed
pursuant to contractual agreements. Under ownership agreements with the
Yankee companies, PSNH may be asked to provide direct or indirect
financial support for one more or of the companies. For more
information on these agreements, see Note 10E, "Commitments and
Contingencies - Purchased Power Arrangements."
The YAEC nuclear power plant was shut down permanently on February 26,
1992. For more information on the Yankee companies, see Note 4,
"Nuclear Decommissioning."
Millstone 3: The company has a 2.85 percent joint ownership interest
in Millstone 3, a 1,154-megawatt (MW) nuclear generating unit. As of
December 31, 1994 and 1993, plant-in-service included approximately
$118.3 million and $118.1 million, respectively, and the accumulated
provision for depreciation included approximately $24.2 million and
$21.1 million, respectively, for PSNH's proportionate share of
Millstone 3. PSNH's share of Millstone 3 expenses is included in the
corresponding operating expenses on the accompanying Statements of
Income.
Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman
Unit 4 (Wyman), a 632 -MW oil-fired generating unit. At December 31,
1994 and 1993, plant-in-service included approximately $6.0 million and
the accumulated provision for depreciation included approximately $3.3
million and $3.1 million, respectively, for PSNH's share of Wyman.
PSNH's share of Wyman expenses is included in the corresponding
operating expenses on the accompanying Statements of Income.
<F1E> E. 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 New Hampshire Public Utilities Commission (NHPUC).
Except for major facilities, depreciation factors 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. For Millstone 3, the costs of removal, less salvage,
that have been funded through an external decommissioning trust will be
paid with funds from the trust and charged to the accumulated reserve
for decommissioning included in the accumulated provision for
depreciation over the expected service life of the plant. See Note 4,
"Nuclear Decommissioning," for additional information.
The depreciation rates for the several classes of electric
plant-in-service are equivalent to a composite rate of 3.6 percent for
the years ended December 31, 1994, and December 31, 1993, 3.5 percent
for the six-month and twenty-six day period ending December 31, 1992,
and 3.4 percent for the five-month and four-day period ending June 4,
1992.
<F1F> F. 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 PSNH, are subject to
the provisions of the 1935 Act. Arrangements among the system
companies, outside agencies, and other utilities covering inter-
connections, interchange of electric power, and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. The company is subject to further
regulation for rates, accounting, and other matters by the FERC and the
NHPUC.
<F1G> G. REVENUES
Other than 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. Rates
can be changed only through a formal proceeding before the appropriate
regulatory commission. At the end of each accounting period, PSNH
accrues an estimate for the amount of energy delivered but unbilled.
For additional information see Note 10B, "Commitments and Contingencies
- PSNH Rate Agreement."
<F1H> H. REGULATORY ACCOUNTING
PSNH follows accounting policies that reflect the impact of the rate
treatment of certain events or transactions that differ from generally
accepted accounting principles for those events or transactions
followed by nonregulated enterprises. Under regulatory accounting,
assuming that future revenues are expected to be sufficient to provide
recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an
asset, or create a liability. If the economic entity no longer comes
under the jurisdiction of a regulator or external forces, such as a
move to a competitive environment, effectively limiting the influence
of cost-of-service based rate regulation, the entity may be forced to
abandon regulatory accounting, requiring a reexamination and potential
write-off of net regulatory assets. PSNH continues to be subject to
cost-of-service based rate regulation. Based on current regulation,
PSNH believes that its use of regulatory accounting is still
appropriate.
The components of regulatory assets are as follows:
At December 31, 1994 1993
--------------------------------------------------------------
(Thousands of Dollars)
Regulatory asset (Note 1I) ...........$678,974 $769,498
Recoverable energy costs (Note 1J) ...194,994 122,861
Income taxes, net (Note 1K) .......... 66,466 54,250
Unrecovered contract obligation-
YAEC (Note 4) ........................ 28,572 24,150
Other ................................ 2,499 2,594
------- --------
$971,505 $973,353
======== ========
<F1I> I. REGULATORY ASSET
The regulatory asset represents the aggregate value, as of the
Acquisition Date, placed by the rate agreement with the state of New
Hampshire (Rate Agreement) on PSNH's assets in excess of the net book
value of PSNH's non-Seabrook assets and the $700 million value assigned
to Seabrook by the Rate Agreement. The regulatory asset was valued at
approximately $920.6 million on the Acquisition Date. The Rate
Agreement provides for the recovery, through rates, of the amortization
of the regulatory asset with a return each year on the unamortized
portion of the asset. The Rate Agreement provides that $425 million of
the regulatory asset be amortized over the first seven years after May
16, 1991 (Reorganization Date), with the remaining amount to be
amortized over the 20-year period after the Reorganization Date.
<F1J> J. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (Energy Act), PSNH 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.
PSNH has begun to recover these costs.
The Rate Agreement includes a comprehensive fuel and purchased power
adjustment clause (FPPAC) permitting PSNH to pass through to retail
customers, for a ten-year period, the retail portion of differences
between the fuel and purchase power costs assumed in the Rate Agreement
and PSNH's actual costs, which include the costs under the Seabrook
Power Contract. The cost components of the FPPAC are subject to a
prudence review by the NHPUC.
The costs associated with purchases from certain nonutility generators
(NUGs), over the level assumed in the Rate Agreement, are deferred and
recovered through the FPPAC. PSNH has been attempting to negotiate the
rate orders mandating the purchase of high-cost NUG power. In
September 1994, the NHPUC approved an amendment to the Rate Agreement
allowing settlement agreements to be implemented with two NUGs. The
two NUGs have given up their right to sell their output to PSNH in
exchange for lump sum cash payments of approximately $40 million. The
deferred buyout payments are included as part of PSNH's recoverable
energy costs. During the Rate Agreement's Fixed-Rate period, all the
savings from the buyout will be used to reduce PSNH's recoverable
energy costs. At the end of the Fixed-Rate period, 50 percent of the
savings will be used to reduce the recoverable energy costs with the
remainder reducing current rates. At December 31, 1994, PSNH's
recoverable energy costs included fuel and purchase power deferrals
($154.9 million), the deferred buyout ($39.8 million), and the D&D
assessment ($0.3 million). See Note 10B, "Commitments and
Contingencies - PSNH Rate Agreement," for further information.
<F1K> K. 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 income
subject to tax) is accounted for in accordance with the ratemaking
treatment of the applicable regulatory commissions. See Note 8,
"Income Tax Expense," for the components of income tax expense.
In 1992, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income
tax accounting standards. PSNH adopted SFAS 109, on a prospective
basis, during the first quarter of 1993. The adoption of SFAS 109 has
not had a material effect on the net income or on the balance sheet of
the company. As a result of the adoption of SFAS 109, the company has
increased the deferred tax asset for net-operating-losses (NOLs)
previously not recognized. A valuation reserve was not established.
As it is probable that the increase in deferred tax liabilities will be
recovered from customers through rates, PSNH also established a
regulatory asset.
The tax effect of temporary differences which give rise to the
accumulated deferred tax obligation are as follows:
At December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences .......... $ 106,683 $ 150,238
Net operating loss carryforwards ..... (247,440) (270,612)
Regulatory liabilities -
income tax gross up (46,445) (49,423)
Other ................................ 249,282 187,873
-------- --------
$ 62,080 $ 18,076
========= =========
At December 31, 1994, PSNH had a regular tax NOL carryforward of
approximately $726 million, and an Alternative Minimum Tax (AMT) NOL
carryforward of $529 million, both to be used against PSNH's federal
taxable income and expiring between the years 2000 and 2006. PSNH also
had Investment Tax Credit (ITC) carryforwards of $54 million, which
expire between the years 1995 and 2004. For a portion of the
carryforward amounts indicated above, the reorganization of PSNH under
Chapter 11 of the United States Bankruptcy Code limits the annual
amount of NOL and ITC carryforwards that may be used. Approximately
$249 million of the NOL, $189 million of the AMT NOL, and $23 million
of the ITC carryforwards are subject to this limitation.
<F1L>L. DERIVATIVE FINANCIAL INSTRUMENTS
PSNH utilizes interest-rate caps to manage well defined interest rate
risks. Premiums paid for purchased interest-rate-cap agreements are
amortized to interest expense over the terms of the caps. Unamortized
premiums are included in Deferred Charges - Other. Amounts receivable
under cap agreements are accrued as a reduction of interest expense.
Any material unrealized gains or losses on interest rate caps will be
deferred until realized. For further information, see Note 11,
"Derivative Financial Instruments."
<F2>2. SEABROOK POWER CONTRACT
On June 5, 1992, NAEC and PSNH entered into the Seabrook Power Contract
(Contract), under which PSNH is obligated to buy from NAEC, and NAEC is
obligated to sell to PSNH, all of NAEC's 35.6 percent ownership share of
the capacity and output of Seabrook 1 for a period equal to the length of
the NRC's full power operating license for Seabrook 1. Accordingly, PSNH
has included its right to buy power from NAEC on its Balance Sheets as part
of utility plant with a corresponding obligation. At December 31, 1994,
this right was valued at approximately $882.8 million. Under the Contract,
PSNH is unconditionally obligated to pay NAEC's cost of service during this
period whether or not Seabrook 1 is operating. NAEC's cost of service
includes all of its Seabrook-related costs, including operation and
maintenance expense, fuel expense, property tax expense, depreciation
expense, and certain overhead and other costs.
The Contract establishes the value of the initial investment in Seabrook
(Initial Investment) at $700 million and the initial investment in nuclear
fuel at $0. NAEC is depreciating its Initial Investment on a straight line
basis over the remaining term of Seabrook's full power operating license.
Any subsequent additions to Seabrook 1 will be depreciated on a straight-
line basis over the remaining term of the Contract at the time the
additions are brought into service. The Contract provides that NAEC's
return on its allowed investment in Seabrook 1 (its investment in working
capital, fuel, capital additions after the date of commercial operation of
Seabrook 1 and a portion of the Initial Investment) is calculated based on
NAEC's actual capitalization from time to time over the term of the
Contract, which includes its actual debt and preferred equity costs, and a
common equity cost of 12.53 percent for the first ten years of the
Contract, and thereafter at an equity rate of return to be fixed in a
filing with FERC. The portion of the Initial Investment which is included
in the allowed investment was 40 percent at the Acquisition Date, and will
increase by 15 percent in each of the following four years beginning
May 15, 1993. As of December 31, 1994, the portion of the initial
investment included in the allowed investment was 70 percent. From the
Acquisition Date through December 31, 1994, NAEC recorded an additional
$131.5 million of deferred return. The deferred return on the excluded
portion of the Initial Investment, including the $50.9 million, will be
recovered with carrying charges by NAEC through the Contract beginning six
months after the end of PSNH's Fixed Rate Period and will be fully
recovered by May 15, 2001.
If Seabrook 1 is shut down prior to the expiration of the NRC operating
license term, PSNH will be unconditionally required to pay NAEC termination
costs for 39 years, less the period during which Seabrook 1 has operated.
These costs are designed to reimburse NAEC for its share of Seabrook 1
shut-down and decommissioning costs and to pay NAEC a return of and on any
undepreciated balance of its Initial Investment in the plant over the then-
remaining term of the Contract, and the return of and on any capital
additions to the plant made after the Acquisition Date over a period of
five years after shut down (net of any tax benefits to NAEC attributable to
such cancellation).
Contract payments charged to operating expense were $143 million, including
an interest component of $43 million for the year ended December 31, 1994;
$123 million, including an interest component of $33 million for the year
ended December 31, 1993; and $26.5 million, including $16.3 million for the
period June 5, 1992 through December 31, 1992.
On February 15, 1994, NAEC acquired Vermont Electric Generation and
Transmission Cooperative, Inc.'s (VEG&T) 0.4 percent ownership interest in
Seabrook for approximately $6.4 million. NAEC sells the output from the
Seabrook interest purchased from VEG&T on February 15, 1994 to PSNH under
an agreement that has been approved by the FERC and is substantially
similar to the Seabrook Power Contract between PSNH and NAEC that was
effective on the Acquisition Date.
Future minimum payments, excluding executory costs, such as property taxes,
state use taxes, insurance, and maintenance, under the terms of the
contracts, as of December 31, 1994, are approximately:
Seabrook Power Contracts
------------------------
(Thousands of Dollars)
1995 ................................ $ 72,300
1996 ................................ 81,200
1997 ................................ 91,100
1998 ................................ 169,700
1999 ................................ 167,900
After 1999 .......................... 1,341,900
----------
Future minimum payments ............. 1,924,100
Less amount representing interest .. 1,041,300
----------
Present value of Seabrook Power
Contracts payments ............... $ 882,800
==========
<F3>3. LEASES
PSNH has entered into lease agreements, for the use of data processing and
office equipment, vehicles, and office space. The provisions of these
lease agreements generally provide for renewal options. The following
rental payments have been charged to operating expense:
Year Capital Leases Operating Leases
---- -------------- ----------------
1994 ................ $1,061,000 $4,255,000
1993 ................ 701,000 6,197,000
1992 ................ - 8,511,000
Interest included in capital leases was $394,000 in 1994 and $403,000 in
1993.
Future minimum rental payments, excluding executory costs, such as property
taxes, state use taxes, insurance, and maintenance, under long-term
noncancelable leases, as of December 31, 1994, are approximately:
Operating Leases
----------------
(Thousands of Dollars)
1995 ............................... $ 7,900
1996 ............................... 6,900
1997 ............................... 5,800
1998 ............................... 4,500
1999 ............................... 4,000
After 1999 ......................... 14,100
--------
Future minimum lease payments $43,200
=======
<F4>4. NUCLEAR DECOMMISSIONING
The company's 1992 decommissioning study concluded that complete and
immediate dismantlement at retirement continues to be the most viable and
economic method of decommissioning Millstone 3. A 1994 Seabrook
decommissioning study, which is currently under review by the New Hampshire
Decommissioning Financing Committee, also confirmed that complete and
immediate dismantlement at retirement is the most viable and economic
method of decommissioning Seabrook 1. Decommissioning studies are reviewed
and updated periodically to reflect changes in decommissioning
requirements, technology, and inflation.
The estimated cost of decommissioning PSNH's 2.85 percent ownership share
of Millstone 3 and NAEC's 36.0 percent share of Seabrook 1 (utilizing the
currently approved decommissioning study), in year-end 1994 dollars, is
$12.8 million and $137.3 million, respectively. These estimated costs have
been levelized and assume after-tax earnings on the Millstone and Seabrook
decommissioning funds of 6.5 percent and 6.1 percent, respectively. Future
escalation rates in decommissioning costs for Millstone 3 and Seabrook 1
are assumed. PSNH's Millstone 3 decommissioning costs are accrued over the
expected service life of the unit and are included in depreciation expense
on its Statements of Income. Nuclear decommissioning related to PSNH's
share of Millstone 3 amounted to $0.3 million in 1994 and 1993, and $0.2
million in 1992. Nuclear decommissioning costs, as a cost of removal, are
included in the accumulated provision for depreciation on PSNH's Balance
Sheets. At December 31, 1994, the balance in the accumulated reserve for
decommissioning amounted to $1.8 million. See "Nuclear Decommissioning" in
Management's Discussion and Analysis for a discussion of changes being
considered by the FASB related to accounting for decommissioning costs.
PSNH makes payments to an independent decommissioning trust for its portion
of the costs of decommissioning Millstone 3. Under the terms of the Rate
Agreement, PSNH is obligated to pay NAEC's share of Seabrook's
decommissioning costs, even if the unit is shut down prior to the
expiration of its operating license. Accordingly, NAEC bills PSNH directly
for its share of the costs of decommissioning Seabrook. PSNH records its
Seabrook decommissioning costs as a component of purchased power expense on
its Statement of Income. Under the Rate Agreement, PSNH's Seabrook
decommissioning costs are recovered through base rates.
As of December 31, 1994, PSNH has collected, through rates, approximately
$1.5 million toward the future decommissioning costs of its share of
Millstone 3, which has been transferred to the external decommissioning
trust. Earnings on the decommissioning trusts increase the decommissioning
trusts balance and the accumulated reserve for decommissioning. Due to
PSNH's adoption, effective January 1, 1994, of SFAS 115, Accounting for
Certain Investments in Debt and Equity Securities, unrealized gains and
losses associated with the decommissioning trusts also impact the balance
of the trusts and the accumulated reserve for decommissioning.
As of December 31, 1994, NAEC (including pre-Acquisition Date payments made
by PSNH) has paid approximately $10.1 million, into Seabrook 1's
decommissioning trust.
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. PSNH 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 PSNH. Because allowances for decommissioning have
increased significantly in recent years, ratepayers in future years may
need to increase their payments to offset the effects of any insufficient
rate recoveries in previous years.
PSNH, along with other New England utilities, has equity investments in the
four Yankee companies. Each Yankee company owns a single nuclear
generating unit. PSNH's ownership share of the estimated costs, in year-
end 1994 dollars, of decommissioning of CY, MY, and VY are $18.1 million,
$16.9 million, and $13.2 million, respectively. Under the terms of the
contracts with the Yankee companies, the shareholders-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 by PSNH.
YAEC has begun component removal activities related to decommissioning of
its nuclear facility. In June 1992, YAEC filed a rate filing to obtain
FERC authorization to collect the closing and decommissioning costs and to
recover the remaining investment in the YAEC nuclear power plant over the
remaining period of the plant's Nuclear Regulatory Commission (NRC)
operating license. The bulk of these costs has been agreed to by the YAEC
joint owners and approved, as a settlement, by FERC. In October 1994, YAEC
submitted a revised decommissioning cost estimate as part of its
decommissioning plan with the NRC. Following the receipt of NRC approval,
this estimate will be filed with the FERC. This revised estimate increased
PSNH's ownership share of decommissioning YAEC's nuclear facility by
approximately $6.6 million in January 1, 1994 dollars. At December 31,
1994, the estimated remaining costs, including decommissioning, amounted to
$408.2 million, of which PSNH's share was approximately $28.6 million.
Management expects that PSNH will continue to be allowed to recover such
FERC-approved costs from its customers. Accordingly, PSNH has recognized
these costs as a regulatory asset, with a corresponding obligation, on its
Balance Sheets.
<F5>5. SHORT-TERM DEBT
PSNH has credit lines totaling $125 million available through a Revolving-
Credit Facility with a group of 19 banks. PSNH may borrow funds on a
short-term revolving basis using either fixed-rate or standby loans. Fixed
rates are set using competitive bidding. Standby-loan rates are based upon
several alternative variable rates. PSNH is obligated to pay a facility
fee of 0.25 percent per annum on the total commitment. At December 31,
1994 and 1993, there were no borrowings under the Facility.
Certain subsidiaries of NU, including PSNH, 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.
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. Investing and borrowing subsidiaries receive or pay
interest based on the average daily Federal Funds rate. At December 31,
1994, there were no outstanding borrowings from the Pool. At December 31,
1993, PSNH had $2.5 million in outstanding borrowings the Pool, for which
the average interest rate was 2.9 percent.
Maturities of PSNH's short-term debt obligations were for periods of three
months or less.
The amount of short-term borrowings that may be incurred by PSNH is subject
to periodic approval by the SEC under the 1935 Act. Under the SEC
restrictions, PSNH was authorized, as of January 1, 1995 to incur short-
term borrowings up to a maximum of $175 million.
<F6>6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Details of preferred stock subject to mandatory redemption are:
Shares Outstanding December 31,
--------------------------
Description December 31, 1994 1994 1993 1992
-----------------------------------------------------------------
(Thousands of Dollars)
10.60% Series A of 1991 5,000,000 $125,000 $125,000 $125,000
======== ======== ========
In case of default on dividends or 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 PSNH is in
arrears in the payment of dividends on any outstanding shares of preferred
stock, PSNH would be prohibited from redemption or purchase of less than
all of the preferred stock outstanding. The Series A Preferred Stock is
not subject to optional redemption by PSNH. It is subject to a sinking
fund beginning on June 30, 1997, sufficient to retire annually 1,000,000
shares at $25 per share.
<F7>7. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31,
-------------------
1994 1993
----------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
8 7/8% Series A ........due 1996 $172,500 $172,500
9.17% Series B ........due 1998 170,000 170,000
--------- --------
Total First Mortgage Bonds ..... 342,500 342,500
Term Loan/Notes:
Variable Rate ................due 1996 141,000 235,000
Pollution Control Revenue Bonds:
7.65% Series A ........due 2021 66,000 66,000
7.50% Series B ........due 2021 108,985 108,985
7.65% Series C ........due 2021 112,500 112,500
Adjustable Rate Series D due 2021 39,500 39,500
Adjustable Rate Series E due 2021 69,700 69,700
Adjustable Rate, Tax-Exempt,
Series D due 2021 75,000 75,000
Adjustable Rate, Tax-Exempt,
Series E due 2021 44,800 44,800
Less: Amounts due within one year ... 94,000 94,000
-------- --------
Long-term debt, net ............ $905,985 $999,985
======== ========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1994 for the years 1995 through 1999
are approximately $94,000,000 in 1995, $219,500,000 in 1996, $0 in 1997,
$170,000,000 in 1998, and $0 in 1999. Also, there are annual renewal and
replacement fund requirements equal to 2.25 percent of the average of net
depreciable property owned by PSNH at the Reorganization Date, plus
cumulative gross property additions thereafter. PSNH expects to meet its
future fund requirements by certifying property additions. Any deficiency
would need to be satisfied by the deposit of cash or bonds.
Essentially, all utility plant of PSNH is subject to the lien of its first
mortgage bond indenture. PSNH's two bank facilities, the Term Loan and
Revolving Credit Facility are secured by a second lien, junior to the lien
of its first mortgage bond indenture, on all PSNH property located in New
Hampshire. At December 31, 1994, and the principal amount outstanding
under the Term Loan was $141 million and $235 million, respectively. The
average effective interest rates for the Term Loan for 1994 and 1993 were
approximately 5.2 percent and 4.3, respectively. At December 31, 1994,
there were no borrowings under the Revolving Credit Facility.
Concurrent with the issuance of PSNH's Series A and B First Mortgage Bonds,
PSNH entered into financing arrangements with the Industrial Development
Authority of the state of New Hampshire (IDA). Pursuant to these
arrangements, the IDA issued five series of Pollution Control Revenue Bonds
(PCRBs) and loaned the proceeds to PSNH. At December 31, 1994 and 1993,
$516.5 million of the PCRBs were outstanding. The average effective
interest rates on the variable-rate pollution percent control notes ranged
from 2.90 to 4.3 percent for 1994 and from 2.5 percent to 3.4 percent for
1993. PSNH's obligation to repay each series of PCRBs is secured by a
series of First Mortgage Bonds that were issued under its indenture. Each
such series of First Mortgage Bonds contains terms and provisions with
respect to maturity, principal payment, interest rate and redemption that
correspond to those of the applicable series of PCRBs; for financial
reporting purposes, these bonds would not be considered outstanding unless
PSNH fails to meet its obligation under the PCRBs.
The Series A and B First Mortgage Bonds are not redeemable prior to their
maturity except in limited circumstances. The PCRBs, except for Series D
and E, are redeemable on or after May 1, 2001, at the option of the company
with accrued interest and at specified premiums. Under current interest
rate elections by PSNH, the Series D and E PCRBs are redeemable, at par
plus accrued interest at the end of each interest rate period. Future
interest rate elections by PSNH could significantly defer or eliminate the
availability of optional redemptions by PSNH and could affect costs as
well.
<F8>8. INCOME TAX EXPENSE
The components of federal and state income tax provisions are:
Jan. 1, 1993
Jan. 1, 1994 to June 5, 1992 Jan. 1, 1992
to Dec. 31, 1993 to to
For the Periods Dec.31, 1994 (Note 1K) Dec. 31. 1992 June 4, 1992
-----------------------------------------------------------------------------
(Thousands of Dollars)
Current income taxes:
Federal .............. $ 368 $ (937) $ 2,400 | $ 415
State ................ 1,219 1,183 - | 79
--------- -------- -------- | ---------
Total current 1,587 246 2,400 | 494
--------- -------- -------- | ---------
|
Deferred income taxes, net: |
Federal 63,941 47,407 23,086 | 8,703
State 3,666 3,131 - | -
--------- -------- -------- | ---------
|
Total deferred 67,607 50,538 23,086 | 8,703
--------- -------- -------- | ---------
|
|
Investment tax credits, net (560) (565) (326) | (341)
-------- --------- -------- | ---------
|
Total income tax expense $ 68,634 $ 50,219 $ 25,160 | $ 8,856
======== ======== ======== ========
The components of total income tax expense are classified as follows:
Income taxes charged to
operating expenses... $68,088 $54,087 $39,197 | $16,449
Income taxes associated |
with the deferred |
return on Seabrook.. - - - | 4,793
Income taxes associated |
with allowance for funds |
used during construction |
and the deferred return |
on NHEC deferred costs - - 217 | 428
Other income taxes - credit 546 (3,868) (14,254) | (12,814)
-------- -------- ------- | -------
|
Total income tax expense. $ 68,634 $ 50,219 $25,160 | $ 8,856
======== ======== ======= =======
Deferred income taxes are comprised of the tax effects of temporary
differences as follows:
Jan. 1, 1993
Jan. 1, 1994 to June 5, 1992 Jan. 1, 1992
to Dec. 31, 1993 to to
For the Periods Dec. 31, 1994 (Note 1K) Dec. 31, 1992 June 4, 1992
-------------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation $ 2,701 $ 4,549 $ 1,629 | $12,333
Energy adjustment clauses 30,954 15,155 14,520 | (1,359)
Deferred tax asset |
associated with NOL 23,611 25,438 9,335 | (2,317)
Alternative minimum tax (301) 1,056 (2,441) | (394)
Amortization of prepaid |
deferred taxes 11,501 7,667 - | -
Deferred return on Seabrook - - - | 4,793
Severance benefits - - 254 | (1,020)
Other (859) (3,327) (211) | (3,333)
--------- -------- ------- | --------
|
|
Deferred income taxes, net $67,607 $50,538 $23,086 | $ 8,703
======= ======= ======= ========
A reconciliation between income tax expense and the expected tax expense at
the applicable statutory rates is as follows:
Jan. 1, 1993
Jan. 1, 1994 to June 5, 1992 Jan. 1, 1992
to Dec.31, 1993 to to
For the Periods Dec. 31,1994 (Note 1K) Dec. 31, 1992 June 4, 1992
----------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income
for 1994 and 1993 and at
34 percent for 1992 $51,127 $35,860 $18,550 |$ 7,356
Tax effect of differences: |
Depreciation differences 1,407 1,593 1,032 | (8,314)
Amortization of regulatory |
asset - Rate Agreement 20,007 23,765 17,624 | 12,477
Seabrook intercompany loss (19,637) (19,176) (11,903) | -
Reorganization expenses - - 22 | 1,728
Deferred investment return - - - | (3,832)
State income taxes, net of |
federal benefit 3,175 2,804 - | -
Amortization of prepaid deferred |
taxes 11,501 7,667 - | -
Other, net 1,054 (2,294) (165) | (559)
-------- ------ --------- | -------
|
Total income tax expense $68,634 $50,219 $25,160 |$ 8,856
======= ======= ======= =======
9. EMPLOYMENT BENEFITS
<9A>A. PENSION BENEFITS
The company participates in a uniform noncontributory defined benefit
retirement plan covering all regular system employees (the Plan).
Benefits are based on years of service and employees' highest eligible
compensation during five consecutive years of employment. Effective
January 1993, PSNH's plan was merged into the NU system's uniform
noncontributory defined benefit plan. The company's direct portion of
the system's pension cost, part of which was charged to utility plant,
approximated $4.4 million in 1994, $6.6 million 1993, and $4.4 million
for the period January 1, 1992 to June 4, 1992 and $3.5 million for the
period June 5, 1992 to December 31, 1992. The pension cost for January
1, 1992 to June 4, 1992 includes employees of NHY, who are now employees
of NAESCO. Pension costs for 1994 and 1993 included approximately $1.9
million and $3.4 million, respectively, related to work force reduction
programs.
Currently, PSNH 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 PSNH are:
Jan. 1, 1994 Jan. 1, 1993 June 5, 1992 Jan. 1, 1992
to to to to
For the Periods Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992
----------------------------------------------------------------------
(Thousands of Dollars)
Service cost $ 5,531 $ 7,539 $ 2,889 | $ 3,850
Interest cost 11,129 11,180 6,810 | 6,200
Return on plan assets 246 (19,308) (5,026) | (4,561)
Net amortization (12,526) 7,215 (1,206) | (1,067)
------- -------- ------ | --------
|
Net pension cost $ 4,380 $ 6,626 $ 3,467 | $ 4,422
======== ======== ======= ========
--------------------------------------------------------------------
For calculating pension cost, the following assumptions were used:
Jan. 1, 1994 Jan. 1, 1993 June 5, 1992 Jan. 1, 1992
to to to to
For the Periods Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992
-------------------------------------------------------------------------------
Discount rate ............ 7.75% 8.00% 8.00% | 8.00%
Expected long-term rate . |
of return ............... 8.50 8.50 9.00 | 9.00
Compensation/progression . |
rate .................. 4.75 5.00 6.00 | 6.00
The following table represents the Plan's funded status reconciled to
the Balance Sheets:
At December 31, 1994 1993
-------------------------------------------------------------------
(Thousands of Dollars)
Accumulated benefit obligation,
including $111,198,000 of vested
benefits at December 31, 1994
$111,691,000 of vested
benefits at December 31, 1993 $121,202 $122,429
======== ========
Projected benefit obligation (PBO) $146,972 $156,475
Market value of plan assets 136,104 145,536
-------- --------
PBO in excess of plan assets (10,868) (10,939)
Unrecognized transition amount 5,004 5,338
Unrecognized prior service costs 5,775 4,890
Unrecognized net gain ...... (36,180) (31,179)
-------- --------
Accrued pension liability .. $(36,269) $ (31,890)
========= ==========
The following actuarial assumptions were used in calculating the Plan's
year-end funded status:
For the Years Ended December 31, 1994 1993
------------------------------------------------------------
Discount rate...................... 8.25% 7.75%
Compensation/progression rate 5.00 4.75
<F9B>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. These benefits are available for employees leaving
the company who are otherwise eligible to retire and have met specified
service requirements. Effective January 1, 1993, the company adopted
SFAS 106, Employer's Accounting for Postretirement Benefits Other Than
Pensions, on a prospective basis. PSNH's direct portion of health care
and life insurance costs, part of which were deferred or charged to
utility plant, approximated $7.6 million in 1994, $9.1 million in 1993,
and $3.3 million in 1992.
On January 1, 1993, the accumulated postretirement benefit obligation
represented the company's transition obligation upon the adoption of
SFAS 106. As allowed by SFAS 106, the company is amortizing its
transition obligation of approximately $59 million over a 20-year
period. 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.
During 1993, the company began funding SFAS 106 postretirement costs
through external trusts. The company is funding annually amounts that
have been rate recovered and which also are tax-deductible under the
Internal Revenue Code. The trust assets are invested primarily in
equity securities and bonds.
The following table represents the plan's funded status reconciled to
the Balance Sheet.
At December 31, 1994 1993
------------------------------------------------------------------
(Thousands of Dollars)
Accumulated postretirement benefit obligation of:
Retirees ...................... $39,881 $51,832
Fully eligible active employees 52 99
Active employees not eligible to retire 9,065 7,888
--------- -------
Total accumulated postretirement benefit
obligation .................... 48,998 59,819
Market value of plan assets ...... 6,606 2,387
--------- --------
Accumulated postretirement benefit
obligation in excess of plan assets (42,392) (57,432)
Unrecognized transition amount ... 52,930 55,870
Unrecognized net gain ............ (13,204) (1,065)
-------- --------
Accrued postretirement benefit liability $ (2,666) $ (2,627)
======== ========
-------------------------------------------------------------
The components of health care and life insurance costs are:
For the Years Ended December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Service cost ..................... $ 971 $1,260
Interest cost .................... 3,844 4,800
Return on plan assets ............ 37 -
Net amortization ................. 2,735 3,046
------ ------
Net health care and life insurance costs $7,587 $9,106
====== ======
-------------------------------------------------------------
The following actuarial assumptions were used in calculating the Plan's
year-end funded status:
At December 31, 1994 1993
------------------------------------------------------------
(Thousands of Dollars)
Discount rate .................... 8.00% 7.75%
Long-term rate of return -
health assets,net of tax ........ 5.00 5.00
Long-term rate of return - life assets 8.50 8.50
Health care cost trend rate (a) .. 10.20 11.10
(a) Annual growth in per capita cost of covered health care benefits
was assumed to decrease to 5.4 percent for 2002.
The effect of increasing the assumed health care cost trend rates by
one percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1994 by $2.4
million and the aggregate of the service and interest cost components
of net periodic postretirement benefit cost for the year then ended by
$233,000. The trust holding the plan assets is subject to federal
income taxes at a 35-percent tax rate.
PSNH is currently recovering SFAS 106 costs, including previously
deferred costs. Deferral of such costs are permitted since it is
expected that the period of recovery of deferred costs will be within
the time frame established by the applicable accounting requirements.
10. COMMITMENTS AND CONTINGENCIES
<F10A>A.CONSTRUCTION PROGRAM
The construction program is subject to periodic review and revision.
Actual construction expenditures may vary from estimates due to factors
such as revised load estimates, inflation, revised nuclear safety
regulations, delays, difficulties in the licensing process, the
availability and cost of capital, and the granting of timely and
adequate rate relief by regulatory commissions, as well as actions by
other regulatory bodies.
PSNH currently forecasts construction expenditures (including AFUDC) of
$195.5 million for the years 1995-1999, including $50.7 million for
1995. In addition, PSNH estimates that nuclear fuel requirements, for
its share of Millstone 3, will be $4.2 million for the years 1995-1999,
including $790,000 for 1995.
<F10B>B.PSNH RATE AGREEMENT
The Rate Agreement provided the financial basis for PSNH's Plan of
Reorganization (the Plan). The Rate Agreement calls for seven
successive 5.5 percent annual increases in PSNH's base rates for its
charges to retail customers (the Fixed-Rate Period). The first
increase was put into effect on January 1, 1990 and the remaining two
increases are scheduled to be put into effect annually beginning on
June 1, 1995. As discussed in Note 1J, "Recoverable Energy Costs," the
FPPAC protects PSNH from changes in fuel and purchased power costs.
Although the Rate Agreement provides an unusually high degree of
certainty as to PSNH's future retail rates, it also entails a risk when
sales are lower than anticipated or if PSNH should experience
unexpected increases in its costs other than those for fuel and
purchased power, since PSNH has agreed that it will not seek additional
rate relief during the Fixed-Rate Period, except in limited
circumstances. However, in order to provide protection from
significant variations from the costs assumed in base rates over the
Fixed-Rate Period, the Rate Agreement establishes a return on equity
(ROE) collar to prevent PSNH from earning a ROE in excess of an upper
limit or below a lower limit. To date, PSNH's ROE has been within the
limits of the ROE collar.
<F10C>C.ENVIRONMENTAL MATTERS
PSNH is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the disposal of toxic
substances and hazardous and solid wastes, and the handling and use of
chemical products. PSNH has an active environmental auditing and
training program and believes that it is in substantial compliance with
current environmental laws and regulations.
Changing environmental requirements could hinder the construction of
new generating units, transmission and distribution lines, substations,
and other facilities. The cumulative long-term, economic cost impact
of increasingly stringent environmental requirements cannot accurately
be estimated. Changing environmental requirements could also require
extensive and costly modifications to PSNH's existing generating units,
and transmission and distribution systems, and could raise operating
costs significantly. As a result, PSNH 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. PSNH may also encounter
significantly increased costs to remedy the environmental effects of
prior waste handling activities.
PSNH has recorded a liability for what it believes is, based upon
information currently available, its estimated environmental
remediation costs for waste disposal sites for which it expects to bear
legal liability. In most cases, the extent of additional future
environmental cleanup costs is 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 methods, and the possible effects of
technological changes. At December 31, 1994, the liability recorded by
PSNH for its estimated environmental remediation costs, excluding any
possible insurance recoveries or recoveries from third parties,
amounted to approximately $2 million.
PSNH cannot estimate the potential liability for future claims 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 PSNH's financial
position or future results of operations.
<F10D>D.NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first
$200 million of liability would be provided by purchasing the maximum
amount of commercially available insurance. Additional coverage of up
to a total of $8.3 billion would be provided by an assessment of $75.5
million per incident, levied on each of the 110 nuclear units that are
currently subject to the Secondary Financial Protection Program in the
United States, subject to a maximum assessment of $10 million per
incident per nuclear unit in any year. In addition, if the sum of all
public liability claims and legal costs arising from any nuclear
incident exceeds the maximum amount of financial protection, each
reactor operator can be assessed an additional 5 percent, up to
$3.8 million, or $415.3 million in total, for all 110 nuclear units.
The maximum assessment is to be adjusted at least every five years to
reflect inflationary changes. Under the terms of the Contract with
NAEC, PSNH would be obligated to pay for any assessment charged to NAEC
as a "cost of service." At December 31, 1994, based on PSNH's
ownership interests in Millstone 3, and NAEC's ownership interests in
Seabrook 1, PSNH's maximum liability would be $30.7 million per
incident. In addition, through PSNH's purchased power contracts with
the three operating Yankee regional nuclear generating companies, PSNH
would be responsible for up to an additional $11.1 million per
incident. The payments for PSNH's ownership interest in nuclear
generating facilities and costs resulting from the Contract with NAEC
would be limited to a maximum of $5.3 million per incident per year.
Effective January 1, 1995, insurance was purchased from Nuclear Mutual
Limited (NML) to cover the primary cost of repair, replacement, or
decontamination of utility property resulting from insured occurrences
with respect to PSNH's ownership interest in Millstone 3 and CY. All
companies insured with NML are subject to retroactive assessments if
losses exceed the accumulated funds available to NML. The maximum
potential assessment against PSNH with respect to losses arising during
the current policy year is approximately $0.5 million under the NML
primary property insurance program.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL) to cover (1) certain extra costs incurred in obtaining
replacement power during prolonged accidental outages with respect to
PSNH's Contract with NAEC; and (2) the excess cost of repair,
replacement, or decontamination or premature decommissioning of utility
property resulting from insured occurrences with respect to PSNH's
ownership interests in Millstone 3, CY, MY, and VY; and NAEC's
ownership interest in Seabrook. All companies insured with NEIL are
subject to retroactive assessments if losses exceed the accumulated
funds available to NEIL. The maximum potential assessments against
PSNH (including costs resulting from PSNH's Contract with NAEC) with
respect to losses arising during current policy years are approximately
$1.5 million under the replacement power policies and $11.3 million
under the excess property damage, decontamination, and decommissioning
policies. Although PSNH has purchased the limits of coverage currently
available from the conventional nuclear insurance pools, the cost of a
nuclear incident could exceed available insurance proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual
Atomic Energy Liability Underwriters, aggregating $200 million on an
industry basis for coverage of worker claims. All reactor operators
insured under this coverage are subject to retrospective assessments of
$3.1 million per reactor. The maximum potential assessments against
PSNH (including costs resulting from PSNH's Contract with NAEC) with
respect to losses arising during the current policy period are
approximately $1.9 million.
<F10E>E.PURCHASED POWER ARRANGEMENTS
PSNH, along with CL&P and WMECO, purchase approximately 10 percent of
their electricity requirements pursuant to long-term contracts with the
Yankee companies. Under the terms of its agreements, the company pays
its ownership share (or entitlement share) of generating costs, which
includes depreciation, taxes, operation and maintenance expenses, 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. PSNH's total cost of purchases under
these contracts for the units that are operating amounted to $23.4
million in 1994, $26.5 million in 1993 and $24.8 million in 1992. See
Note 1D, "Summary Of Significant Accounting Policies-Investments and
Jointly Owned Electric Utility Plant" and Note 4, "Nuclear
Decommissioning" for more information on the Yankee companies.
PSNH has entered into multiple purchases of capacity and energy from
nonutility generators pursuant to rate orders. These arrangements have
terms from 20 to 30 years, and require the company to purchase the
energy at specified prices or formula rates. For the 12 months ended
December 31, 1994, approximately 14 percent of NU system electricity
requirements was met by nonutility generators. The total cost to the
company of purchases under these arrangements amounted to $130 million
in 1994, $133.4 million in 1993, and $92.1 million in 1992. These
costs are eventually recovered through the company's rates. See Note
1J, "Summary of Significant Accounting Policies - Recoverable Energy
Costs" for further information.
In an effort to control costs from nonutility generators and as
required by the rate agreement, PSNH has been negotiating with 13
nonutility generators. As of February 1995, eight of those
negotiations were complete. This includes five hydroelectric
facilities that were renegotiated to convert their rate orders to long-
term contracts and three wood-burning facilities had either their rate
orders bought out or entered into a new contract. Mediation efforts
continue with the five wood burners that have not been settled.
PSNH entered into a buy-back agreement to purchase the capacity and
energy of the New Hampshire Electric Cooperative, Inc.'s (NHEC)
Seabrook entitlement and to pay all of NHEC's Seabrook costs for a ten-
year period which began July 1, 1990. The total cost of purchases
under this agreement was $15.7 million in 1994, $14.4 million in 1993,
and $13.8 million in 1992. Part of these costs is collected currently
through the FPPAC and part is deferred for future collection in
accordance with the Rate Agreement. In connection with the agreement,
NHEC agreed to continue as a firm-requirements customer of PSNH for 15
years.
The estimated annual cost of PSNH's significant purchased power
arrangements are as follows:
1995 1996 1997 1998 1999
-------------------------------------------------------------
(Millions of Dollars)
Yankee companies ......$ 27.3 $ 28.5$ 25.5 $ 30.5 $ 30.1
Nonutility generators . 116.3 121.6 123.9 126.0 128.1
NHEC .................. 16.5 16.5 25.1 33.2 32.8
<F10F>F.HYDRO-QUEBEC
Along with other New England utilities, PSNH entered into agreements to
support transmission and terminal facilities to import electricity from
the Hydro-Quebec system in Canada. PSNH is obligated to pay, over a
30-year period, its proportionate share of the annual operation,
maintenance, and capital costs of these facilities, which are currently
forecast to be $53.7 million for the years 1995-1999, including $12.0
million for 1995.
<F10G>G.DEFERRED RECEIVABLE FROM AFFILIATED COMPANY
At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance
with the phase-in under the Rate Agreement, it began accruing a
deferred return on a portion of its Seabrook investment. From May 16,
1991 to the Acquisition Date, PSNH accrued a deferred return of
$50.9 million. On the Acquisition Date, PSNH sold the $50.9 million
deferred return to NAEC as part of the Seabrook-related assets.
At the time PSNH transferred the deferred return to NAEC, it realized,
for income tax purposes, a gain that is deferred under the consolidated
income tax rules. This gain will be restored for income tax purposes
when the deferred return of $50.9 million, and the associated income
taxes of $32.9 million, are collected by NAEC through the Contract.
When NAEC recovers the $32.9 million in years eight through ten of the
Rate Agreement, it is obligated to make corresponding payments to PSNH.
On the Acquisition Date, PSNH recorded the $32.9 million of income
taxes associated with the deferred return as a deferred receivable from
NAEC, with a corresponding entry to deferred revenue, on its Balance
Sheet. In 1993, due to changes in tax rates, this amount was adjusted
to $33.3 million.
<F11> 11. DERIVATIVE FINANCIAL INSTRUMENTS
The company utilizes derivative financial instruments to manage well-
defined interest-rate risks. The company does not use them for trading
purposes.
PSNH has entered into an interest-rate cap contract with a financial
institution in order to reduce a portion of the interest-rate risk
associated with certain variable-rate tax-exempt pollution control revenue
bonds, as well as a portion of the PSNH Variable-Rate Term Loan. During
1994, there were three outstanding contracts held by PSNH, covering $225
million of its variable rate debt, with terms ranging from one to three
years. The contact entitles PSNH to receive from its counterparties the
amount, if any by which the interest payments on its variable-rate tax-
exempt pollution control revenue bond exceeds the J. J. Kenny High Grade
Index and the PSNH Variable-Rate Term Loan exceeds the three-month LIBOR
rate. These contracts are settled on a quarterly basis. As of December
31, 1994, PSNH had a total of $75 million in caps outstanding, with a
positive mark-to-market position of approximately $0.8 million.
PSNH is exposed to credit risk on the interest-rate caps if the
counterparties fail to perform their obligations. However, PSNH
anticipates that the counterparties will be able to fully satisfy their
obligations under the contracts.
<F12>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 requires investments in debt and equity securities to be presented
at fair value and was adopted by PSNH on a prospective basis as of January
1, 1994. There was no change in funding requirements of the trusts nor any
impact on earnings as a result of the adoption of SFAS 115.
Preferred stock and long-term debt: The fair value of PSNH's securities is
based upon the quoted market price for those issues or similar issues.
Adjustable rate securities are assumed to have a fair value equal to their
carrying value.
The carrying amounts of PSNH's financial instruments and the estimated fair
values are as follows:
At December 31, 1994 Carrying Amount Fair Value
-----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock subject to mandatory
redemption ........................$125,000 $127,500
Long-term debt -
First Mortgage Bonds .............. 342,500 342,931
Other long-term debt .............. 657,485 641,673
-----------------------------------------------------------------
At December 31, 1993 Carrying Amount Fair Value
-----------------------------------------------------------------
(Thousands of Dollars)
Preferred stock subject to mandatory
redemption ........................$125,000 $139,375
Long-term debt -
First Mortgage Bonds .............. 342,500 359,878
Other long-term debt .............. 751,485 783,389
The fair values shown above have been reported to meet disclosure
requirements and do not purport to represent the amounts at which those
obligations would be settled.
To the Board of Directors
of Public Service Company of New Hampshire:
We have audited the accompanying balance sheets of Public Service Company
of New Hampshire (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1994 and 1993, and the related
statements of income, common equity and cash flows for the years ended
December 31, 1994 and 1993 and the periods from January 1, 1992 to June 4, 1992
and June 5, 1992 to December 31, 1992. 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 Public Service Company of
New Hampshire as of December 31, 1994 and 1993, and the results of its
operations and its cash flows for the years ended December 31, 1994 and 1993 and
the periods from January 1, 1992 to June 4, 1992 and June 5, 1992 to
December 31, 1992, in conformity with generally accepted accounting principles.
As explained in Note 9B to the financial statements, effective January 1,
1993, Public Service Company of New Hampshire changed its methods of accounting
for postretirement benefits other than pensions.
/s/ Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
---------------------------------------------------------------------
This section contains management's assessment of PSNH's (the company)
financial condition and the principal factors having an impact on the
results of operations. The company is a wholly owned subsidiary of
Northeast Utilities (NU). This discussion should be read in conjunction
with the company's financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
Net income increased to approximately $77 million in 1994 from approximately $52
million in 1993. The increase from 1993 is a result of increased revenues from
retail rate increases, higher retail kilowatt-hour sales, and higher income from
the amortization of the company's regulatory liability.
In 1994, PSNH's retail kilowatt-hour sales rose by 2.0 percent over 1993, due in
large part to the beginning of an economic recovery in New England. Employment
levels have risen, unemployment rates have fallen, and personal income has
increased in New Hampshire. Retail sales were also affected by colder winter
weather in early 1994.
In 1995, PSNH expects little retail sales growth over 1994, primarily because of
the effects of higher interest rates on the economy and a return to normal
weather. Over the longer term, retail kilowatt-hour sales growth is expected to
be strong in New Hampshire, which by some measures has the fastest growing
economy in New England. In 1994, many businesses announced plans to expand in
New Hampshire. The company estimates that it will have compounded annual sales
growth of 1.9 percent from 1994 through 1999.
Competitive forces within the electric utility industry are continuing to
increase due to a variety of influences, including legislative and regulatory
actions, technological advances, and changes in consumer demand. PSNH has
developed, and is continuing to develop, a number of initiatives to retain and
continue to serve its existing customers and to expand its retail customer base.
The company believes the steps it is taking, including a companywide process
reengineering effort, will have significant, positive effects, including reduced
operating costs and improved customer service, in the next few years. The
company also benefits from a diverse retail base with no significant dependence
on any one retail customer or industry.
PSNH continues to operate predominantly in a state-approved franchise territory
under traditional cost-of-service regulation. Retail wheeling, under which a
retail customer would be permitted to select an electricity supplier and require
the local electric utility to transmit the power to the customer's site, is not
required in PSNH's service territory. Several bills related to retail wheeling
have been introduced in the New Hampshire legislature. To date, none of these
bills have been enacted. The chairman of the New Hampshire Public Utilities
Commission (NHPUC) has set up a roundtable discussion with legislators,
utilities, customers and other interested parties regarding competition in the
electric utility industry. In addition, a new entity, Freedom Electric Power
Company (FEPCO), has filed with the NHPUC for permission to do business as an
electric utility to serve selected large PSNH customers. PSNH and other New
Hampshire utilities are opposing FEPCO's petition before the NHPUC. Management
cannot assess the impact of any potential legislative or regulatory outcomes on
PSNH.
While retail competition is not required in the company's retail service
territory, competitive forces are nonetheless influencing retail pricing.
These forces include competition from alternate fuels such as natural gas,
competition from customer-owned generation, and regional competition for
business retention and expansion. PSNH's retail business group continues to
work with customers to address their concerns. PSNH has reached long-term rate
agreements with new and existing customers to gain or retain their business. In
general, these rate agreements have terms of about five years. Negotiated
retail rate reductions for PSNH customers under rate agreements in effect for
1994 amounted to approximately $3 million. Management believes that the
aggregate amount of negotiated retail rate reductions will increase in 1995, but
that the related agreements will continue to provide significant benefits to
PSNH, including the preservation of approximately 4 percent of retail revenues.
The company is also working with its regulators to address the needs of
customers more widely. PSNH has a seven-year rate agreement in effect through
May 1997. Management will continue to evaluate the use of agreements of this
type to keep retail rates competitive.
RATE MATTERS
PSNH follows accounting principles that allow the rate treatment for certain
events or transactions to be reflected. These principles may differ from the
accounting principles followed by nonregulated enterprises. Regulators may
permit incurred costs, which would normally be treated as expenses by non-
regulated enterprises, to be deferred as regulatory assets and recovered in
revenues at a later date. Regulatory assets at December 31, 1994 were
approximately $972 million. Based on current regulation, the company believes
that its use of regulatory accounting is still appropriate.
See the "Notes To Financial Statements," Note 1H, for further details on
regulatory accounting.
In June 1994, PSNH's base rates increased by 5.5 percent under a seven-year 1989
rate agreement approved by the NHPUC.
The costs associated with purchases by PSNH from certain nonutility generators
(NUGs) over the level assumed in rates are deferred and recovered over ten-year
periods through the Fuel and Purchased Power Adjustment Clause (FPPAC). At
December 31, 1994, the unrecovered deferrals were approximately $174 million.
PSNH is attempting to renegotiate these arrangements with the NUGs.
On September 23, 1994, the NHPUC approved settlement agreements with two wood-
fired NUGs covering approximately 20 megawatts (MW) of capacity. These two NUGs
gave up their rights to sell their output to PSNH in exchange for lump sum cash
payments by PSNH totaling approximately $40 million. The buyout payment was
added to the deferred balance of NUG costs. The savings resulting from the
agreements will be used to reduce the NUG deferred balance over the remaining
period of the cancelled arrangements. PSNH is involved in mediations with the
owners of the six remaining wood-fired facilities, which account for
approximately 87 MW of capacity. PSNH has reached an agreement with one of
these six NUGs, which calls for a payment by PSNH of $52 million in return for a
substantial reduction in the rates charged to PSNH. The agreement was filed
with the NHPUC in February 1995.
SEABROOK PERFORMANCE
The Seabrook plant operated at 61.6 percent of capacity for the year ended
December 31, 1994, compared with 89.8 percent in 1993 and a 1994 national
average of 73.2 percent. The lower 1994 capacity factor was primarily the
result of an unplanned outage early in the year and an extended refueling and
maintenance outage. The unit was taken out of service on January 25, 1994 when
an automatic trip from 100 percent power occurred when a main steam isolation
valve closed during quarterly surveillance testing. The unit returned to
service on February 18, 1994. The unit began its scheduled 57-day refueling and
maintenance outage on April 9, 1994. The unexpected discovery of reactor
coolant pump locking cups and a bolt in the reactor vessel contributed
substantially to the extension of the outage. The unit returned to service on
August 1, 1994 for an outage duration of 114 days. The next refueling outage is
scheduled for November 1995.
ENVIRONMENTAL MATTERS
NU devotes substantial resources to identify and then to meet the multitude of
environmental requirements it faces. PSNH has active auditing programs
addressing a variety of different regulatory requirements, including an
environmental auditing program to detect and remedy noncompliance with
environmental laws or regulations.
The company is potentially liable for environmental cleanup costs at a number of
sites both 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 December 31, 1994, the
liability recorded by the company, amounted to approximately $2 million, which
represents the highest cost probable at this time.
The company expects that the implementation of the 1990 Clean Air Act Amendments
(CAAA) as they relate to sulfur dioxide emissions will require only modest
emissions reductions for PSNH. The company is subject to more stringent
emission limits for nitrogen oxides (NOX) within the next five years under the
CAAA requirements. PSNH will install at Merrimack Station a selective catalytic
reduction (SCR) pollution control system by May 1995 to comply with CAAA
requirements. The cost of the SCR installation is approximately $22 million,
with approximately $10 million of costs incurred as of December 31,1994.
Additional capital costs of approximately $5-$7 million are expected to be
incurred to comply with NOX emission limits for 1999.
NUCLEAR DECOMMISSIONING
The company's estimated cost to decommission its share of Millstone 3 and North
Atlantic Energy Corporation's (NAEC) share of Seabrook is approximately $13
million and $137 million, respectively, in year-end 1994 dollars. Under the
terms of the Rate Agreement, the company is obligated to pay NAEC's share of
Seabrook's decommissioning costs, even if the unit is shut down prior to the
expiration of its operating license. In addition, the company's estimated cost
to decommission its shares of the regional nuclear generating units is estimated
to be approximately $48 million. These costs are being recognized over the lives
of the respective units and a portion of the costs is being recovered through
rates. Yankee Atomic Electric Company (YAEC) has begun component removal
activities related to the decommissioning of its nuclear facility. PSNH's
estimated obligation to YAEC has been recorded on its Balance Sheets.
Management expects that the company will continue to be allowed to recover these
costs.
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
this company, regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. The Financial Accounting Standards Board is
currently reviewing the accounting for removal costs, including decommissioning
and similar costs. If current electric utility industry accounting practices
for such decommissioning costs are changed: (1) annual provisions for
decommissioning could increase, (2) the estimated costs for decommissioning
could be recorded as a liability rather than as accumulated depreciation, and
(3) trust fund income from the external decommissioning trust could be reported
as investment income rather than as a reduction to decommissioning expense.
See the "Notes to Financial Statements," Note 4, for further information on
nuclear decommissioning.
PROPERTY TAXES
PSNH has had a significant court appeal for municipal property tax assessments
in the town of Bow, New Hampshire. The central issue in the case is the fair
market value of utility property. The company believes that the assessments
should be based on a fair market value that approximates net book cost. This is
the assessment level that taxing authorities are predominantly using throughout
Connecticut, Massachusetts, and some of New Hampshire. However, towns such as
Bow advocate a method that approximates reproduction costs.
PSNH's appeal of the property tax as assessed against them by Bow has been
dismissed by the Supreme Court of New Hampshire. The company estimates that,
for assessments in towns such as Bow, the change to the reproduction cost
methodology could result in property valuations approximately three times
greater than values approximating net book cost. If other towns adopt this
methodology, there could be a significant adverse impact on the company's future
results of operations and financial condition. However, the extent to which
other towns successfully adopt this methodology and any subsequent increase in
the company's property tax liability cannot be determined at this time.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations decreased approximately $8 million in 1994, as
compared with 1993, primarily due to higher payments to nonutility generators.
Cash used for financing activities was approximately $38 million lower in 1994,
as compared with 1993, primarily due to a lower repayment of short-term debt.
Cash used for investments was approximately $40 million higher in 1994, as
compared with 1993, primarily due to an increase in short-term loans to other NU
system companies under the NU system Money Pool.
The company has a more leveraged capital structure than most other investor-
owned public utilities and is required to make substantial interest payments.
The company's indebtedness under the Term Loan, Revolving Credit Facility, and
some of the company's pollution control revenue bonds bear interest at floating
rates to be set periodically, causing the company to be sensitive to prevailing
interest rates. The company has entered into interest rate cap contracts to
reduce a portion of the interest rate risk on certain variable-rate tax-exempt
pollution control revenue bonds and the variable-rate term loan. Any premiums
paid on these contracts are deferred and amortized over the life of the
contracts. The differential paid or received as interest rates change is
recognized in income when realized.
For further information on Derivatives, see the "Notes to Financial Statements,"
Note 11, "Derivative Financial Instruments," and Note 12, "Fair Value of
Financial Instruments."
PSNH is obligated to meet approximately $559 million of long-term debt and
preferred stock maturities and cash sinking-fund requirements during the 1995
through 1999 period, including approximately $94 million for 1995. The
company's Term Loan must be repaid in 16 quarterly installments of approximately
$24 million that commenced in August 1992. PSNH's Series A preferred stock has
an annual sinking fund of approximately $25 million beginning in 1997. The
company may need to supplement its internal cash generation with outside
financing, including additional borrowings if additional agreements are reached
with the wood-fired NUGs.
PSNH's construction program expenditures, including allowance for funds used
during construction (AFUDC), for the period 1995 through 1999 are estimated to
be approximately $196 million, including approximately $51 million for 1995.
The construction program's main focus is maintaining and upgrading the existing
transmission and distribution system, as well as nuclear and fossil-generating
facilities. NU does not foresee the need for new major generating facilities,
at least until the year 2009.
RESULTS OF OPERATIONS
PSNH's results of operations for the twelve months ended December 31, 1994 and
1993 and the period June 5, 1992 through December 31, 1992 reflect the results
after the acquisition of PSNH by NU on June 5, 1992. The results for the 1993
period compared to the 1992 period are not comparable because of the significant
impacts of the acquisition on the company's results.
OPERATING REVENUES
The components of the change in operating revenues for the past two years are
provided in the table below.
Change in Operating Revenues
Increase/(Decrease)
1994 vs. 1993 1993 vs. 1992
--------------------------------------------------------------------
(Millions of Dollars)
Regulatory decisions $20 $24
Fuel, purchased power
and FPPAC cost recoveries 32 23
Sales volume 6 7
Other revenues - 1
Sales to other utilities - (49)
1992 Escrowed revenues - (16)
----- ----
Total revenue change $58 ($10)
=== ====
Operating revenues increased approximately $58 million in 1994 from 1993.
Revenues related to regulatory decisions increased primarily because of the
effects of the June 1993 and 1994 retail rate increases. Fuel, purchased power,
and FPPAC cost recoveries increased primarily due to higher fuel and purchased
power costs. Sales volume increased as a result of higher retail sales from an
improving economy and colder winter weather. Retail sales increased 2.0 percent
in 1994 from 1993 sales levels.
Operating revenues decreased approximately $10 million in 1993 from 1992
primarily due to lower short-term power sales to other utilities as a result of
the elimination, effective with the acquisition, of sales to NU, and the one-
time impact in 1992 of $16 million of revenues released from escrow at the
acquisition date. These decreases were partially offset by retail rate
increases in June 1992 and 1993 and higher fuel, purchased power, and FPPAC cost
recoveries. Retail sales increased 1.4 percent in 1993 from 1992 sales levels.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power increased approximately $15 million in
1994, as compared to 1993, primarily due to an increase in purchased power.
Fuel, purchased and net interchange power decreased approximately $21 million
in 1993, as compared to 1992, primarily due to the timing in the recognition of
fuel expenses under the FPPAC.
OTHER OPERATION AND MAINTENANCE EXPENSES
Other operation and maintenance expenses increased by approximately $10 million
in 1994, as compared to 1993, primarily as a result of maintenance work during
the two outages at the Seabrook nuclear plant in 1994 and higher storm-related
expenses in 1994, partially offset by lower 1994 payroll and benefit costs and
the cost of an employee reduction program in 1993.
Other operation and maintenance expenses increased by approximately $14 million
in 1993, as compared to 1992, primarily as a result of the payments made by PSNH
to NAEC for costs associated with the Seabrook plant under the Seabrook Power
Contract, beginning June 5, 1992.
See "Notes to Financial Statements," Note 2, for further information on the
Seabrook Power Contract.
DEPRECIATION
Depreciation expense decreased $8 million in 1993 as compared to 1992, as a
result of the transfer of the company's investment in Seabrook to NAEC and the
inclusion of such costs in the Seabrook Power Contract.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased $12 million in 1994, as
compared to 1993, primarily due to the higher amortization in 1994 of the
regulatory liability recognized under a global settlement approved at the end of
1993. Approximately $128 million of pre-acquisition losses are being amortized
over six years as a credit to amortization expense. 1994 included a full year
of amortization as compared to only eight months of amortization in 1993.
Amortization of regulatory assets, net decreased $20 million in 1993, as
compared to 1992, primarily due to the amortization of the regulatory
liability recognized under the global settlement.
FEDERAL AND STATE INCOME TAXES
Federal and state income taxes increased approximately $18 million in 1994, as
compared to 1993, primarily because of higher taxable income.
Federal and state income taxes increased approximately $22 million in 1993, as
compared to 1992, primarily because of higher taxable income.
DEFERRED NUCLEAR PLANTS RETURN
The company has not recorded a deferred Seabrook return after June 4, 1992
because the company's investment in Seabrook was transferred to NAEC at the
acquisition date. Prior to the transfer of Seabrook to NAEC, a deferred return
was calculated on the portion of the Seabrook investment not reflected in rate
base.
OTHER INCOME, NET
Bankruptcy related expenses for the period prior to June 5, 1992, represent
costs associated with PSNH's bankruptcy. In 1988, PSNH filed a petition for
reorganization under Chapter 11 of the Bankruptcy Code.
The gain on generating projects of $6 million for the period prior to June 5,
1992, represents a first quarter 1992 adjustment related to the settlement of a
Seabrook contractor dispute and a Seabrook property tax abatement.
INTEREST CHARGES
Interest on long-term debt and other interest charges are lower for 1993, as
compared to 1992, due to the assumption by NAEC, at the acquisition date, of
the company's obligations under the 15.23 percent Notes, paydown of the Term
Loan and a reduction in borrowings under the revolving credit facility.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
---------------------------------------------------------------------------
SELECTED FINANCIAL DATA
---------------------------------------------------------------------------
<TABLE>
<CAPTION>
Jan. 1, 1994 Jan. 1, 1993 June 5, 1992* Jan. 1, 1992 May 16, 1991**
to to to to to
For the Periods Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991
------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Operating Revenues $922,039 $864,415 $492,559 | $381,769 $539,827 |
| |
Operating Income... 152,086 124,710 61,206 | 34,250 82,755 |
| |
Net Income (Loss)... 77,444 52,237 29,398 | 12,778 52,694 |
| |
At Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992* Dec. 31, 1991
------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Total Assets $2,845,967 $2,774,511 $2,793,768 | $2,693,414 $2,636,525 |
| |
Long-Term Debt (a).. 999,985 1,093,985 1,187,985 | 1,488,985 1,515,985 |
| |
Liabilities Subject to | |
Settlement (a).. - - - | - - |
| |
Preferred Stock Subject | |
to Mandatory Redemption (a) 125,000 125,000 125,000 | 125,000 125,000 |
| |
Prefered Stock Not Subject | |
to Mandatory Redemption - - - | - - |
| |
Obligations Under Seabrook | |
Power Contract and Other | |
Capital Leases (a) 887,967 856,559 787,826 | - - |
(a)Includes portions due within one year.
* PSNH was acquired by NU on June 5, 1992 - See Note 1 of Notes to Financial Statements.
**PSNH was reorganized on May 16, 1991.
</TABLE>
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Jan. 1, 1991 Jan. 1, 1990
to to
For the Periods May 15, 1991 Dec. 31, 1990
-----------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
Operating Revenues $246,281 $660,122
Operating Income... 21,616 63,059
Net Income (Loss)... (100,791) (210,012)
At May 15, 1991** Dec. 31, 1990
-----------------------------------------------------------------------
(Thousands of Dollars)
Total Assets $2,502,237 $2,490,534
Long-Term Debt (a).... - -
Liabilities Subject to
Settlement (a)...... 1,901,803 1,864,681
Preferred Stock Subject
to Mandatory Redemption (a) - 420,613
Prefered Stock Not Subject
to Mandatory Redemption - 48,587
Obligations Under Seabrook
Power Contract and Other
Capital Leases (a) - -
(a)Includes portions due within one year.
* PSNH was acquired by NU on June 5, 1992 - See Note 1 of Notes to
Financial Statements.
**PSNH was reorganized on May 16, 1991.
--------------------------------------------------------------------------
STATISTICS
--------------------------------------------------------------------------
Gross Electric Average
Utility Plant Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (Millions) Customer(kWh)(Average)(December 31,)
--------------------------------------------------------------------
1994 $2,058,654 11,008 6,768 400,775 1,374
1993 1,990,730 11,146 6,817 397,277 1,426
1992* 1,894,359 12,294 6,874 394,046 1,680
1991 1,782,894 11,377 7,184 390,793 2,639
1990 2,585,890 8,324 7,015 388,192 2,766
1989 2,555,404 7,656 7,311 383,497 2,786
STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
----------------------------------------------------------------------------
1994 March 31 June 30 September 30 December 31
----------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $ 249,279 $ 210,875 $ 227,976 $ 233,909
========= ========= ========= =========
Operating Income $ 43,441 $ 32,388 $ 38,713 $ 37,544
========= ========= ========= =========
Net Income (Loss) $ 24,278 $ 14,001 $ 19,262 $ 19,903
========= ========= ========= =========
----------------------------------------------------------------------------
1993 March 31 June 30 September 30 December 31
----------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $ 224,705 $ 192,360 $ 222,717 $ 224,633
========= ========= ========= =========
Operating Income $ 35,077 $ 21,682 $ 24,725 $ 43,226
========= ========= ========= =========
Net Income (Loss) $ 15,558 $ 2,995 $ 8,583 $ 25,101
========= ========= ========= =========
* PSNH was acquired by NU on June 5, 1992 - See Note 1A of Notes to
Financial Statements.
</TABLE>
Exhibit 13.5
1994
ANNUAL REPORT
NORTH ATLANTIC ENERGY CORPORATION
---------------------------------
1994 Annual Report
North Atlantic Energy Corporation
Index
Contents Page
-------- ----
Balance Sheets..................................... 1-2
Statements of Income............................... 3
Statements of Cash Flows........................... 4
Statements of Common Stockholder's Equity.......... 5
Notes to Financial Statements...................... 6-16
Report of Independent Public Accountants........... 17
Management's Discussion and Analysis of Financial
Condition and Results of Operations............... 18-20
Selected Financial Data............................ 21
Statistics......................................... 21
Statement of Quarterly Financial Data.............. 21
Bondholder Information............................. Back Cover
NORTH ATLANTIC ENERGY CORPORATION
BALANCE SHEETS
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
At December 31, 1994 1993
--------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
------
Utility Plant, at original cost:
Electric................................................ $769,379 $758,170
Less: Accumulated provision for depreciation......... 75,176 56,649
--------- ---------
694,203 701,521
Construction work in progress........................... 3,704 7,618
Nuclear fuel, net....................................... 19,797 23,339
--------- ---------
Total net utility plant............................. 717,704 732,478
--------- ---------
Other Property and Investments:
Nuclear decommissioning trusts, at market in 1994 and
at cost in 1993 (Note 8)<F8>........................... 10,342 7,881
Other, at cost.......................................... 222 -
--------- ---------
10,564 7,881
--------- ---------
Current Assets:
Cash and special deposits (Note 1K)<F1K>................ 8,166 8,404
Notes receivable from affiliated companies.............. 28,750 -
Receivables............................................. - 3,677
Receivables from affiliated companies................... 13,983 20,304
Materials and supplies, at average cost................. 10,036 7,353
Prepayments and other................................... 2,149 4,183
--------- ---------
63,084 43,921
--------- ---------
Deferred Charges:
Regulatory assets (Note 1G)<F1G>........................ 166,598 109,765
Unamortized debt expense................................ 4,834 5,507
Other................................................... 795 1,269
--------- ---------
172,227 116,541
--------- ---------
Total Assets........................................ $963,579 $900,821
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTH ATLANTIC ENERGY CORPORATION
BALANCE SHEETS
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
At December 31, 1994 1993
---------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock--$1 par value--authorized
and outstanding 1,000 shares in 1994 and 1993........... $ 1 $ 1
Capital surplus, paid in................................. 160,999 160,999
Retained earnings........................................ 59,236 38,701
--------- ---------
Total common stockholder's equity............... 220,236 199,701
Long-term debt (Note 4)<F4>.............................. 540,000 560,000
--------- ---------
Total capitalization............................ 760,236 759,701
--------- ---------
Current Liabilities:
Long-term debt--current portion.......................... 20,000 -
Accounts payable......................................... 4,073 3,999
Accounts payable to affiliated companies................. 38 2,389
Accrued interest......................................... 18,288 18,288
Accrued taxes............................................ 1,439 127
Deferred DOE obligation--current portion................. 845 845
Other.................................................... 329 -
--------- ---------
45,012 25,648
--------- ---------
Deferred Credits:
Accumulated deferred income taxes (Note 1I)<F1I>......... 120,250 74,772
Deferred obligation to affiliated company (Note 6)<F6>... 33,284 33,284
Deferred DOE obligation.................................. 3,553 3,941
Deferred Seabrook tax settlement obligation.............. 1,022 3,475
Other.................................................... 222 -
--------- ---------
158,331 115,472
--------- ---------
Commitments and Contingencies (Note 7)<F7>
Total Capitalization and Liabilities............ $963,579 $900,821
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
January 1, January 1, June 5,
1994 1993 1992
to to to
December 31, December 31, December 31,
For the Periods 1994 1993 1992(a)
-----------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Operating Revenues............................. $ 145,751 $ 125,408 $ 78,444
------------- ------------- -------------
Operating Expenses:
Operation --
Fuel...................................... 7,144 7,067 1,688
Other..................................... 37,929 35,656 25,305
Maintenance.................................. 14,951 7,858 9,413
Depreciation................................. 22,959 22,642 12,905
Federal and state income taxes (Note 5)<F5>.. 8,027 5,673 2,583
Taxes other than income taxes................ 11,791 12,794 10,428
------------- ------------- -------------
Total operating expenses............... 102,801 91,690 62,322
------------- ------------- -------------
Operating Income............................... 42,950 33,718 16,122
------------- ------------- -------------
Other Income:
Deferred Seabrook return--other
funds (Note 1H)<F1H>....................... 12,951 13,397 7,784
Other, net................................... 1,272 1,891 200
Income taxes--credit......................... 3,970 1,653 10,428
------------- ------------- -------------
Other income, net...................... 18,193 16,941 18,412
------------- ------------- -------------
Income before interest charges......... 61,143 50,659 34,534
------------- ------------- -------------
Interest Charges:
Interest on long-term debt................... 64,022 64,022 36,647
Other interest............................... (280) 45 200
Deferred Seabrook return--borrowed
funds (Note 1H)<F1H>....................... (33,134) (39,406) (15,016)
------------- ------------- -------------
Interest charges, net.................. 30,608 24,661 21,831
------------- ------------- -------------
Net Income..................................... $ 30,535 $ 25,998 $ 12,703
============= ============= =============
</TABLE>
(a) NAEC began operations on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
NORTH ATLANTIC ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------
January 1, January 1, June 5,
1994 1993 1992
to to to
December 31, December 31, December 31,
For the Periods 1994 1993 1992
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net Income................................................ $ 30,535 $ 25,998 $ 12,703
Adjustments to reconcile to net cash
from operating activities:
Depreciation............................................ 22,959 22,642 12,905
Deferred income taxes and investment tax credits, net... 34,449 37,121 8,505
Deferred return - Seabrook.............................. (46,085) (52,803) (22,800)
Other sources of cash................................... 5,096 9,050 5,491
Other uses of cash...................................... (2,842) (1,028) (8,104)
Changes in working capital:
Receivables............................................. 9,998 (790) (20,736)
Materials and supplies.................................. (2,683) (1,990) (2,288)
Accounts payable........................................ (2,277) 5,026 1,362
Accrued taxes........................................... 1,312 126 (4,970)
Other working capital (excludes cash)................... 2,363 822 2,330
----------- ------------ ------------
Net cash flows from (used for) operating activities......... 52,825 44,174 (15,602)
----------- ------------ ------------
Cash Flows From Financing Activities:
Issuance of common shares................................. - - 161,000
Issuance of long-term debt................................ - - 355,000
Net (decrease) increase in short-term debt................ - (18,500) 18,500
Cash dividends on common stock............................ (10,000) - -
----------- ------------ ------------
Net cash flows (used for) from financing activities......... (10,000) (18,500) 534,500
----------- ------------ ------------
Investment Activities:
Investment in plant:
Investment in Seabrook assets, net...................... - - (504,265)
Electric utility plant.................................. (11,256) (6,707) (6,307)
Nuclear fuel............................................ (1,227) (13,983) (511)
----------- ------------ ------------
Net cash flows used for investments in plant.............. (12,483) (20,690) (511,083)
NU System Money Pool...................................... (28,750) - -
Other investment activities, net.......................... (1,830) (2,844) (1,551)
----------- ------------ ------------
Net cash flows used for investments......................... (43,063) (23,534) (512,634)
Net (Decrease) Increase In Cash For The Period.............. (238) 2,140 6,264
Cash and special deposits - beginning of period............. 8,404 6,264 -
----------- ------------ ------------
Cash and special deposits - end of period................... $ 8,166 $ 8,404 $ 6,264
=========== ============ ============
Supplemental Cash Flow Information:
Cash paid (received) during the year for:
Interest, net of amounts capitalized during construction.. $ 64,056 $ 63,393 $ 18,166
=========== ============ ============
Income taxes.............................................. $ (34,988) $ (32,350) $ (16,000)
=========== ============ ============
NAEC began operations on June 5, 1992.
</TABLE>
The accompanying notes are an integral part of these financial statements.
NORTH ATLANTIC ENERGY CORPORATION
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 June 5, 1992 (b)............. $ - $ - $ - $ -
Net income for 1992................. 12,703 12,703
Issuance of 1,000 shares of common
stock, $1 par value............... 1 1
Premium on common stock............. 160,999 160,999
---------- ---------- --------- ----------
Balance at December 31, 1992............ 1 160,999 12,703 173,703
Net income for 1993................. 25,998 25,998
---------- ---------- --------- ----------
Balance at December 31, 1993............ 1 160,999 38,701 199,701
Net income for 1994................. 30,535 30,535
Cash dividends on common stock...... (10,000) (10,000)
---------- ---------- --------- ----------
Balance at December 31, 1994............ $ 1 $ 160,999 $ 59,236 $ 220,236
========== ========== ========= ==========
</TABLE>
(a) The company had dividend restrictions imposed by its long-term debt
agreement and was effectively prohibited by the agreement from the
distribution of any dividends through May 1993. After that time, all
retained earnings are available plus an allowance of $10 million.
(b) NAEC began operations on June 5, 1992.
The accompanying notes are an integral part of these financial statements.
NORTH ATLANTIC ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
<F1A>A. GENERAL
North Atlantic Energy Corporation (NAEC or the Company) is a wholly
owned subsidiary of Northeast Utilities (NU). NAEC was incorporated on
September 20, 1991 for the purpose of acquiring Public Service Company
of New Hampshire's (PSNH) ownership interest in the Seabrook nuclear
project (Seabrook). The company has no employees. Upon NU's
acquisition of PSNH on June 5, 1992 (Acquisition Date), PSNH's 35.6
percent share of the Seabrook nuclear power plant (Seabrook 1) and
other Seabrook-related assets were transferred to NAEC. NAEC also
acquired PSNH's 35.6 percent interest in the nuclear fuel for
Seabrook 1 and the cancelled Seabrook 2. In addition, it acquired from
PSNH ownership of the approximately 719 acres of exclusion area land
which surrounds the location of the two Seabrook units. NAEC does not
operate Seabrook 1, which at the Acquisition Date, was being operated
by the New Hampshire Yankee Division (NHY) of PSNH. Effective June 29,
1992, North Atlantic Energy Service Corporation (NAESCO, another newly
formed, wholly owned, subsidiary of NU), replaced NHY as the managing
agent and represents the Seabrook joint owners, including NAEC, in the
operation of Seabrook 1. On June 29, 1992, all NHY employees became
employees of NAESCO.
On February 15, 1994, NAEC acquired Vermont Electric Generation and
Transmission Cooperative's (VEG&T) 0.4 percent ownership interest of
Seabrook for approximately $6.4 million.
The company, The Connecticut Light and Power Company, PSNH, Western
Massachusetts Electric Company, and Holyoke Water Power Company are the
operating subsidiaries comprising the Northeast Utilities system (the
system) and are wholly owned by NU. Other wholly owned subsidiaries of
NU provide substantial support services to the system. Northeast
Utilities Service Company (NUSCO) supplies centralized accounting,
administrative, data processing, engineering, financial, legal,
operational, planning, purchasing, and other services to the system
companies. Northeast Nuclear Energy Company acts as agent for system
companies in constructing and operating the Millstone nuclear
generating facilities.
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.
<F1B>B. RECLASSIFICATIONS
Certain reclassifications of prior years' data have been made to
conform with the current year's presentation.
<F1C>C. JOINTLY OWNED UTILITY PLANT
As of December 31, 1994, NAEC has a 35.98 percent joint-ownership
interest in Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells
all of its share of the power generated by Seabrook 1 to PSNH. As of
December 31, 1994 and 1993, plant-in-service included approximately
$707.8 million and $758.1 million, respectively, and the accumulated
provision for depreciation included approximately $63.1 million and
$56.6 million, respectively, for NAEC's share of Seabrook 1. NAEC's
share of Seabrook 1 expenses is included in the operating expenses on
the accompanying Statements of Income. In February 1994, NAEC
purchased an additional 0.4 percent share of Seabrook 1 from VEG&T.
<F1D>D. 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 FERC. Major facilities are depreciated from the time they are
placed in service. For other than major facilities, depreciation
factors are applied to the average plant-in-service during the period.
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. For Seabrook 1, the costs of removal, less
salvage, that have been funded through external decommissioning trusts
will be paid with funds from the trusts and charged to the accumulated
reserve for decommissioning included in the accumulated provision for
depreciation over the expected service life of the plant. See Note 2,
"Nuclear Decommissioning," for additional information.
The depreciation rates for the several classes of electric plant-in-
service are equivalent to a composite rate of 3.3 percent in 1994 and
3.2 percent in 1993 and 1992.
<F1E>E. 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 NAEC, are subject to
the provisions of the 1935 Act. Arrangements among the system
companies, outside agencies, and other utilities covering inter-
connections, interchange of electric power, and sales of utility
property are subject to regulation by the Federal Energy Regulatory
Commission (FERC) and/or the SEC. The company is subject to further
regulation for rates, accounting, and other matters by the FERC and the
New Hampshire Public Utilities Commission (NHPUC).
<F1F>F. SEABROOK POWER CONTRACT
On June 5, 1992, NAEC and PSNH entered into the Seabrook Power Contract
(Contract), under which PSNH is obligated to buy from NAEC, and NAEC is
obligated to sell to PSNH, all of NAEC's original 35.6 percent
ownership share of the capacity and output of Seabrook 1 for a period
equal to the length of the Nuclear Regulatory Commission's (NRC) full
power operating license for Seabrook 1. The Contract is included as
part of the rate agreement between PSNH and the state of New Hampshire
(the Rate Agreement). Under the Contract, PSNH is unconditionally
obligated to pay NAEC's cost of service during this period whether or
not Seabrook 1 is operating. NAEC's cost of service includes all of
its Seabrook-related costs, including operation and maintenance
expense, fuel expense, property tax expense, depreciation expense, and
certain overhead and other costs.
The Contract established the value of the initial investment in
Seabrook at $700-million (Initial Investment) and the initial
investment in nuclear fuel at $0. NAEC is depreciating its Initial
Investment on a straight-line basis over the remaining term of Seabrook
1's full power operating license. Any subsequent additions to
Seabrook 1 will be depreciated on a straight-line basis over the
remaining term of the Contract at the time the additions are brought
into service. The Contract provides that NAEC's return on its allowed
investment in Seabrook 1 (its investment in working capital, fuel,
capital additions after the date of commercial operation of Seabrook 1
and a portion of the Initial Investment) is calculated based on NAEC's
actual capitalization from time to time over the term of the Contract,
which includes its actual debt and preferred equity costs, and a common
equity cost of 12.53 percent for the first ten years of the Contract,
and thereafter at an equity rate of return to be fixed in a filing with
FERC.
If Seabrook 1 is shut down prior to the expiration of the NRC operating
license term, PSNH will be unconditionally required to pay NAEC
termination costs for 39 years, less the period during which Seabrook 1
has operated. These payments are designed to reimburse NAEC for its
share of Seabrook 1 cancellation and decommissioning costs and to
provide NAEC a return of and on any undepreciated balance of its
Initial Investment in the plant over the then-remaining term of the
Contract, and the return of and on any capital additions to the plant
made after the Acquisition Date over a period of five years after shut
down (net of any tax benefits to NAEC attributable to such shut down).
NAEC is selling the output from the additional 0.4 percent Seabrook
interest purchased from VEG&T on February 15, 1994 to PSNH under an
agreement that has been approved by the FERC and is substantially
similar to the Seabrook Power Contract between PSNH and NAEC that was
effective on the Acquisition Date.
<F1G>G. REGULATORY ACCOUNTING
NAEC follows accounting policies that reflect the impact of the rate
treatment of certain events or transactions that differ from generally
accepted accounting principles for those events or transactions
followed by nonregulated enterprises. Under regulatory accounting,
assuming that future revenues are expected to be sufficient to provide
recovery, regulators may permit incurred costs, normally treated as
expenses, to be deferred and recovered in revenues at a later date.
Regulatory accounting is unique in that the actions of a regulator can
provide reasonable assurance of the existence of an asset. Regulators,
through their actions, may also reduce or eliminate the value of an
asset, or create a liability. If the economic entity no longer comes
under the jurisdiction of a regulator or external forces, such as a
move to a competitive environment, effectively limiting the influence
of cost-of-service based rate regulation, the entity may be forced to
abandon regulatory accounting, requiring a reexamination and potential
write-off of net regulatory assets. NAEC continues to be subject to
cost-of-service based rate regulation. Based on current regulation,
NAEC believes that its use of regulatory accounting is still
appropriate.
The components of regulatory assets are as follows:
At December 31, 1994 1993
--------------------------------------------------------------
(Thousands of Dollars)
Deferred costs-Seabrook (Note 1H) .... $131,513 $ 85,428
Income taxes, net (Note 1I) .......... 30,461 19,432
Recoverable energy costs (Note 1J) ... 4,624 4,905
-------- ---------
..................................... $166,598 $ 109,765
======== =========
<F1H>H. DEFERRED COST - SEABROOK
NAEC is phasing into rates the recoverable portions of its investment
in Seabrook 1. NAEC is deferring costs as part of its phase-in plan.
Its plan is in compliance with SFAS No. 92, Regulated Enterprises -
Accounting for Phase-In Plans.
As prescribed by the Rate Agreement, NAEC is phasing in its investment
in Seabrook 1. As of December 31, 1994, the portion of the investment
on which NAEC is entitled to earn a cash return was 70 percent and will
increase by 15 percent in each of the next two years beginning May 1,
1995. From the Acquisition Date through December 31, 1994, NAEC
recorded $131.5 million of deferred return on the excluded portion of
its investment in Seabrook 1, which has been recorded in "Regulatory
Assets" on the Balance Sheets. The deferred return on the excluded
portion of NAEC's investment in Seabrook 1 will be recovered with
carrying charges beginning six months after the end of PSNH's fixed-
rate period (which continues through May 1997) and will be fully
recovered by May 2001.
<F1I>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 income
subject to tax) is accounted for in accordance with the ratemaking
treatment of the FERC. See Note 5, "Income Tax Expense," for the
components of income tax expense.
When NU acquired PSNH on June 5, 1992, PSNH and NAEC became parties to
the Tax Allocation Agreement among the members of the NU system. The
Tax Allocation Agreement requires each member of the NU system to pay
to NU the amount, if any, that would have been its federal income tax
liability if it had filed a separate return, with certain adjustments,
and requires NU to distribute the excess of the sum of such payments
over the NU system's consolidated federal income tax liability among
those members of the NU system that had tax items that reduced the NU
system's current consolidated tax liability. A substantial portion of
NAEC's cash flow for the first few years of operations is expected to
consist of payments made by NU to NAEC under the Tax Allocation
Agreement. The amount of such payments will decrease over time but is
expected to remain substantial during the first few years of operations
when NAEC is expected to incur losses for tax purposes due to the
accelerated tax depreciation of Seabrook 1. Under the Tax Allocation
Agreement, NAEC's tax losses may be utilized to offset taxable income
of the NU system and NU is required, under the Tax Allocation
Agreement, to pay NAEC for the use of such tax benefits. Such tax
losses, if not fully utilized in the taxable year in which they were
incurred, may be carried back to each of the three taxable years of the
NU system preceding the taxable year in which they are incurred. If
the NU system does not have enough taxable income in the taxable year
in which such losses are incurred or in the preceding taxable years to
permit it to take full advantage of such tax losses, or if the NU
system is in an alternative minimum tax position in any such year, then
the amount of payments under the Tax Allocation Agreement to NAEC will
be decreased and NAEC's cash flow will be adversely affected. No
assurance can be given that NAEC's cash flow will not be adversely
affected in subsequent years by the inability of the other members of
the NU system to utilize fully the tax losses expected to be incurred
by NAEC.
In 1992, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income
tax accounting standards. NAEC adopted SFAS 109, on a prospective
basis, during the first quarter of 1993. The adoption of SFAS 109 has
not had a material effect on the net income or on the balance sheet of
the company. As it is probable that the increase in deferred tax
liabilities will be recovered from customers through rates, NAEC also
established a regulatory asset.
The tax effect of the temporary differences which give rise to the
accumulated deferred tax obligation are as follows:
At December 31, 1994 1993
-------------------------------------------------------------
(Thousands of Dollars)
Accelerated depreciation and other
plant-related differences ........ $ 93,486 $ 46,184
Regulatory assets-income tax gross up 7,223 6,801
Other .............................. 19,541 21,787
-------- --------
................................... $120,250 $ 74,772
======== ========
<F1J>J. RECOVERABLE ENERGY COSTS
Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed for
its proportionate shares 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.
NAEC has begun to recover these costs.
<F1K>K. CASH AND SPECIAL DEPOSITS
Cash and special deposits at December 31, 1994 and 1993 included $5.7
million and $7.3 million, respectively, in special deposits that will
be used to fund the company's share of future Seabrook operational
costs.
<F2>2. NUCLEAR DECOMMISSIONING
A 1994 Seabrook decommissioning study, which is currently under review by
the New Hampshire Decommissioning Financing Committee, confirmed that
complete and immediate dismantlement at retirement is the most viable and
economic method of decommissioning Seabrook 1. Decommissioning studies are
reviewed and updated periodically to reflect changes in decommissioning
requirements, technology, and inflation.
NAEC's 36 percent ownership of the estimated cost of decommissioning
Seabrook 1 (utilizing the currently approved decommissioning study), in
year-end 1994 dollars, is $137.3 million. These estimated costs have been
levelized and assume after-tax earnings on the Seabrook decommissioning
funds of 6.1 percent. Future escalation rates in decommissioning costs for
Seabrook are assumed. Nuclear decommissioning costs are accrued over the
expected service life of the unit and are included in depreciation expense
on the Statements of Income. Nuclear decommissioning costs amounted to
$2.7 million in 1994, $2.6 million in 1993 and $1.4 million in 1992.
Nuclear decommissioning, as a cost of removal, is included in the
accumulated provision for depreciation on the Balance Sheets. At
December 31, 1994, the balance in the accumulated reserve for
decommissioning amounted to $10.3 million. See "Nuclear Decommissioning"
in the Management's Discussion and Analysis for a discussion of changes
being considered by the FASB related to accounting for decommissioning
costs.
Under the terms of the Rate Agreement, PSNH is obligated to pay NAEC's
share of Seabrook's decommissioning costs, even if the unit is shut down
prior to the expiration of its operating license. NAEC's portion of the
cost of decommissioning Seabrook 1 is paid to an independent
decommissioning trust, held by a financing fund managed by the state of New
Hampshire.
As of December 31, 1994, NAEC (including pre-Acquisition Date payments made
by PSNH) has paid approximately $10.1 million into Seabrook 1's
decommissioning trust. Earnings on the decommissioning trust increase the
decommissioning trust balance and the accumulated reserve for
decommissioning. Due to NAEC's adoption, effective January 1, 1994, of
SFAS 115, Accounting for Certain Investments in Debt and Equity Securities,
unrealized gains and losses associated with the decommissioning trust also
impact the balance of the trust and the accumulated reserve for
decommissioning.
Changes in requirements or technology, the timing of funding or
dismantling, or adoption of a decommissioning method other than immediate
dismantlement, would change decommissioning cost estimates. Because
allowances for decommissioning have increased significantly in recent
years, PSNH may need to increase its payments in future years to offset the
effects of any insufficient rate recoveries in previous years.
<F3>3. SHORT-TERM DEBT
NAEC is a limited participant in the Northeast Utilities System Money Pool
(Pool). As a limited participant, NAEC is limited to borrowing funds
provided by NU parent. 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. 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
December 31, 1994 and 1993, NAEC had no outstanding borrowings from the
Pool.
Maturities of NAEC's short-term debt obligations were for periods of three
months or less.
The amount of short-term borrowings that may be incurred by the system
companies is subject to periodic approval by the SEC under the 1935 Act.
Under the SEC restrictions, NAEC was authorized, as of January 1, 1995, to
incur short-term borrowings up to a maximum of $50 million.
<F4>4. LONG-TERM DEBT
Details of long-term debt outstanding are:
December 31
-----------
1994 1993
----------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds:
9.05% Series A, due 2002 ..... $355,000 $355,000
Notes:
15.23% due 2000 ............. 205,000 205,000
Less: Amounts due within one year 20,000 -
-------- --------
Long-term debt, net .... $540,000 $560,000
======== ========
Long-term debt maturities and cash sinking-fund requirements on debt
outstanding at December 31, 1994 for the years 1995 through 1999 are
$20,000,000 annually for 1995-1998 and $70,000,000 in 1999.
The Series A Bonds are not redeemable prior to maturity except out of
proceeds of sales of property subject to the lien of the Series A First
Mortgage Bond Indenture (Indenture), at general redemption prices
established by the Indenture, and out of condemnation or insurance proceeds
and through the operation of the sinking fund discussed above.
Essentially all of NAEC's utility plant is subject to the lien of its
Indenture.
<F5>5. INCOME TAX EXPENSE
The components of the federal and state income tax provisions are:
<TABLE>
<CAPTION>
January 1, 1994 January 1 to June 5,
to December 31, 1993 to
For the Periods December 31, 1994 (Note 1I) December 31, 1992
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
Current income taxes:
Federal $(30,553) $(33,225) $(16,350)
State 161 124 -
-------- -------- --------
Total current (30,392) (33,101) (16,350)
-------- -------- --------
Deferred income taxes, net:
Federal 34,449 37,199 16,240
State 0 (78) 1,979
-------- -------- ---------
Total deferred 34,449 37,121 18,219
-------- -------- ---------
Total income tax expense $ 4,057 $ 4,020 $ 1,869
========= ========= =========
The components of total income tax expense are classified as follows:
Income taxes charged to operating
expenses $ 8,027 $ 5,673 $ 2,583
Income taxes associated with allowance for
funds used during construction (AFUDC)
and deferred Seabrook 1 return -
borrowed funds - - 9,714
Other income taxes - credit (3,970) (1,653) (10,428)
--------- --------- ---------
Total income tax expense $ 4,057 $ 4,020 $ 1,869
========= ========= =========
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
January 1, 1994 January 1 to June 5,
to December 31, 1993 to
For the Periods December 31, 1994 (Note 1I) December 31, 1992
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Depreciation $22,783 $23,000 $16,146
Alternative minimum tax 73 1,250 (7,641)
AFUDC and deferred Seabrook
return, net 11,597 13,792 9,714
Property taxes - (1,003) -
Other (4) 82 -
------- ------- -------
Deferred income taxes, net $34,449 $37,121 $18,219
======== ======= =======
A reconciliation between income tax expense and the expected tax expense at the applicable
statutory rate is as follows:
January 1, 1994 January 1 to June 5,
to December 31, 1993 to
For the Periods December 31, 1994 (Note 1I) December 31, 1992
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Expected federal income tax at
35 percent of pretax income for
1994 and 1993 and at
34 percent for 1992 $12,107 $10,506 $ 4,954
Tax effect of differences:
Depreciation differences (2,087) (1,481) (1,546)
Deferred Seabrook return -
other funds (4,533) (4,689) (2,647)
State income taxes, net of
federal benefit 104 30 1,306
Other, net (1,534) (346) (198)
-------- -------- --------
Total income tax expense $ 4,057 $ 4,020 $ 1,869
======== ======== ========
</TABLE>
<F6>6. DEFERRED OBLIGATION TO AFFILIATED COMPANY
At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance
with the phase-in under the Contract, it began accruing a deferred return
on a portion of its Seabrook investment. From May 16, 1991 to the
Acquisition Date, PSNH accrued a deferred return of $50.9 million. On the
Acquisition Date, PSNH transferred the $50.9 million deferred return to
NAEC as part of the Seabrook-related assets.
At the time PSNH sold the deferred return to NAEC, it realized, for income
tax purposes, a gain that is deferred under the consolidated income tax
rules. This gain will be restored for income tax purposes when the
deferred return of $50.9 million, and the associated income taxes of
$32.9 million, are collected by NAEC through the Contract. When NAEC
recovers the $32.9 million in years eight through ten of the Rate
Agreement, it is obligated to make corresponding payments to PSNH.
On the Acquisition Date, NAEC recorded the $32.9 million of income taxes
associated with the deferred return as an adjustment to the purchase price
of the Seabrook-related assets, with a corresponding obligation to PSNH, on
its Balance Sheet. In 1993, due to changes in tax rates, this amount was
adjusted to $33.3 million.
7. COMMITMENTS AND CONTINGENCIES
<F7A>A. SEABROOK 1 CONSTRUCTION PROGRAM
The construction program for Seabrook 1 is subject to periodic review
and revision. Actual construction expenditures may vary from estimates
due to factors such as inflation, revised nuclear safety regulations,
delays, difficulties in the licensing process, the availability and
cost of capital, and other actions taken by regulatory bodies.
NAEC currently forecasts construction expenditures (including AFUDC)
for its share of Seabrook 1 to be $31.9 million for the years 1995-
1999, including $5.0 million for 1995. In addition, NAEC estimates
that its share of Seabrook 1 nuclear fuel requirements will be
$46.1 million for the years 1995-1999, including $9.6 million for 1995.
<F7B>B. ENVIRONMENTAL MATTERS
NAEC is subject to regulation by federal, state, and local authorities
with respect to air and water quality, handling the disposal of toxic
substances and hazardous and solid wastes, and the handling and use of
chemical products. NAEC has an active environmental auditing and
training program and believes that it is in substantial compliance with
current environmental laws and regulations.
Changing environmental requirements could hinder future construction.
The cumulative long-term, economic cost impact of increasingly
stringent environmental requirements cannot be accurately estimated.
Changing environmental requirements could also require extensive and
costly modifications to NAEC's existing investment in Seabrook 1 and
could raise operating costs significantly. As a result, NAEC may incur
significant additional environmental costs, greater than amounts
included in cost of removal and other reserves, in connection with the
generation of electricity and the storage, transportation, and disposal
of by-products and wastes. NAEC may also encounter significantly
increased costs to remedy the environmental effects of prior waste
handling activities.
In most cases, the extent of additional future environmental cleanup
costs is 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.
NAEC cannot estimate the potential liability for future claims that may
be brought against it. However, considering known facts and existing
laws, and regulatory practices, management does not believe the matters
disclosed above will have a material effect on NAEC's financial
position or future results of operations.
<F7C>C. NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. The first
$200 million of liability would be provided by purchasing the maximum
amount of commercially available insurance. Additional coverage of up
to a total of $8.3 billion would be provided by an assessment of
$75.5 million per incident, levied on each of the 110 nuclear units
that are currently subject to the Secondary Financial Protection
Program in the United States, subject to a maximum assessment of
$10 million per incident per nuclear unit in any year. In addition, if
the sum of all public liability claims and legal costs arising from any
nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5 percent, up to
$3.8 million, or $415.3 million in total, for all 110 nuclear units.
The maximum assessment is to be adjusted at least every five years to
reflect inflationary changes. At December 31, 1994, based on NAEC's
ownership interest in Seabrook 1, the maximum liability would be $28.5
million per incident. Payments for NAEC's ownership interest in
Seabrook 1 would be limited to a maximum of $3.6 million per incident
per year.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL) to cover the cost of repair, replacement, or decontamination or
premature decommissioning of utility property resulting from insured
occurrences with respect to NAEC's ownership interest in Seabrook 1.
All companies insured with NEIL are subject to retroactive assessments
if losses exceed the accumulated funds available to NEIL. The maximum
potential assessments against NAEC with respect to losses arising
during current policy years are approximately $8.4 million under the
property damage, decontamination, and decommissioning policies.
Although NAEC has purchased the limits of coverage currently available
from the conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual
Atomic Energy Liability Underwriters, aggregating $200 million on an
industry basis for coverage of worker claims. All companies insured
under this coverage are subject to retrospective assessments of $3.1
million per reactor. The maximum potential assessments against NAEC
with respect to losses arising during the current policy period are
approximately $1.1 million.
Under the terms of the Contract, any nuclear insurance assessments
described above would be passed on to PSNH as a "cost of service."
<F8>8. 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, special deposits, and nuclear decommissioning trust: The carrying
amounts approximate fair value.
SFAS 115 requires investment in debt and equity securities to be presented
at fair value and was adopted by the company on a prospective basis as of
January 1, 1994. As a result of the adoption of SFAS 115, the investments
held by the decommissioning trust decreased by approximately $850 thousand
as of December 31, 1994, with a corresponding offset to the accumulated
provision for depreciation. There was no change in the funding
requirements of the trust nor any impact on earnings as a result of the
adoption of SFAS 115.
Long-term debt: The fair value of NAEC's long-term debt is based upon the
quoted market price for those issues or similar issues.
The carrying amounts of NAEC's financial instruments and the estimated fair
values are as follows:
At December 31, 1994 Carrying Amount Fair Value
----------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bond ............ $355,000 $351,450
Other long-term debt ........... 205,000 242,925
At December 31, 1993 Carrying Amount Fair Value
------------------------------------------------------------------
(Thousands of Dollars)
First Mortgage Bonds ........... $355,000 $373,496
Other long-term debt ........... 205,000 254,057
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.
NORTH ATLANTIC ENERGY CORPORATION
------------------------------------------------------------------
Report of Independent Public Accountants
------------------------------------------------------------------
To the Board of Directors
of North Atlantic Energy Corporation:
We have audited the accompanying balance sheets of North Atlantic Energy
Corporation (a New Hampshire corporation and a wholly owned subsidiary of
Northeast Utilities) as of December 31, 1994 and 1993, and the related
statements of income, common stockholder's equity, and cash flows for the year
ended December 31, 1994 and 1993 and the period from June 5, 1992 to
December 31, 1992. 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 North Atlantic Energy
Corporation as of December 31, 1994 and 1993, and the results of its operations
and its cash flows for the years ended December 31, 1994 and 1993 and the
period from June 5, 1992 to December 31, 1992, in conformity with generally
accepted accounting principles.
/s/ Arthur Andersen LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
February 17, 1995
NORTH ATLANTIC ENERGY CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
---------------------------------------------------------------------
This section contains management's assessment of NAEC's (the company)
financial condition and the principal factors having an impact on the
results of operations. The company is a wholly-owned subsidiary of
Northeast Utilities (NU). This section should be read in conjunction
with the company's financial statements and footnotes.
FINANCIAL CONDITION
OVERVIEW
On June 5, 1992 (Acquisition Date), NU acquired Public Service Company of New
Hampshire (PSNH), and PSNH's 35.6 percent share of the Seabrook 1 nuclear
power plant (Seabrook 1) and other Seabrook-related assets were transferred to
the company. At the Acquisition Date, PSNH and the company entered into the
Seabrook Power Contract (Contract), under which PSNH is obligated to buy from
the company, and the company is obligated to sell to PSNH, all of the company's
capacity and output of Seabrook for a period equal to the length of the Nuclear
Regulatory Commission full-power operating license for Seabrook (through 2026).
Under the Contract, PSNH is unconditionally obligated to pay the company's
"cost of service" during the period whether or not Seabrook is operating and
without regard to the cost of alternative sources of power. In addition, PSNH
will be obligated to pay decommissioning and project cancellation costs after
the termination of the operating license.
The company's "cost of service" includes all of its prudently incurred
Seabrook-related costs, including operation and maintenance expense, fuel
expense,property tax expense, depreciation expense, certain overhead and other
costs,and a phased-in return on its Seabrook investment. The Contract
established the initial recoverable investment in Seabrook at $700 million
(Initial Investment), plus any capital additions, net of depreciation.
The company's only assets are Seabrook and other Seabrook-related assets and
its only source of revenue is the Contract. PSNH's obligations under the
Contract are solely its own and have not been guaranteed by NU. The Contract
contains no provisions entitling PSNH to terminate its obligations. If,
however, PSNH were to fail to perform its obligations under the Contract, the
company would be required to find other purchasers for Seabrook power.
RATE MATTERS
NAEC follows accounting principles that allow the rate treatment for certain
events or transactions to be reflected. These principles may differ from the
accounting principles followed by nonregulated enterprises. Regulators may
permit incurred costs, which would normally be treated as expenses by
nonregulated enterprises, to be deferred as regulatory assets and recovered in
revenues at a later date. Regulatory assets at December 31, 1994 were
approximately $167 million. Based on current regulation, the company believes
that its use of regulatory accounting is still appropriate.
As of December 31, 1994, NAEC has included in rates $490 million of its
Seabrook investment. The remaining investment ($210 million) will be phased
into rates over the next two years, beginning in May 1995. As of December 31,
1994, the deferred return associated with the amount of investment that has not
been included in rates was approximately $183 million, including approximately
$51 million which is recorded as utility plant. This amount and the additional
deferred amounts associated with the remaining phase-in will be recovered under
NAEC's Contract with PSNH over the period December 1997 through May 2001.
SEABROOK PERFORMANCE
The Seabrook plant operated at 61.6 percent of capacity for the year ended
December 31, 1994, compared with 89.8 percent in 1993 and a 1994 national
average of 73.2 percent. The lower 1994 capacity factor was primarily the
result of an unplanned outage earlier in the year and an extended refueling and
maintenance outage. The unit was taken out of service on January 25, 1994 when
an automatic trip from 100 percent power occurred when a main steam isolation
valve closed during quarterly surveillance testing. The unit returned to
service on February 18, 1994. The unit began its scheduled 57-day refueling
and maintenance outage on April 9, 1994. The unexpected discovery of reactor
coolant pump locking cups and a bolt in the reactor vessel contributed
substantially to the duration of the outage. The unit returned to service on
August 1, 1994 for an outage duration of 114 days. The next refueling outage
is scheduled for November 1995.
ENVIRONMENTAL MATTERS/NUCLEAR DECOMMISSIONING
NAEC is subject to regulation by federal, state, and local authorities with
respect to air and water quality, handling and the disposal of toxic substances
and hazardous and solid wastes, and the handling and use of chemical products.
The cumulative long-term economic cost impact of increasingly stringent
environmental requirements cannot be estimated. However, NAEC has an active
environmental auditing program to detect and remedy noncompliance with
environmental laws or regulations. NAEC may incur significant additional
costs, greater than amounts included in cost of removal and other reserves, in
connection with the generation of electricity and the storage, transportation,
and disposal of by-products and wastes. NAEC may also encounter significantly
increased costs to remedy the environmental effects of prior waste handling
activities.
The estimated cost of decommissioning NAEC's 36 percent ownership share of
Seabrook, in year-end 1994 dollars, is approximately $137 million. Nuclear
decommissioning costs are accrued over the expected service life of the unit
and are included in depreciation expense on the Statements of Income. Nuclear
decommissioning costs amounted to $2.7 million in 1994 and $2.6 million in
1993.
PSNH is obligated to pay the company's share of Seabrook's decommissioning
costs even if the unit is shut down prior to the expiration of its license.
Nuclear decommissioning, as a cost of removal, is included in the accumulated
provision for depreciation on the Balance Sheets.
The staff of the Securities and Exchange Commission has questioned certain of
the current accounting practices of the electric utility industry, including
this company, regarding the recognition, measurement, and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. The Financial Accounting Standards Board is
currently reviewing the accounting for removal costs, including decommissioning
and similar costs. If current electric utility industry accounting practices
for such decommissioning costs are changed: (1) annual provisions for
decommissioning could increase, (2) the estimated costs for decommissioning
could be recorded as a liability rather than as accumulated depreciation, and
(3) trust fund income from the external decommissioning trust could be reported
as investment income rather than as a reduction to decommissioning expense.
See "Notes to Financial Statements" for further information regarding nuclear
decommissioning and other environmental matters.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided from operations increased approximately $9 million in 1994, as
compared with 1993, primarily due to the increased return associated with the
phase-in of additional Seabrook plant. Cash used for financing activities was
approximately $9 million lower in 1994, as compared with 1993, primarily due
to the repayment of short-term debt in 1993, partially offset by the payment
of cash dividends on common stock in 1994. Cash used for investments was
approximately $20 million higher in 1994, as compared with 1993, primarily due
to short-term loans to other NU system companies under the NU system Money Pool
and higher investment in plant, partially offset by lower nuclear fuel
expenditures in 1994.
The company's construction program expenditures amounted to approximately $11
million in 1994, as compared to approximately $7 million for 1993. The increase
is due to expenditures incurred as a result of NAEC's purchase of Vermont
Electric Generation and Transmission Company's 0.4 percent share of Seabrook in
1994, for approximately $6 million.
Nuclear fuel expenditures decreased approximately $13 million in 1994 from 1993
due to expenditures in 1993 for the Seabrook refueling outage.
The company has ongoing cash requirements for Seabrook-related capital
expenditures, nuclear fuel expenditures, interest and operating expenses.
Capital expenditures for the period 1995 through 1999 are expected to be
approximately $32 million (including allowance for funds used during
construction (AFUDC)), including $5 million for 1995. Nuclear fuel
expenditures for the same period are expected to be approximately $46 million
(excluding AFUDC), including $10 million for 1995. Such cash requirements are
expected to be met from payments under the Contract and the Tax Allocation
Agreement, except that to the extent some or all of the capital expenditures
and nuclear fuel expenditures may have to be financed, the company expects to
borrow under the Money Pool. As of December 31, 1994, there were no borrowings
outstanding under the Money Pool.
A substantial portion of the company's cash flow for the first few years is
expected to consist of payments made by NU to the company under a Tax
Allocation Agreement that the company entered into with NU at the time of the
acquisition. The amount of such payments will decrease over time but is
expected to remain substantial during the first few years when the company is
expected to incur losses for tax purposes due to accelerated tax depreciation
of Seabrook. The company received approximately $16 million from NU for the
period ended December 31, 1994 under this agreement. No assurance can be
given, however, as to the extent of the future benefits, if any, that will
actually accrue to the company under the Tax Allocation Agreement. (See "Notes
to Financial Statements" for further information regarding the Tax Allocation
Agreement.)
RESULTS OF OPERATIONS
Operating revenues represent amounts billed to PSNH under the terms of the
Contract and billings to PSNH for decommissioning expense. Operating revenues
increased approximately $20 million in 1994, as compared to 1993, primarily due
to the higher operation and maintenance expenses and the increased return
associated with the phase-in of additional Seabrook plant in May 1994.
Operation and maintenance expenses increased approximately $9 million in 1994,
as compared to 1993, primarily due to the unplanned and extended Seabrook
outages in 1994.
Deferred Seabrook return - other and borrowed funds decreased approximately $6
million in 1994, as compared to 1993, primarily because additional Seabrook
investment was phased into rates in May 1994.
The company has no historical results prior to June 5, 1992. Therefore, the
Statements of Income for the periods June 5, 1992 to December 31, 1992 and
January 1, 1993 to December 31, 1993 are not comparable.
SELECTED FINANCIAL DATA
1994 1993 1992*
----------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.... $145,751 $125,408 $ 78,444
======== ======== =========
Operating Income...... $ 42,950 $ 33,718 $ 16,122
========= ========= =========
Net Income............ $ 30,535 $ 25,998 $ 12,703
========= ========= =========
Cash Dividends on Common Stock$ 10,000 $ - $ -
========= ========== =========
Total Assets.......... $963,579 $900,821 $818,123
======== ======== ========
Long-Term Debt(a)..... $560,000 $560,000 $560,000
======== ======== ========
(a)Includes portion due within one year
STATISTICS 1994 1993 1992*
---------------------------------------------------------------------------
Gross Electric Utility
Plant December 31,
(Thousand of Dollars). $792,880 $789,127 $774,920
======== ======== ========
kWh Sales (Millions).. 2,229 3,218 1,268
======== ======== ========
STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
-------------------------------------------------------------------------
Quarter Ended
-----------------------------------------------
1994 March 31 June 30 September 30 December 31
-------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.... $32,211 $40,011 $37,603 $35,926
======= ======= ======= =======
Operating Income...... $ 8,594 $10,718 $11,851 $11,787
======= ======= ======= =======
Net Income............ $ 6,643 $ 6,725 $ 8,161 $ 9,006
======= ======== ======== =======
1993
-------------------------------------------------------------------------
Operating Revenues.... $29,153 $29,952 $31,845 $34,458
======= ======= ======= =======
Operating Income...... $ 6,541 $ 7,964 $ 9,657 $ 9,556
======= ======= ======= =======
Net Income............ $ 5,185 $ 5,985 $ 7,491 $ 7,337
======= ======= ======= =======
* The company began commercial opertions on June 5, 1992.
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000072741
<NAME> NORTHEAST UTILITIES AND SUBSIDIARIES
<MULTIPLIER>1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6,603,447
<OTHER-PROPERTY-AND-INVEST> 389,695
<TOTAL-CURRENT-ASSETS> 779,637
<TOTAL-DEFERRED-CHARGES> 2,812,101
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 10,584,880
<COMMON> 671,051
<CAPITAL-SURPLUS-PAID-IN> 904,371
<RETAINED-EARNINGS> 946,988
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,309,086
375,250
234,700
<LONG-TERM-DEBT-NET> 3,942,005
<SHORT-TERM-NOTES> 180,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 10,000
<LONG-TERM-DEBT-CURRENT-PORT> 170,523
4,425
<CAPITAL-LEASE-OBLIGATIONS> 166,018
<LEASES-CURRENT> 73,103
<OTHER-ITEMS-CAPITAL-AND-LIAB> 3,119,770
<TOT-CAPITALIZATION-AND-LIAB> 10,584,880
<GROSS-OPERATING-REVENUE> 3,642,742
<INCOME-TAX-EXPENSE> 280,126
<OTHER-OPERATING-EXPENSES> 2,800,866
<TOTAL-OPERATING-EXPENSES> 3,094,510
<OPERATING-INCOME-LOSS> 548,232
<OTHER-INCOME-NET> 49,256
<INCOME-BEFORE-INTEREST-EXPEN> 611,006
<TOTAL-INTEREST-EXPENSE> 281,090
<NET-INCOME> 329,916
43,042
<EARNINGS-AVAILABLE-FOR-COMM> 286,874
<COMMON-STOCK-DIVIDENDS> 219,317
<TOTAL-INTEREST-ON-BONDS> 314,191
<CASH-FLOW-OPERATIONS> 920,882
<EPS-PRIMARY> 2.30
<EPS-DILUTED> 0.00
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000023426
<NAME> THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
<MULTIPLIER>1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,133,653
<OTHER-PROPERTY-AND-INVEST> 241,644
<TOTAL-CURRENT-ASSETS> 413,003
<TOTAL-DEFERRED-CHARGES> 1,429,157
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 6,217,457
<COMMON> 122,229
<CAPITAL-SURPLUS-PAID-IN> 632,117
<RETAINED-EARNINGS> 765,724
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,520,070
226,250
166,200
<LONG-TERM-DEBT-NET> 1,815,579
<SHORT-TERM-NOTES> 168,750
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 10,000
<LONG-TERM-DEBT-CURRENT-PORT> 8,111
3,750
<CAPITAL-LEASE-OBLIGATIONS> 120,268
<LEASES-CURRENT> 55,701
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,122,778
<TOT-CAPITALIZATION-AND-LIAB> 6,217,457
<GROSS-OPERATING-REVENUE> 2,328,052
<INCOME-TAX-EXPENSE> 186,001
<OTHER-OPERATING-EXPENSES> 1,850,855
<TOTAL-OPERATING-EXPENSES> 2,045,893
<OPERATING-INCOME-LOSS> 282,159
<OTHER-INCOME-NET> 25,962
<INCOME-BEFORE-INTEREST-EXPEN> 317,158
<TOTAL-INTEREST-EXPENSE> 118,870
<NET-INCOME> 198,288
23,895
<EARNINGS-AVAILABLE-FOR-COMM> 174,393
<COMMON-STOCK-DIVIDENDS> 159,388
<TOTAL-INTEREST-ON-BONDS> 119,927
<CASH-FLOW-OPERATIONS> 532,322
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000106170
<NAME>WESTERN MASSACHUSETTS ELECTRIC COMPANY
<MULTIPLIER>1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
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24,000
68,500
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675
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5,897
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<NAME>PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
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13,250
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<NAME>NORTH ATLANTIC ENERGY CORPORATION
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0
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