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:
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
($)
---------------- ------- ------- ---------- ------- ---------- --------- -------- ---------
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
--------------------------------------------------------------------------------------------------------
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)
1994 1993
---------- ----------
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
=========== ===========
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)
1994 1993 1992
------------- ------------- -------------
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
============= ============= =============
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1994, 1993, 1992
(Thousands of Dollars)
1994 1993 1992
-------------- -------------- --------------
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)
============== ============== ==============
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
-----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 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.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
---------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
---------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 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.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 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
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
-----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 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.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 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.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 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.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
-----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,816 $ 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.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,780 $ 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.
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)
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,834 $ 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.
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)
-------------------------------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------------------------------
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.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1994
(Thousands of Dollars)
------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
-----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,997 $ 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.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1993
(Thousands of Dollars)
----------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
----------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,117 $ 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.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 1992
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
--------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,977 $ 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.
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.