SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission Registrants, State of Incorporation I.R.S. Employer
File Number Address; and Telephone Number Identification
No.
1-5366 EASTERN UTILITIES ASSOCIATES 04-1271872
(A Massachusetts voluntary association)
One Liberty Square
Boston, Massachusetts 02109
Telephone (617) 357-9590
0-2602 Blackstone Valley Electric Company 05-0108587
(A Rhode Island Corporation)
750 W. Center Street
West Bridgewater, Massachusetts 02379
Telephone (508) 559-1000
0-8480 Eastern Edison Company 04-1123095
(A Massachusetts Corporation)
750 W. Center Street
West Bridgewater, Massachusetts 02379
Telephone (508) 559-1000
Securities registered pursuant to Section 12(b) of the Act:
Name of each Exchange
Registrant Title of Each Class on which registered
Eastern Utilities Common Shares, New York Stock Exchange
Associates par value $5 per share Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class
Blackstone Valley 4.25% Non-Redeemable Preferred Stock,
Electric Company $100 Par Value
5.60% Non-Redeemable Preferred Stock,
$100 Par Value
Eastern Edison 6.625% Redeemable Preferred Stock,
Company $100 Par Value
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
State the aggregate market value of the voting stock held by non-affiliates of
the registrants. As of March 16, 1998:
Eastern Utilities Associates Common Shares, $5 par value - $510,899,925
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Eastern Utilities Associates Common Shares
Outstanding at March 16, 1998: 20,435,997
Blackstone Valley Electric Company Common Shares
Outstanding at March 16, 1998: 184,062
Eastern Edison Company Common Shares
Outstanding at March 16, 1998: 2,891,357
Portions of the Annual Reports to Shareholders of Eastern Utilities
Associates, Blackstone Valley Electric Company, and Eastern Edison Company for
the year ended December 31, 1997, are incorporated by reference into Part II.
Portions of the Eastern Utilities Associates Proxy Statement dated March 25,
1998 are incorporated by reference into Part III.
EASTERN UTILITIES ASSOCIATES
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
1997 Annual Report on Form 10-K
Table of Contents
Table of Contents. . . . . . . . . . . . . . . . . . . . . . . .I
GLOSSARY OF DEFINED TERMS. . . . . . . . . . . . . . . . . . . IV
PART I
Item 1. BUSINESS. . . . . . . . . . . . . . . . . . . . .1
System Overview . . . . . . . . . . . . . . . . . . . . . .1
General - Core Electric Business. . . . . . . . . . . . . .1
Electric Utility Industry Restructuring . . . . . . . . . .5
Unbundled Services. . . . . . . . . . . . . . . . . . . .5
Stranded Costs. . . . . . . . . . . . . . . . . . . . . .5
Rhode Island - Retail . . . . . . . . . . . . . . . . . .6
Massachusetts - Retail . . . . . . . . . . . . . . . . .7
FERC - Wholesale . . . . . . . . . . . . . . . . . . . .8
Divestiture . . . . . . . . . . . . . . . . . . . . . . .9
Accounting Issues . . . . . . . . . . . . . . . . . . . .9
General - EUA Cogenex . . . . . . . . . . . . . . . . . . 10
General - EUA Energy Investment . . . . . . . . . . . . . 12
Capital Requirements . . . . . . . . . . . . . . . . . . 13
Capital Requirements - EUA. . . . . . . . . . . . . . . 13
Construction Program - Blackstone . . . . . . . . . . . 13
Construction Program - Eastern Edison . . . . . . . . . 14
Fuel for Generation . . . . . . . . . . . . . . . . . . . 14
Nuclear Power Issues . . . . . . . . . . . . . . . . . . 17
General . . . . . . . . . . . . . . . . . . . . . . . . 17
Decommissioning . . . . . . . . . . . . . . . . . . . . 18
Millstone 3 . . . . . . . . . . . . . . . . . . . . . . 18
Connecticut Yankee . . . . . . . . . . . . . . . . . . 20
Maine Yankee . . . . . . . . . . . . . . . . . . . . . 20
Yankee Atomic . . . . . . . . . . . . . . . . . . . . . 21
General . . . . . . . . . . . . . . . . . . . . . . . . 21
Public Utility Regulation . . . . . . . . . . . . . . . . 22
Rates . . . . . . . . . . . . . . . . . . . . . . . . . 23
FERC Proceedings - Transmission . . . . . . . . . . . . 25
FERC Proceedings - Supply . . . . . . . . . . . . . . . 26
Massachusetts Proceedings . . . . . . . . . . . . . . . 26
Rhode Island Proceedings . . . . . . . . . . . . . . . 27
Environmental Regulation . . . . . . . . . . . . . . . . 28
General . . . . . . . . . . . . . . . . . . . . . . . . 28
Preconstruction Reviews . . . . . . . . . . . . . . . . 28
Solid and Hazardous Waste Regulation. . . . . . . . . . 28
Superfund Requirements. . . . . . . . . . . . . . . . . 29
Chemical Regulation . . . . . . . . . . . . . . . . . . 29
Potential Regulation of Electric and Magnetic Fields. . 29
Water Regulation. . . . . . . . . . . . . . . . . . . . 30
Air Regulation. . . . . . . . . . . . . . . . . . . . . 30
Other Requirements. . . . . . . . . . . . . . . . . . . 32
Environmental Regulation of Nuclear Power . . . . . . . . 33
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Item 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . 33
Power Supply . . . . . . . . . . . . . . . . . . . . . . 33
Other Property. . . . . . . . . . . . . . . . . . . . . . 36
Item 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . 37
Rate Proceeding . . . . . . . . . . . . . . . . . . . . . 37
Environmental Proceedings . . . . . . . . . . . . . . . . 37
Ridgewood . . . . . . . . . . . . . . . . . . . . . . . . 40
Other Proceedings . . . . . . . . . . . . . . . . . . . . 41
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS 41
Executive Officers of Eastern Utilities Associates. . . . 42
PART II
Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS. . . . . . . . . . . . . . . . . . . . . . . . 43
Item 6. SELECTED FINANCIAL DATA. . . . . . . . . . . . . . 43
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS . . . . . . . . . . . . . 43
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . 43
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURES. . . . . . . . 43
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS 44
Eastern Utilities Associates. . . . . . . . . . . . . . . 44
Blackstone and Eastern Edison . . . . . . . . . . . . . . 44
Item 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . 45
Eastern Utilities Associates. . . . . . . . . . . . . . . 45
Blackstone and Eastern Edison . . . . . . . . . . . . . . 46
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT . . . . . . . . . . . . . . . . . . . . . 46
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . 46
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K. . . . . . . . . . . . . . . . . . . . . . 47
(a)(1) Financial Statements . . . . . . . . . . . . . . . 47
(a)(2) Financial Statement Schedules . . . . . . . . . . 47
(a)(3) Exhibits (*denotes filed herewith).. . . . . . . . 47
(b) Reports on Form 8-K. . . . . . . . . . . . . . . . . 61
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . 63
Report of Independent Accountants. . . . . . . . . . . . . . . 74
Consent of Independent Accountants . . . . . . . . . . . . . . 76
GLOSSARY OF DEFINED TERMS
The following is a glossary of frequently used abbreviations and/or acronyms
found throughout this report:
The EUA System Companies
Blackstone Blackstone Valley Electric Company
Eastern Edison Eastern Edison Company
EUA Eastern Utilities Associates
EUA Cogenex EUA Cogenex Corporation
EUA Day EUA Day Company, a division of EUA Cogenex
EUA Ocean State EUA Ocean State Corporation
EUA Service EUA Service Corporation
EUA Energy EUA Energy Investment Corporation
EUA Energy Services EUA Energy Services Corporation
EUA Telecommunications EUA Telecommunications Corporation
Montaup Montaup Electric Company
Newport Newport Electric Corporation
Registrants EUA, Blackstone and Eastern Edison
Renova Renova (formerly EUA Nova), a division
of EUA Cogenex
Retail Subsidiaries Blackstone, Eastern Edison and Newport
Non-Affiliated Companies
Maine Yankee Maine Yankee Atomic Power Company
OSP Ocean State Power Project Units 1 and 2
Yankee Atomic Yankee Atomic Electric Company
Regulators/Regulations
1935 Act Public Utility Holding Company Act of 1935
CERCLA Federal Comprehensive Environmental
Response, Compensation and Liability
Act of 1980
Chapter 21E Massachusetts Oil and Hazardous Material
Release Prevention and Response Act
Clean Air Act Amendments Clean Air Act Amendments of 1990
DEQE Massachusetts Department of Environmental
Quality Engineering
GLOSSARY OF DEFINED TERMS (Cont'd)
Regulators/Regulations (continued)
DOE Department of Energy
DTE Massachusetts Department of Telecommunications
and Energy (formerly Massachusetts Department
of Public Utilities)
EITF Emerging Issues Task Force
Energy Policy Act Energy Policy Act of 1992
EPA Federal Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
IRS Internal Revenue Service
MADEP Massachusetts Department of Environmental
Protection
MADOER Massachusetts Department of Energy Resources
NESCAUM Northeast States for Coordinated Air Use
Management
NRC Nuclear Regulatory Commission
NWPA Nuclear Waste Policy Act
Price-Anderson Act The Price-Anderson Act, as amended by the
Price-Anderson Amendments of 1988
PURPA Public Utility Regulatory Policies Act
of 1978
RIDEM Rhode Island Department of Environmental
Management
RIDIV Rhode Island Division of Public Utilities
and Carriers
RIPUC Rhode Island Public Utilities Commission
SEC Securities and Exchange Commission
TSCA Toxic Substances Control Act
Other
BTU British Thermal Unit
DSM Demand Side Management
EMF Electric and Magnetic Fields
EWG Exempt Wholesale Generator
IPP Independent Power Producer
ISO Independent System Operator
kv Kilovolt
kWh Kilowatthour
mmBtu Millions of British Thermal Units
MOU Memorandum of Understanding
mw Megawatt
NEPOOL New England Power Pool
PCB Polychlorinated Biphenyls
GLOSSARY OF DEFINED TERMS (Cont'd)
Other (continued)
PRP Potentially Responsible Party
QF Qualifying cogeneration and small power
production facilities pursuant to PURPA
Seabrook Project Seabrook Nuclear Power Project located in
Seabrook, New Hampshire
PART I
Item 1. BUSINESS
System Overview
Eastern Utilities Associates is a Massachusetts voluntary association
organized and existing under a Declaration of Trust dated April 2, 1928, as
amended, and is a registered holding company under the 1935 Act. Blackstone, a
registered retail electric utility organized under the laws of the State of
Rhode Island in 1912 operates in northern Rhode Island. Eastern Edison, a
registered retail electric utility company, was organized under the laws of the
Commonwealth of Massachusetts in 1883 and operates in southeastern
Massachusetts. EUA owns directly all of the shares of common stock of
Blackstone, Eastern Edison, and Newport, a retail electric utility which
operates in south coastal Rhode Island. These subsidiaries are collectively
referred to as the Retail Subsidiaries. Eastern Edison owns all of the
permanent securities of Montaup, a generation and transmission company, which
currently supplies electricity to Eastern Edison, Blackstone, Newport and two
unaffiliated utilities for resale. EUA also owns directly all of the shares of
common stock of EUA Cogenex, EUA Energy, EUA Ocean State, EUA Energy Services,
EUA Service and EUA Telecommunications. EUA Service provides various
accounting, financial, engineering, planning, data processing and other
services to all EUA System companies. EUA Cogenex is an energy
services company. EUA Energy invests in energy-related projects. EUA Ocean
State owns a 29.9% interest in OSP's two gas-fired generating units. (See Item
2. PROPERTIES --Power Supply.) EUA Energy Services markets energy and energy
related services. EUA Telecommunications provides telecommunications and
information services. The holding company system of EUA, the Retail
Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy, EUA Ocean State,
EUA Energy Services, and EUA Telecommunications is referred to as the EUA
System. The EUA System is organized into a business unit structure. The Core
Electric Business consists of the Retail Subsidiaries and Montaup. (See
Electric Utility Industry Restructuring for a discussion of changes
taking place in the utility industry in the territories served by EUA's Core
Electric Business.) The Energy Related Business includes EUA Cogenex, EUA
Energy, EUA Ocean State, EUA Energy Services and EUA Telecommunications. The
Corporate Business is made up of EUA and EUA Service.
General - Core Electric Business
As of December 31, 1997, the number of regular employees in the core
electric and corporate business units was 983. Blackstone had 95 regular non-
union employees. Eastern Edison and Montaup had 281 regular employees.
Newport and EUA Service employed 58 and 549, respectively, at December 31,
1997. Labor bargaining unit contracts covering approximately 70 employees of
Eastern Edison in the Fall River area, and approximately 62 employees of
Montaup, and 53 employees of Newport expire in June 1999, January 2000, and
September 1998, respectively. Relations with employees are considered to be
satisfactory.
The Core Electric Business supplies retail electric service in 33 cities
and towns in southeastern Massachusetts and Rhode Island. The largest
communities served are the cities of Brockton and Fall River, Massachusetts.
The retail electric service territory covers approximately 595 square miles and
has an estimated population of approximately 737,000. At December 31, 1997,
Core Electric Business served approximately 302,000 retail customers.
Blackstone serves a territory of about 150 square miles in portions of
northern Rhode Island with a population of approximately 207,000. At December
31, 1997, Blackstone furnished retail electric service to approximately 85,000
customers in the cities of Central Falls, Pawtucket and Woonsocket, and four
surrounding towns.
Eastern Edison supplies retail electric service in 22 cities and towns in
southeastern Massachusetts. The largest communities served are the cities of
Brockton and Fall River, Massachusetts. The retail electric service territory
covers approximately 390 square miles and has an estimated population of
approximately 461,000. At December 31, 1997, Eastern Edison served
approximately 184,000 retail customers.
Newport supplies retail electric service to approximately 33,000 customers
in the cities of Jamestown, Middletown, Newport, and Portsmouth, Rhode Island.
The retail electric service territory covers approximately 55 square miles and
has an estimated population of approximately 69,000.
The Core Electric Business accounted for approximately 89% of total
operating revenues of the EUA System in 1997 and 1996, and approximately 86% in
1995. The remaining balance of operating revenues during these periods were
primarily attributable to EUA Cogenex.
Montaup is currently required to backstop the Retail Subsidiaries'
standard offer energy requirements (See "Massachusetts-Retail" under Electric
Utility Industry Restructuring below.) About 48% of the current net generating
capacity of the EUA System comes from a combination of the following sources:
(i) wholly owned EUA System generating plants, primarily Montaup's 154
mw Somerset facility located in Somerset, Massachusetts; (ii) Montaup's net
entitlement of 243 mw from the 586 mw Canal No. 2 unit, which is located in
Sandwich, Massachusetts and is 50% owned by Montaup; and, (iii) entitlements
from units in which Montaup has partial ownership interests (by joint ownership
through tenancy-in-common or by stock ownership) that are 4.5% or less. The
remaining 52% of the net generating capacity of the EUA System comes from units
in which Montaup has long-term or short-term power contracts for shares ranging
from 5.1% to 41.7% of the unit's capacity, including 28% of the OSP Units 1 and
2 in which EUA Ocean State has a 29.9% partnership interest, or entitlements
from the Hydro-Quebec Project through NEPOOL. (See Item 2. PROPERTIES -- Power
Supply for further details of the EUA System's sources of power supply).
Consistent with Electric Utility Industry Restructuring legislation passed
in Rhode Island and Massachusetts and settlement agreements approved by
regulators in Rhode Island, Massachusetts, and at FERC, Montaup has agreed to
sell its generating assets. EUA anticipates the sale will be completed in
early 1999. (See Electric Utility Industry Restructuring for further
discussion of the divestiture process.)
The Retail Subsidiaries and Montaup hold valid franchises, permits and
other rights which are necessary to allow these companies to conduct electric
business within the territories which they serve. Such franchises, permits and
other rights contain no unduly burdensome restrictions or limitations upon
duration. Section 312 of the Massachusetts Electric Industry Restructuring Act
signed into law on November 25, 1997 directs the DTE in conjunction with the
Massachusetts Department of Energy Resources (MADOER) to commence, no sooner
than January 1, 2000, an investigation and review of the manner in which
metering billing and information services (MBIS) are provided and the
exclusivity of electric distribution service territories. In the event that
the DTE determines that such services should be subject to competition or that
territorial exclusivity shall be terminated or altered in any manner, the DTE
shall, by no later than January 1, 2001, file its recommendations, along with
drafts of legislation necessary to implement said recommendations, with the
clerk of the house of representatives. Any unbundling and creation of
competition of such services shall not commence unless statutorily authorized.
The EUA System's electric sales are seasonal to some extent due to
electricity usage for heating and lighting in the winter and air conditioning
in the summer. The EUA System is not dependent on a single customer or a few
customers for its electric sales.
There is no competition from other electric distribution utilities within
the retail territories served by the Retail Subsidiaries at this time.
The electric generation, or supply function is now a competitive industry
in Rhode Island and Massachusetts, and initiatives nationwide are considering
adopting similar principles. Recently announced sales of generating portfolios
by regional utility companies, including Montaup, should generate a more robust
energy market in the regions served by EUA's Core Electric Business as new
supply entrants vie for customers. Montaup faces competition from these new
suppliers as well as existing suppliers and marketers in selling the output of
its current generating capacity and its capacity remaining after divestiture.
Competition in the generation sector has been developing for two decades,
enabled and encouraged by federal and state initiatives. PURPA was intended,
among other things, to promote national energy independence and diversification
of energy supply and to improve the overall efficiency of energy usage. PURPA
created a class of non-utility power generation facilities called qualifying
facilities or QFs. PURPA currently allows QFs to sell power generated by the
QFs to local utilities at specified rates based on each utility's avoided cost.
In order to further promote competition in energy supply, the Energy Policy Act
established another class of non-utility generators, generally referred to as
EWGs, which are exempt from the 1935 Act. Non-utility wholesale generators,
generally known as independent power producers or IPPs, are subject to FERC
regulations under the Federal Power Act as well as various other federal,
state, and local regulations. The Energy Policy Act also increased FERC's
power to order transmission access, resulting in FERC's open access
transmission order and Regional Transmission Group Policy. As a complement
to the federal initiatives, the DTE and the RIPUC implemented regulations in
the 1980's and early 1990's which require utilities to integrate least-cost
planning with competitive proposals to meet requirements for new generation.
Both states also approved in 1993 a Memorandum of Understanding among Montaup
and the Retail Subsidiaries that establishes a framework which makes possible a
coordinated, regional review of the resource planning and procurement process
of the EUA System Companies. (See Electric Utility Industry Restructuring and
Public Utility Regulation below).
On April 24, 1996, the FERC issued orders No. 888 and No. 889 to encourage
competition in the bulk power market by requiring all public utilities that
own, operate or control interstate transmission to file tariffs that offer
others the same transmission services they provide themselves, under comparable
terms and conditions, establishing the right and a mechanism for recovery of
prudently incurred stranded costs and requiring public utilities to implement
standards of conduct and an Open Access Same-time Information System (OASIS).
FERC also issued a Notice of Proposed Rulemaking (NOPR) requesting comment on
replacing the single tariff contained in the final open access rule with a
capacity reservation tariff that would reveal how much transmission is
available at any given time. (See Public Utility Regulation below.)
NEPOOL is a voluntary organization open to any person engaged in the
electric business such as investor-owned utilities, municipals, cooperative
utilities, power marketers, brokers and load aggregators. On December 31, 1996,
NEPOOL, on behalf of its participants, filed a restructuring proposal with
FERC. The NEPOOL restructuring proposal is the product of over two years of
intense discussions, deliberations and negotiations among the over 130 NEPOOL
member participants and many non-participants, including New England state
regulators. The key elements of the restructuring proposal are the
implementation of a regional NEPOOL Open Access Transmission Tariff (NEPOOL
Tariff), the creation of an Independent System Operator (ISO), and the
restatement of the NEPOOL Agreement to establish a broader governance structure
for NEPOOL and to develop a more open competitive market structure.
The NEPOOL Tariff, which became effective on March 1, 1997, ensures non-
discriminatory open access to the regional transmission network by providing a
single rate for all transactions that utilize the NEPOOL's bulk power
transmission facilities. The NEPOOL Tariff promotes competition in the New
England power market through its single transmission rate structure. All
regional service within NEPOOL, except for wheeling through or out, is to be
provided as a network service.
On June 25, 1997, FERC issued an order conditionally authorizing the
establishment of an ISO by NEPOOL effective July 1, 1997, affirming that the
transfer of control of transmission facilities owned by the public utility
members of NEPOOL to the ISO is consistent with the public interest under
section 203 of the Federal Power Act.
NEPOOL is in the process of transferring operational control of the New
England bulk power system to the ISO, a newly created non-profit Delaware
corporation. The ISO's primary responsibility is to ensure system reliability,
administer the NEPOOL Tariff, and oversee the efficient and competitive
functioning of the regional power market. The selection of the ISO's Board of
Directors was announced in April 1997.
To give market participants more choice and to foster competition, the
restructured NEPOOL proposes the unbundling of electric service in the NEPOOL
control area. The restructured NEPOOL calls for the development of competitive
wholesale markets for installed capability, operable capability, energy, and
reserves. These wholesale products will be market priced based on bid clearing
pricing rather than the current cost-based pricing. Market participants will be
able to transfer their responsibility for these products by buying or selling
these various services through bilateral transactions or through the regional
power exchange that will be administered through the ISO. The installed
capability market will most likely be implemented in April of 1998, the
operable capability and energy markets are planned for November of 1998, and
the reserve markets will subsequently be implemented.
In general, the EUA System companies support the changes to NEPOOL because
much of the cross-subsidies for sharing costs will be eliminated. These changes
will have an impact on the Company's operating revenues and costs as NEPOOL
transitions from a cost based to a bid based system.
Electric Utility Industry Restructuring
Unbundled Services:
The electric utility industry in both Massachusetts and Rhode Island, the
states in which EUA provides electric services, is transitioning from a
traditional rate regulated environment to a competitive marketplace.
Traditional electric utility services - generation, transmission and
distribution - have been unbundled into separate and distinct services. The
generation, or supply, function is now competitive with customers able to
choose their own electricity supplier at market prices. The transmission and
distribution functions remain regulated services. The local distribution
company is responsible for providing distribution services to the ultimate
electricity consumer within its franchised service territory and the
transmission company is required to provide open access, non-discriminatory
transmission services to generation or supply companies.
Stranded Costs:
Stranded costs represent prudently incurred costs of generation which are
now above their current economic value. In both Massachusetts and Rhode Island
(see discussions below) stranded costs have been defined to include items such
as above-market net investments in generation assets, generation related
regulatory assets, nuclear decommissioning and above market commitments under
current power purchase contracts. A December 19, 1997 order from FERC provides
Montaup, the EUA System's generation company, with full recovery of its
stranded costs. Stranded costs are recovered, via a Contract Termination
Charge (CTC) under a contract termination agreement which replaced the all-
requirements contracts formerly in force between Montaup and its retail
affiliates. In its order, FERC approved settlement agreements between Montaup,
its retail affiliates and consumer representatives in Massachusetts and Rhode
Island. Both states' regulatory bodies have approved retail settlements in
accordance with enabling state legislation. At December 31, 1997 Montaup
estimated its stranded costs, including unmitigated investment in owned
generation, generation-related regulatory assets, above-market purchase power
commitments, nuclear decommissioning and transition expenses to be
approximately $1 billion on a present value basis. This estimate is subject to
significant uncertainties including the future market price of electricity.
(See "Divestiture" below for a discussion of stranded cost mitigation.)
Rhode Island - Retail:
On August 7, 1996, the Governor of Rhode Island signed into law the
Utility Restructuring Act of 1996 (URA). The URA provides for customer choice
of electricity supplier in several phases commencing July 1, 1997 for certain
customers and culminating with choice for all customers by July 1, 1998, or
sooner. Under the URA, the local distribution company retains the
responsibility of providing distribution services to the ultimate electricity
consumer within its franchised service territory. For customers who do not
choose an alternative supplier, the local distribution company must arrange for
standard offer service. Distribution companies are providers of last resort
service for customers who are unable to obtain their own supply.
The URA provides for full recovery of stranded costs, through a non-
bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The transition charge recovers, among other things, costs
of depreciated generation, net of its market value; regulatory assets;
nuclear decommissioning costs; and above-market payments to power suppliers.
The costs of net, above-market generation assets and regulatory assets will be
recovered, with a return, through a fixed component of the transition charge
from January 1, 1998, through December 31, 2009. A variable component of the
transition charge will recover, on a reconciling basis, among other things,
nuclear decommissioning and above market purchased power commitments from
January 1, 1998, through the life of the respective unit or contract. The URA
also provides for commitments to demand side management initiatives and
renewables, low-income customer protections, divestiture of at least 15%
of owned non-nuclear generating units as a valuation basis for mitigation of
stranded cost recovery, and performance-based ratemaking (PBR) standards for
electric distribution companies to be in effect until the end of 1998. These
performance-based standards provide for a 6% minimum and an approximate 12%
maximum allowed return on equity for Blackstone and Newport, EUA's Rhode
Island Distribution Companies (R.I. Distribution Companies). In addition, the
URA provides for adjustments to electric distribution companies' base rates
using the prior year's Consumer Price Index for 1997 and 1998 and other
performance factors. Under this provision of the law, rates were
increased 1.3% for customers of both Blackstone and Newport effective January
1, 1998.
In February 1997, Blackstone, Newport and Montaup reached a settlement in
principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the Rhode Island Public Utilities Commission (RIPUC),
outlining the terms of the settlement. The settlement was submitted to the
RIPUC in two separate filings which were approved on April 21, 1997 and
December 17, 1997, respectively. In addition to complying with the URA, the
settlement, similar in many respects to the settlement negotiated in
Massachusetts, described below, provided for a 4% rate reduction for
Newport's customers and a 13% rate reduction for Blackstone's customers
effective January 1, 1998, amendments to Blackstone and Newport power contracts
with Montaup to replace all-requirements provisions with a CTC concurrent with
retail access and the filing of a plan to divest all of Montaup's generating
assets. The net proceeds of the divestiture will be used to mitigate the
amount of Montaup's stranded costs to be recovered through the CTC. (See
"Divestiture" below for a discussion of Montaup's divestiture process.)
On December 17, 1997, the RIPUC approved a retail settlement which
included a distribution rate freeze through December 31, 2000, except for any
temporary credit or surcharge resulting from PBR implementation or the standard
offer reconciliation, and retail access for all customers commencing January 1,
1998.
Massachusetts - Retail:
On December 23, 1996, Eastern Edison and Montaup reached an agreement in
principle with the Attorney General of Massachusetts and the MADOER and filed a
MOU with the Massachusetts Department of Telecommunications and Energy (DTE)
(formerly the Department of Public Utilities) outlining the terms of a plan,
similar in many aspects to the URA, which would allow retail customers to
choose their supplier of electricity in 1998 and provide Eastern Edison and
Montaup full recovery of stranded costs. On May 16, 1997 an Offer of
Settlement was filed with the DTE.
The Offer of Settlement provided all of Eastern Edison's customers the
ability to choose an alternative supplier of electricity beginning as soon as
January 1, 1998. Until a customer chooses an alternative supplier, that
customer would receive standard offer service which would be priced to
guarantee at least a 10% reduction in electricity rates. Eastern Edison would
be required to arrange for standard offer service through December 31, 2004 and
would purchase power for standard offer service from suppliers through a
competitive bidding process. Montaup has guaranteed standard offer supply at a
fixed price schedule for the duration of the standard offer period. For
competitive suppliers to be eligible to provide supplies for standard offer
service, their prices must be competitive with the fixed prices guaranteed by
Montaup. In the event that some, or all, of the standard offer requirement is
not awarded to competitive suppliers, Montaup has an obligation to provide such
requirement at the indicated fixed price schedule, so called backstop service.
This backstop service will be assigned proportionately to purchasers of
Montaup's generating capacity. The agreement is also designed to achieve full
divestiture of Montaup's generating assets via implementation of a plan, that
would require (1) functional separation by Montaup of its generating and
transmission businesses, and (2) full market valuation and sale of all
non-nuclear generating assets through an auction or equivalent process.
On March 1, 1998, concurrent with retail choice in Massachusetts,
Montaup's FERC - approved, all-requirements wholesale contract with Eastern
Edison was terminated. In its place, Montaup is billing Eastern Edison a CTC
designed to recover, among other things, Montaup's stranded costs. Eastern
Edison recovers the CTC through a non-bypassable transition access charge
to all of its distribution customers. The transition access charge will be
reduced by the fair market value of Montaup's generating assets as determined
by selling, spinning off, or otherwise disposing of such generating facilities.
(See "Divestiture" below.)
Embedded costs associated with generating plants and regulatory assets are
recovered, with a return, over a period of twelve years ending December 31,
2009. Purchased power contracts and nuclear decommissioning costs are
recovered as incurred over the life of those obligations, a period expected to
extend beyond twelve years. The initial transition access charge is set at
3.04 cents per kWh through December 31, 2000, and is expected to decline
thereafter.
The agreement also establishes a performance component for Eastern Edison,
incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates are frozen until December 31,
2000. Subsequent to the commencement of retail choice, Eastern Edison's annual
return on equity is subject to a floor of 6% and a ceiling of 11.75%.
On November 25, 1997, the Governor of Massachusetts signed the Electric
Industry Restructuring Act (the Act) into law. The Act directed the DTE to
require electric companies to accommodate retail access to generation services
and choice of supplier by March 1, 1998 and to require electric companies to
file restructuring plans to do so. The Act also provides for a 10%
reduction in electric rates commencing March 1, 1998 and an additional 5%
reduction, adjusted for inflation, commencing September 1, 1999. The
additional 5% reduction may be accomplished with benefits from asset
divestiture and/or securitization. Recognizing the fact that certain electric
companies, including Eastern Edison, had already submitted restructuring
settlement agreements, the Act provided that "an electric company that has
filed a plan which substantially complies or is consistent with this chapter as
determined by the department shall not be required to file a new plan,
and the department shall allow such plans previously approved or pending before
the department to be implemented." On December 5, 1997, the DTE issued a
notice seeking comments on whether the Eastern Edison Settlement Agreement
"substantially complies or is consistent with this chapter." Eastern Edison and
other parties provided comments.
on December 23, 1997 the DTE approved the Settlement as being in
substantial compliance with the Act. Retail access commenced on March 1, 1998
for Eastern Edison's retail customers.
In January 1998, several parties filed motions for reconsideration of
Eastern Edison's approved settlement agreement and motions to extend the
judicial appeal period with the DTE. The motions for reconsideration claim
that provisions of the approved plan involving consumer rates, cost recovery,
energy efficiency and reliability do not meet standards set forth in the Act.
The DTE denied one party's motion and that party has appealed the DTE's ruling
to the Massachusetts Supreme Judicial Court. Management cannot predict the
ultimate outcome of the pending motions for reconsideration or judicial appeal.
The Office of the Attorney General has certified a referendum petition to
repeal the Act as a matter appropriate for a referendum initiative. A petition
was filed with the Election Division of the Office of the Secretary of State in
February 1998. A question on repealing the Act will be presented to voters on
the November 1998 ballot. EUA and the electric industry in Massachusetts
will actively oppose repeal. Management cannot predict the outcome of the
November ballot question.
FERC - Wholesale:
On May 1, 1997, Montaup and the R.I. Distribution Companies jointly filed
amendments to their FERC-approved all-requirements power contracts. The filing
included a calculation for a CTC to recover stranded costs and a provision for
standard offer service for resale to retail customers who do not choose an
alternate generation supplier as discussed under "Massachusetts-Retail" above.
These provisions replaced the services offered by the all-requirements
contracts upon full retail access pursuant to the URA. The filing also
included hold harmless provisions for Montaup's other wholesale customers and
for retail customers of the R.I. Distribution Companies and lost revenue
provisions, which allow for recovery of any of Montaup's lost revenues for the
period from the initial phases of retail access in Rhode Island through
completion of Montaup's divestiture process. This filing allowed the R.I.
Distribution Companies to implement on July 1, 1997 the phase-in provisions
of the URA and prevented any cross-subsidies by their retail customers who were
excluded from the groups of customers given retail choice prior to January 1,
1998 and by Montaup's other customers.
On May 30, 1997, elements of the Massachusetts Settlement Agreement,
including the CTC calculation, which fall under the jurisdiction of FERC were
filed with FERC.
The May 1st and May 30th filings were consolidated by FERC and on October
29, 1997, settlement agreements among Montaup, its affiliated and non-
affiliated customers, the Massachusetts Attorney General, the MADOER, the RIDIV
and RIPUC were submitted for FERC approval. These settlements represent a
comprehensive resolution of federal/wholesale issues of electric utility
industry restructuring based on the settlement agreements in Massachusetts and
Rhode Island. FERC approved the settlements on December 19, 1997,
accommodating retail choice for EUA's retail customers in Massachusetts and
Rhode Island.
Divestiture:
Montaup began marketing its portfolio of generation assets in July 1997,
and subsequently received bids from a number of potential purchasers. On
January 23, 1998, based on a review of the offers and discussions with
potential purchasers, Montaup announced that it was reopening the sales
process on the majority of its generating assets. The process is expected to
require four to six months to execute the purchase and sale agreement. The net
proceeds of the sale, as defined in the settlement agreements, will be used to
mitigate Montaup's CTC to its retail affiliates via a Residual Value Credit
(RVC). The RVC will reduce the fixed component of the CTC for the net
proceeds, with a return, in equal annual amounts over the period commencing on
the date the RVC is implemented through December 31, 2009. Subject to
regulatory approvals, Montaup anticipates the sale will be completed in early
1999.
Accounting Issues:
Historically, electric rates have been designed to recover a utility's
full cost of providing electric service including recovery of investment in
plant assets. Also, in a regulated environment, electric utilities are subject
to certain accounting rules that are not applicable to other industries.
These accounting rules allow regulated companies, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the current
financial impact of certain costs that are expected to be recovered in future
rates. The SEC has raised issues concerning the continued applicability of
these standards with certain other electric utilities in other states facing
restructuring.
In July 1997, the Financial Accounting Standards Board's (FASB) Emerging
Issues Task Force (EITF) reached a consensus regarding certain issues raised
related to the application of Statement of Financial Accounting Standards No.
71 (FAS71), "Accounting for the Effects of Certain Types of Regulation." The
EITF determined that when sufficient detail is available for an enterprise to
reasonably determine, from legislation and enabling rate orders, how the
transition plan will affect the separable portion of its business being
deregulated, the enterprise should discontinue the application of FAS71 to that
deregulated portion of its business. The EITF also concluded that utilities
can continue to carry previously recorded regulatory assets on their balance
sheet if regulators have guaranteed a regulated cash flow stream to recover the
cost of those assets.
In light of approved restructuring settlement agreements and restructuring
legislation in both Massachusetts and Rhode Island, EUA has determined that
Montaup no longer will apply the provisions of FAS71 to the generation portion
of its business. Due to the recoverability of regulatory assets granted in the
approved restructuring plans, EUA believes that the discontinuation of FAS71
for the generation portion of Montaup's business will not have a material
impact on EUA's results of operation or financial condition. EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover a company's costs, a write-
down of plant assets could be required pursuant to Financial Accounting
Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of." EUA does not anticipate any write-down
of plant assets as a result of approved restructuring plans or enacted
legislation at this time.
General - EUA Cogenex
EUA Cogenex is a wholly owned subsidiary of EUA. EUA Cogenex is an
energy services company that employs energy efficient technology and equipment
intended to reduce the energy consumption and costs of its customers. Such
technology and equipment include building automation systems, lighting
modifications, boiler and chiller replacements and other mechanical
measures such as motors and drives. EUA Cogenex may design, install, own,
operate, maintain, and finance specific energy efficient applications for its
customers.
EUA Cogenex is compensated for these services primarily through energy
services agreements in which EUA Cogenex and the customer who occupies or owns
a facility agree upon a prescribed base year and a set of savings calculations.
EUA Cogenex then receives payments based on a portion of the savings that
result from the installation and maintenance of the energy efficient
equipment in the facility. Some of EUA Cogenex revenues under these
agreements are dependent upon the actual achievement of energy savings. In
addition, EUA Cogenex participates in demand side management (DSM) programs
sponsored by electric utilities as a means to decrease both base
load and peak demand on the utilities' systems. In utility DSM programs, EUA
Cogenex contracts with the utility and its commercial and industrial customers
in order to decrease the overall demand on the utility system or to reduce peak
demand, curtailing the need for costly capacity additions. EUA Cogenex
contracts for utility DSM programs through a bidding process or participates in
the utility's "Fixed Rate Program." EUA Cogenex also may, from time to time,
acquire existing DSM contracts or energy services agreements, or the benefits
from those contracts from other energy services companies through its
"flexifund" finance division.
EUA Cogenex's principal markets include institutional, commercial,
industrial, government entities and, through its EUA Citizens Conservation
Services subsidiary, public and private multi-family housing.
Difficulties in turning project proposals into signed contracts, the
virtual elimination of utility sponsored DSM programs and the termination of
two joint ventures hampered EUA Cogenex's 1996 earnings. As a result, a write-
off of certain start-up costs of abandoned joint ventures, and expenses
related to certain project proposals along with a reduction in carrying value
of certain on-going projects necessitated by market conditions resulted in a
$5.9 million pre-tax ($3.7 million after-tax or 18 cents per share) charge to
earnings in the second quarter of 1996.
In the early part of 1997, EUA Cogenex restructured its senior management
to provide a more efficient control function and created a "team" concept
whereby every employee is assigned to a work team for project implementation
and administrative purposes. While EUA believes that the energy efficiency
market still provides a viable business opportunity for EUA Cogenex, it will
be important for EUA Cogenex to continue to improve the performance of its
sales activity.
EUA Cogenex also operates a lighting services division, Renova (Formally
EUA Nova), and a controls division, EUA Day. Renova provides lighting
products designed to achieve an efficiency gain through the integration of
various lamp, ballast and light reflector products. EUA Day, is primarily
engaged in the business of customization, installation and servicing of
building temperature control systems, monitoring and verification systems and
process control systems for the purpose of energy conservation. These systems
are primarily designed for regulating lighting and heating, ventilation and
air-conditioning, but can also simultaneously be used for security
surveillance, building entry and exit, equipment monitoring and air quality
monitoring.
EUA Cogenex also provides consulting services to its customers in the form
of training in the proper use and maintenance of the energy equipment. This
service includes instruction in the use of existing equipment as well as newly
installed equipment so that further energy savings can be realized. In
addition, EUA Cogenex monitors installed projects on a 24-hour basis and
dispatches third party contractors to make repairs and/or adjustments.
In 1995, EUA Cogenex acquired certain energy services assets of Citizens
Conservation Corporation with headquarters in Boston, Massachusetts in exchange
for preferred stock of a newly formed subsidiary of EUA Cogenex, EUA Citizens
Conservation Services, which will utilize those assets. EUA Citizens
Conservation provides energy conservation services to the public and private
multi-family housing sector. EUA Cogenex also acquired the Highland Energy
Group, an energy services company in Boulder, Colorado in exchange for common
shares of EUA. Highland provides energy conservation services in Colorado,
Texas, Ohio, North Carolina and certain mid-western states. In early 1996, EUA
Cogenex announced a proposed joint venture with Monenco-Agra of Canada to
provide similar services in Canada.
At December 31, 1997, EUA Cogenex employed 197 persons in its operations.
EUA Cogenex's competition is comprised primarily of the manufacturers and
distributors of the energy efficiency equipment which it installs, other
utility-owned energy services companies, engineering consulting firms and from
financial institutions who provide capital to finance energy efficiency
projects.
The deregulation of the electric utility industry may have an effect on
EUA Cogenex. Electric industry deregulation may present new markets and
opportunities in which EUA Cogenex may participate. However, some electric
utilities have, or announced plans to establish, subsidiaries that will
compete directly with EUA Cogenex. In 1996, the move toward electric industry
deregulation resulted in a reduction of electric utility sponsored DSM programs
which resulted in a reduction of EUA Cogenex's revenues. However, certain
electric industry restructuring statutes have created additional DSM spending
requirements and those requirements should provide greater revenue
opportunities for EUA Cogenex.
As of December 31, 1997, EUA Cogenex participated in five partnerships.
It is the managing general partner in all of the partnerships and has limited
partnership interest in certain of the partnerships. EUA Cogenex has provided
virtually all of the capital to the partnerships and is generally entitled to a
return of, and on, this capital before any significant partnership distribution
is made to the other general partners. All partnerships and their customers
are subject to the same selection and screening process to establish acceptable
credit quality.
The rates charged by EUA Cogenex to customers through its energy service
agreements are not subject to the jurisdiction of any regulatory agency.
The following table sets forth the amounts of revenues, pre-tax income,
net earnings and identifiable assets attributable to the consolidated
operations of EUA Cogenex:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Operating Revenues $61,321 $ 56,317 $ 79,499
Pre-tax (Loss) Income $769 $(10,186)(1) $ (13,885)(2)
Net (Loss) Earnings $202 $ (6,522)(1) $ (7,904)(2)
Total Assets $188,351 $195,161 $ 199,115
(1) Includes pre-tax charge of $5.9 million, $3.7 million after-tax, related to
the June 1996 write down of certain project costs.
(2) Includes pre-tax charge of $18.1 million, $10.5 million after-tax, related
to discontinuance of cogeneration operations.
General - EUA Energy Investment
EUA Energy Investment is a wholly owned subsidiary of EUA. EUA Energy
Investment invests in energy related projects such as EUA BIOTEN, Separation
Technologies, and EUA TransCapacity. EUA BIOTEN is an investment in a general
partnership which is developing a generating unit that burns biomass-
agricultural waste and creates renewable energy. Separation Technologies, Inc.
of which EUA Energy Investment has a 20% equity interest, markets and installs
patented technology that separates unburned carbon from coal fly-ash, which
enables the customer to sell the fly-ash to secondary markets and to reburn the
separated carbon. EUA TransCapacity is an investment in a limited partnership
which has developed and now markets software system of data acquisition,
delivery and coordination using electronic data interchange (EDI) for the
natural gas industry. EUA Compression Services holds our 50% equity interest
in the joint venture which develops services to upgrade natural gas pipeline
compression infrastructure.
See Note I - Financial Information by Business Segment, of Consolidated
Financial Statements contained in the EUA's Annual Report to Shareholders for
the year ended December 31, 1997 (Exhibit 13-1.03 filed herewith).
Capital Requirements
Capital Requirements - EUA:
The EUA System's cash construction expenditures for the year ended
December 31, 1997 were approximately $76.1 million.
Planned core electric cash construction expenditures and energy related
capital requirements for 1998, 1999 and 2000 as set forth below, are estimated
to total $271.6 million, and are expected to be financed with internally
generated funds.
EUA SYSTEM CONSTRUCTION PROGRAM
(In Thousands)
1998 1999 2000 3-Yr. Total
Generation $10,080 $ (a) $ (a) $ 10,080
Transmission 2,606 5,171 3,242 11,019
Distribution 16,746 19,774 18,429 54,949
General 1,025 762 785 2,572
Total Utility
Construction
Requirements 30,457 25,707 22,456 78,620
EUA Cogenex Capital
Requirements 49,509 56,935 65,476 171,920
EUA Energy Capital
Requirements 6,765 10,300 4,000 21,065
Total $86,731 $92,942 $91,932 $271,605
(a) Based on anticipated divestiture of Montaup's generation assets, no
construction expenditures are being forecasted by EUA beyond 1998
(See "Divestiture" under Electric Utility Industry Restructuring).
Construction Program - Blackstone:
Blackstone's cash construction expenditures for the year ended December
31, 1997 were approximately $3.8 million, related primarily to its electric
distribution system.
Planned cash construction expenditures for 1998, 1999 and 2000, as set
forth below, are estimated to total $15.3 million.
BLACKSTONE CONSTRUCTION PROGRAM
(In Thousands)
1998 1999 2000 3-Yr. Total
Transmission $ 90 $ 293 $ 141 $ 524
Distribution 4,071 5,903 4,251 14,225
General 185 190 196 571
Total $4,346 $6,386 $4,588 $15,320
Construction Program - Eastern Edison:
Eastern Edison's cash construction expenditures for the year ended
December 31, 1997 were approximately $15.7 million.
Cash construction expenditures of Eastern Edison and Montaup for 1998,
1999 and 2000 as set forth below, are estimated to total $53.4 million.
<TABLE>
EASTERN EDISON CONSTRUCTION PROGRAM
(In Thousands)
<CAPTION>
1998 1999 2000 3-Yr. Total
Eastern Eastern Eastern Eastern
Edison Montaup Edison Montaup Edison Montaup Edison Montaup Combined
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Generation(a) $ $10,074 $ $ $ $ $ $10,074 $10,074
Transmission 722 1,767 1,870 2,982 1,892 1,182 4,484 5,931 10,415
Distribution 9,931 190 11,197 11,421 32,549 190 32,739
General 42 42 44 128 128
Total $10,695 $12,031 $ 13,109 $ 2,982 $13,357 $1,182 $37,161 $16,195 $53,356
(a) Based on anticipated divestiture of Montaup's generation assets, no
construction expenditures are being forecasted by EUA beyond 1998 (See
"Divestiture" under Electric Utility Industry Restructuring).
</TABLE>
Fuel for Generation
The Retail Subsidiaries currently rely primarily on power purchased from
Montaup to meet the electric energy requirements of their standard offer and
default service customers. The standard offer requirement will be subjected to
a competitive solicitation expected to be completed by the second quarter of
1998. Power purchases for Montaup's remaining obligations to the retail
subsidiaries are arranged on a system basis, by Montaup, under which power is
made available to the EUA System and allocated to the Retail Subsidiaries in
accordance with their peak requirements. Future purchases for standard offer
and default service will likely be made by the Retail Subsidiaries themselves.
(See Electric Utility Industry Restructuring above.)
The Retail Subsidiaries recover their cost of power through the operation
of revenue adjustment clauses which are designed to provide timely recovery of
such costs.
For 1997, the EUA System's sources of energy, by fuel type, were as
follows: 31% oil, 28% gas, 18% coal, 17% nuclear, and 6% other. During 1997,
Montaup had an average inventory of 40,550 tons of coal for its steam
generating unit at the Somerset Station, the equivalent of 52 days' supply
(based on average daily output at 80% capacity factor for the coal unit (see
Item 2. PROPERTIES -- Power Supply)). The cost of coal averaged about $49.54
per ton in 1997 which is equivalent to oil at $11.16 per barrel. Montaup coal
is under contract, and coal prices have historically been very stable. Montaup
also maintained an average inventory of Nos. 2 and 6 oil of 540 barrels and
30,040 barrels, respectively. These fuels are used for start-up and flame
stabilization for Montaup's steam generating unit. The cost of Nos. 2 and 6
oil averaged $25.69 per barrel and $18.79 per barrel in 1997, respectively.
Montaup also maintained an average inventory of jet oil of 2,816 barrels at an
average cost per barrel of $27.11 during 1997 for its two peaking units at the
Somerset Station.
Montaup has a two year purchase order effective through December 1998 with
a coal producer. Barge and rail agreements for coal transportation are also in
place through 1998. The 1997 year-end coal inventory of approximately 58,382
tons is all 0.6% to 0.7% sulfur coal which is compliant with Clean Air Act
requirements.
Canal Electric Company (Canal), on behalf of itself, Montaup and others
has a one year contract with a supplier for up to 100% of the fuel-oil
requirements of Canal Unit Nos. 1 and 2 that expires in March of 1999. The
current contracts permit up to 35% of fuel oil purchases in the spot
market. Fuel prices are based on oil market posting at the time of delivery.
For 1997, the cost of oil per barrel at Canal averaged $17.26. Additionally,
Canal has a contract with a gas supplier for approximately 70% of Canal No. 2's
daily gas requirements. Canal No. 2 completed its gas conversion and testing
in September 1996. The unit is now able to burn gas, oil, or a blend of the
two fuels. Economics, generation and supply will determine actual fuel type
usage.
Montaup's costs of fossil and nuclear fuels for the years 1995 through
1997, together with the weighted average cost of all fuels, are set forth
below:
Mills* per kWh
1997 1996 1995
Nuclear . . . . . . . . . 5.7 5.0 6.3
Gas . . . . . . . 16.4 14.4 14.3
Coal . . . . . . . . 18.6 19.6 20.3
Oil . . . . . . . . . 31.0 37.7 30.2
All fuels . . . . . . . . . 19.2 16.7 16.7
*One Mill is 1/10 of one cent
OSP has two gas supply contracts which expire on September 30, 2011, for
its two 250 mw generators. The cost of gas for 1997 averaged $1.45 per mmBtu
or approximately 12.3 mills per kWh generated.
The owners (or lead participants) of the nuclear units in which Montaup
has an interest have made, or expect to make, various arrangements for the
acquisition of uranium concentrate, the conversion, enrichment, fabrication and
utilization of nuclear fuel and the disposition of that fuel after use. The
owners (or lead participants) of United States nuclear units have entered into
contracts with the DOE for disposal of spent nuclear fuel in accordance with
the NWPA. The NWPA requires (subject to various contingencies) that the
federal government design, license, construct and operate a permanent
repository for high level radioactive wastes and spent nuclear fuel and
establish a prescribed fee for the disposal of such wastes and nuclear fuel.
The NWPA specifies that the DOE provide for the disposal of such waste and
spent nuclear fuel starting in 1998. Objections on environmental and other
grounds have been asserted against proposals for storage as well as disposal
of spent nuclear fuel. The DOE now estimates that a permanent disposal site
for spent fuel will not be ready to accept fuel for storage or disposal until
at least the year 2010. Montaup owns a 4.01% interest in Millstone 3 and a
2.9% interest in Seabrook I. Northeast Utilities, the operator of the units,
indicates that Millstone 3 has sufficient on-site storage facilities which,
with rack additions, can accommodate its spent fuel for the projected life of
the unit. At the Seabrook Project, there is on-site storage capacity which,
with rack additions, will be sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest. These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners or power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through the contract termination charge.
In early 1998, Yankee Atomic, Maine Yankee, and Connecticut Yankee
individually, as well as a number of other utilities filed suit in federal
appeals court seeking a court order to require the Department of Energy (DOE)
to immediately establish a program for the disposal of spent nuclear
fuel. Yankee Atomic and Connecticut Yankee are also seeking damages in of
approximately $70 million, and $90 million, respectively. Under the Federal
Energy Policy Act of 1992 and Nuclear Waste Policy Act, the DOE was to provide
for the disposal of radioactive wastes and spent nuclear fuel starting in 1998
and has collected funds from owners of nuclear facilities to do so. Management
cannot predict the ultimate outcome of this issue.
Nuclear Power Issues
General:
Nuclear generating facilities, including those in service in which Montaup
participates, as shown in the table under Item 2. PROPERTIES -- Power Supply,
are subject to extensive regulation by the NRC. The NRC is empowered to
authorize the siting, construction and operation of nuclear reactors after
consideration of public health, safety, environmental and anti-trust matters.
The NRC has promulgated numerous requirements affecting safety systems,
fire protection, emergency response planning and notification systems, and
other aspects of nuclear plant construction, equipment and operation. These
requirements have caused modifications to be made at some of the nuclear units
in which Montaup has an interest. Montaup has been affected, to the extent of
its proportionate share, by the costs of such modifications.
Nuclear units in the United States have been subject to widespread
criticism and opposition. Some nuclear projects have been canceled following
substantial construction delays and cost overruns as the result of licensing
problems, unanticipated construction problems and other difficulties. Various
groups have by litigation, legislation and participation in administrative
proceedings sought to prohibit the completion and operation of nuclear units
and the disposal of nuclear waste. In the event of cancellation or shutdown of
any unit, the unit must be decontaminated of any residual radioactivity so as
to satisfy NRC regulations which generally require that the property be
releasable for unrestricted use. The cost of such decommissioning, depending
on the circumstances, could substantially exceed the owners' investment at the
time of cancellation.
Joint owners of nuclear projects are subject to the risk that one of their
number may be unable or unwilling to finance its share of the project's costs,
thus jeopardizing continuation of the project. Also, the continuing public
controversy concerning nuclear power could affect the operating units
in which Montaup has an interest. While management cannot predict the ultimate
effect of such controversy, it is possible that it could result in the
premature shutdown of one or more of the units.
The Price-Anderson Act provides, among other things, that the liability
for damages resulting from a nuclear incident would not exceed an amount which
at present is about $8.7 billion. Under the Price-Anderson Act, prior to
operation of a nuclear reactor, the licensee is required to insure against this
exposure by purchasing the maximum amount of liability insurance available from
private sources (currently $200 million) and to maintain the insurance
available under a mandatory industry-wide retrospective rating program. Should
an individual licensee's liability for an incident exceed $200 million, the
difference between such liability and the overall maximum liability,
currently about $8.7 billion, will be made up by the retrospective rating
program. Under such a program, each owner of an operating nuclear facility may
be assessed a retrospective premium of up to a limit of $79.3 million (which
shall be adjusted for inflation at least every five years) for each reactor
owned in the event of any one nuclear incident occurring at any reactor in the
United States, with provision for payment of such assessment to be made over
time as necessary to limit the payment in any one year to no more than $10
million per reactor owned. With respect to operating nuclear facilities of
which it is a part owner or from which it contracts (on terms reflecting such
liability) to purchase power, Montaup would be obligated to pay its
proportionate share of any such assessment.
Decommissioning:
Vermont Yankee, an operating nuclear generating company in which Montaup
has an equity ownership interest (see Item 2. PROPERTIES -- Power Supply) has
developed its estimate of the cost of decommissioning its unit and has received
the approval of FERC to include charges for the estimated costs of
decommissioning its unit in the cost of energy which it sells. From time to
time, Vermont Yankee re-estimates the cost of decommissioning and applies to
FERC for increased rates in response to increased decommissioning costs. Maine
Yankee has filed a decommissioning financing plan under a Maine statute which
requires the establishment of a decommissioning trust fund. That statute also
provides that if the trust has insufficient funds to decommission the plant,
the licensee (Maine Yankee) is responsible for the deficiency and, if the
licensee is unable to provide the entire amount, the "owners" of the licensee
are jointly and severally responsible for the remainder. The definition of
"owner" under the statute includes Montaup and may include companies affiliated
with Montaup. The applicability and effect of this statute cannot be
determined at this time. Montaup would seek to recover through its rates any
payments that might be required. (See "Connecticut Yankee" and "Maine Yankee"
below.)
Montaup is recovering through rates its share of estimated decommissioning
costs for Millstone 3 and Seabrook I. Montaup's share of the current estimate
of total costs to decommission Millstone 3 is $21.9 million in 1997 dollars,
and Seabrook I is $13.7 million in 1997 dollars. These figures are based on
studies performed for the lead owners of the plants. In addition, pursuant to
contractual arrangements with other nuclear generating facilities in which
Montaup has an equity ownership interest or life of the unit entitlement,
Montaup pays into decommissioning reserves. Such expenses are currently
recoverable through rates.
Millstone 3:
Montaup has a 4.01% ownership interest in Millstone 3, an 1154-mw nuclear
unit that is jointly owned by a number of New England utilities, including
subsidiaries of Northeast Utilities (Northeast). Subsidiaries of Northeast are
the lead participants in Millstone 3. On March 30, 1996, it was necessary to
shut down the unit following an engineering evaluation which determined that
four safety-related valves would not be able to perform their design function
during certain postulated events.
The Nuclear Regulatory Commission (NRC) has raised numerous issues with
respect to Millstone 3 and certain of the other nuclear units in which
Northeast and its subsidiaries, either individually or collectively, have the
largest ownership shares, including Connecticut Yankee. (See "Connecticut
Yankee" below.)
In October 1996, the NRC informed Northeast that it was establishing a
Special Projects Office to oversee inspection and licensing activities at
Millstone. The Special Projects Office is responsible for (1) licensing and
inspection activities at Northeast's Connecticut plants, (2) oversight of an
Independent Corrective Action Verification Program (ICAVP), (3) oversight of
Northeast's corrective actions related to safety issues involving employee
concerns, and (4) inspections necessary to implement NRC oversight of the
plants' restart activities. Also, the NRC directed Northeast to submit a plan
for disposition of safety issues raised by employees and retain an independent
third-party to oversee implementation of this plan.
In March 1997, Northeast announced that Millstone 3 had been designated as
the lead unit in the recovery process of the three Millstone nuclear units that
are currently out of service. Millstone 3 is the largest of the three units
currently out of service, and its return to service will most benefit the
energy needs of the New England region.
On January 8, 1998, Northeast announced that Millstone 3 was "physically
ready for restart" indicating that virtually all of the restart-required
physical work had been completed. Northeast indicated that a small amount of
systems work needs to be completed prior to restart. Various NRC and
independent inspections are required prior to restarted. EUA cannot predict
when the plant will be restarted.
While Millstone 3 is out of service, Montaup will incur incremental
replacement power costs estimated at up to $1 million per month.
In August 1997, nine non-operating owners, including Montaup, who together
own approximately 19.5% of Millstone 3, filed a demand for arbitration against
Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company
(WMECO) as well as lawsuits against Northeast and its Trustees. CL&P and
WMECO, owners of approximately 65% of Millstone 3, are Northeast subsidiaries
that agreed to be responsible for the proper operation of the unit.
The non-operating owners of Millstone 3 claim that Northeast and its
subsidiaries failed to comply with NRC regulations, failed to operate the
facility in accordance with good utility operating practice and attempted to
conceal their activities from the non-operating owners and the NRC. The
arbitration and lawsuits seek to recover costs associated with replacement
power and O&M costs resulting from the shutdown of Millstone 3. The non-
operating owners conservatively estimate that their losses will exceed $200
million.
Montaup pays its share of Millstone 3's O&M expenses on a reservation of
right basis. The fact that Montaup makes payment for these expenses is not an
admission of financial responsibility for expenses incurred or to be incurred
due to the outage.
EUA cannot predict the ultimate outcome of the NRC inquiries or legal
proceedings brought against CL&P, WMECO and Northeast or the impact which they
may have on Montaup and the EUA system.
Connecticut Yankee:
Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July 1996
because of issues related to certain containment air recirculation and service
water systems. Montaup has a 4.5% equity ownership in Connecticut Yankee with
a book value of $5.0 million at December 31, 1997.
In October 1996, Montaup, as one of the joint owners, participated in an
economic evaluation of Connecticut Yankee which recommended permanently closing
the unit and replacing its output with less expensive energy sources. In
December 1996, the Board of Directors of Connecticut Yankee voted to retire the
generating station. Connecticut Yankee certified to the NRC that it had
permanently closed power generation operations and removed fuel from the
reactor. Montaup's share of the total estimated costs for the permanent
shutdown, decommissioning, and recovery of the investment in Connecticut Yankee
is approximately $27.4 million and is included with Other Liabilities on the
Consolidated Balance Sheet as of December 31, 1997. The recovery of this
estimated amount, elements of which have been disputed by certain intervening
parties, is subject to approval of FERC. Also, due to anticipated
recoverability, a regulatory asset has been recorded for the same amount and is
included with Other Assets. Montaup cannot predict the ultimate outcome of
FERC's review.
See Fuel for Generation for a discussion of a Connecticut Yankee action against
the DOE.
Maine Yankee:
On August 6, 1997, as the result of an economic evaluation, the Maine
Yankee Board of Directors voted to permanently close that nuclear plant.
Montaup has a 4.0% equity ownership in Maine Yankee with a book value of
approximately $3.2 million at December 31, 1997. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning, and recovery of
the remaining investment in Maine Yankee, is approximately $35.4 million and is
included with Other Liabilities on the Consolidated Balance Sheet at December
31, 1997. Also, due to anticipated recoverability, a regulatory asset has been
recorded for the same amount and is included with Other Assets.
On August 7, 1997, Maine Yankee submitted to the NRC a certification
that the plant had ceased operations permanently and a certification that the
nuclear fuel had been permanently removed from the plant's reactor. On August
27, 1997, Maine Yankee submitted to the NRC its Post Shutdown Decommissioning
Activities Report describing its plan for decommissioning the plant. On
November 5, 1997, Maine Yankee submitted a rate filing to the FERC to provide
for recovery of its costs during the decommissioning period. The filing
provides for the investment in plant, nuclear fuel and associated facilities to
continue to be recovered through October 2008. There are several intervenors
in this FERC filing and Montaup cannot predict the outcome of FERC's review.
In November 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy) signed
an agreement to renew the contract for Entergy to provide management services
to Maine Yankee. Entergy will provide management services for the initial
decommissioning of Maine Yankee activities through September 30, 1998.
Also, as a result of the August 1997 shutdown, Montaup and the other
equity owners have been notified by the Secondary Purchasers that they will no
longer make payments for purchased power to Maine Yankee. The Secondary
Purchase Contracts are between the equity owners as a group and 30
municipalities throughout New England. Presently, the equity owners are making
payments to Maine Yankee to cover the payments that would be made by the
municipals.
On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation
of Arbitration to the equity owners of Maine Yankee. On December 15, 1997, the
equity owners as a group filed at FERC a Complaint and Petition for
Investigation, Contract Modification, and Declaratory Order. The equity owners
are seeking an order from FERC declaring that the Secondary Purchasers remain
responsible for payments due under the Purchase Contracts and directing the
Secondary Purchasers to make such payments. The equity owners also seek a
modification of the Secondary Purchase Contracts to extend the termination date
or otherwise to ensure that the equity owners may fully recover from the
Secondary Purchasers a share of the costs of shutting down and decommissioning
the Maine Yankee plant that is proportionate to the Secondary Purchasers'
entitlements to energy from the plant. Management does not believe that this
contract issue will have a material effect on EUA's future operating results or
financial position and cannot predict its ultimate outcome at this time.
See Fuel for Generation for a discussion of a Maine Yankee action against the
DOE.
Yankee Atomic Electric Company (Yankee Atomic):
Montaup holds a 4.5% equity ownership in Yankee Atomic. In October 1997,
Yankee Atomic announced that it had accepted a Duke Engineering and Services
(DE&S) Letter of Intent to acquire Yankee Atomic's Nuclear Services Division.
Yankee Atomic indicated it was seeking a purchaser with a long-term commitment
to excellence in nuclear operations and support services that would continue to
provide that level of service to its affiliated New England nuclear plants.
Yankee Atomic's plan is to continue as a smaller organization responsible for
the completion of the safe and effective decommissioning of the Yankee Nuclear
Power Plant in Rowe, Massachusetts. The acquisition was completed on December
1, 1997.
See Fuel for Generation for a discussion of a Yankee Atomic action against the
DOE.
General:
Recent actions by the NRC, some of which are cited above, indicate that
the NRC has become more critical and active in its oversight of nuclear power
plants. EUA is unable to predict at this time, what, if any, ramifications
these NRC actions will have on any of the other nuclear power plants in which
Montaup has an ownership interest or power contract.
Public Utility Regulation
Eastern Edison and Montaup are subject to regulation by the DTE with
respect to the issuance of securities, the form of accounts, and in the case of
Eastern Edison, rates to be charged, services to be provided, and other
matters. Blackstone and Newport are subject to regulation in numerous respects
by the RIPUC and the RIDPUC, including matters pertaining to financing, sales
and transfers of utility properties, accounting, rates and service. In
addition, by reason of its ownership of fractional interests in certain
facilities located in other states, Montaup is subject to limited regulation in
those states. (See Electric Utility Industry Restructuring.)
IPPs, including OSP in which EUA Ocean State has a 29.9% ownership
interest, do not benefit from the PURPA exemptions and are subject to FERC
regulation under the Federal Power Act as well as various other federal, state
and local regulations.
The EUA System is subject to the jurisdiction of the SEC under the 1935
Act by virtue of which the SEC has certain powers of regulation, including
jurisdiction over the issuance of securities, changes in the terms of
outstanding securities, acquisition or sale of securities or utility
assets or other interests in any business, intercompany loans and other
intercompany transactions, payment of dividends under certain circumstances,
and related matters. Eastern Edison is a holding company under the 1935 Act by
reason of its ownership of securities of Montaup. As a subsidiary of EUA, a
registered holding company, Eastern Edison is exempted from registering as a
holding company by complying with the applicable rules thereunder.
The Retail Subsidiaries and Montaup are also subject to the jurisdiction
of FERC under Parts II and III of the Federal Power Act. That jurisdiction
includes, among other things, rates for sales for resale, interconnection of
certain facilities, accounts, service, and property records.
In 1993, the DTE and RIPUC approved a Memorandum of Understanding (MOU)
between Eastern Edison, Blackstone, Newport and Montaup which established a
framework for a coordinated, regional review of the resource planning and
procurement process of those companies. It was based on the assumption that
resource planning and procurement by a regional electric company may be
implemented more effectively under a coordinated, consensual review process
involving the EUA retail companies and the state public utility commissions to
which the EUA retail companies are subject. Pursuant to the terms of the MOU,
at least every two years Montaup and Eastern Edison were to file with the DTE
and Blackstone and Newport were to file with the RIPUC an integrated
resource plan concurrently. The MOU outlined a mechanism and a timetable by
which the reviews by the two commissions would be coordinated and any
inconsistencies among the decisions by the state commissions would be resolved.
In conjunction with its approval of the MOU, the DTE granted Eastern
Edison and Montaup an exemption from the DTE's Integrated Resource Management
regulations, but required them to plan, solicit and procure additional
resources according to newly promulgated regional Integrated Regional Planning
procedures consistent with the MOU. The Integrated Resource Management Plan
of Blackstone and Newport meet the criteria of the RIPUC.
Implementation of the MOU has not had a material effect on the EUA System.
The move to restructure the industry to a more competitive model may, however,
impact the role of the states in reviewing utilities' resource planning and
procurement activities. Retail customers' direct access to power suppliers
and the limitation of distribution companies' power supply activities to
standard offer and default services competitively procured from the market may
substantially alter the practical effect of state regulation. As competition
becomes more prevalent in the electric industry, it is anticipated that
regulatory review of power supply will decrease accordingly.
See Rates with respect to regulation of rates charged to customers. See
Environmental Regulation. See Fuel for Generation with respect to the disposal
of spent nuclear fuel. See Environmental Regulation of Nuclear Power and see
Nuclear Power Issues with respect to regulation of nuclear facilities by the
NRC. See also Electric Utility Industry Restructuring.
Rates
Rates charged by Montaup (which sells power only for resale) are subject
to the jurisdiction of FERC. The rates for services rendered by the Retail
Subsidiaries for the most part are subject to approval by and are on file with
the DTE in the case of Eastern Edison and with the RIPUC in the case of
Blackstone and Newport. For the twelve months ended December 31, 1997, 61% of
EUA's consolidated revenues were subject to the jurisdiction of FERC, 15% to
that of the DTE and 13% to that of the RIPUC. The remaining 11% of
consolidated revenues are not subject to jurisdiction of utility commissions.
For the twelve months ended December 31, 1997, 79.9% of Eastern Edison's
consolidated revenues were subject to the jurisdiction of the FERC and 20.1% to
DTE. Additionally, rates charged by OSP are subject to the jurisdiction of
FERC. All OSP (Unit 1 and Unit 2) power contracts have been approved by FERC.
However, pursuant to the OSP unit power agreements, rate supplements are
required to be filed annually subject to FERC approval. This process may
result in rate increases or decreases to OSP power purchasers.
Recent general rate increases (reduction) for Montaup and the Retail
Subsidiaries are as follows (In Thousands):
Applied For Effective (1) Return on
Annual Annual Common
Revenue Date Revenue Date Equity %
Federal
- Montaup See Electric Utility Industry Restructuring
Massachusetts
None
Rhode Island
- Blackstone
RIPUC - 2498 3,094 11/15/96(2) 2,821 1/1/97
RIPUC - 2498 2,265 11/15/97(3) 2,265 1/1/98
- Newport
RIPUC - 2499 1,437 11/15/96(2) 1,425 1/1/97
RIPUC - 2499 1,031 11/15/97(3) 1,055 1/1/98
Notes:
(1) Per final order or settlement agreement.
(2) The revenue requirement represents the compliance with
R.I.G.L. 39-1-27.4 to file performance based rates reflecting
the change in the Consume Price Index for the most recent 2
months ended September 30, 1996.
(3) The revenue requirement represents the compliance with
R.I.G.L. 39-1-27.4 to file rates reflecting the change in the
Consumer Price Index for the most recent 12 months ended
September 30, 1997.
FERC Proceedings - Transmission:
Open-access transmission tariffs for point-to-point and local network
service were filed with FERC by Montaup in February 1996 and became effective
April 21, 1996, subject to refund, for a period of at least one year. The
rates in the tariffs were the subject of a settlement agreement which was filed
on July 9, 1996 to modify its terms and conditions in conformance with FERC
orders No. 888 and No. 889, issued on April 24, 1996.
On December 31, 1996, Montaup filed revisions to its Open Access
Transmission tariff necessary to comply with FERC's order on September 11,
1996, which dealt with use rights of High Voltage Direct Current (HVDC)
interconnection transmission facilities with the Hydro Quebec system and on
January 21, 1997, filed additional revisions to coincide with the NEPOOL Open
Access Transmission filing.
On January 3, 1997, as required by FERC in Order No. 889, Montaup filed its
Standards of Conduct Implementation Procedures detailing Montaup's compliance
with the requirements of FERC's standards. Coincident with this filing,
Montaup complied with OASIS's requirements as part of a region wide OASIS in
NEPOOL.
On March 4, 1997, FERC issued Orders 888A and 889A which reaffirmed the
legal and policy bases in which Orders 888 and 889 were grounded and addressed
interventions that were filed in response to Orders 888 and 889. As a result,
on July 14, 1997, Montaup filed revisions to its open access transmission
service for compliance with FERC Order 888A. The filing incorporates all of
the tariff amendments to date.
On June 4, 1997, as supplemented on July 14, 1997, Montaup filed with FERC
in Docket No. ER97-3200-000 amendments to its open access transmission tariff
to provide for unbundled retail transmission service. Montaup proposed to
allow retail customers to obtain retail transmission service directly from
Montaup or through Montaup's retail affiliates acting as the retail customers'
agent. Montaup requested FERC to allow the tariff amendments to become
effective for service to retail customers in Blackstone's and Newport's service
areas on July 1, 1997. FERC accepted the amendment to become effective
subject to refund on that date in an order issued September 12, 1997. FERC
accepted the amendment subject to any modification that may be required as a
result of other pending proceedings concerning Montaup's transmission tariff
and ordered Montaup to make a compliance filing changing the amendments in
certain limited respects. The compliance filing was made by Montaup on October
10, 1997.
On October 29, 1997 Montaup filed an Offer of Settlement for all non-rate
issues in FERC Docket ER97-2338-000. This docket included the filing of
unsigned network transmission service agreements and network operating
agreements with Montaup's non-affiliated wholesale customers. The Offer of
Settlement was accepted by FERC on October 31, 1997.
On October 31, 1997 Montaup filed an amendment to its open access
transmission tariff to include retail transmission service to customers of the
Pascoag Fire District. This filing was accepted by FERC subject to refund and
became effective on January 1, 1998. Montaup has concluded settlement
discussions with the Pascoag Fire District and has filed an Offer of Settlement
with FERC.
On November 25, 1997 Montaup filed an amendment to its open access
transmission tariff to include support payments made by Montaup for Pool
Transmission Facilities (PTF). The impact of this filing in FERC Docket
ER98-861-000 is to increase Montaup's annual transmission revenue requirement
by approximately $1.8 million. On January 14, 1998 the Commission consolidated
this filing with FERC Docket ER97-4691-000. Montaup has reached a settlement
with the municipals and the FERC Staff in this docket and has filed and Offer
Settlement with FERC.
On December 15, 1997 Montaup reached a settlement with its wholesale
customers and FERC to resolve FERC Docket ER97-4691-000. This docket
established a formula rate schedule for Montaup's annual transmission revenue
requirement. Filing of the Settlement has been delayed by the Commission's
decision on January 14, 1998 to consolidate FERC Docket ER98-861-000 into this
proceeding.
FERC Proceedings - Supply:
Montaup submitted an informational filing of a Divestiture Plan on July 1,
1997 whereby Montaup would no longer be a subsidiary of Eastern Edison.
On October 29, 1997 Montaup filed settlement agreements in dockets ER97-
2800 and ER97-3121 among Montaup, Blackstone, Newport, RIDIV, RIPUC and the
R.I. Attorney General; a settlement agreement among Montaup, the Division of
Energy Resources of the Office of the Attorney General of Massachusetts and
Eastern Edison; separate settlements between Montaup and the Middleborough Gas
and Electric Department; Montaup and the Pascoag Fire District; and a
settlement between Montaup and Taunton Municipal Lighting Plant. These
settlements shorten the notice of termination from three years to 90 days.
(See Electric Utility Industry Restructuring for further discussion of the
termination of Montaup's all-requirements contracts with its affiliated
customers and other electric utility industry restructuring issues.)
Massachusetts Proceedings:
On May 16, 1997 a restructuring Settlement Agreement was filed with the
DTE outlining terms of a settlement of electric utility industry restructuring
issues reached among Eastern Edison, Montaup the Massachusetts Attorney
General, MADOER and several other signatories. The DTE held evidentiary
hearings on the Settlement Agreement in July 1997, and issued a letter of
conditional approval on October 3, 1997. Eastern made a compliance filing
addressing specific concerns of the DTE on October 10, 1997 and final approval
was expected within 30 days of that compliance filing. In light of pending
electric utility industry restructuring legislation, the DTE did not act upon
the compliance filing within the 30 days. On November 25, 1997 the Electric
Industry Restructuring Act was signed into law and on December 5, 1997 DTE
issued a notice seeking comments on whether the Settlement Agreement was
in substantial compliance with the Act. Eastern Edison and others provided
comments and on December 23, 1997 the DTE approved Eastern Edison's Settlement
Agreement. (See Electric Utility Industry Restructuring for further discussion
of settlement terms.) On December 31, 1997 Eastern made a partial compliance
filing of unbundled rates and Terms and Conditions to facilitate the Settlement
Agreement and received an order approving them on January 8, 1998. On February
9, 1998 Eastern made a second compliance filing of retail delivery rates and
standard offer and default service. On February 25, 1998, Eastern Edison
submitted revisions to its February 9, 1998 compliance filing and on February
27, 1998 the DTE approved the filing. Rates were effective March 1, 1998.
Retail choice of electricity supplier started March 1, 1998.
On July 1, 1997, the EUA companies filed their Plan for Implementing
Divestiture and Corporate Restructuring with the DTE, seeking approval of the
plan for divestiture of generation assets, creation of a transmission
affiliate, the transfer of control over transmission assets to that affiliate,
and the various financing transactions necessary to accomplish restructuring.
At the DTE's request, consideration of the plan was deferred until the third
quarter of 1997, and is currently pending before the DTE in Docket DTE 97-105.
The plan was updated in a supplemental filing on November 21, 1997.
Rhode Island Proceedings:
On December 18, 1996 the RIPUC initiated Docket No. 2509 to investigate
utility company storm contingency funds. Both Blackstone and Newport are
recovering through rates amounts for storm contingencies. A hearing was held
on February 28, 1997 and a decision was reached in June 1997 directing Newport
to use its 1996 Purchased Capacity Adjustment Clause refund from Montaup,
approximately $1.2 million, to fund the Newport Storm Contingency fund.
Stipulations filed by each of the companies and the RIDPUC outlining individual
storm thresholds and deductibles for eligible storm fund coverage were also
accepted.
The RIPUC opened Docket No. 2514 to investigate a restructuring plan filed
on December 27, 1996 by Blackstone and Newport in compliance with the URA. The
plan covered such issues as corporate restructuring, unbundled rates, terms and
conditions, and performance based rates. In February 1997, Blackstone, Newport
and Montaup reached a settlement with the RIDPUC and the Rhode Island Attorney
General and subsequently filed a Memorandum of Understanding with the RIPUC
outlining the terms of the settlement for implementation of their restructuring
plan. A hearing on the MOU was held on March 20, 1997.
On September 4, 1997, the RIPUC issued an order approving a partial
settlement of retail issues. This partial settlement approves specifically the
Transmission Cost Adjustment Clause, Customer Terms and Conditions, Retail
Delivery Rate Schedules and Terms and Conditions for Nonregulated Power
Producers. A settlement agreement filed on June 9, 1997 defining Performance
Standards under PBR was also approved. However, as explained above under
Montaup's Open Access Transmission Tariff, as amended, in FERC Docket No. ER97-
3200-000, Montaup will directly, or indirectly through Blackstone and Newport,
acting as Montaup's agents, bill retail choice customers for transmission
service. Consequently, Blackstone and Newport amended their Retail Delivery
Rate Schedules and Terms and Conditions for Electric Service by removing the
transmission service charges and references thereto from these tariffs, and to
cancel their Transmission Cost Adjustment Clauses as the need for the clauses
no longer exists. The remaining retail issues were approved by the RIPUC on
December 17, 1997.
On July 1, 1997 a Plan for Implementing Divestiture and Corporate
Restructuring was filed. After holding hearings the plan was approved at an
open meeting of the RIPUC on September 2, 1997, and by written order dated
October 21, 1997. Montaup, Blackstone and Newport are required to report
on the progress of the divestiture plan.
Also included in the settlement, approved at an open meeting held on
December 17, 1997, is a stipulation to expand eligibility to the low income
rate. It was also stipulated that Blackstone would sell its Pawtucket No. 2
Hydro Station and associated properties. The RIPUC issued its order December
31, 1997.
Blackstone and Newport made a Standard Offer and Last Resort Power Supply
filing on November 7, 1997. By order of December 31, 1997 the Standard Offer
filing was found not to comply with the URA since it was not subject to
separate bid. However, interim generation services rates and the last resort
service rates were approved for service on and after January 1, 1998.
Environmental Regulation
General:
The Retail Subsidiaries and Montaup and other companies owning generating
units from which power is obtained are subject, like other electric utilities,
to environmental and land use regulations at the federal, state and local
levels. The EPA, and certain state and local authorities, have jurisdiction
over releases of pollutants, contaminants and hazardous substances into the
environment and have broad authority in connection therewith, including the
ability to require installation of pollution control devices and remedial
actions. In 1994, EUA instituted an environmental audit program for Montaup
and the Retail Subsidiaries, designed to ensure compliance with environmental
laws and regulations and to identify and reduce liability with respect to those
requirements.
Preconstruction Reviews:
Federal, Massachusetts and Rhode Island legislation and regulations
require the preparation of reports evaluating the environmental impact of large
projects and of ways for limiting their adverse impact as a prerequisite to the
granting of various government permits and licenses. Federal, Massachusetts
and Rhode Island air quality regulations also require that plans for
construction or modification of fossil fuel generating facilities (including
procedures for operation and maintenance) receive prior approval from the MADEP
or RIDEM. In addition, in Massachusetts, certain electric generation and
transmission facilities will be permitted to be built only if they are
consistent with a long-range forecast of energy demand filed by the utility
concerned and approved by the Massachusetts Energy Facilities Siting Council.
In Rhode Island, siting, construction and modification of major electric
generating and transmission facilities must be approved by the Rhode Island
Energy Facility Siting Board.
Generating facilities owned or operated by Montaup and Newport as well as
those in which they have an interest, and are required to pay a share of the
costs, are also subject, like other electric utilities, to regulation with
regard to zoning, land use, and similar controls by various state and local
authorities.
Solid and Hazardous Waste Regulation:
Federal, Massachusetts and Rhode Island legislation and regulations impose
requirements on the generation, transportation, storage and disposal of
hazardous and solid wastes. In Massachusetts, the state and some of the
federal requirements are implemented and enforced by the MADEP, whereas in
Rhode Island, RIDEM carries out these activities. Generating facilities owned
or operated by Montaup and Newport, as well as those in which they have an
interest and must pay a share of the costs, are subject to these requirements.
Superfund Requirements:
Remediation of contaminated sites is subject to federal and state
legislation and regulation. At the federal level, the governing statute is the
Comprehensive Environmental Responsibility, Compensation, and Liability Act of
1980 (CERCLA), as amended by the Superfund Amendments and Reauthorization Act
of 1986. In Massachusetts, the superfund statute is known as Chapter 21E,
while in Rhode Island it is called the "Industrial Property Site Remediation
and Reuse Act." In addition, certain sections of the Massachusetts and Rhode
Island hazardous waste requirements are relevant to the reporting, study, and
cleanup of site contamination. Such authorities impose liability for site
contamination and spills and authorize response by government agencies. Under
these provisions, joint and several liability may be imposed for cleanup costs
upon, among others, the owners or operators of a facility where hazardous
substances were disposed, the party who generated the substances, or any
party who arranged for the disposition or transport of the substances. Due to
the nature of the business of EUA's utility subsidiaries, certain materials are
generated that may be classified as hazardous under CERCLA, Chapter 21E and
Rhode Island law. As a rule, the subsidiaries employ licensed contractors
to dispose of such materials. (See Item 3. LEGAL PROCEEDINGS -- Environmental
Proceedings, for a discussion of specific sites where such authorities have
been invoked.)
Chemical Regulation:
The EPA, pursuant to the Toxic Substances Control Act (TSCA),
regulates the use, storage, and disposal of polychlorinated biphenyls (PCBs)
and other dielectric fluids. Because the EUA System had owned and used some
electrical transformers containing PCBs, it is subject to EPA regulation under
TSCA. These PCB transformers have been either declassified or disposed of in
accordance with TSCA requirements. EUA currently uses mineral oil transformers
which may contain traces of PCBs and which may be subject to regulations
pursuant to TSCA.
Potential Regulation of Electric and Magnetic Fields:
A number of scientific studies in the past several years have examined the
possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. The research to date has not conclusively established a direct
causal relationship between EMF exposure and human health. Additional studies,
which are intended to provide a better understanding of EMF, are continuing.
On October 31, 1996, the National Academy of Sciences issued a literature
review of all research to date, "Possible Health Effects of Exposure to
Residential Electric and Magnetic Fields." Its most widely reported conclusion
stated, "No clear, convincing evidence exists to show that residential
exposures to EMF are a threat to human health."
Some states have enacted regulations to limit the strength of EMF at the
edge of transmission line rights-of-way. The Rhode Island legislation has
enacted a statute which authorizes and directs the Rhode Island Energy Facility
Siting Board to establish rules and/or regulations governing construction
of high voltage transmission lines of 69 kv or more. In addition, an energy
facility siting application, in Rhode Island must include, when applicable, any
current independent, scientific research pertaining to EMF exposure for review
by the Board. Management cannot predict the impact if any, which
legislation(s) or other developments concerning EMF may have on the EUA System.
Water Regulation:
The objective of the Federal Water Pollution Control Act (FWPCA) is to
restore and maintain the chemical, physical, and biological integrity of the
nation's navigable waters, and it prohibits the discharge of pollutants
(including heat) into navigable waters without a permit. All wastewater
discharge permits for plants in Massachusetts, including those for the Somerset
and Canal plants, are issued jointly by the EPA and MADEP. These same agencies
also regulate certain industrial stormwater discharges. In addition, the EPA
has promulgated requirements under the authority of the FWPCA regarding the
preparation of oil spill prevention counter measure and control (SPCC) plans
for certain oil storage facilities that are located near a waterway. Similar
requirements are mandated under the Oil Pollution Act of 1990 which mandates
the preparation of contingency plans to prevent releases of oil and to ensure
that sufficient resources are in place and ready to respond to any release of
oil.
Standards have been established to control the dredging and filling of
wetlands under the FWPCA, the Massachusetts Wetland Protection Act, the
Massachusetts Rivers Protection Act and the Rhode Island Wetland Act. The EPA,
the Army Corps of Engineers, RIDEM, the Rhode Island Coastal Resources
Management Council and the MADEP are pursuing a non-degradation (no loss)
policy for wetlands. In addition, the MADEP is responsible for promulgating
regulations relating to water usage and conservation, under the Massachusetts
Water Management Act, and for licensing structures (Chapter 91 licenses) in
Massachusetts waterways.
Most of the generating units from which Montaup obtains power operate
under permits which limit their wastewater discharges into waterways, require
monitoring and, in some instances, biological studies and toxicity testing of
the impact of the discharges. Such permits are issued for a period of not
more than five years, at the expiration of which renewal must be sought. The
permit for the Somerset plant was renewed on September 30, 1994 and expires on
September 30, 1998. Such units are also subject to stormwater discharge and
wetlands permitting requirements, and the Somerset plant and the South Somerset
property have been issued Chapter 91 licenses. In addition, the Somerset plant
has an approved contingency plan under the Oil Pollution Act, as well as an
SPCC Plan under the EPA rules, implementing the FWPCA which is designed to
minimize the release of oil and other substances into navigable waters.
Air Regulation:
All fossil fuel plants from which Montaup obtains power operate under
permits which limit their emissions into the air and require monitoring of the
emissions. Air quality requirements adopted by state authorities in
Massachusetts pursuant to the Clean Air Act impose limitations with respect to
pollutants such as sulfur dioxide (SO2), oxides of nitrogen (NOx) and
particulate matter. Montaup's Somerset Station is permitted to burn coal which
results in SO2 emissions not in excess of 1.2 pounds per million BTU heat
release potential (approximately 0.75% sulfur content coal). Canal No. 2 is
permitted to burn fuel oil which results in SO2 emissions not in excess of 1.2
pounds per million BTU heat release potential (approximately 1% sulfur content
fuel oil).
The EPA has established clean air standards for certain pollutants,
including standards limiting emissions from coal-fired and oil-fired
generators. The 1990 amendments to the federal Clean Air Act created additional
regulatory programs and strengthened air pollution control requirements that
affect electric generating facilities. Title IV of the Clean Air Act
Amendments addresses acid deposition abatement and establishes a two-phase
utility power plant pollution control program to reduce emissions of SO2 and
NOx. The first phase began in 1995 and affected approximately 261 large units
in 21 eastern and midwestern states. Phase II, which begins in the year 2000,
imposes more stringent emission limits on these larger plants and also sets
restrictions on smaller, cleaner plants fired by coal, oil and gas. Montaup's
Somerset Station is classified as a Phase II facility with a compliance
deadline set for the end of 1999. The control program establishes a national
cap of 8.90 million tons per year for SO2 emissions for utilities. Beginning
in the year 2000, the EPA will issue these allowances to utilities on an annual
basis. Such utilities will include Montaup's Somerset Station and Canal No. 2.
MADEP regulations established a statewide cap on SO2 emissions and
required Montaup's facilities to meet an average emission rate of 1.2 pounds of
SO2 per million BTU of fuel input by the end of 1994. Under Title IV of the
Clean Air Act, Montaup would not be required to meet this SO2 emission level
until the year 2000. As required by state regulations, Montaup submitted and
received approval of a plan detailing how it would meet the 1995 SO2 standard.
Montaup is now achieving compliance by using lower sulfur content fuels.
Other provisions of the Clean Air Act Amendments will likely impact
Montaup. Title I of the Act establishes a strategy to be followed by the
states in order to attain national air quality standards, particularly the
ozone standard. NOx is an important precursor in the formation of ozone.
Title I requires additional controls on industrial sources of NOx, including
utility power plants. It also creates the Northeast Ozone Transport Region
covering a multi-state area that includes Massachusetts and Rhode Island.
Areas within the transport region will become subject to enhanced controls on
NOx emissions.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight Northeast states including
Massachusetts and Rhode Island, issued recommendations with respect to NOx
controls for existing utility boilers required to meet the ozone non-attainment
requirements of the Clean Air Act Amendments. The NESCAUM recommendations
cover more facilities than EPA's requirements. The MADEP and RIDEM have
amended their regulations in accordance with the NESCAUM recommendations and
require that Reasonably Available Control Technology (RACT) be implemented at
all stationary sources potentially emitting 50 tons per year or more of NOx.
Montaup has received NOx RACT approvals for a boiler and two combustion
turbines at the Somerset facility and has initiated compliance through, among
other things, selective noncatalytic reduction processes. In 1996, MADEP
issued regulations that establish an emissions budget for NOx in the
Commonwealth and would require additional NOx emission reductions beginning on
May 1, 1999. Montaup is evaluating its compliance options under this program.
Title V of the Clean Air Act Amendments provides for the issuance of
federally enforceable operating permits which contain limits and conditions
necessary to comply with all applicable air requirements. Montaup submitted
its initial Operating Permit Application under this program on May 5, 1995. On
September 20, 1995, MADEP issued Montaup an Administrative Completeness
Determination and Application Shield for its Operating Permit Application, and
a permit is expected to be issued in 1998. Although individual sources will
be required to pay fees to the various states which will administer the
program, it is not expected to have a material financial impact on the EUA
System.
On July 16, 1997, the EPA issued a new and more stringent rule covering
ozone and particulate matter under the federal Clean Air Act to be followed by
promulgation of more stringent ozone and particulate matter standards. The
states will prepare plans for meeting these standards beginning about 2004.
At this time, management is unable to predict the financial impact this rule
might have on the EUA System since the federal standards and the state plans
for adopting these standards have yet to be adopted. Moreover, more data must
be collected prior to promulgation of particulate matter standards.
On October 28, 1997, Eastern Edison, Montaup, the Massachusetts Attorney
General and Division of Energy Resources entered into a settlement regarding
electric utility restructuring in the State of Massachusetts which was approved
by the FERC, subject to compliance with certain conditions, on December 19,
1997. The settlement includes a plan for emissions reductions related to
Montaup's Somerset Station Units 5 and 6, and to Montaup's 50% ownership share
of Canal No. 2. The basis for SO2 and NOx emission reductions in the proposed
settlement is an allowance cap calculation. Within this allowance cap, the
following commitments were made:
- Montaup may meet its allowance caps (effective emission rates) by any
combination of control technologies, fuel switching, operational
changes, and/or the use of purchased or surplus allowances;
- By January 1, 2000, Somerset Units 5 & 6 must comply with an effective
annual SO2 emission rate of 0.30 lbs/mmBtu;
- By January 1, 2000, Units 5 & 6 must comply with an effective NOx
emission rate of 0.21 lbs/mmBtu for the seven months outside the ozone
season, and 0.15 lbs/mmBtu during the five month ozone season (May
through September). For Unit 6, the cost of compliance with this NOx
limit is capped at $405,000 per year until January 1, 2003. Unit 5, if
reactivated, must comply with the more stringent of: (1) best available
control technology (or BACT), and (2) the emission rates set forth above
with no cost cap; and
- By January 1, 2003, Unit 6 must comply with an effective annual emission
limit of 0.15 lbs Nox/mmBtu. Unit 5, if reactivated, must comply with
the more stringent of: (1) BACT, or (2) 0.15 lbs NOx /mmBtu.
- By January 1, 2010, Canal No. 2 must comply with an effective SO2
emission rate of 0.30 lbs/mmBtu, and an effective NOx emission rate of
0.15 lbs/mmBtu, on an annual basis; this commitment only applies to
Montaup's 50% ownership share of Canal No. 2.
Other Requirements:
The EPA and state and local authorities may, after appropriate
proceedings, require modification of generating facilities for which
construction permits or operating licenses have already been issued,
or impose new conditions on such permits or licenses, and may require that the
operation of a generating unit cease or that its level of operation be
temporarily or permanently reduced. Such action may result in increases in
capital costs and operating costs which may be substantial, in delays or
cancellation of construction of planned facilities, or in modification or
termination of operations of existing facilities.
Other activities of the EUA System from time to time are subject to the
jurisdiction of various other local, state and federal regulatory agencies. It
is not possible to predict with certainty what effects the above described
statutes and regulations will have on the EUA System.
Environmental Regulation of Nuclear Power
The NRC has promulgated a variety of standards to protect the public from
radiological pollution caused by the normal operation of nuclear generating
facilities. For example, the NRC requires licensed facilities to develop plans
to respond to unexpected developments.
Under the Nuclear Waste Policy Act (NWPA), the federal government is
charged with providing facilities for the disposal or permanent storage of
civilian nuclear waste. (See Fuel for Generation above.) The NRC has
promulgated regulations for the protection of the public from radiological
dangers in connection with the disposal of nuclear waste materials.
In certain instances the NRC and the EPA have overlapping jurisdiction.
Thus, NRC regulations are supplemented by requirements imposed by the EPA under
a variety of federal environmental statutes. Those include requirements for
permits covering the discharge of pollutants (including heat) into the
nation's waters and compliance with EPA standards for so-called mixed waste
(i.e. hazardous waste which contains radioactive materials) and for certain
toxic air pollutants which include radionuclides. The EPA has also promulgated
environmental radiation protection standards for nuclear power plants to
regulate the doses of radiation received by the general public.
Environmental regulation of nuclear facilities in which the EUA System has
an interest or from which they purchase power may result in significant
increases in capital and operating costs. They could also result in delays or
cancellation of construction of planned improvements, or in modification or
termination of existing facilities.
Other
EUA occasionally makes forward-looking projections of expected future
performance or statements of our plans and objectives. These forward-looking
statements may be contained in filings with the SEC, press releases and oral
statements. Actual results could differ materially from these statements.
Therefore, no assurances can be given that such forward-looking statements and
estimates will be achieved.
Item 2. PROPERTIES
Power Supply
In 1997, the EUA System's wholly owned generating units referred to in the
following table consisted of Montaup's jet-fueled peaking units (Somerset Jet 1
and Jet 2) and Somerset 6 which was converted from oil to coal burning in 1983,
Blackstone's Pawtucket Hydro, which was repowered in 1985 and Newport's diesel
peaking units (Eldred in Jamestown and Jepson in Portsmouth), leased to
Montaup, which supply the EUA System with 8 mw and 8.25 mw, respectively. With
the exception of Somerset's Jet 1 and Jet 2, Montaup has not significantly
increased its wholly owned generating units since 1959. The EUA System has
found it more economically beneficial to join with other utilities in
the joint ownership of large generating units and in long-term purchase
contracts, and to supplement these sources with short-term purchases as
required. EUA believes that spreading the EUA System's sources of electricity
among a number of plants should improve the reliability of its power supply and
limit the financial exposure relating to construction and potentially prolonged
outages of a generating unit. (See Item 1. BUSINESS -- Electric Utility
Industry Restructuring for a discussion of future power needs and plans to
divest all of Montaup's generating assets.)
The EUA System experienced a new all-time peak demand of approximately 933
mw on July 17, 1997.
<TABLE>
EUA SYSTEM CAPABILITY
GENERATING UNITS IN SERVICE AS OF DECEMBER 31, 1997
<CAPTION>
GROSS WINTER MAX GROSS NET
IN SYSTEM CLAIMED SYSTEM UNIT SYSTEM
SERVICE SHARE CAPABILITY SHARE SALES SHARE
DATE UNIT NAME FUEL TYPE OWNER/OPERATOR % MW MW MW MW
<S> <C> <C> <C> <C> <C> <C> <C> <C>
100% OWNERSHIP:
1959 SOMERSET 6 COAL MONTAUP ELECTRIC CO. 100.00 115.32 115.32 0.00 115.32
1970 SOMERSET J1 JET OIL MONTAUP ELECTRIC CO. 100.00 23.70 23.70 0.00 23.70
1971 SOMERSET J2 JET OIL MONTAUP ELECTRIC CO. 100.00 24.30 24.30 0.00 24.30
1985 PAWTUCKET HYDRO HYDRO BLACKSTONE VALLEY ELEC. 100.00 1.24 1.24 0.00 1.24
1961 JEPSON DIESEL NEWPORT ELECTRIC CORP. 100.00 8.00 8.00 0.00 8.00
1978 ELDRED DIESEL NEWPORT ELECTRIC CORP. 100.00 8.60 8.60 0.00 8.60
SUBTOTAL: 118.16 0.00 181.16
JOINT OWNERSHIP:
1976 CANAL 2 NO. 6 OIL CANAL ELECTRIC COMPANY 50.00 556.33 278.17 34.53 243.64
1978 WYMAN 4 (YAR 4) NO. 6 OIL CENTRAL MAINE POWER CO. 2.63 620.00 16.30 0.00 16.30
1986 MILLSTONE 3 NUCLEAR NORTHEAST UTILITIES 4.01 1145.70 45.93 0.00 0.00
1990 SEABROOK NUCLEAR NORTH ATLANTIC ENERGY CORP 2.90 1162.00 33.70 0.00 33.70
SUBTOTAL: 374.10 34.53 293.63
EQUITY OWNERSHIP:
1972 VERMONT YANKEE NUCLEAR VT. YANKEE NUCLEAR POWER 2.25 531.00 11.95 0.00 11.95
SUBTOTAL: 11.95 0.00 11.95
PURCHASED POWER:
1968 CANAL 1 NO. 6 OIL CANAL ELECTRIC COMPANY 25.00 564.00 141.00 0.00 141.00
1972 PILGRIM 1 NUCLEAR BOSTON EDISON COMPANY 11.00 666.13 73.27 0.00 73.27
1977 POTTER 2 GAS/OIL BRAINTREE ELEC. LIGHT DEPT 41.67 96.00 40.00 0.00 40.00
1975 CLEARY 9 GAS/OIL TAUNTON MUNIC. LIGHTING 13.64 110.00 15.00 0.00 15.00
1984 MCNEIL WOOD VERMONT ELECTRIC POWER 15.24 53.00 8.08 0.00 8.08
1972 BERLIN A&B JET OIL GREEN MOUNTAIN POWER 26.50 56.60 15.00 0.00 15.00
1974 BEAR SWAMP GT1 HYDRO NEW ENGLAND POWER 5.13 292.50 15.00 0.00 15.00
1974 BEAR SWAMP GT2 HYDRO NEW ENGLAND POWER 5.13 292.50 15.00 0.00 15.00
1990 OSP 1 GAS OCEAN STATE POWER 28.00 306.60 85.85 0.00 85.85
1991 OSP 2 GAS OCEAN STATE POWER 28.00 306.60 85.85 0.00 85.85
1991 NEA GAS NORTHEAST ENERGY ASSOC. 8.62 333.43 28.74 0.00 28.74
1982/1986 STONY BROOK 2A&2B NO. 2 OIL MA MUNIC. WHOLESALE ELEC. 2.94 85.00 2.50 0.00 2.50
1970 NU JETS JET OIL NORTHEAST UTILITIES 2.94 85.00 2.50 0.00 2.50
SUBTOTAL: 527.79 0.00 527.79
HYDRO QUEBEC ENTITLEMENT:
1991 HYDRO QUEBEC I&II HYDRO HQ / NEPOOL 4.06 630.00 25.57 0.00 25.57
SUBTOTAL: 25.57 0.00 25.57
TOTAL GROSS SYSTEM CAPABILITY (MW) -------------------------- 1,120.57
LESS: MILLSTONE 3 CAPABILITY (MW) ------------------------- 45.93
LESS: UNIT CONTRACT SALES (MW) ------------------ 34.53
TOTAL NET SYSTEM CAPABILITY (MW) ------------------------------ 1,040.11
</TABLE>
Montaup's participation in generating units of which it is not the sole
owner takes various forms including stock (equity) ownership, joint ownership
and purchase contracts. In most cases (other than short-term purchased power
contracts) the purchaser is required to pay its share (i.e., the same
percentage as the percentage of its entitlement to the output) of all of the
costs of the generating unit (whether or not the unit is operating) including
fixed costs, operating costs, costs of additional construction or modification,
costs associated with condemnation, shutdown, retirement, or decommissioning of
the unit, and certain transmission charges. Under its contracts with Maine
Yankee, Connecticut Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic and, under its agreements relating to Phase II of
the interconnection with Hydro-Quebec, Montaup may be called upon to provide
additional capital and/or other types of direct or indirect financial support.
(See Item 1. BUSINESS -- Nuclear Power Issues.) (See also Item 1. BUSINESS --
Electric Utility Industry Restructuring regarding Montaup's disposition of its
generating assets.)
Other Property
The EUA System owns approximately 6,900 miles of transmission and
distribution lines and approximately 84 substations located in the cities and
towns served.
Blackstone owns approximately 1,700 miles of transmission and distribution
lines and approximately 26 substations located in the cities and towns served.
Blackstone also owns 100% of a 1.2-mw hydroelectric generating plant located in
Pawtucket, Rhode Island. See Note E of Notes to Financial Statements in
Blackstone's 1997 Annual Report (Exhibit 13-1.01 filed herewith) regarding
encumbrances.
Eastern Edison and Montaup own approximately 4,400 miles of transmission
and distribution lines and approximately 44 substations located in the cities
and towns served. See Note F of Notes to Consolidated Financial Statements in
Eastern Edison's 1997 Annual Report (Exhibit 13-1.08 filed herewith) regarding
encumbrances.
Newport owns approximately 800 miles of transmission and distribution
lines and approximately 14 substations located in the cities and towns served.
See Note E to Notes to Consolidated Financial Statements contained in EUA's
Annual Report to Shareholders for the year ended December 31, 1997, (Exhibit
13-1.03 filed herewith) regarding encumbrances.
In addition to the above, the Retail Subsidiaries, Montaup, and EUA
Service also own several buildings which house distribution, maintenance or
general office personnel. See Note E of Notes to Consolidated Financial
Statements contained in EUA's Annual Report to Shareholders for the year ended
December 31, 1997, (Exhibit 13-1.03 filed herewith) regarding encumbrances.
Item 3. LEGAL PROCEEDINGS
Rate Proceeding
See descriptions of proceedings under Item 1. BUSINESS -- Rates.
Environmental Proceedings
1. In March 1985, Blackstone was notified by the DEQE, which is now the
MADEP, that it had been identified, along with other parties, as a potentially
responsible party under Massachusetts law for a condition of soil and ground
water contamination in Lowell, Massachusetts. The site in question was
occupied by a scrap metal reclamation facility which received transformers and
other electrical equipment from utility companies and others from the early
1960s until 1984. Among the contaminants apparently released at the site were
PCBs. The potentially responsible parties (PRPs), including Blackstone,
performed site studies and proposed a remedial action plan, which was approved
by the DEQE several years ago. Since that time, the PRPs have negotiated over
access, taxes and similar issues with the site owner and other parties. The
remedial option selected but not yet completed is a process of solidification;
however, a risk assessment that is now required could lead the PRPs to choose
capping as the remedial option. The cost of implementing either remedy could
vary from $250,000 for capping to $600,000 for solidification. Blackstone is
alleged to be the fifth ranked generator out of approximately twenty
potentially responsible parties. However, Blackstone's estimated 2% share
allocation is considerably less than the shares of the four largest
contributors at the site. In 1997, the PRPs resolved outstanding issues with
the MADEP relative to the status of the site under the current Massachusetts
Contingency Plan (MCP). A Phase II site study was initiated in May 1997 and
is expected to be completed in early 1998. Site remediation may begin later in
1998; Blackstone's share of these costs is expected to be minimal.
2. On July 14, 1987, the Commonwealth of Massachusetts (the Commonwealth)
on behalf of the MADEP filed a cost recovery action pursuant to CERCLA and
Massachusetts General Laws Chapter 21E against Blackstone in the United States
District Court for the District of Massachusetts (District Court). The
Complaint seeks $2.2 million in costs incurred by the MADEP in the cleanup of
an alleged coal gasification waste site at Mendon Road in Attleboro,
Massachusetts. In October 1987, without admitting liability, Blackstone
entered into an Administrative Consent Order with the MADEP regarding the
Mendon Road site and another alleged coal gasification site discovered by the
MADEP approximately 1/4 mile away known as the Lawn Street site in Attleboro.
Blackstone agreed to perform preliminary assessments at both sites in order to
determine what remediation, if any, was necessary at the site. In 1988,
Blackstone submitted Phase II testing results for the Lawn Street site to the
MADEP for review and approval. On April 24, 1996, MADEP ordered Blackstone to
conduct additional site assessment work at the Lawn Street site. On August 15,
1996 Blackstone signed an amended Administrative Consent Order and a Tier IB
permit pursuant to Chapter 21E. The site assessment work began in the Summer
of 1997. On May 26, 1993, the MADEP requested Blackstone to submit additional
Phase I testing for the Mendon Road site which was completed and sent to the
MADEP on December 20, 1993. Meanwhile, Blackstone has contested the MADEP's
cost recovery action, arguing, inter alia, that the ferric ferrocyanide (FFC)
waste removed from the Mendon Road site was not "hazardous" within the meaning
of CERCLA or Massachusetts General Laws Chapter 21E, and that the MADEP's
cleanup actions were inconsistent with the National Contingency Plan (NCP). On
November 25, 1991, the District Court held that the waste was "hazardous"
within the meaning of both statutes and on December 20, 1992, the District
Court held Blackstone and a co-defendant, the Courtois Sand & Gravel Co.
(Courtois) liable for an undetermined amount of cleanup costs. The District
Court remanded the case to the MADEP to supplement the administrative record
with Blackstone's oral and written comments concerning the cleanup. On March
19, 1993, Blackstone made an oral presentation to the MADEP and on April 19,
1993, Blackstone submitted written comments. On December 13, 1994, the
District Court issued a judgment against Blackstone finding Blackstone liable
to the Commonwealth for the full amount of response costs incurred by the
Commonwealth in the cleanup of the Mendon Road site. The judgment also found
Blackstone liable for interest and litigation expenses calculated to the date
of judgment. The total liability at December 31, 1994 was approximately $5.9
million, including approximately $3.6 million in interest which has
accumulated since 1985.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue
on the judgment amount.
Blackstone filed a Notice of Appeal of the District Court's judgment and
filed its brief with the United States Court of Appeals for the First Circuit
(Circuit Court) on February 24, 1995. On October 6, 1995, the Circuit Court
vacated the District Court's $5.9 million judgement. Rather than remand the
case to the District Court for a trial on the issue of whether ferric
ferrocyanide (FFC) is a hazardous substance, the Circuit Court exercised its
primary jurisdictional powers to send the matter to the EPA for an
administrative determination on the issue. Given the present posture of the
case, Blackstone may not be liable to reimburse the Commonwealth for the Mendon
Road cleanup costs. On January 9, 1997, Blackstone met with representatives of
EPA and the Commonwealth to discuss the procedure EPA would follow in resolving
the FFC issue. In January 1997, Blackstone submitted written comments which
were followed by the Commonwealth's written reply in March 1997. Both parties
submitted additional memoranda to the EPA during the remainder of the year.
The EPA will now determine whether FFC is hazardous substance. Further court
proceedings are likely.
On January 28, 1994, Blackstone filed a Complaint in the Massachusetts
District Court seeking, among other relief, contribution and reimbursement from
Stone & Webster Inc., of New York City and several of its affiliated companies
(Stone & Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley)
for any damages incurred by Blackstone regarding the Mendon Road site. The
District Court has denied motions to dismiss the complaint filed by Stone &
Webster and Valley in 1994. This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is a hazardous substance. On
March 22, 1996, Blackstone and Valley filed a Complaint in the Rhode Island
District Court seeking contribution from Stone & Webster for the cleanup of the
Tidewater site mentioned below.
3. On October 28, 1986, RIDEM notified Blackstone that there may have
been a release of hazardous material at the Tidewater Plant site in Pawtucket,
Rhode Island. The site was placed on EPA's CERCLA list in 1987. The site
includes the Tidewater Plant owned by Valley Gas Company (approximately 8
acres), the No. 1 Station owned by Blackstone (approximately 12 acres), and
land formerly owned by Blackstone that was sold in 1968 to the City of
Pawtucket (approximately 8 acres). RIDEM told Blackstone that the site
contained hazardous materials and petroleum-contaminated soils due to tanks
formerly located at the site. In December, 1990, after obtaining approval from
RIDEM, Blackstone removed approximately 1,000 tons of soil from the site. On
September 3, 1991, RIDEM initiated a site investigation which constitutes the
second step in a site screening and assessment process established by the EPA
to determine whether the site should be listed as a Superfund site. On
February 3, 1993, RIDEM notified Blackstone that it required further assessment
and evaluation of site conditions to determine if the site qualifies for review
pursuant to the Hazard Ranking System. On September 12, 1995, RIDEM notified
Blackstone and Valley of their responsibility regarding the release of
hazardous substances at the Tidewater Plant site. RIDEM ordered Blackstone
and Valley to conduct an environmental study of the Tidewater Plant site and
adjoining lots. On the adjacent lots are the Francis J. Varieur Elementary
School and the Max Read Field athletic facility and ball fields. Blackstone
and Valley have entered into an agreement to share the expenses of conducting
the study and/or retaining an environmental consulting firm to conduct a
Remedial Investigation. A work plan was submitted to RIDEM in April 1996 and
it was approved on June 14, 1996. Preliminary field work was completed in
September 1996. However, RIDEM required additional sampling to be conducted by
Blackstone and Valley. In 1997, that sampling was completed and RIDEM is
currently reviewing the draft Remedial Investigation Report and follow-up
documents. It is expected that RIDEM will order further investigation and
clean up.
4. On September 12, 1995, RIDEM demanded payment of $296,000 which
represents the amount of money plus interest RIDEM expended to clean up oxide
box waste at the Cumberland, Rhode Island site. Following extended discussions
and negotiations with legal counsel on behalf of RIDEM, Blackstone was able to
reach an agreement with RIDEM to escrow approximately $296,000 in an interest-
bearing account pending the outcome of EPA's remand proceedings to determine
whether FFC is a hazardous substance. This money has been placed in an
interest-bearing escrow account by Blackstone pending the outcome of EPA's
proceedings for the Mendon Road site described above. If EPA finds that FFC is
not a hazardous substance, Blackstone will be able to recover the escrowed
funds on the basis that RIDEM's clean up of the site in 1986 was not required
by law. If EPA determines that FFC is a hazardous substance, Blackstone will
appeal that determination in district court in Massachusetts.
5. On January 10, 1997, Blackstone, Valley, and a representative of RIDEM
met at Valley's Woonsocket property (the Hamlet Avenue, Woonsocket site), which
is the site of a former manufactured gas plant owned by Blackstone's and
Valley's predecessor, Blackstone Valley Gas & Electric Company and a
predecessor, the Woonsocket Gas Company. The site also includes an active
electric substation, and a former electric generating facility previously owned
by Blackstone Valley Gas & Electric Company and a predecessor, Woonsocket
Electric Machine and Power Company. The entire site consists of several
adjoining properties encompassing approximately nine acres. On February 11,
1997, RIDEM ordered Blackstone and Valley to conduct a site assessment of the
site. Blackstone and Valley submitted a Work Plan on June 16, 1997. The Work
Plan is under review by RIDEM.
Blackstone has notified certain liability insurers and has filed claims
with respect to the Mendon Road site. Blackstone is actively pursuing coverage
from other carriers for the Mendon Road, Tidewater, Lawn Street, Cumberland,
and Hamlet Avenue, Woonsocket Sites.
Neither Blackstone or Montaup are able to predict the outcome of any of
the foregoing environmental matters or that pertain to each of them to estimate
the potential costs which may ultimately result. It is the policy of EUA
System Companies in such cases to provide notice to liability insurers and to
make claims. However, it is not possible at this time to predict whether the
insurance carriers will honor such claims, or whether such claims can be
enforced against them. Under CERCLA, each responsible party can be held
"jointly and severally" liable for clean-up costs. EUA or a subsidiary
could thus be held fully liable for environmental damages for which they were
only partially responsible. However, EUA might then be entitled to recover
costs from other PRPs.
As of December 31, 1997, the EUA System has incurred costs of
approximately $6.7 million (excluding the Mendon Road judgment) in connection
with the foregoing environmental matters. These amounts have been financed
primarily by internally generated cash. EUA estimates that additional
expenditures (excluding the Mendon Road judgment) may be incurred through 1998
of up to $1.3 million, substantially all of which relates to Blackstone.
As a general matter, the EUA System will seek to recover costs relating to
environmental proceedings in their rates. Blackstone is currently amortizing
all of its incurred costs over a five-year period consistent with prior
regulatory recovery periods and is recovering certain of those costs in rates.
Estimated amounts after 1998 are not now determinable since site studies which
are the basis of these estimates have not been completed. As a result of the
recoverability in current rates and the uncertainty regarding both its
estimated liability, as well as potential contributions from insurance carriers
and other responsible parties, EUA does not believe that the ultimate impact of
the environmental costs will be material to the financial position of the EUA
System or to any individual subsidiary and thus, no loss provision is required
at this time.
Ridgewood
In September 1995, EUA FRC II Energy Associates, Micro Utility Partners of
America, L.P., and EUA Westcoast, L.P., each of which is a partnership of which
EUA Cogenex is the managing partner (the Partnerships) and EUA Cogenex entered
into an assignment agreement with Ridgewood/Mass. Corp. (f/k/a Ridgewood Cogen
Corporation) (Ridgewood) whereby Ridgewood acquired the benefits and obligation
to certain cogeneration projects from EUA Cogenex and the Partnerships. In
1996, the Partnerships and EUA Cogenex filed a suit in the United States
District Court for the district of Massachusetts against Ridgewood and others
seeking payment of approximately $518,000, resulting from Ridgewood's failure
and refusal to pay for services provided on their behalf under a certain
Transition Period Agreement between and among the parties. On December 2,
1996, Ridgewood filed a demand for arbitration in Boston, Massachusetts with
regard to such claim and with regard to an alleged breach of representations
and warranties by EUA Cogenex and the Partnerships under the assignment
agreement. Ridgewood seeks a total of approximately $4.3 million. The federal
court action has been dismissed without prejudice pending the arbitration. In
the arbitration, EUA Cogenex and the Partnerships have filed a counterclaim in
which they also seek a determination that certain provisions of the assignment
agreement are binding and enforceable according to their terms. The amount in
controversy with respect to the counterclaims has not yet been determined. In
1997, the American Arbitration Association set a preliminary hearing date of
June 14, 1998. Management cannot determine at this time the ultimate outcome
of these proceedings.
Other Proceedings
On December 15, 1995, Eastern Edison exercised its right to terminate a
Power Purchase Agreement (PPA) entered into with the Meridian Middleboro
Limited Partnership (MMLP) and a related entity on September 20, 1993. In
February and May of 1996, MMLP made demands for over $25 million under the
termination provision of the PPA. On June 17, 1996, Eastern Edison responded
to MMLP's demand stating that if Eastern Edison were to be liable for payments,
only approximately $170,000 would be due under the termination provision. On
July 18, 1996, Eastern Edison filed a declaratory judgement action in Suffolk
Superior Court in Boston, Massachusetts against MMLP seeking a declaration of
the rights of the parties under the PPA. MMLP's response to the complaint,
filed on August 8, 1996, included counterclaims in excess of $20 million and a
request for treble damages. Eastern Edison paid MMLP, under a reservation of
rights, approximately $192,000 as the amount Eastern Edison might owe to MMLP.
The Company is vigorously defending itself from the counterclaims. The Company
cannot determine the outcome of this proceeding at this time.
On January 10, 1997, the Internal Revenue Service (IRS) issued a report in
connection with its examination of the consolidated income tax returns of EUA
for 1992 and 1993. The report includes an adjustment to disallow EUA's
inclusion of its investment in EUA Power's Preferred Stock as a deduction in
determining Excess Loss Account (ELA) taxable income relating to the redemption
of EUA Power's Common and Preferred Stock in 1993. The IRS has taken the
position that the redemption of the Preferred Stock resulted in a capital loss
transaction and not a deduction in determining ELA. The Company disagrees with
the IRS's position and filed a protest in March 1997. EUA believes that it
will ultimately prevail in this matter. However, if the ultimate resolution of
this matter is a favorable decision for the IRS and EUA does not have
sufficient capital gain transactions to offset the capital loss then EUA could
be required to record a charge that could have a material impact on financial
results in the year of the charge but would not materially impact the financial
position of the company.
In early 1997, ten plaintiffs brought suit against numerous defendants,
including EUA, for injuries and illness allegedly caused by exposure to
asbestos over approximately a thirty-year period, at premises, including some
owned by EUA companies. The total damages claimed in all of these complaints
was $25 million in compensatory and punitive damages, plus exemplary damages
and interest and costs. Each complaint names between fifteen and twenty-eight
defendants, including EUA. These complaints have been referred to the
applicable insurance companies. Counsel has been retained by the insurers and
is actively defending all cases. Three cases have been dismissed as against
EUA companies, with prejudice. EUA cannot predict the ultimate outcome of this
matter at this time.
See Item 1. BUSINESS -- Fuel for Generation for a discussion of legal
actions filed against the DOE.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
Executive Officers of Eastern Utilities Associates
The names, ages and positions of all of the executive officers of EUA as
of March 16, 1998, are listed below along with their business experience during
the past five years. Officers are elected annually by the Trustees at the
following meeting of Trustees after the annual meeting of shareholders.
The 1998 Annual Meeting of Shareholders is scheduled to be held on May 18,
1998. There are no family relationships among these officers, nor any
arrangement or understanding between any officer and any other person pursuant
to which the officer was selected. The executive officers also serve as
officers/or directors of various subsidiary companies.
Name, Age and Position Business Experience During Past 5 Years
John D. Carney, 53 Executive Vice President since April 1995;
Executive Vice President President of Eastern Edison Company since January
1990; President of Blackstone and Newport since
April 1995. Responsible for the day-to-day
activities of The EUA System's retail electric
operations.
Clifford J. Hebert, Jr., Treasurer since April 1986; Secretary since May,
50, Treasurer and 1995. Responsible for financial, treasury and
Secretary corporate affairs of the EUA System.
Donald G. Pardus, 57 Chairman since July 1990; Chief Executive Officer
Chairman of the Board, since April 1989. Responsible for the overall
Chief Executive Officer management of the EUA System.
and Trustee
Robert G. Powderly, 50 Executive Vice President since April 1992.
Executive Vice President Responsible for purchasing, customer information
services, information systems, human resources,
marketing and rate activities of the EUA System.
John R. Stevens, 57 President since July 1990; Chief Operating
President, Chief Officer since January 1990. Responsible for
Operating Officer and retail operations and new ventures of the EUA
Trustee System.
There have been no events under any bankruptcy act, no criminal
proceedings and no judgments or injunctions material to the evaluation of the
ability and integrity of any director or executive officer during the past five
years.
PART II
Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information set forth under the caption "QUARTERLY FINANCIAL AND
COMMON SHARE INFORMATION" included in EUA's Annual Report to Shareholders for
the year ended December 31, 1997 (Exhibit 13-1.03 filed herewith) is
incorporated herein by reference.
The information required by this item for Blackstone and Eastern Edison is
incorporated by reference to information contained under the like captioned
sections of Blackstone's and Eastern Edison's 1997 Annual Reports (Exhibit 13-
1.01 and 13-1.08, respectively, filed herewith).
As of February 1, 1998 there were 11,130 EUA common shareholders of
record.
The closing price of EUA's Common Shares as reported by the Wall Street
Journal on March 16, 1998 was $25.
Item 6. SELECTED FINANCIAL DATA
The information set forth under the caption "SELECTED CONSOLIDATED
FINANCIAL DATA" included in EUA's Annual Report to Shareholders and Eastern
Edison's Annual Report for the year ended December 31, 1997, (Exhibit 13-1.03
and 13-1.08, respectively, filed herewith) and the information set forth under
the caption "SELECTED FINANCIAL DATA" included in the Annual Report for the
year ended December 31, 1997 for Blackstone (Exhibits 13-1.01 filed herewith)
are incorporated herein by reference.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information required by this item is incorporated herein by reference
to pages 9 through 28 in the 1997 EUA Annual Report to Shareholders, pages 3
through 10 in the 1997 Blackstone Annual Report and pages 3 through 14 in the
1997 Eastern Edison Annual Report (Exhibits 13-1.03, 13-1.01 and 13-1.08 for
EUA, Blackstone and Eastern Edison , respectively, filed herewith).
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item is incorporated herein by reference
to pages 30 through 45 in the 1997 EUA Annual Report to Shareholders, page 2
and pages 12 through 29 in the 1997 Blackstone Annual Report and, page 2 and
pages 16 through 36 in the 1997 Eastern Edison Annual Report (Exhibits 13-1.03,
13-1.01 and 13-1.08 for EUA, Blackstone and Eastern Edison, respectively,
filed herewith).
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Eastern Utilities Associates
The information concerning trustees and executive officers set forth under
the caption "ELECTION OF TRUSTEES AND OWNERSHIP OF COMMON SHARES" in EUA's
definitive Proxy Statement to be mailed to shareholders in connection with the
shareholders' annual meeting to be held on May 18, 1998, and filed with the SEC
is incorporated herein by reference. (See Item 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY-HOLDERS -- Executive Officers of Eastern Utilities
Associates.)
Blackstone and Eastern Edison
The names, ages and positions of all of the directors and executive
officers of Blackstone and Eastern Edison as of March 16, 1998 are listed below
with their business experience during the past five years. The directors of
Blackstone and the directors, Treasurer and Clerk of Eastern Edison are
each elected to serve until the next annual stockholders' meeting. All other
officers are elected to serve until the next meeting of directors following the
annual stockholders' meeting. There is no family relationship between any of
the directors or officers of Blackstone and Eastern Edison. Messrs.
Pardus and Stevens are Trustees of EUA. Certain officers of Blackstone and
Eastern Edison are, or at various times in the past have been, officers and/or
directors of the System Companies with which Blackstone and Eastern Edison have
entered into contracts and had other business relations.
Name, Age and Position Business Experience During Past 5 Years
John D. Carney, 53* President and Director of Blackstone and Newport
Director and President since April 1995; President and Director of
Eastern Edison since January 1990.
Barbara A. Hassan, 48 Vice President of Blackstone since April 1995;
Vice President Vice President of Eastern Edison since January
1990. Responsible for employee benefits, wages,
risk management and labor relations.
Clifford J. Hebert, Jr., 50* Director of both Blackstone and Eastern Edison
Director, Treasurer and since April 1997. Treasurer since April 1986
Secretary/Clerk and Secretary/Clerk since April 1995 of both
Blackstone and Eastern Edison.
Michael J. Hirsh, 43 Vice President of Blackstone since July 1991;
Vice President Vice President of Eastern Edison since April
1995; prior to that he was either a Director or
Manager of the Engineering or Resource Planning
Departments of EUA Service for more than five
years. Responsible for all engineering and
technical services.
Kevin A. Kirby, 47 Vice President of Blackstone and Eastern Edison
Vice President since April, 1995; prior to that he was a
Director of the Integrated Resource Management
department of EUA Service for five years;
responsible for the resource planning, power
supply and contract administration activities of
the EUA System.
Marc F. Mahoney, 43 Vice President of Blackstone and Eastern Edison
Vice President since July 1997; prior to that he was Director of
Transmission & Distribution for Blackstone and
Eastern Edison since April 1995 and Distribution
Superintendent of Eastern Edison since November
1991. Responsible for the operation and
maintenance of the transmission and distribution
facilities.
Donald G. Pardus, 57* Chairman of the Board since July 1989 and
Director and Director since 1979 of both Blackstone and
Chairman of the Board Eastern Edison.
Robert G. Powderly, 50* Executive Vice President and Director since March
Director and Executive 1992 of both Blackstone and Eastern Edison.
Vice President
John R. Stevens, 57* Vice Chairman of the Board since July 1989 and
Director and Vice Director since July 1987 of both Blackstone and
Chairman of the Board Eastern Edison.
* Please refer to the material supplied under the caption "EXECUTIVE OFFICERS
OF EASTERN UTILITIES ASSOCIATES" following Item 4 herein for other
information regarding this officer.
Item 11. EXECUTIVE COMPENSATION
Eastern Utilities Associates
The information concerning executive compensation set forth under the
caption "COMPENSATION AND OTHER TRANSACTIONS" in EUA's definitive Proxy
Statement to be mailed to shareholders in connection with the shareholders'
annual meeting to be held on May 18, 1998 and filed with the SEC is
incorporated herein by reference with the exception of the Report of the
Compensation and Nominating Committee on Compensation of Executive Officers and
accompanying Corporate Performance Graph that appears therein and which are
specifically not incorporated herein by reference.
Blackstone and Eastern Edison
The Chief Executive Officer and the four other most highly compensated
executive officers of Blackstone and Eastern Edison hold the same or similar
positions with EUA and are not paid directly by either Blackstone or Eastern
Edison. The information required by this item is incorporated herein by
reference to the material under the caption "COMPENSATION AND OTHER
TRANSACTIONS" in the definitive Proxy Statement of EUA, dated March 25, 1998,
with the exception of the Report of the Compensation and Nominating Committee
on Compensation of Executive Officers and accompanying Corporate Performance
Graph that appears therein and which are specifically not incorporated herein
by reference.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners of Blackstone and
Eastern Edison.
<TABLE>
<CAPTION>
Amount (number of
Name and Address of shares) and Nature of Percent of
Title of Class Beneficial Owner Beneficial Ownership Class
<S> <C> <C> <C>
Common Stock Eastern Utilities Associates 2,891,357 of Eastern Edison* 100%
One Liberty Square 184,062 of Blackstone* 100%
Boston, Massachusetts
_______________
*All shares, which are the only voting securities of Eastern Edison and Blackstone, are registered
in the name of the beneficial owner.
</TABLE>
(b) Security ownership of certain beneficial owners of EUA and management of
EUA, Blackstone and Eastern Edison.
The statements concerning security ownership of certain beneficial owners
and management set forth under the caption "ELECTION OF TRUSTEES AND OWNERSHIP
OF COMMON SHARES" in EUA's definitive Proxy Statement to be mailed to
shareholders in connection with the shareholders' annual meeting to be held on
May 18, 1998 and filed with the SEC are incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Financial Statements
The response to this portion of Item 14 is set forth under Item 8.
(a)(2) Financial Statement Schedules
The following additional consolidated financial statement schedules filed
herewith for EUA and Blackstone should be considered in conjunction with the
financial statements in the EUA's Annual Report to Shareholders and
Blackstone's Annual Report for the year ended December 31, 1997 (Exhibit 13-
1.03 and 13-1.01, respectively, filed herewith):
1. Financial Statement Schedules:
EUA
Schedule II - Valuation and Qualifying Accounts for the three years
ended December 31, 1997.
Blackstone
Schedule II - Valuation and Qualifying Accounts for the three years
ended December 31, 1997.
(a)(3) Exhibits (*denotes filed herewith)
Articles of Incorporation and By-Laws:
-EUA-
3-1.03 - Declaration of Trust of EUA, dated April 2, 1928, as amended
(Exhibit A-3, File No. 70-3188; Exhibit 1 to EUA's 8-K Reports for
April in each of the years 1957, 1962, 1966, 1968, 1972, and 1973,
File No. 1-5366; Exhibit A-1 (a), Amendment No. 2 to Form U-1,
File No. 70-5997; Exhibit 4-3, Registration No. 2-72589;
Exhibit 1 to Certificate of Notification, File No. 70-6713;
Exhibit 1 to Certificate of Notification, File No. 70-7084;
Exhibit 3-2, Form 10-K of EUA or 1987, File No. 1-5366).
- Eastern Edison -
3-1.08 - Form of Restated and Amended Articles of Organization (filed as
Exhibit B-1 to Form U5S of EUA for 1993). Instruments Defining
the Rights of Shareholders, Including Indentures:
- Eastern Edison -
4-1.08 - Indenture of First Mortgage and Deed of Trust dated as of
September 1, 1948 of Eastern Edison (Exhibit 4-1, Registration No.
2-77468), and twenty-six supplements thereto (Exhibit A, File No.
70-3015; Exhibit A-3, File No. 70-3371; Exhibit C to Certificate
of Notification, File No. 70-3371; Exhibit D to Certificate
of Notification, File No. 70-3619; Exhibit D to Certificate of
Notification, File No. 70-3798; Exhibit F to Certificate of
Notification, File No. 70-4164; Exhibit D to Certificate of
Notification, File No. 70-4748; Exhibit C to Certificate of
Notification, File No. 70-5195; Exhibit F to Certificate of
Notification, File No. 70-5379; Exhibit C to Certificate of
Notification, File No. 70-5719; Exhibit 5-24, Registration No. 2-
65785; Exhibit F to Certificate of Notification, File No. 70-6463;
Exhibit C to Certificate of Notification, File No. 70-6608;
Exhibit C to Certificate of Notification, File No. 70-6737;
Exhibit F to Certificate of Notification, File No. 70-6851;
Exhibit 4-31, Form 10-K of EUA for 1984, File No. 1-5366; Exhibit
F to Certificate of Notification, File No. 70-7254; Exhibit C
to Certificate of Notification, File No. 70-7373; Exhibit C to
Certificate of Notification, File No. 70-7373; Exhibit C to
Certificate of Notification, File No. 70-7373; Exhibit F to
Certificate of Notification, File No. 70-7511; Exhibit 4-34,
Form 10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 4-
24, Form 10-K of Eastern Edison for 1992, File No. 0-8480; Exhibit
4-35, Form 10-K of Eastern Edison for 1990, File No. 0-8480;
Exhibit 4-36, Form 10-K of Eastern Edison for 1990, File No. 0-
8480; Exhibit C-33 to Form U5S of EUA for 1993; Exhibit C-34 to
Form U5S of EUA for 1993; Exhibit 4-29.08, Form 10-K of Eastern
Edison for 1994, File No. 0-8480).
*4-1.09 - Twenty-Seventh Supplemental Indenture of Eastern Edison dated as
of January 1, 1998.
- Montaup -
4-1.05 - Form of 8% Debenture Bonds due 2000 of Montaup (Exhibit 4-10,
Registration No. 2-41488).
4-2.05 - Form of 8-1/4% Debenture Bonds due 2003 of Montaup (Exhibit B-3,
Form U5S of EUA for year 1973).
4-3.05 - Form of 14% Debenture Bonds due 2005 of Montaup (Exhibit 4-11,
Registration No. 2-55990).
4-4.05 - Form of 10% Debenture Bonds due 2008 of Montaup (Exhibit 5-3,
Registration No. 2-65785).
4-5.05 - Form of 16-1/2% Debenture Bonds due 2010 of Montaup (Exhibit 4-11,
Form 10-K of EUA for 1980, File No. 1-5366).
4-6.05 - Form of 12-3/8% Debenture Bonds due 2013 of Montaup (Exhibit 4-13,
Form 10-K of EUA for 1983, File No. 1-5366).
4-7.05 - Form of 10-1/8% Debentures due 2008 of Montaup (Exhibit 4, Form
10-Q of Eastern Edison for quarter ended September 30, 1983, File
No. 0-8480).
4-8.05 - Form of 9% Debenture Bonds due 2020 of Montaup (Exhibit 4-10, Form
10-K of Eastern Edison for 1990, File No. 0-8480).
4-9.05 - Form of 9 3/8% Debenture Bonds due 2020 of Montaup (Exhibit 4-11,
Form 10-K of Eastern Edison for 1990, File No. 0-8480).
- Blackstone -
4-1.01 - First Mortgage Indenture and Deed of Trust dated as of December 1,
1980 of Blackstone (Exhibit A, Form 8-K of EUA dated January 14,
1981, File No. 1-5366) and two supplements thereto (Exhibit 4-33,
Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 4-3, Form 10-K
of BVE for 1990, File No. 0-2602).
4-4.01 - Loan Agreement between Rhode Island Industrial Facilities
Corporation and Blackstone dated as of December 1, 1984 (Exhibit
10-72, Form 10-K of EUA for 1984, File No. 1-5366).
- EUA Service -
4-1.07 - Note Purchase Agreement dated as of January 13, 1988 of Service
(Exhibit 4-38, Form 10-K of EUA for 1987, File No. 1-5366).
- EUA Cogenex -
4-1.10 - Note Agreement dated as of June 28, 1990 of EUA Cogenex with the
Prudential Insurance Company of America (Exhibit 4-46, Form 10-K
of EUA for 1990, File No. 1-5366).
4-2.10 - Note Agreement dated as of October 29, 1991 between EUA Cogenex
and Prudential Insurance Company of America (Exhibit 4-55, Form
10-K of EUA for 1991, File No. 1-5366).
4-3.10 - Indenture dated September 1, 1993 between EUA Cogenex and the Bank
of New York as Trustee (Exhibit 4-4.10, Form 10-K of EUA for 1993,
File No. 1-5366).
- Newport -
4-1.14 - Indenture of First Mortgage dated as of June 1, 1954 of Newport,
as supplemented on August 1, 1959, April 1, 1962, October 1, 1964,
April 1, 1967, September 1, 1969, September 1, 1970, June 1, 1978,
October 1, 1978, May 1, 1986, December 1, 1987 and November 1,
1989 (Exhibit 4-49, Form 10-K of EUA for 1990, File No. 1-5366).
4-2.14 - United States Government Small Business Administration Loan to
Newport entitled, "Base Closing Economic Injury Loan", signed May
30, 1975 and amended on October 6, 1983 (Exhibit 4-50, Form 10-K
of EUA for 1990, File No. 1-5366).
4-3.14 - Indenture of Second Mortgage dated as of September 1, 1982 of
Newport, as supplemented on December 1, 1988 (Exhibit 4-51, Form
10-K of EUA for 1990, File No. 1-5366).
4-4.14 - Loan Agreement between the Rhode Island Port Authority and
Economic Development Corporation and Newport Electric Corporation
dated as of January 6, 1994 (Exhibit 4-4.14, Form 10-K of EUA for
1993, File No. 1-5366).
4-5.14 - Trust Indenture between the Rhode Island Authority and Economic
Development Corporation and Newport Electric Corporation dated as
of January 1, 1994 (Exhibit 4-5.14, Form 10-K of EUA for 1993,
File No. 1-5366).
4-6.14 - Letter of Credit and Reimbursement Agreement dated January 6, 1994
(Exhibit 4-6.14, Form 10-K of EUA for 1993, File No. 1-5366).
- EUA Ocean State -
4-1.12 - Note Purchase Agreement dated as of January 16, 1992 between EUA
Ocean State Corporation and John Hancock Mutual Life Insurance
Company (Exhibit 4-56, Form 10-K of EUA for 1991, File No. 1-
5366).
Material Contracts:
- EUA -
10-1.03 - Employees' Retirement Plan of Eastern Utilities Associates and its
Subsidiary Companies Trust Agreement as amended and restated,
effective July 1, 1981 (Exhibit 10-1, Registration No. 2-80205).
10-2.03 - Eastern Utilities Associates Employees' Savings Plan Trust
Agreement (Exhibit 10-3, Form 10-K of EUA for 1992, File No. 1-
5366).
10-3.03 - Eastern Utilities Associates Employees' Savings Plan as amended
and restated effective January 1, 1989 (including amendments
through January 1, 1992) and December 21, 1994 (Exhibit 10-15.03,
Form 10-K of EUA for 1995, File No. 1-5366; Exhibit 10-17.03 Form
10-K of EUA for 1995, File No. 1-5366).
10-4.03 - Stock Purchase Agreement dated as of December 10, 1986, among
Eastern Utilities Associates, Citizens Corporation and Citizens
Energy Corporation (Exhibit 10-104, Form 10-K of EUA for 1986,
File No. 1-5366).
10-5.03 - Precedent Agreement dated as of November 29, 1989 between EUA and
NECO Enterprises, Inc. (Exhibit B-4, Form U-1, File No. 70-7677).
10-6.03 - Amendment to and Restatement of Stock Purchase Agreement dated as
of February 1, 1990 between EUA, NECO Enterprises, Inc., Newport
Electric Corporation and a special-purpose subsidiary of EUA for
the acquisition by EUA of the stock of Newport Electric
Corporation (Exhibit B-3, Form U-1, File No. 70-7677).
10-7.03 - Letter of Assurance in connection with the Credit Agreement
between Vermont Electric Transmission Company, Inc. and Bank of
America National Trust and Savings Association dated July 19, 1983
(Exhibit 10-111, Form 10-K of EUA for 1990, File No. 1-5366).
10-8.03 - Amended and Restated Equity Maintenance Agreement dated as of
September 29, 1992 among EUA and The Prudential Insurance Company
of America and Pruco Life Insurance Company (Exhibit 10-9, EUA 10-
K for 1992, File No. 1-5366).
10-9.03 - Guaranty, dated June 28, 1990 made by EUA in favor of The
Prudential Life Insurance Company of America (Exhibit 10-10, EUA
10-K for 1992, File No. 1-5366).
10-10.03 - Guaranty, dated January 16, 1992 made by EUA in favor of John
Hancock Mutual Life Insurance Company (Exhibit 4-125, Form 10-K of
EUA for 1991, File No. 1-5366).
10-11.03 - Form of Service Contract between EUA Service Corporation and each
of the other companies (including EUA) in the EUA System (Exhibit
13-1.03, Registration No. 2-55990).
10-12.03 - Form of EUA Restricted Stock Plan effective July 17, 1989 (Exhibit
10-13, EUA Form 10-K for 1992, File No. 1-5366).
10-13.03 - Eastern Utilities Associates Employees' Share Ownership Plan Trust
Agreement (Exhibit 5, Form 10-K of EUA for 1977, File No. 1-5366).
10-14.03 - Employees' Retirement Plan of Eastern Utilities Associates and Its
Affiliated Companies as amended and restated effective January 1,
1989, and December 21, 1994 (Exhibit 10-14.03, Form 10-K of EUA
for 1995, File No. 1-5 366; Exhibit 10-16.03, Form 10-K of EUA for
1995, File No. 1-5366).
*10-15.03 - Second Amendment to the Eastern Utilities Associates Employees'
Savings Plan dated May 30, 1997.
*10-16.03 - Third Amendment to the Eastern Utilities Associates Employees'
Savings Plan dated March 17, 1997.
*10-17.03 - Fourth Amendment to the Eastern Utilities Associates Employees'
Savings Plan dated June 16, 1997.
*10-18.03 - Second Amendment to the Employees' Retirement Plan of Eastern
Utilities Associates and its Affiliated Companies dated March 17,
1997.
*10-19.03 - First Amendment to the Eastern Utilities Associates Restricted
Stock Plan dated November 17, 1997.
- Eastern Edison -
10-1.08 - Trust Agreement dated as of July 1, 1993 between Massachusetts
Industrial Finance Agency and Shawmut Bank, N.A. (filed as Exhibit
10-1.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480).
10-2.08 - Loan Agreement dated as of July 1, 1993 between Massachusetts
Industrial Finance Agency and Eastern Edison (filed as Exhibit 10-
2.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480).
10-3.08 - Power Purchase Agreement entered into as of September 20, 1993 by
and between Meridian Middleboro Limited Partnership and Eastern
Edison Company (filed as Exhibit 10-3.08 to Eastern Edison's Form
10-K for 1993, File No. 0-8480).
10-4.08 - Inducement Letter dated July 14, 1993 from Eastern Edison to the
Massachusetts Industrial Finance Agency and Goldman, Sachs &
Company and Citicorp Securities Markets, Inc. (filed as Exhibit
10-4.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480).
- Montaup -
10-1.05 - Montaup Contract, as amended (Exhibit 4-B, Registration No. 2-
14119; Exhibit 13-A1, Registration No. 2-14718; Exhibit 4-B-2,
Registration No. 2-26509; Exhibit 4-B-3, Registration No. 2-
33061; Exhibits 13-3 and 13-4, Registration No. 2-48966; Exhibit
B-2, Form U5S of EUA for year 1974 and Exhibit 5-40, Registration
No. 2-62862).
10-2.05 - Power Contract (composite copy) between Connecticut Yankee Atomic
Power Company and Montaup dated July 1, 1964 as amended and
supplemented March 1, 1978, August 22, 1980, October 15, 1982, and
December 4, 1996 (Exhibit B-1, File No. 70-4245; Exhibit 20, Form
10-K of EUA for 1977, File No. 1-5366; Exhibit 10-52, Form 10-K
for EUA for 1981, File No. 1-5366; Exhibit 10-67, Form 10-K for
EUA for 1983, File No. 1-5366; Exhibit 10-37.05, Form 10-K for
EUA for 1996, File No. 1-5366).
10-3.05 - Capital Funds Agreement (composite copy) between Connecticut
Yankee Atomic Power Company and Montaup dated September 1, 1964
(Exhibit B-2, File No. 70-4245).
10-4.05 - Stockholder Agreement (composite copy) among Connecticut Yankee
Atomic Power Company's Sponsors, including Montaup, dated July 1,
1964 (Exhibit B-4, File No. 70-4245).
10-5.05 - Contract for sale of power to Montaup by Canal Electric Company
dated December 1, 1965 (Exhibit 2D, File No. 0-688).
10-6.05 - Capital Funds Agreement (composite copy) between Vermont Yankee
Nuclear Power Corporation and Montaup dated as of February 1,
1968, and Amendment thereto dated as at March 12, 1968 (Exhibit B-
2, File No. 70-4611; Exhibit B-3, File No. 70-4611).
10-7.05 - Form of Power Contract between Vermont Yankee Nuclear Power
Corporation and Montaup dated as of February 1, 1968, as amended
June 1, 1972, April 15, 1983, April 24, 1985, June 1, 1985, May 6,
1988 (2), June 15, 1989 and December 1, 1989 (Exhibit B-4, File
No. 70-4591; Exhibit 13-21, Registration No. 2-46612; Exhibit 10-
63, Form 10-K of EUA for 1983, File No. 1-5366; Exhibit 10-74,
Form 10-K of EUA for 1985, File No. 1-5366; Exhibit 10-78, Form
10-K of EUA for 1986, File No. 1-5366; Exhibits 10-97 and 10-98,
Form 10-K of EUA for 1988, File No. 1-5366; Exhibit 10-95, Form
10-K of EUA for 1989, File No. 1-5366; Exhibit 10-80, Form 10-K of
Eastern Edison for 1990, File No. 0-8480).
10-8.05 - Sponsor Agreement (composite copy) among Vermont Yankee Nuclear
Power Corporation's Sponsors, including Montaup, dated as of
August 1, 1968 (Exhibit 4-0, Registration No. 2-33061).
10-9.05 - Capital Funds Agreement (composite copy) between Maine Yankee and
Montaup dated May 20, 1968 and as amended August 1, 1985 (Exhibit
B-2, File No. 70-4658; Exhibit 10-78, Form 10-K of EUA for 1985,
File No. 1-5366).
10-10.05 - Power Contract (composite copy) between Maine Yankee Atomic and
Montaup dated May 20, 1968, as amended December 19, 1983 and
January 1, 1984 (Exhibit B-3, File No. 70-4658; Exhibit 10-64,
Form 10-K of EUA for 1983, File No. 1-5366; Exhibit 10-66, Form
10-K of EUA for 1984, File No. 1-5366).
10-11.05 - Stockholder Agreement (composite copy) among Maine Yankee
Sponsors, including Montaup, dated May 20, 1968 (Exhibit B-4, File
70-4658).
10-12.05 - Agreement (composite copy) among Vermont Yankee Nuclear Power
Corporation's Sponsors, including Montaup, dated as of April 30,
1969 (Exhibit B-7, File No. 70-4435).
10-13.05 - Form of Agreement among Maine Yankee Atomic Power Company's
Sponsors dated as of May 20, 1969 (Exhibit B-5, File No. 70-4658).
10-14.05 - Form of New England Power Pool Agreement dated as of September 1,
1971, as amended as of July 1, 1972, March 1, 1973, April 2, 1973,
March 15, 1974, June 1, 1975, September 1, 1975, December 31,
1976, January 31, 1977, July 1, 1977, August 1, 1977, August 15,
1978, January 31, 1980, February 1, 1980, September 1, 1981,
December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983,
August 1, 1985, August 15, 1985, January 1, 1986, September 1,
1986, March 1, 1988, May 1, 1988, March 15, 1989, October 1, 1990,
September 15, 1992, May 1, 1993, and December 31, 1996, (Exhibit
13-45, Registration No. 2-41488; Exhibit 13-38, Registration No.
2-46612; Exhibits 13-39 and 13-40, Registration No. 2-48966;
Exhibit B-3, Form U5S of EUA for year 1974; Exhibit 13-35(a),
Registration No. 2-54449; Exhibit 13-35, Registration No. 2-
55990, Exhibits 5-69 and 5-70, Registration Exhibit 13-35(a),
Registration No. 2-54449; Exhibit 13-35, Registration No. 2-55990,
Exhibits 5-69 and 5-70, Registration No. 2-58625; Exhibit 6, Form
10-K of EUA for 1977, File No. 1-5366; Exhibit 1, Form 10-K of EUA
for 1979, File No. 1-5366; Exhibit No. 10-67, Registration No. 2-
80205; Exhibit 10-65, Form 10-K of EUA for 1983, File No. 1-5366;
Exhibit 10-66, Form 10-K of EUA for 1983, File No. 1-5366;
Exhibits 10-75, 10-76, and 10-77, Form 10-K of EUA for 1985, File
No. 1-5366; Exhibit 10-79, Form 10-K of EUA for 1986, File No. 1-
5366; Exhibits 10-99 and 10-100, Form 10-K of EUA for 1988,
File No. 1-5366; Exhibit 10-96, Form 10-K of EUA for 1989, File
No. 1-5366; Exhibit 10-81, Form 10-K of Eastern Edison for 1990,
File No. 0-8480; Exhibit 10-38.05, Form 10-K of EUA for 1995, File
No. 1-5366; Exhibit 10-39.05, Form 10-K of EUA for 1995, File No.
1-5366; Exhibit 10-40.05, Form 10-K of EUA for 1995, File No. 1-
5366 Exhibit 10-38.05 Form 10-K of EUA for 1996, File No. 1-5366).
10-15.05 - Unit Participation Agreement between Maine Electric Power Company,
Inc. and New Brunswick Electric Power Commission dated November
15, 1971 (Exhibit 13-43.1, Registration No. 2-44377).
10-16.05 - Assignment Agreement dated March 20, 1972 between Maine Electric
Power Company, Inc. and New Brunswick Electric Power Commission
(Exhibit 13-43.3, Registration No. 2-44377).
10-17.05 - Agreement between Montaup and Boston Edison Company dated August
1, 1972 and as amended January 1, 1985 for purchase of power from
Pilgrim No. 1 nuclear unit at Plymouth, Massachusetts (Exhibit 13-
41, Registration No. 2-46612; Exhibit 10-67, Form 10-K of EUA for
1984, File No. 1-5366).
10-18.05 - Agreement dated as of May 1, 1973 for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units among
Public Service Company of New Hampshire and other utilities
including Montaup, as amended as of May 24, 1974, June 21, 1974,
September 25, 1974, October 25, 1974, January 31, 1975, as
supplemented by Letter Agreement dated April 27, 1978 and amended
as of April 18, 1979 (two amendments), April 25, 1979, June 8,
1979, October 11, 1979, December 15, 1979, June 16, 1980, December
31, 1980, June 1, 1982, April 27, 1984, June 15, 1984, March 8,
1985, March 14, 1986, May 1, 1986, September 19, 1986, November 5,
1987, January 13, 1989 and November 1, 1990. (Exhibit 13-57,
Registration No. 2-48966; Exhibit B-6, Form U5S of EUA for year
1974; Exhibit 5-130, Registration No. 2-62862; Exhibit 5-70,
Registration No. 2-65785; Exhibit 2, Form 10-K of EUA for 1979,
File No. 1-5366; Exhibit 5-34, Registration No. 2-69052; Exhibit
20-1, Form 10-K of EUA for 1980, File No. 1-5366; Exhibit 10-69,
Registration No. 2-80205; Exhibit 2, Form 10-Q of EUA for
the Quarter Ended March 31, 1984, File No. 1-5366; Exhibit 3, Form
10-Q of EUA for the Quarter Ended June 30, 1984, File No. 1-5366;
Exhibit 10-70, Form 10-K of EUA for 1985, File No. 1-5366;
Exhibits 10-80 and 10-81, Form 10-K of EUA for 1986, File No. 1-
5366; Exhibits 10-95 and 10-96, Form 10-K of EUA for 1987, File
No. 1-5366; Exhibit 10-101, Form 10-K of EUA for 1988, File No. 1-
5366; Exhibit 10-82, Form 10-K of Eastern Edison for 1990, File
No. 0-8480).
10-19.05 - Sharing Agreement dated as of September 1, 1973 among The
Connecticut Light and Power Company and other utilities, including
Montaup, concerning participation in a nuclear generating unit
located in Connecticut (Millstone Unit No. 3), as amended and
supplemented by Amendatory Agreement dated May 11, 1984 as amended
as of April 1, 1986 (Exhibit B-17, Form U5S of EUA for year 1973;
Exhibit B-8, as amended as of April 11, 1986, Form U5S of EUA for
year 1974; Exhibit B-30, Form U5S of EUA for year 1976; Exhibit
10-68, Form 10-K of EUA for 1984, File No. 1-5366; Exhibit 10-82,
Form 10-K of EUA for 1986, File No. 1-5366).
10-20.05 - Agreement for Joint Ownership, Construction and Operation of
William F. Wyman Unit No. 4 dated November 1, 1974 as amended
June 30, 1975, August 16, 1976 and December 31, 1978 among Central
Maine Power Company and other utilities including Montaup (Exhibit
B-9, Form U5S of EUA for year 1974; Exhibit 13-58, Registration
No. 2-55990; Exhibit 5-95, Registration No. 2-58625; Exhibit 5-40,
Registration No. 2-69052).
10-21.05 - Agreement for Joint Ownership dated as of October 27, 1970 between
Canal Electric Company and Montaup (Exhibit 13-71, Registration
No. 2-55990).
10-22.05 - Agreement for use of Common Facilities by Canal Units I and II and
for Allocation of Related Costs dated as of October 27, 1970
between Canal Electric Company and Montaup (Exhibit 13-72,
Registration No. 2-55990).
10-23.05 - Guarantee Agreement (composite copy) dated as of November 13, 1981
between The Connecticut Bank and Trust Company, as Trustee, and
Montaup relating to debentures of Connecticut Yankee Atomic Power
Company (Exhibit 10-61, Form 10-K of EUA for 1981, File No. 1-
5366).
10-24.05 - Agreement for Seabrook Project Disbursing Agent, dated as of May
23, 1984, as amended March 8, 1985, May 20, 1985, June 18, 1985,
January 1, 1986, November, 1987, August 1, 1989, and restated as
of November 1, 1990, among the participants in the Seabrook
nuclear generating project, including Montaup and Yankee Atomic
Electric Company (Exhibit 2, Form 10-Q of EUA for the Quarter
Ended June 30, 1984, File No. 1-5366; Exhibit 10-69, Form 10-K of
EUA for 1985, File No. 1-5366; Exhibits 10-86, 10-87 and 10-88,
Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-97, Form
10-K of EUA for 1987, File No. 1-5366; Exhibit 10-105, Form 10-K
of EUA for 1989, File No. 1-5366; Exhibit 10-84, Form 10-K of
Eastern Edison for 1990, File No. 0-8480).
10-25.05 - Guarantee Agreement dated as of August 1, 1985 among The
Connecticut Bank and Trust Company, Connecticut Yankee Atomic
Power Company and Montaup Electric Company relating to Revolving
Credit Loans of Connecticut Yankee (Exhibit 10-85, Form 10-K of
EUA for 1985, File No. 1-5366).
10-26.05 - Equity Funding Agreement for New England Hydro-Transmission
Corporation dated as of June 1, 1985, between New England Hydro-
Transmission Corporation and several New England electric
utilities, including Montaup as amended as of May 1, 1986 and
September 1, 1987 (Exhibits 10-96 and 10-97, Form 10-K of
EUA for 1986, File No. 1-5366; Exhibit 10-116, Form 10-K of EUA
for 1987, File No. 1-5366).
10-27.05 - Equity Funding Agreement for New England Hydro-Transmission
Electric Company, Inc. dated as of June 1, 1985, between New
England Hydro-Transmission Electric Company, Inc. and several New
England electric utilities, including Montaup as amended as of May
1, 1986 and September 1, 1987 (Exhibits 10-98 and 10-99, Form 10-K
of EUA for 1986, File No. 1-5366; Exhibit 10-117, Form 10-K of EUA
for 1987, File No. 1-5366).
10-28.05 - Unit Power Agreement for the Sale of Unit Capacity and Energy from
Ocean State Power Project to Montaup Electric Company dated as of
May 14, 1986 as amended as of August 27, 1986, September 27, 1988,
October 21, 1988, July 21, 1989, February 7, 1990, December 21,
1990, and February 12, 1996 (Exhibits 10-101 and 10-102, Form 10-K
of EUA for 1986, File No. 1-5366; Exhibits 10-106 and 10-107, Form
10-K of EUA for 1988, File No. 1-5366; Exhibit 10-106, Form 10-K
of EUA for 1989, File No. 1-5366; Exhibits 10-86 and 10-87, Form
10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 10-39.05
and 10-40.05, Form 10-K of EUA for 1996, File No. 1-5366).
10-29.05 - Power Purchase Agreement dated as of October 17, 1986, between
Northeast Energy Associates and Montaup as amended as of June 28,
1989 (Exhibit 10-103, Form 10-K of EUA for 1986, File No. 1-5366;
Exhibit 10-103, Form 10-K of EUA for 1989, File No. 1-5366).
10-30.05 - Settlement Agreement dated as of January 13, 1989 among Montaup,
EUA Power, certain past and present owners of the Seabrook Project
and Yankee Atomic Electric Company (Exhibit 10-110, Form 10-K of
EUA for 1988, File No. 1-5366).
10-31.05 - Unit Power Agreement for the Sale of Second Unit Capacity and
Energy from Ocean State Power Project to Montaup Electric Company
dated as of September 28, 1988 as amended as of July 21, 1989,
February 7, 1990, and February 12, 1996 and a Supplemental
Agreement dated July 21, 1989 (Exhibit 10-104, Form 10-K of EUA
for 1989, File No. 1-5366; Exhibits 10-41.05 and 10-42.05, Form
10-K of EUA for 1996, File No. 1-5366; Exhibit No. 10-88, Form 10-
K of Eastern Edison for 1990, File No. 0-8480).
10-32.05 - Purchase Power Contract between Newport and Montaup dated July 23,
1963, as revised on March 23, 1983 (Exhibit 10-108, Form 10-K of
EUA for 1990, File No. 1-5366).
10-33.05 - Purchase Power Contract between Newport and Montaup for Contract
Demand Service effective May 1, 1983, as amended on July 1, 1983,
December 28, 1983 and November 1, 1984 (Exhibit 10-89, Form 10-K
of Eastern Edison for 1990, File No. 0-8480 and Exhibit 10-109,
Form 10-K of EUA for 1990, File No. 1-5366).
10-34.05 - Power Contract (composite copy) between Yankee Atomic Electric
Company and Montaup dated June 30, 1959 as revised April 1, 1975,
as further amended October 1, 1980, April 1, 1985, May 6, 1988,
June 26, 1989, July 1, 1989 and February 1, 1992 (Exhibit 10-6,
Registration No. 2-72655; Exhibit 10-73, Form 10-K of EUA for
1985, File No. 1.5366; Exhibit 10-96, Form 10-K of EUA for
1988, File No. 1-5366; Exhibits 10-93 and 10-94, Form 10-K of EUA
for 1989, File No. 1-5366; Exhibit 10-46 Form 10-K of Eastern
Edison for 1992, File No. 0-8480).
10-35.05 - Memorandum of understanding by and between Canal Electric Company
and Montaup Electric Company dated September 23, 1993 (Exhibit 10-
39.05, Eastern Edison 10-K for 1993, File No. 0-8480).
10-36.05 - Ancillary Agreement by and between Algonquin Gas Transmission
Company, Canal Electric Company and Montaup Electric Company dated
October 8, 1993. (Exhibit 10-40.05 of Eastern Edison 10-K for
1993, File No. 0-8480).
- Blackstone -
10-1.01 - Trust Indenture between Rhode Island Industrial Facilities
Corporation and the Rhode Island Hospital Trust Company dated as
of December 1, 1984 (Exhibit 10-73, Form 10-K of EUA for 1984,
File No. 1-5366).
10-2.01 - Remarketing Agreement between Rhode Island Hospital Trust Company,
Citibank and Blackstone dated as of December 19, 1984 (Exhibit 10-
74, Form 10-K of EUA for 1984, File No. 1-5366).
10-3.01 - Letter of Credit and Reimbursement Agreement between Blackstone
Valley Electric Company and The Bank of New York dated as of
January 21, 1993 (Exhibit 10-10, Form 10-K of Blackstone for 1992,
File No. 0-2602).
10-4.01 - Interconnection Agreement by and between Blackstone and Ocean
State Power dated November 1, 1988, as amended and restated
effective August 16, 1989 by and among Blackstone, Ocean State
Power I and Ocean State Power II (Exhibit 10-100, Form 10-K of EUA
for 1989, File No. 1-5366).
10-5.01 - Power Purchase Agreement between Blackstone and Blackstone Hydro,
Inc. dated as of January 8, 1989 and assignment to Montaup
(Exhibits 10-101 and 10-102, Form 10-K of EUA for 1989, File No. 1-
5366).
- Newport -
10-1.14 - Phase I Vermont Transmission Line Support Agreement dated as of
December 1, 1981 and as amended as of June 1, 1982, November 1,
1982 and January 1, 1986 between Vermont Electric Transmission
Company, Inc. and several New England utilities, including Montaup
(Exhibit 10-65, Form 10-K of EUA for 1981, File No. 1-5366;
Exhibit 10-72, Registration No. 2-80205; Exhibit 10-64, Form 10-K
of EUA for 1982, File No. 1-5366; Exhibit 10-84. Form 10-K of EUA
for 1986, File No. 1-5366).
10-2.14 - Letter amendment dated August 4, 1983 reallocating the
participating shares originally assigned to the Chicopee Municipal
Lighting Plant and the Taunton Municipal Lighting Plant under the
Phase I Vermont Transmission Line Support Agreement between
Vermont Electric Transmission Company, Inc. and several New
England electric utilities, including Newport, dated December 1,
1981, as amended on June 1, 1982 and November 1, 1982 (Exhibit 10-
110, Form 10-K of EUA for 1990, File No. 1-5366).
10-3.14 - Phase I Terminal Facility Support Agreement dated December 1, 1981
and as amended as of June 1, 1982, November 1, 1982 and January
1, 1986 between New England Electric Transmission Corporation and
several New England utilities, including Montaup (Exhibit 10-68,
Form 10-K of EUA for 1981, File No. 1-5366; Exhibit 10-74,
Registration No. 1-5366; Exhibit 10-68. Form 10-K of EUA for
1986, File No. 1-5366).
10-4.14 - Letter amendment dated July 29, 1983 reallocating the
participating shares originally assigned to the Chicopee Municipal
Lighting Plant and the Taunton Municipal Lighting Plant under the
Phase I Terminal Facility Support Agreement between New England
Transmission Corporation and several New England electric
utilities, including Newport, dated December 1, 1981, as amended
on June 1, 1982 and November 1, 1982 (Exhibit 10-112, Form 10-K of
EUA for 1990, File No. 1-5366).
10-5.14 - Purchase Power Contract between Newport and City of Burlington
Electric Department (life of the unit contract) for purchase of
15.24% of net capability of station output from Joseph C. McNeil
Electric Generating Station located in Burlington, Vermont dated
December 19, 1984 (Exhibit 10-115, Form 10-K of EUA for 1990, File
No. 1-5366).
10-6.14 - Firm Energy Contract between Hydro-Quebec and several New England
electric utilities, including Newport, dated as of October 14,
1985 (Exhibit 10-116, Form 10-K of EUA for 1990, File No. 1-5366).
10-7.14 - Unit Power Agreement for the Sale of Unit Capacity and Energy from
Ocean State Power Project to Newport Electric Corporation dated
May 14, 1986, as amended on August 20, 1986, July 12, 1988,
September 23, 1988, October 21, 1988, July 21, 1989, February 7,
1990 and December 21, 1990 (Exhibit 10-117, Form 10-K for 1990,
File No. 1-5366).
10-8.14 - Unit Power Agreement for the Sale of Second Unit Capacity and
Energy from Ocean State Power Project to Newport Electric
Corporation dated July 12, 1988 as amended and supplemented
September 23, 1988, July 21, 1989 and February 7, 1990 (Exhibit
10-118, Form 10-K for 1990, File No. 1-5366).
10-9.14 - Agreement for Joint Ownership, Construction and Operation of
William F. Wyman Unit No. 4 dated November 1, 1974 as amended
June 30, 1975, August 16, 1976 and December 31, 1978 among Central
Maine Power Company and other utilities including Newport (Exhibit
B-9, Form U5S of EUA for year 1974; Exhibit 13-58, Registration
No. 2-55990; Exhibit 5-95, Registration No. 2-58625; Exhibit 5-40,
Registration No. 2-69052).
- EUA Ocean State -
10-1.12 - Ocean State Power Amended and Restated General Partnership
Agreement among EUA Ocean State, Ocean State Power Company, TCPL
Power Ltd., Narragansett Energy Resources Company and NECO Power,
Inc. (collectively, the "OSP Partners") dated as of December 2,
1988, as amended March 27, 1989, December 31, 1990, November 12,
1992 and February 23, 1993 (Exhibit 10-107, Form 10-K of EUA for
1989; File No. 1-5366, Exhibits 10-3.12, 10-4.12 and 10-5.12, Form
10-K of EUA for 1994, File No. 1-5366).
10-2.12 - Ocean State Power II Amended and Restated General Partnership
Agreement among EUA Ocean State, JMC Ocean State Corporation,
Makowski Power, Inc., TCPL Power Ltd., Narragansett Energy
Resources Company and Newport Electric Power Corporation
(collectively, the "OSP II Partners") dated as of September 29,
1989 (Exhibit 10-110, Form 10-K of EUA for 1989, File No. 1-5366).
Annual Reports to Shareholders:
*13-1.03 - Annual Report to Shareholders of EUA for 1997, portions of which
are incorporated by reference in this Annual Report on Form 10-K.
Only the portions expressly so incorporated under PART II, Items
5, 6, 7 and 8 are to be deemed filed herewith.
*13-1.01 - Annual Report to Shareholders of Blackstone for 1997, portions of
which are incorporated by reference in this Annual Report on Form
10-K. Only the portions expressly so incorporated under PART II,
Items 5, 6, 7 and 8 are to be deemed filed herewith.
*13-1.08 - Annual Report to Shareholders of Eastern Edison for 1997, portions
of which are incorporated by reference in this Annual Report on
Form 10-K. Only the portions expressly so incorporated under PART
II, Items 5, 6, 7 and 8 are to be deemed filed herewith.
Subsidiaries of EUA:
21-1.03 - Direct subsidiaries of Eastern Utilities Associates and the state
of organization of each are: Blackstone Valley Electric Company
(Rhode Island), Eastern Edison Company (Massachusetts), EUA
Cogenex Corporation (Massachusetts), EUA Service Corporation
(Massachusetts), EUA Ocean State Corporation (Rhode Island), EUA
Energy Investment Corporation (Massachusetts), Newport Electric
Corporation (Rhode Island), EUA Energy Services, Inc.
(Massachusetts) and EUA Telecommunications (Massachusetts).
Montaup Electric Company (Massachusetts) is a subsidiary of
Eastern Edison Company. Each of the above subsidiaries does
business under its indicated corporate name.
Consent of Experts and Counsel:
*23-1.03 - Consent of Independent Accountants.
(b) Reports on Form 8-K
On October 2, 1997, EUA filed a Current Report on Form 8-K with respect to
Item 5 (Other Events).
[This page left blank intentionally]
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.
Signature Title Date
EASTERN UTILITIES ASSOCIATES
By /s/John R. Stevens President and Chief Operating Officer March 16, 1998
John R. Stevens (Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/Donald G. Pardus Chairman and Chief Executive Officer
Donald G. Pardus (Principal Executive Officer) and Trustee
/s/John R. Stevens President and Chief Operating Officer
John R. Stevens (Principal Accounting Officer) and Trustee
/s/Clifford J. Hebert, Jr. Treasurer
Clifford J. Hebert, Jr. (Principal Financial Officer)
Russell A. Boss Trustee
/s/Paul J. Choquette, Jr. Trustee
Paul J. Choquette, Jr.
March 16, 1998
/s/Peter S. Damon Trustee
Peter S. Damon
/s/Peter B. Freeman Trustee
Peter B. Freeman
/s/Larry A. Liebenow Trustee
Larry A. Liebenow
/s/Jacek Makowski Trustee
Jacek Makowski
/s/Wesley W. Marple, Jr. Trustee
Wesley W. Marple, Jr.
/s/Margaret M. Stapleton Trustee
Margaret M. Stapleton
Trustee
W. Nicholas Thorndike
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.
Signature Title Date
BLACKSTONE VALLEY ELECTRIC COMPANY
By/s/John R. Stevens Vice Chairman and Director March 16, 1998
John R. Stevens (Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/Donald G. Pardus Chairman of the Board and
Donald G. Pardus Director (Principal Executive Officer)
/s/John R. Stevens Vice Chairman and Director
John R. Stevens (Principal Accounting Officer)
/s/Clifford J. Hebert, Jr. Treasurer and Director
Clifford J. Hebert, Jr. (Principal Financial Officer)
/s/John D. Carney President and Director March 16, 1998
John D. Carney
/s/Robert G. Powderly Executive Vice President and
Robert G. Powderly Director
[This page left blank intentionally]
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.
Signature Title Date
EASTERN EDISON COMPANY
March 16, 1998
By/s/John R. Stevens Vice Chairman and Director
John R. Stevens (Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/Donald G. Pardus Chairman of the Board and Director
Donald G. Pardus (Principal Executive Officer)
/s/John R. Stevens Vice Chairman and Director
John R. Stevens (Principal Accounting Officer)
/s/Clifford J. Hebert, Jr. Treasurer and Director March 16, 1998
Clifford J. Hebert, Jr. (Principal Financial Officer)
/s/John D. Carney President and Director
John D. Carney
/s/Robert G. Powderly Executive Vice President and
Robert G. Powderly Director
EASTERN UTILITIES ASSOCIATES AND SUBSIDIARY COMPANIES
Item 14(a)(2). Financial Statement Schedules
<TABLE> Schedule II
Eastern Utilities Associates and Subsidiary Companies
Valuation and Qualifying Accounts
In Thousands)
<CAPTION>
Column A Column B Column C Column D Column E
Additions
(1) (2)
Balance at Charged to Charged Balance at
Beginning Costs and to Other Deductions- End of
Description of Period Expenses Accounts Describe Period
<S> <C> <C> <C> <C> <C>
For the Year Ended December 31, 1997:
Allowance for Doubtful Accounts $976 $1,090 $450 (a) $1,407 (b) $1,109
For the Year Ended December 31, 1996:
Allowance for Doubtful Accounts $690 $1,754 $292 (a) $1,760 (b) $976
For the Year Ended December 31, 1995:
Allowance for Doubtful Accounts $629 $1,217 $287 (a) $1,443 (b) $690
</TABLE>
<TABLE> Schedule II
Blackstone Valley Electric Company
Valuation and Qualifying Accounts
(In Thousands)
<CAPTION>
Column A Column B Column C Column D Column E
Additions
(1) (2)
Balance at Charged to Charged Balance at
Beginning Costs and to Other Deductions- End of
Description of Period Expenses Accounts Describe Period
<S> <C> <C> <C> <C> <C>
For the Year Ended December 31, 1997:
Allowance for Doubtful Accounts $151 $550 $332 (a) $884 (b) $149
For the Year Ended December 31, 1996:
Allowance for Doubtful Accounts $127 $800 $232 (a) $1,008 (b) $151
For the Year Ended December 31, 1995:
Allowance for Doubtful Accounts $125 $585 $217 (a) $800 (b) $127
(a) Recoveries of accounts previously written off.
(b) Principally Accounts Receivable written off.
</TABLE>
Report of Independent Accountants
To the Trustees and Shareholders of
Eastern Utilities Associates:
Our report on the consolidated financial statements of Eastern Utilities
Associates and subsidiaries has been incorporated by reference in this Form 10-
K from page 44 of the 1997 Annual Report to Shareholders of Eastern Utilities
Associates. In connection with our audits of such consolidated financial
statements, we have also audited the related consolidated financial statement
schedule listed in Item 14 (a)(2) of this Form 10-K.
In our opinion, the consolidated financial statement schedule referred to
above, when considered in relation to the basic financial statements taken as a
whole, presents fairly, in all material respects, the information required to
be included therein.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 3, 1998
Report of Independent Accountants
To the Directors and Shareholder of
Blackstone Valley Electric Company:
Our report on the financial statements of Blackstone Valley Electric Company
has been incorporated by reference in this Form 10-K from page 29 of the 1997
Annual Report of Blackstone Valley Electric Company. In connection with our
audits of such financial statements, we have also audited the related financial
statement schedule listed in Item 14 (a)(2) of this Form 10-K.
In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 3, 1998
EASTERN EDISON COMPANY
TO
STATE STREET BANK AND TRUST COMPANY
(formerly State Street Trust Company)
BOSTON, MASSACHUSETTS,
Trustee
TWENTY-SEVENTH SUPPLEMENTAL INDENTURE
Dated as of January 1, 1998
Supplementing the Indenture of First Mortgage
And Deed of Trust Dated As Of
September 1, 1948
This is a Mortgage of Personal Property as well as a
Mortgage upon Real Estate.
THIS TWENTY-SEVENTH SUPPLEMENTAL INDENTURE, dated as of January 1,
1998, between Eastern Edison Company (formerly named Brockton Edison Company),
as Debtor (its Federal tax number being 04-1123095), a corporation organized
and existing under the laws of The Commonwealth of Massachusetts and having its
principal place of business and mailing address at 750 West Center Street in
the City of West Bridgewater in said Commonwealth (hereinafter sometimes called
the "Company"), party of the first part, and State Street Bank and Trust
Company (formerly State Street Trust Company and hereinafter sometimes called
the "Trustee"), as Secured Party (its Federal tax number being 04-1867445), a
corporation duly organized and existing under the laws of The Commonwealth of
Massachusetts, having its principal office and mailing address at 225 Franklin
Street, Boston, Massachusetts 02110, party of the second part.
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture of First Mortgage and Deed of Trust dated as of September
1, 1948 (hereinafter called the "Original Indenture") to secure, as provided
therein, its bonds (in the Original Indenture and herein called the "Bonds"),
not limited except as provided in Section 3.01 of the Original Indenture, to be
known generally as its "First Mortgage and Collateral Trust Bonds", and to be
issued in one or more series as provided in the Original Indenture; and
WHEREAS, the Company has heretofore executed and delivered to the
Trustee twenty-six indentures supplemental to the Original Indenture as
follows: a First Supplemental Indenture dated as of February 1, 1953
(hereinafter sometimes called the "First Supplemental Indenture"), a Second
Supplemental Indenture dated as of May 1, 1954 (hereinafter sometimes called
the "Second Supplemental Indenture"), a Third Supplemental Indenture dated as
of June 1, 1955 (hereinafter sometimes called the "Third Supplemental
Indenture"), a Fourth Supplemental Indenture dated as of September 1, 1957
(hereinafter sometimes called the "Fourth Supplemental Indenture"), a Fifth
Supplemental Indenture dated as of April 1, 1959 (hereinafter sometimes called
the "Fifth Supplemental Indenture"), a Sixth Supplemental Indenture dated as of
October 1, 1963 (hereinafter sometimes called the "Sixth Supplemental
Indenture"), a Seventh Supplemental Indenture dated as of June 1, 1969
(hereinafter sometimes called the "Seventh Supplemental Indenture"), an Eighth
Supplemental Indenture dated as of July 1, 1972 (hereinafter sometimes called
the "Eighth Supplemental Indenture"), a Ninth Supplemental Indenture dated as
of September 1, 1973 (hereinafter sometimes cal led the "Ninth Supplemental
Indenture"), a Tenth Supplemental Indenture dated as of October 1, 1975
(hereinafter sometimes called the "Tenth Supplemental Indenture"), an Eleventh
Supplemental Indenture dated as of January 1, 1979 (hereinafter sometimes
called the "Eleventh Supplemental Indenture"), a Twelfth Supplemental Indenture
dated as of October 1, 1980 (hereinafter sometimes called the "Twelfth
Supplemental Indenture"), a Thirteenth Supplemental Indenture dated as of July
1, 1981 (hereinafter sometimes called the "Thirteenth Supplemental Indenture"),
a Fourteenth Supplemental Indenture dated as of June 1, 1982 (hereinafter
sometimes called the "Fourteenth Supplemental Indenture"), a Fifteenth
Supplemental Indenture dated as of May 1, 1983 (hereinafter sometimes called
the "Fifteenth Supplemental Indenture"), a Sixteenth Supplemental Indenture
dated as of September 1, 1984 (hereinafter sometimes called the "Sixteenth
Supplemental Indenture"), a Seventeenth Supplemental Indenture dated as of July
1, 1986 (hereinafter sometimes called the "Seventeenth Supplemental
Indenture"), an Eighteenth Supplemental Indenture dated as of June 1, 1987
(hereinafter sometimes called the "Eighteenth Supplemental Indenture"), a
Nineteenth Supple mental Indenture dated as of November 1, 1987 (hereinafter
sometimes called the "Nineteenth Supplemental Indenture"), a Twentieth
Supplemental Indenture dated as of May 1, 1988 (hereinafter sometimes called
the "Twentieth Supplemental Indenture"), a Twenty-First Supplemental Indenture
dated as of September 1, 1988 (hereinafter sometimes called the "Twenty-First
Supplemental Indenture"), a Twenty-Second Supplemental Indenture dated as of
December 1, 1990 (hereinafter sometimes called the "Twenty-Second Supplemental
Indenture"), a Twenty-Third Supplemental Indenture dated as of July 1, 1992
(hereinafter sometimes called the "Twenty-Third Supplemental Indenture"), a
Twenty-Fourth Supplemental Indenture dated as of May 1, 1993 (hereinafter some
times called the Twenty-Fourth Supplemental Indenture) and a Twenty-Fifth
Supplemental Indenture dated as of July 1, 1993 (hereinafter sometimes called
the Twenty-Fifth Supplemental Indenture), a Twenty-Sixth Supplemental Indenture
dated as of September 1, 1993 (hereinafter sometimes called the "Twenty-Sixth
Supplemental Indenture") (the Original Indenture, as supplemented and modified
by the First Supplemental Indenture, the Eighth Supplemental Indenture, the
Ninth Supplemental Indenture, the Tenth Supplemental Indenture and the Eleventh
Supplemental Indenture and as supplemented by the Second Supplemental
Indenture, the Third Supplemental Indenture, the Fourth Supplemental Indenture,
the Fifth Supplemental Indenture, the Sixth Supplemental Indenture, the Seventh
Supplemental Indenture, the Twelfth Supplemental Indenture, the Thirteenth
Supplemental Indenture, the Fourteenth Supplemental Indenture, the Fifteenth
Supplemental Indenture, the Sixteenth Supplemental Indenture, the Seventeenth
Supplemental Indenture, the Eighteenth Supplemental Indenture, the Nineteenth
Supplemental Indenture, the Twentieth Supplemental Indenture, the Twenty-First
Supplemental Indenture, the Twenty-Second Supplemental Indenture, the Twenty-
Third Supplemental Indenture, the Twenty-Fourth Supplemental Indenture, the
Twenty-Fifth Supplemental Indenture, the Twenty-Sixth Supplemental Indenture
and this Twenty-Seventh Supplemental Indenture, being herein sometimes called
the "Indenture"); and
WHEREAS, Article Eighteen of the Original Indenture provides, among
other things, that the Company, when authorized by a resolution of the Board of
Directors, and the Trustee, from time to time and at any time, subject to the
restrictions in the Indenture contained, may, and when so required by the
Indenture, shall, enter into indentures supplemental to the Original Indenture
and which thereafter shall form a part thereof, for the purposes, among others,
of mortgaging, pledging, conveying, transferring or assigning to the Trustee,
and subjecting to the lien of the Indenture, additional properties acquired by
the Company; and
WHEREAS, the Board of Directors of the Company, by resolutions duly
adopted authorized the execution of this Twenty-Seventh Supplemental Indenture
for the purpose of substituting the Montaup Contract with the Settlement
Agreement filed in FERC Docket No. ER97-3200-000 by and among Montaup Electric
Company, the Company, Blackstone Valley Electric Company and Newport Electric
Corporation, (the "Settlement Agreement"), pursuant to Section 9.13 of the
Indenture.
NOW, THEREFORE, THIS INDENTURE WITNESSETH, that in order to secure the
payment of the principal of and premium, if any, and interest on all Bonds at
any time issued and outstanding under the Indenture, according to their tenor,
purport and effect, to confirm the lien of the Indenture upon the mortgaged
property mentioned therein including any and all property purchased,
constructed or otherwise acquired by the Company since the date of execution of
the Original Indenture and to secure the performance and observance of all the
covenants and conditions in the Bonds and in the Indenture contained, and for
and in consideration of the premises and of mutual covenants herein contained,
and of the sum of $10 duly paid to the Company by the Trustee, at or before the
ensealing and delivery hereof, and for other valuable consideration, the
receipt whereof is hereby acknowledged, the Company has executed and delivered
this Twenty-Seventh Supplemental Indenture, and by these presents, does grant,
bargain, sell, alien, remise, release, convey, assign, transfer, mortgage,
pledge, set over and confirm unto State Street Bank and Trust Company, Trustee,
its successors in trust and its and their successors and assigns, all the
property, rights, privileges and franchises (other than excepted property) of
the character described in the Granting Clauses of the Original Indenture now
owned of record or otherwise by the Company, whether or not constructed or
acquired since the date of execution of the Original Indenture or which may
hereafter be constructed or acquired by it, including without limiting the
generality of the foregoing the property described in Article One hereof, if
any, but subject to all exceptions, reservations and matters of the character
therein referred to, and expressly excepting and excluding from the lien and
operation of the Indenture all properties of the character specifically
excepted by Paragraphs B through H of Granting Clause VII of the Original
Indenture and all property released or otherwise disposed of pursuant to the
provisions of the Indenture.
If, upon the happening of any default as defined in Article Twelve of
the Original Indenture, the Trustee or a receiver or trustee shall enter upon
and take possession of the trust estate, the Trustee or such receiver or
trustee may, to the extent permitted by law, at the same time likewise take
possession of any and all of the property of the character specifically
excepted under the heading "Excepted Property" of Granting Clause VII of the
Original Indenture, other than Paragraph F thereof, then on hand and use and
administer the same to the same extent as if such property were part of the
trust estate, unless and until such default shall be remedied or waived and
possession of the trust estate restored to the Company.
TO HAVE AND TO HOLD all of the property, real, personal and mixed, and
all and singular the lands, properties, estates, rights, franchises, privileges
and appurtenances hereby granted, bargained, sold, aliened, remised, released,
conveyed, as signed, transferred, mortgaged, pledged, set over or confirmed, or
intended so to be, unto the Trustee and its successors in trust and to its and
their successors and assigns, forever.
BUT IN TRUST, NEVERTHELESS, for the equal and proportionate use,
benefit, security and protection of those who from time to time shall hold the
Bonds and coupons, or any of them, authenticated and delivered under the
Original Indenture, as heretofore and hereby supplemented and modified, and
duly issued by the Company, without any discrimination, preference or priority
of any one Bond or coupon over any other by reason of priority in the time of
issue, sale or negotiation thereof or otherwise, except as provided in Section
12.28 of the Original Indenture, so that, subject to said Section 12.28, each
and all of said Bonds and coupons shall have the same right, lien and privilege
under the Original Indenture, as heretofore and hereby supplemented and
modified, and shall be equally and proportionately secured thereby and hereby
(except as any sinking, replacement or other analogous fund established in
accordance with the provisions of the Indenture may afford additional security
f or the Bonds of any specific series), with the same effect as if all of the
Bonds and coupons had been issued, sold and negotiated simultaneously on the
date of the delivery of the Original Indenture.
THE COMPANY HEREBY DECLARES that it holds and will hold and apply all
property and rights of the character described in Paragraph F of Granting
Clause VII of the Original Indenture as specifically reserved and excepted,
upon the trusts set forth in the Original Indenture, as heretofore and hereby
supplemented and modified, and as the Trustee (or any purchaser upon any sale
of the mortgaged property) shall for such purpose direct from time to time, to
the fullest extent permitted by law o r in equity and by any instruments
creating the same, as fully as if the same could be and had been hereby
granted, conveyed, mortgaged, pledged, transferred and assigned to and vested
in the Trustee.
It is hereby covenanted, declared and agreed by and between the parties
hereto that all Bonds and coupons, if any, are to be authenticated, delivered
and issued and that all property subject to or to become subject to the
Indenture is to be held, subject to the further covenants, conditions, uses and
trusts set forth in the Indenture, and the Company for itself and its
successors or assigns does hereby covenant and agree to and with the Trustee
and its successor or successors in such trust, for the benefit of those who
shall hold Bonds, or coupons, or any of them as follows:
ARTICLE ONE
Amendment of the Original Indenture
Section 1.01. Granting Clause I of the Original Indenture is hereby
modified by deleting the word "Contract" in the fourth line of said Clause and
substituting the words "Settlement Agreements."
Section 1.02. Article Twenty (C) is hereby modified by replacing it
in its entirety with the following:
C. Schedule of Montaup Securities and Settlement Agreements.
1. All of the bonds, notes and other evidences of
indebtedness, whether secured or unsecured, and all preferred, common, or
capital stock or other certificates of interest, of Montaup Electric Company,
a corporation organized and existing under the laws of the Commonwealth of
Massachusetts now owned or hereafter acquired by the Company and pledged
hereunder, including specifically, without limiting the generality of the
foregoing,
(a) 586,000 shares Montaup Electric Company Common Stock ($100 par value);
(b) 15,000 shares Montaup Electric Company Preferred Stock ($100 par value);
(c) $8,500,000 Montaup Electric Company 8% Debenture Bonds due May 1, 2000;
(d) $12,800,000 Montaup Electric Company 8 1/4% Debenture Bonds due October 1,
2003;
(e) $26,000,000 Montaup Electric Company 14% Debenture Bonds due October 1,
2005;
(f) $40,000,000 Montaup Electric Company 10 1/8% Debentures due August 1, 2008;
(g) $9,275,000 Montaup Electric Company 10% Debenture Bonds due December 1,
2008;
(h) $19,000,000 Montaup Electric Company 16 1/2% Debenture Bonds due October 1,
2010;
(i) $30,000,000 Montaup Electric Company 12 3/8% Debenture Bonds due May 1,
2013;
(j) $25,000,000 Montaup Electric Company 9 3/8% Debenture Bonds due December 1,
2020; and
(k) $5,000,000 Montaup Electric Company 9% Debenture Bonds due December 1,
2020.
which constitute all the securities of Montaup Electric Company now owned by
the Company.
2. All the rights, interest, claim and benefits of the Company,
subject to its liabilities and obligations thereunder, in and under those
certain Settlement Agreements filed with the Federal Energy Regulatory
Commission (a) by and among Montaup Electric Company, the Company, and the
Division of Energy Resources of the Office of the Attorney General of
Massachusetts, and (b) by and among Montaup Electric Company, the Rhode Island
Division of Public Utilities and Carriers, Blackstone Valley Electric Company
and Newport Electric Corporation, and as the same may be further changed,
amended or modified from time to time, and any agreements substituted therefor,
as provided in Section 9.13 of this Indenture (herein as amended and any
agreements substituted therefor sometimes called the "Settlement Agreements"),
which agreements provide, among other things, for the termination of the
Montaup Contract and the right of Montaup to recover stranded costs from the
Company, Blackstone Valley Electric Company and Newport Electric Corporation.
Notwithstanding anything contained in this Indenture, no authority is hereby,
or by the pleading hereunder of the Montaup Securities or the Settlement
Agreements, conferred upon or shall be exercised by the Trustee in
contravention of the provisions of the Settlement Agreements.
ARTICLE TWO
Miscellaneous
SECTION 2.01. This Twenty-Seventh Supplemental Indenture is executed
and shall be construed as an indenture supplemental to the Original Indenture,
as supplemented and modified, and shall form a part thereof, and the Original
Indenture, as heretofore supplemented and modified (to the extent and when
and as the same shall become and be effective as provided in the respective
modifying supplemental indentures) and as hereby supplemented is hereby
confirmed. All terms used in this Twenty-Seventh Supplemental Indenture shall
be taken to have the same meaning as in the Original Indenture, as supplemented
and modified, except in cases where the context clearly indicates otherwise.
SECTION 2.02. All recitals in this Twenty-Seventh Supplemental
Indenture are made by the Company only and not by the Trustee; and all of the
provisions contained in the Original Indenture in respect of the rights,
privileges, immunities, powers and duties of the Trustee shall be applicable in
respect hereof as fully and with like effect as if set forth herein in full.
SECTION 2.03. The Company covenants that it is lawfully seized and
possessed at the date of execution of this Twenty-Seventh Supplemental
Indenture of all the trust estate described in this Twenty-Seventh Supplemental
Indenture, except as specifically otherwise stated in this Twenty-Seventh
Supplemental Indenture, and that all the trust estate so described is free and
clear of any lien other than the lien of the Indenture and permitted
encumbrances; that the Company will warrant and for ever defend all the trust
estate so described to the Trustee against the claims of all persons whomsoever
except as in the Indenture specifically otherwise stated; that it will maintain
and preserve the lien of the Indenture so long as any of the Bonds issued under
the Indenture are outstanding; and that it has good right and lawful authority
to subject all the trust estate so described to the lien of the Indenture as
provided in and by the Original Indenture, as heretofore supplemented and
modified and as supplemented by this Twenty-Seventh Supplemental Indenture.
SECTION 2.04. This Twenty-Seventh Supplemental Indenture may be
executed in several counterparts, and each of such counterparts shall for all
purposes be deemed to be an original, and all such counterparts, or as many of
them as the Company and the Trustee shall preserve undestroyed, shall together
constitute but one and the same instrument.
SECTION 2.05. Although this Twenty-Seventh Supplemental Indenture is
dated for convenience and for the purpose of reference as of January 1, 1998,
the actual date or dates of execution by the Company and by the Trustee are as
indicated by t heir respective acknowledgments hereto annexed.
[Remainder of Page Intentionally Left Blank]
IN WITNESS WHEREOF, Eastern Edison Company has caused this Twenty-
Seventh Supplemental Indenture to be signed in its corporate name and behalf by
its President, either of its Vice Chairmen or one of its Vice Presidents and
its corporate seal to be hereunto affixed and attested by its Clerk or one of
its Assistant Clerks, and State Street Bank and Trust Company in token of its
acceptance of the trust hereby created has caused this Twenty-Seventh
Supplemental Indenture to be signed in its corporate name and behalf by one of
its Assistant Vice Presidents, and its corporate seal to be hereunto affixed
and attested by its Secretary or one of its Assistant Secretaries, all as of
the day and year first above written.
EASTERN EDISON COMPANY
By:/s/John R. Stevens
John R. Stevens
Vice Chairman
Attest:
/s/ Clifford J. Hebert, Jr.
Clerk (CORPORATE SEAL)
STATE STREET BANK AND TRUST
COMPANY
By:/s/Daniel Golden
Daniel Golden
Assistant Vice President
Attest:
/s/ Scott A. Knox
Assistant Secretary
(CORPORATE SEAL)
COMMONWEALTH OF MASSACHUSETTS )
COUNTY OF SUFFOLK ) ss.:
At Boston on this 6th day of January, 1998, before me appeared John R.
Stevens and Clifford J. Hebert, Jr., to me personally known, who, being by me
duly sworn, did say that they are a Vice Chairman and a Clerk, respectively, of
Eastern Edison Company, and that the seal affixed to the foregoing instrument
is the corporate seal of said Corporation, and that the said instrument was
signed and sealed by them on behalf of said Corporation by authority of its
Board of Directors, and each of s aid officers acknowledged said instrument to
be the free act and deed of said Corporation.
/s/Philip Good
Notary Public
My Commission Expires 9/18/2003
(Notarial Seal)
COMMONWEALTH OF MASSACHUSETTS )
COUNTY OF SUFFOLK ) ss.:
At Boston on this 6th day of January, 1998, before me Daniel Golden
and Scott A. Knox, to me personally known, who being by me duly sworn, did say
that they are an Assistant Vice President and an Assit. Secretary,
respectively, of State Street Bank and Trust Company, and that the seal affixed
to the foregoing instrument is the corporate seal of said Trust Company, and
that the said instrument was signed and sealed by them on behalf of said Trust
Company by authority of its Board of Directors and each of said officers
acknowledged said instrument to be the free act and deed of said Trust Company.
/s/Philip Good
Notary Public
My Commission Expires 9/18/2003
(Notarial Seal)
SECOND AMENDMENT
TO THE
EASTERN UTILITIES ASSOCIATES
EMPLOYEES' SAVINGS PLAN
WHEREAS, Eastern Utilities Associates (the "Employer) previously
adopted the Eastern Utilities Associates Employees' Savings Plan (the "Plan")
effective January 1, 1982;
WHEREAS, the Employer amended and restated the Plan effective January
1, 1989;
WHEREAS, the Employer has resolved to provide Participants who have
attained age fifty-seven and completed ten or more years of Service the right
to reinvest up to twenty percent of the EUA Common Shares allocated to such
Participant's Matching Contribution Account each Plan Year; and
WHEREAS, the Employer has reserved the right to amend the Plan from
time to time under Section 13.2 of the Plan;
NOW, THEREFORE, in accordance with and pursuant to the foregoing, the
Plan is amended, effective April 15, 1997, as follows:
1. Article I is hereby amended by adding the following Section 1.46
thereto:
"1.46 "Qualified Participant" shall mean a Participant who has attained
age fifty-seven and completed 10 or more years of Service."
2. Article I is hereby amended by adding the following Section 1.47
thereto:
"1.47 "Special Investment Option" shall mean the option made available
to a Qualified Participant under Section 5.5 of the Plan."
3. The second sentence of Section 4.2 is hereby amended by deleting the
same in its entirety and by substituting therefore the following:
"Matching Contributions shall be invested in EUA Common Shares pursuant
to Article V, subject to the rights of a Qualified Participant to elect the
Special Investment Option available under Section 5.5 of the Plan and except as
may otherwise be provided under the terms of a collective bargaining agreement.
4. The second sentence of Section 5.2 of the Plan is hereby amended by
deleting the same in its entirety and by substituting therefore the
following:
"Matching Contributions and any Rollover Contributions from a
terminated plan maintained by the Employer which were invested in EUA Common
Shares shall be invested wholly in EUA Common Shares subject to the rights of a
Qualified Participant t o elect the Special Investment Option available under
Section 5.5 of the Plan."
5. Section 5.4(b) of the Plan is hereby amended by deleting the first
paragraph of said section in its entirety and by substituting therefore
the following:
"A Participant's Matching Contribution Account and Rollover
Contribution Account attributable to amounts distributed from a terminated plan
maintained by the Employer which was invested in EUA Common Shares shall be
invested exclusively in EU A Common Shares, subject to the rights of a
Qualified Participant to elect the Special Investment Option available under
Section 5.5 of the Plan."
6. A new Section 5.5 of the Plan is hereby added to the Plan as follows:
5.5. Special Investment Option.
(a) A Qualified Participant shall have an option (the "Special
Investment Option") each Plan Year to have transferred to any Fund offered
from time to time under the Plan up to the amount of the Available Divestiture
Amount. For purposes of this Section 5.5, the Available Divestiture Amount
shall equal twenty percent of the number of the EUA Common Shares (excluding
partial shares) allocated to the Participant's Matching Contribution Account
and Rollover Account as the last day of t he Plan Year immediately preceding
the Plan Year in which the Participant became a Qualified Participant.
(b) If a qualified Participant either does not elect the Special
Investment Option or elects to transfer less than the maximum amount available
under the Special Investment Option with respect to a Plan Year, then the
unused portion of an y such Special Investment Option shall not be carried
forward to any subsequent Plan Year.
(c) A Qualified Participant's election under the Special Investment
Option to transfer amounts to other Funds shall be made in
multiples of five percent.
(d) The Committee shall establish such rules and regulations as it
deems necessary and appropriate for the administration of the
Special Investment Option.
IN WITNESS WHEREOF, EASTERN UTILITIES ASSOCIATES has caused this
instrument to be executed and delivered on its behalf by the undersigned on
this 30th day of May, 1997.
ATTEST: EASTERN UTILITIES ASSOCIATES
/s/ Clifford J. Hebert, Jr. By: /s/ John R. Stevens
Secretary
Its: President
(Corporate Seal)
THIRD AMENDMENT
TO THE
EASTERN UTILITIES ASSOCIATES
EMPLOYEES' SAVINGS PLAN
WHEREAS, Eastern Utilities Associates (the "Employer") previously
adopted the Eastern Utilities Associates Employees' Savings Plan (the "Plan")
effective January 1, 1982;
WHEREAS, the Employer amended and restated the Plan effective January
1, 1989;
WHEREAS, the Employer has resolved to provide Participants employed by
EUA Cogenex Corporation, EUA Highland Corporation and EUA Citizen Conservation
Services, Inc. an enhanced Matching Contribution effective April 1, 1997; and
WHEREAS, the Employer has reserved the right to amend the Plan from
time to time under Section 13.2 of the Plan;
NOW, THEREFORE, in accordance with and pursuant to the foregoing, the
Plan is amended, effective April 1, 1997, as follows:
1. Section 1.30 shall be amended by adding the following sentences at the
end thereof:
"The Committee shall maintain a schedule of Participating Employers as
part of the Plan."
2. Section 4.1 of the Plan is hereby amended by deleting the first
paragraph of said section in its entirety and by substituting therefore
the following:
"Each Participating Employer shall make a Matching Contribution on
behalf of each of its Participants in an amount equal to 100% of the first 2%
of Earnings and 50% of the next 1% of Earnings with respect to which such
Participant makes Pre-T ax Participant Contribution(s). Notwithstanding the
foregoing, effective April 1, 1997, EUA Cogenex Corporation, EUA Highland
Corporation and EUA Citizen Conservation Services, Inc. shall make a Matching
Contribution on behalf of each of their respective Participants in an amount
equal to 100% of the first 2% of Earnings and 50% of the next 8% of Earnings
with respect to which such Participants makes Pre-Tax Participant
Contribution(s). The level of Matching Contributions for any Employee whose
terms of employment are governed by a collective bargaining agreement shall
be subject to the terms of such collective bargaining agreement with respect to
a Plan Year. Matching Contributions made under this Section 4.1 shall be
subject to the limitations of Sections 4.3, 4.4 and 4.5."
IN WITNESS WHEREOF, EASTERN UTILITIES ASSOCIATES has caused this
instrument to be executed and delivered on its behalf by the undersigned on
this 17 day of March, 1997.
ATTEST: EASTERN UTILITIES ASSOCIATES
/s/ Clifford J. Hebert, Jr. By: /s/ John R. Stevens
Secretary
Its: President
(Corporate Seal)
FOURTH AMENDMENT
TO THE
EASTERN UTILITIES ASSOCIATES
EMPLOYEES' SAVINGS PLAN
WHEREAS, Eastern Utilities Associates (the "Employer") previously
adopted the Eastern Utilities Associates Employees' Savings Plan (the "Plan")
effective January 1, 1982;
WHEREAS, the Employer amended and restated the Plan effective January
1, 1989;
WHEREAS, the Employer has resolved to amend the definition of earnings
under the Plan; and
WHEREAS, the Employer has reserved the right to amend the Plan from
time to time under Section 13.2 of the Plan;
NOW, THEREFORE, in accordance with and pursuant to the foregoing, the
Plan is amended, effective July 1, 1997, as follows:
1. The first paragraph of Section 1.12 is hereby amended by deleting the
same in its entirety and by substituting therefore the following:
"Earnings" shall mean, subject to Section 4.1, the regular straight
time wages, overtime, bonuses and special pay (including commissions) paid by
the Employer to an Employee during the Plan Year, exclusive of the Employer's
cost for any public or private employee benefit plan (including the Plan),
except that Earnings shall include any Pre-Tax Participant Contribution(s) made
hereunder and any salary deferrals made by the Employee to a plan maintained by
a Participating Employer which meets the requirements of Code Section 125
during the Plan Year."
2. The following sentence is hereby added at the end of the first
paragraph of Section 3.1:
The Committee shall establish such rules and regulations as it deems
necessary and appropriate for the administration of elections to make Pre-Tax
Participant Contributions."
3. The following sentence is hereby added to the first paragraph of
Section 4.1 of the Plan as follows:
"Solely for purposes of this Section 4.1, Earnings with respect to
which a Participant makes Pre-Tax Contribution(s) shall only consist of a
Participant's regular straight time wages, overtime and special pay not paid as
a commission."
IN WITNESS WHEREOF, EASTERN UTILITIES ASSOCIATES has caused this
instrument to be executed and delivered on its behalf by the undersigned on
this 16 day of June, 1997.
ATTEST: EASTERN UTILITIES ASSOCIATES
/s/Clifford J. Hebert, Jr. By: /s/ Donald G. Pardus
Secretary
Its: Chairman
(Corporate Seal)
SECOND AMENDMENT
TO THE
EMPLOYEES' RETIREMENT PLAN
OF
EASTERN UTILITIES ASSOCIATES
AND ITS AFFILIATED COMPANIES
WHEREAS, Eastern Utilities Associates (the "Employer") previously
established the Employees' Retirement Plan of Eastern Utilities Associates and
Its Affiliated Companies (the "Plan");
WHEREAS, the Employer amended and restated the Plan effective January
1, 1989;
WHEREAS, EUA Cogenex Corporation has notified the Employer of its
intent to terminate its status as a Participating Employer under the Plan
effective April 1, 1997;
WHEREAS, the Employer has approved the discontinuance of EUA Cogenex
Corporation as a Participating Employer under the Plan effective April 1, 1997;
WHEREAS, the Employer has resolved to eliminate credit for past service
with another utility company; and
WHEREAS, the Employer has reserved the right to amend the Plan from
time to time under Section 12.1 of the Plan;
NOW, THEREFORE, in accordance with and pursuant to the foregoing, the
Plan is amended, effective as of 12:00 a.m. April 1, 1997, as follows:
1. Section 1.32 is amended by deleting the same in its entirety and by
substituting therefore the following:
"1.32 "Participating Employer" shall mean the Employer and any
other Affiliated Employer which has elected to participate in the Plan pursuant
to the provisions under Article XV. The Retirement Board shall maintain a
schedule of Participating Employers as part of the Plan. Effective 12:00 a.m.
April 1, 1997, EUA Cogenex Corporation has withdrawn as Participating Employers
under the Plan."
2. Section 2.3 of the Plan is hereby amended by deleting Paragraph (d) in
its entirety and substituting therefore the following:
"(d) Credited Service shall only be granted hereunder for any period
of time during which an individual:
(1) is in a class of Employees which is eligible to
participate in the Plan; except that for an Employee who was hired prior to
January 1, 1989, Credited Service shall be granted for any period of time on
and after such Employee's attainment of age 21 provided he otherwise satisfied
the requirements of Section 2.1(b) and (c), and
(2) is employed by a Participating Employer.
In no event shall Credited Service be earned by a Participant
after the withdrawal of an Affiliated Employer as a Participating Employer."
3. Section 2.6 of the Plan is hereby amended by adding the following
paragraph (c) at the end thereof:
"(c) Notwithstanding anything to the contrary in Section 2.6(a) and
(b) above, no Employee whose first Hour of Service with an Affiliated Employer
occurs on or after April 1, 1997 shall be eligible to receive past service
credit based on employment with a former employer under this Section 2.6."
4. Section 2.8 of the Plan is hereby amended by deleting the same in its
entirety and by substituting therefore the following:
"2.8 Transfer to Ineligible Status. Any individual who ceases to be
eligible to participate in the Plan by reason of (i) transfer of employment to
an Affiliated Employer which is not a Participating Employer, (ii) a change in
employment classification or (iii) the termination of an Affiliated Employer's
status as a Participating Employer hereunder, either prior to or subsequent to
commencement of his participation in this Plan, shall be credited with Years of
Service during such period of employment pursuant to Section 2.2, solely for
purposes of vesting and eligibility for benefits. Such Participant shall be
entitled only to benefits under the provisions of the Plan as in effect while
he is eligible to participate in the Plan. Credited Service shall only be
earned for period during which the Employee is eligible to participate in the
Plan."
5. A new Article XV is added to the Plan as follows:
"ARTICLE XV PARTICIPATING EMPLOYERS
15.1 Adoption of Plan by a Participating Employer. Any
Affiliated Employer, whether or not presently existing, may adopt the Plan with
respect to all or some of its employees after the Board authorizes the
participation of such employer in the Plan. The Board authorization shall set
forth the date on which the Affiliated Employer may begin to participate in the
Plan and any special restrictions or requirements applicable to the Affiliated
Employer's participation in the Plan. An Affiliated Employer becomes a
Participating Employer under the Plan following such authorization by
appropriate action of its board of directors (or noncorporate counterpart) to
adopt the Plan.
15.2 Plan Provisions Applicable to Participating Employer.
The provisions of the Plan shall apply equally to each Participating Employer
and its Employees except as specifically set forth in the Plan.
15.3 Termination of Participation in the Plan.
(a) A Participating Employer may, but only with the consent of the
Board, suspend or discontinue its contributions under the Plan or terminate
its participation in the Plan by giving not less than 30 days' written notice
to that effect to the Retirement Board.
(b) The Board may, in its sole discretion, terminate a
Participating Employer's participation in the Plan at any time
without consent or approval of such employer.
(c) In the event of the termination of the participation in this
Plan of a Participating Employer under Section 15.3(a) or (b) above, the
Retirement Board may direct that the part of the Fund which it determines to be
attributable to contributions of such Participating Employer be segregated by
the Trustee and held by it as a separate fund. Any such separate fund shall be
distributed in the manner provided in Section 12.3 (in case of the plan
termination) or continued as a separate plan, as such Participating Employer
may direct.
15.4 Single Plan. For purposes of the Code and ERISA, the
Plan as adopted by the Participating Employers shall constitute a single plan
rather than a separate plan of each Participating Employer. All assets in the
Trust Fund shall be available to pay benefits to all Participants and their
Beneficiaries."
IN WITNESS WHEREOF, EASTERN UTILITIES ASSOCIATES has caused this
instrument to be executed and delivered on its behalf by the undersigned on
this 17 day of March, 1997.
ATTEST: EASTERN UTILITIES ASSOCIATES
/s/Clifford J. Hebert, Jr. By: /s/John R. Stevens
Secretary
Its: President
(Corporate Seal)
FIRST AMENDMENT
TO THE
EASTERN UTILITIES ASSOCIATES
RESTRICTED STOCK PLAN
WHEREAS, Eastern Utilities Associates (the "Company") previously
adopted the Eastern Utilities Associates Restricted Stock Plan (the "Plan");
WHEREAS, the Company desires to amend the Plan in the manner and to the
extent hereinafter set forth; and
WHEREAS, pursuant to Section 12(a) of the Plan, the Company has the
right, by action of its Board of Trustees, to amend the Plan at any time and
from time to time, and for that purpose has caused this instrument to be
executed and delivered o n its behalf by its officers thereunto duly authorized
by its Board of Trustees.
NOW, THEREFORE, in accordance with and pursuant to the foregoing, the
Plan is amended, effective November 17, 1997, as follows:
1. Section 5 of the plan is hereby amended by deleting the same in its
entirety and by substituting therefore the following:
"Grant Shares may be awarded to such key employees of the Company,
including any Board member, executive or department head who is employed by the
Company or its affiliates, as are selected by the Committee (any such employee,
a "Participant" )."
2. Section 6 of the Plan is hereby amended by adding the following
provision at the end of the first sentence of said section:
"The Committee may also make special additional awards of Grant Shares on one
or more dates prior to such anniversary, but only top recognize special
nonrecurring circumstances including but not limited to the need to provide
retention incentives to executives and department heads, upon the
recommendation of the CEO that the best interests of the Company would be
served by making additional awards of Grant Shares."
3. Section 7 of the Plan is hereby amended by deleting the same in its
entirety and by substituting therefore the following:
"(a) Unless the Committee specifies otherwise pursuant to paragraphs
(b) and (c) below, Grant Shares shall not be vested and shall be forfeitable
when such Grant Shares are awarded to the Participant. Except as provided in
paragraphs (b) a nd (c), the Participant must remain employed by the Company or
one of its subsidiaries during the five-year period (or such shorter period
designated by the Committee with respect to additional awards of Grant Shares
under Section 6) immediately following the date as of which the Grant Shares
were awarded to him in order for such Grant Shares to become vested in him.
Grant Shares awarded pursuant to an Intervening Award as described in Section
6, above, shall vest at the expiration of the first five-year vesting period
coincident with the five-year vesting period for the Grant Shares awarded on
the Effective Date (or the appropriate triennial anniversary). If the
Participant fails to complete the employment requirement specified by the
Committee for his or her Grant Shares, and such Grant Shares so not otherwise
become vested under paragraphs (b) and (c), the Participant shall forfeit and
transfer to the Company or one or more persons designated by the Committee all
such Grant Shares a warded to him on such date and the Participant shall have
no further rights with respect to such Grant Shares."
IN WITNESS WHEREOF, the Company has caused this instrument to be
executed and delivered on its behalf by its officers thereunto duly authorized
on this 17th day of November 1997.
EASTERN UTILITIES ASSOCIATES
By: /s/Donald G. Pardus
Donald G. Pardus
Chairman of the Board
1997 Annual Report
"Cover with Caption:
"1997's continuing changes
to the very underpinning of
the electric utility industry
challenged us
as never before..." "
"Highlights page with caption:
"...We met every challenge during the year. And we'll continue to deal
with the changes in our industry in ways dedicated to preserving and
enhancing shareholder value.""
<TABLE>
Highlights
<CAPTION>
1997 1996 1995
<S> <C> <C> <C>
FINANCIAL DATA ($ in thousands)
Operating Revenues $ 568,513 $ 527,068 $ 563,363
Consolidated Net Earnings(1) 37,960 30,614 32,626
Return on Average Common Equity 10.2% 8.2% 8.8%
Common Shareholder Equity-
% of Capitalization (Year-End) 50.4% 45.8% 44.5%
Total Assets 1,270,752 1,257,029 1,206,130
Cash Construction Expenditures 76,118 62,730 77,923
COMMON SHARE DATA
Consolidated Earnings per Share<F1> $ 1.86 $ 1.50 $ 1.61
Dividends Paid per Share $ 1.66 $ 1.645 $ 1.585
Annual Dividend Rate $ 1.66 $ 1.66 $ 1.60
Total Common Shares Outstanding 20,435,997 20,435,997 20,436,764
Average Common Shares Traded Daily 88,613 91,843 58,573
Book Value per Share (Year-End) $ 18.27 $ 18.19 $ 18.36
Market Price - High 26 5/8 24 1/4 25 3/8
- Low 16 3/8 14 3/4 21 1/2
- Year-End 26 1/4 17 3/8 23 5/8
OPERATING DATA
Total Primary Sales (mWh) 4,546,000 4,491,000 4,441,000
System Requirements (mWh) 4,765,000 4,699,000 4,668,000
System Peak Demand (mw) 933 854 931
System Reserve Margin (At Peak) 11.5% 34.4% 24.2%
System Load Factor 58.3% 62.6% 57.2%
Customers (Year-End) 302,059 299,471 297,331
Employees (Year-End) - Core Electric <F2> 434 468 541
- Energy Related 197 213 253
- Corporate <F2> 549 564 536
Total 1,180 1,245 1,330
<FN>
<F1> See Management's Discussion and Analysis of Financial Condition and
Results of Operations for details of one-time impacts to earnings.
<F2> Reflects employee shift resulting from corporate reorganization
completed in 1996.
</FN>
</TABLE>
"Caption: "Our customers may choose a new source of electricity, but
they remain our customers." With Map of New England depicting Core Electric
customers as follows:"
Eastern Edison/Brockton
125,000 customers
Abington
Avon
Bridgewater
Brockton
Cohasset
East Bridgewater
Easton
Halifax
Hanson
Hanover
Norwell
Pembroke
Rockland
Scituate
Stoughton
West Bridgewater
Whitman
Eastern Edison/Fall River
59,000 customers
Dighton
Fall River
Somerset
Swansea
Westport
Blackstone Valley Electric
85,000 customers
Central Falls
Cumberland
Lincoln
North Smithfield
Pawtucket
Woonsocket
Burrillville
Newport
Electric
33,000 customers
Jamestown
Middletown
Newport
Portsmouth
About Eastern Utilities Associates
Eastern Utilities Associates (NYSE Symbol: EUA) is a diversified energy
services company whose subsidiaries are known collectively as the EUA System.
To better reflect the new competitive business environment in which it
operates, EUA is organized into four distinct business units covering its
wholesale and retail electric utility businesses, non-utility energy-related
subsidiaries and a corporate unit.
Core Electric Business
The System's core electric utility subsidiaries comprise two business units -
retail and wholesale. The retail business unit provides electric distribution
service to over 300,000 customers in 597 square miles of southeastern
Massachusetts and northern and coastal Rhode Island as follows:
- Blackstone Valley Electric Company: The northern Rhode Island cities
of Pawtucket and Woonsocket and five neighboring communities.
- Eastern Edison Company: Non-contiguous service territories covering
the southeastern Massachusetts cities of Brockton and Fall River
plus 20 surrounding towns.
- Newport Electric Corporation: Newport, Jamestown, Middletown and
Portsmouth, Rhode Island.
The wholesale business unit, Montaup Electric Company, has provided electric
generation and high voltage transmission service at wholesale to the
distribution subsidiaries and to two non-affiliated utilities for resale. EUA
is in the process of dive sting its electric generation business.
Energy-Related Business
This business unit includes the following non-utility energy-related
subsidiaries.
- EUA Cogenex Corporation, one of the nation's premier energy
management companies with contracts nationwide and in Canada, is
our most active energy-related company.
- EUA Ocean State owns a 29.9% partnership interest in the Ocean
State Power generating station in northern Rhode Island, one of the
first and most successful non-utility generating plants in the
country.
- EUA Energy Investment Corporation is our vehicle for investing in
niche-type energy-related companies, including:
- EUA BIOTEN, EUA's investment in a general partnership which is
developing biomass-fueled generating units;
- EUA TransCapacity, EUA's investment in a limited partnership
which has developed and now markets services and computer
software enabling natural gas industry clients to connect,
communicate and coordinate with their trading partners via
electronic data interchange.
- Separation Technologies Inc., in which we own a 20% equity
interest, markets and installs its own proprietary equipment
for separating unburned carbon from coal fly-ash, enabling the
customer to sell the fly-ash to secondary markets and reburn
the carbon.
Corporate
The corporate business unit is made up of the System's parent company " Eastern
Utilities Associates" and EUA Service Corporation, which provides professional
and technical services to all EUA System companies.
Dear Fellow Shareholders,
1997 was truly a transition year for Eastern Utilities. We are active
participants in the rapid transition from the historic era of regulated
electric utility monopolies to a more competitive age, particularly in the
electric generation business.
We negotiated major settlement agreements at both the federal and state level
which defined our plans to bring the benefits of competition and immediate rate
reductions to our customers while preserving shareholder value by ensuring
recovery of past investments and commitments in generation resources, commonly
referred to as stranded costs.
To our shareholders (continued)
By year's end, each of these settlement agreements had been approved by the
respective regulatory bodies, thus removing much of the uncertainty inherent in
such a fundamental change to our core electric business. We look forward to
meeting the challenge of implementing these settlements during 1998.
In addition, the strategic moves we made in 1996 to return our EUA Cogenex
energy services subsidiary to profitability paid off in 1997 with Cogenex
showing a small profit for the year.
Consolidated net earnings were $38.0 million, or $1.86 per share, a 24%
improvement from 1996 net earnings of $30.6 million, or $1.50 per share,
despite the continued burden of supporting our 4% ownership interest in the
Millstone 3 nuclear unit in Connecticut which remained shut down throughout
1997. Internal generation of cash remained strong, providing in excess of 100%
of our cash construction needs during 1997. Cash flow per share for 1997 was
$5.85 and, coupled with our improving financial performance, enabled us to
maintain the dividend at its current annual rate of $1.66 per share in the
midst of fundamental changes in our core electric business.
Our success in dealing with restructuring, returning Cogenex to
profitability and improving financial performance were recognized by the
financial community. Your EUA shares provided you with a 65% total return for
1997, closing the year at a price of $26.25. This total return ranked fifth
nationwide according to the Edison Electric Institute 100 Index of investor-
owned electric utilities.
Core Electric Business Restructuring
While timing and details differ somewhat, the underlying basics of our
settlement agreements defining how we plan to implement competition in
Massachusetts and Rhode Island are similar. In Rhode Island, large industrial
customers of our Blackstone Valley Electric and Newport Electric distribution
subsidiaries were free to choose their electric supplier starting on July 1,
1997. Choice of generation supplier was opened to all Rhode Island customers
on January 1, 1998.
In Massachusetts, where our Eastern Edison distribution subsidiary
operates, legislation was enacted in November 1997 to set the start of retail
competition for all customers at March 1, 1998.
In addition to providing our distribution customers with choice to select
their electric supplier in the competitive market, we also agreed to implement
rate decreases in both states consistent with legislation and settlement
provisions.
Also, beginning in 1997 for our Rhode Island retail subsidiaries and in
1998 for Eastern Edison, distribution rates are subject to performance
standards. Our retail subsidiaries are rewarded or penalized based on their
ability to meet specified standards of safety, reliability and customer service.
We are pleased to report that both our Rhode Island utilities were rewarded
for their performance in 1997.
"Picture of Donald G. Pardus Chairman and Chief Executive Officer"
"Picture of John R. Stevens President and Chief Operating Officer"
"Note in Margin: "Shareholder value in top tier of utility stocks nationwide!""
"Caption: "Our successes in dealing with competition and improved financial
performance resulted in a 65% total return on EUA shares in 1997 - fifth
highest in the country. Chart depicting Total return to shareholders as
follows:
EUA 65%
S&P 500 Index 33%
EEI 100 Index 27%
S&P Electric Company Index 26%
The Federal Energy Regulatory Commission approved terms under which Montaup
Electric, our wholesale generation and transmission company, ended its all-
requirements electric supply agreements with Blackstone Valley Electric,
Eastern Edison and Newport Electric and its partial-requirements contracts with
two non-affiliated utilities. This approval was necessary to accommodate our
distribution customers' choice of electric supplier.
Under terms of our Massachusetts, Rhode Island and federal settlement
agreements, we agreed to divest ourselves of Montaup's entire generation
portfolio and to use the net proceeds of the divestiture to reduce the amount
of stranded costs billed to our distribution customers. In return, the
settlement agreements permit us to recover 100% of the net investment in
generating facilities, with a return, that we made under the prior regulatory
environment. Some of those investments may have otherwise been unrecoverable
"or stranded" in a competitive market. This 100% stranded cost recovery is
critical to the financial health of a competitive EUA.
The settlement agreements are more thoroughly discussed under the heading
Electric Utility Industry Restructuring Initiatives in Management's Discussion
and Analysis of Financial Condition and Review of Operations elsewhere in this
report.
After divesting its generation assets, Montaup will continue to provide
high voltage transmission service, transporting electricity from independent
generation sources on its way to ultimate consumers.
Our distribution utilities "Blackstone Valley Electric, Eastern Edison and
Newport Electric" remain regulated by the states in which they operate as
wires companies, and will continue to deliver electricity from a source of the
customer's choosing over our wires in our existing service territories. We'll
continue to provide our customers with the superior service reliability and
safety to which they are accustomed.
Divestiture of Generation Assets
We began marketing efforts to sell our 1,065 megawatts of owned and purchased
generating capacity, as well as two parcels of real estate suitable for future
power plant development, in July 1997. Based on early indications from
potential purchasers we anticipated an active auction market for our generation
portfolio.
By September, we had received preliminary indications of interest from a
number of potential purchasers. We set an early December deadline for
qualified entities to submit firm offers on all or a portion of the generation
assets owned by Montaup, as well as small diesel generation stations owned by
Newport Electric and a small hydroelectric unit owned by Blackstone Valley
Electric.
"Note in margin: "Essential to continued financial success of EUA.""
After carefully weighing the bids, we determined in early January of this
year that it would be in the best interests of the retail customers of our
electric utility subsidiaries to re-open the sale process for about 500
megawatts of our wholly- and jointly-owned generating capacity and 300
megawatts of power purchase contracts. By doing so, we believe we can benefit
from improved conditions for marketing the assets offered. We expect to have
firm offers in hand later this year. It will likely be late 1998 or early
1999 before we receive the regulatory approvals necessary to complete the
divestiture.
Energy-Related Businesses
EUA's position at the forefront of the transition to competition in 1997
required an enormous investment of resources and staff to accomplish a
balanced approach to competition. This major commitment will continue in
1998. This core business effort runs concurrent with the continued
development of our non-utility energy-related businesses.
Our EUA Ocean State subsidiary continues to be a solid performer,
contributing $4 million in earnings, or just under 20 cents per share in 1997.
Our 29.9% ownership share of Ocean State Power is not among the generation
assets being offered for sale.
EUA Cogenex Corporation, which provides energy efficiency products and
energy-management services throughout North America, experienced a significant
rebound in 1997. Average project size more than doubled, a higher percentage
of project proposals w ere closed, and Cogenex expanded its line of products
and services. At year's end, Cogenex's wholly-owned subsidiary, EUA Citizens
Conservation Services, which specializes in multi-family installations,
announced a major contract to install energy improvements for the Chicago
Housing Authority.
While progress was made in the development of our three start-up
energy-related subsidiaries, TransCapacity, BIOTEN and Separation
Technologies, Inc., this progress was below our expectations.
TransCapacity, our limited partnership which develops and provides computer
software for the natural gas industry, installed its first systems in late
1997. TransCapacity's systems enable gas pipeline companies to comply with
Federal Energy Regulatory Commission directives requiring electronic data
interchange capabilities. Delays in requiring compliance with these federal
mandates have been frustrating; 1998 will be critical to the future of
TransCapacity.
The process of testing the BIOTEN partnership's patented biomass-fired
generating unit in Tennessee continued in 1997 at a slower pace than originally
anticipated. In February 1998, the testing of the unit suffered a setback that
will delay the process for several months. Final testing is now expected in
mid-1998. It is clear that there is a global market for the environmental
benefits of the BIOTEN technology. BIOTEN's marketing efforts are geared to
capture a portion of this vast market.
"Note in margin: "Ocean State Power: one of the first and most successful
non-utility generating plants.""
Separation Technologies, Inc., which markets its proprietary high volume
fine-particle materials separation equipment with funding from our EUA Energy
Investment subsidiary, announced installations of its ash-recovery systems at
power plants in North Carolina and Florida - its first forays outside the
company's New England base. Separation Technologies equipment provides coal-
burning power plants with clean fly-ash, which plant owners can market to
concrete manufacturers, and recovers unburned carbon from the ash for use as a
fuel at the plant.
A different kind of company
EUA today is a far different company from the EUA of four or five years ago.
We've consolidated our management structure so we can react more quickly to
changing conditions. 1997 marked the fourth consecutive year in which we
reduced our workforce. Since 1993, our workforce has decreased by more than
18% and we will continue to look for opportunities to enhance efficiency.
These changes could not have happened without the dedication and commitment
of our staff, who continue to accomplish more with ever decreasing resources.
Staff reductions have not and will not impact on our ability to continue
to provide the customers of our distribution utilities with safe, reliable
electric service. In fact, we were able to provide important assistance in
January of this year when the largest ice storm in Maine's history devastated
the area served by Central Maine Power. Sixty of our lineworkers and
supervisory personnel with the necessary support equipment were among the first
support Central Maine Power received after the ice storm hit, and were among
the last to return home. Central Maine Power has been quick to come to our aid
in previous years; we were glad to reciprocate.
We'll meet the continuing challenges of competition
The early start of competition in Rhode Island and Massachusetts gives us a
head start in dealing with the most fundamental changes affecting the way
electric utilities have done business for more than a century.
Being ahead of the pack provides us the opportunity to work out more
advantageous conditions for recovery of generation-related investments made
under the prior regulatory framework which might be unrecoverable in a
competitive atmosphere (stranded investments) and for divestiture of our
generation assets which will provide us with an immediate cash infusion
enabling us to proceed with changes to our financial structure to better
reflect our conversion from electricity provider to electric service deliverer,
while at the same time reducing the amount of stranded costs billed to our
customers.
"Note in margin: "A responsibility embraced by every member of our EUA team!""
"Caption: "Our customers may now choose the source of the electricity we will
continue to deliver. We pledge to continue our high standards for the
service we provide." with pictures of EUA customers."
We said a year ago that EUA was continually being challenged to be flexible
and innovative. That didn't change in 1997. And 1998 will be another year of
transition. Being a leader in the move to competition means there are no
comfortable precedents for us to follow.
Prior to the start of the competitive revolution, utilities were able to
predict with some accuracy where they would be several years ahead. The need
to plan energy supply for the population of their service territories required
such foresight. Today's utility world is very different from that of only a
few years ago. The only sure prediction for tomorrow's utility is that there
will be even more challenges than there have been to this point. We will
continue to adapt to conditions and to meet those new challenges.
Our mission remains clear
Our overriding mission during this period of transition remains clear -
maximize shareholder value! We have in place a dedicated team of employees who
are committed to accomplishing this mission while continuing to provide our
customers with the superior service reliability and safety which over the
years have become synonymous with Eastern Utilities.
On a personal note . . .
We are saddened by the death last year of John F. G. Eichorn, Jr., retired
Chairman of the Board of Trustees and Chief Executive Officer. Mr. Eichorn led
Eastern Utilities Associates through the oil embargo crisis of the early 1970s
and the tumult surrounding construction of the Seabrook nuclear power
generation station in the '80s.
We will miss his wise counsel.
"Note in margin: "Theres no change in our mission, despite major changes
to our industry.""
/s/ Donald G. Pardus
Donald G. Pardus
Chairman and Chief Executive Officer
/s/ John R. Stevens
John R. Stevens
President and Chief Operating Officer
March 9, 1998
Management's Discussion and Analysis of
Financial Condition and Review of Operations
<TABLE>
Selected Consolidated Financial Data
<CAPTION>
Years Ended December 31,
(In thousands except Common Share Data) 1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating Revenues $ 568,513 $ 527,068 $ 563,363 $ 564,278 $ 566,477
Operating Income<F1> 58,807 55,841 71,728 73,795 75,649
Consolidated Net Earnings<F1> 37,960 30,614 32,626 47,370 44,931
BALANCE SHEET DATA:
Plant in Service 1,079,361 1,067,056 1,037,662 1,020,859 1,016,453
Construction Work in Progress 5,538 3,839 7,570 8,389 8,728
Gross Utility Plant 1,084,899 1,070,895 1,045,232 1,029,248 1,025,181
Accumulated Depreciation and
Amortization 376,722 350,816 324,146 304,034 296,995
Net Utility Plant 708,177 720,079 721,086 725,214 728,186
Total Assets 1,270,752 1,257,029 1,206,130 1,234,049 1,203,137
CAPITALIZATION:
Long-Term Debt - Net 332,802 406,337 434,871 455,412 496,816
Redeemable Preferred Stock - Net 27,612 27,035 26,255 25,390 25,053
Non-Redeemable Preferred Stock - Net 6,900 6,900 6,900 6,900 6,900
Common Equity 373,467 371,813 375,229 365,443 333,165
Total Capitalization 740,781 812,085 843,255 853,145 861,934
Short-Term Debt 61,484 51,848 39,540 31,678 37,168
COMMON SHARE DATA:
Consolidated Basic and Diluted Earnings
per Average Common Share<F1> $ 1.86 $ 1.50 $ 1.61 $ 2.41 $ 2.44
Average Number of Shares Outstanding 20,435,997 20,436,217 20,238,961 19,671,970 18,391,147
Return on Average Common Equity 10.2% 8.2% 8.8% 13.6% 15.0%
Market Price - High 26 5/8 24 1/4 25 27 3/8 29 7/8
- Low 16 3/8 14 3/4 21 1/2 21 3/8 23 7/8
- Year-End 26 1/4 17 3/8 23 5/8 22 28
Dividends Paid per Share $ 1.66 $ 1.645 $ 1.585 $ 1.515 $ 1.42
<FN>
<F1> See Management's Discussion and Analysis of Financial Condition and Results
of Operations for details of one-time impacts to earnings.
</FN>
</TABLE>
Management's Discussion and Analysis of
Financial Condition and Review of Operations
Overview
Consolidated net earnings for 1997 increased $7.3 million to $38.0 million, or
$1.86 per share, on revenues of $568.5 million, a 24% increase over 1996
earnings of $30.6 million, or $1.50 per share, on revenues of $527.1 million.
The results for both years include one-time earnings impacts, discussed below
and listed in the following table.
1996
1997 Net Earnings Earnings
Net Earnings Earnings (Loss) (Loss)
(000's) Per Share (000's) Per Share
Core Electric Business $ 35,188 $ 1.73 $ 37,595 $ 1.84
Energy Related Business 49 0.00 (2,738) (0.13)
Corporate 1,243 0.06 (571) (0.03)
From Operations $ 36,480 $ 1.79 $ 34,286 $ 1.68
One-Time Impacts:
Joint Venture Termination 1,480 0.07
Cogenex Charge (3,672) (0.18)
Consolidated $ 37,960 $ 1.86 $ 30,614 $ 1.50
Major impacts on earnings by business unit are described in the following
paragraphs.
Termination of Power Marketing Joint Venture
In the third quarter of 1997, EUA announced the termination of a power
marketing joint venture with an affiliate of Duke Energy Corporation, the
establishment of contingency reserves related to certain of its energy-related
business activities and other expense reserves. Collectively, these actions
resulted in a net after-tax gain of $1.5 million in third quarter 1997
earnings.
1996 EUA Cogenex Charge to Earnings
Difficulties in turning project proposals into signed contracts, the virtual
elimination of utility-sponsored demand side management programs and
termination of two joint ventures had hampered EUA Cogenex Corporation (EUA
Cogenex) 1996 earnings. As a result, a write-off of certain start-up costs of
abandoned joint ventures, and expenses related to certain project proposals
along with a reduction in carrying value of certain ongoing projects
necessitated by market conditions resulted in a $5.9 million pre-tax ($3.7
million after-tax or 18 cents per share) charge to earnings in the second
quarter of 1996.
Net Earnings and Earnings Per Share by business unit for 1997 and 1996 were as
follows:
"Caption: "Every EUA employee remains dedicated to continuing to capitalize
on competitive opportunities and overcoming any obstacles that could detract
from our performance." with pictures of EUA employees"
Operating Revenues
The following table sets forth estimates of the factors which contributed to
the change in Operating Revenues from 1995 through 1997:
Increase (Decrease)
From Prior Years
($ in millions) 1997 1996
Operating Revenue change attributable to:
Core Electric Business:
Purchased Power Recovery $ 1.3 $ (7.0)
Recovery of Fuel Costs 12.1 0.2
Recovery of C&LM Expenses 3.2 (5.4)
Unit Contracts and Sales to NEPOOL 6.3 0.6
Kilowatthour (kWh) Sales and Other 13.0 (1.5)
Energy Related Business:
EUA Cogenex and EUA Energy Investment 5.5 (23.2)
Total Operating Revenues $ 41.4 $ (36.3)
Core Electric Business: The revenues attributable to Purchased Power
Recovery reflect our retail companies' recovery of purchased power capacity
costs. Revenues attributable to Recovery of Fuel Costs and conservation and
load management (C&LM) expenses result from the operation of adjustment
clauses. The change in such revenues reflects corresponding underlying changes
in costs.
Revenues attributable to Unit Contracts and sales to the New England Power
Pool (NEPOOL) reflect energy revenues from such short-term contracts and
interchange sales with NEPOOL. The change in revenues associated with kWh
Sales and Other reflects the effect of kWh sales and demand billings on base
revenues, Consumer Price Index base rate increases effective January 1, 1997
for Blackstone and Newport of 1.9% and 2.2%, respectively, and changes in other
operating revenues, including off-system contract demand sales.
Energy Related Business: EUA Cogenex revenues, which account for the
majority of the Energy Related Business Unit revenues, increased by
approximately $5.0 million in 1997. This increase was due primarily to
increased revenue of EUA Citizens, Cogenex-Canada and the Cogenex partnerships
aggregating $10.7 million. Project sales at the Cogenex Division also
increased. Offsetting these increases somewhat were decreased revenues of EUA
Day, Renova (formerly EUA Nova) and Cogenex-West (formerly EUA Highland)
aggregating $5.8 million. Also impacting Energy Related Business revenues
were increased revenues of EUA TransCapacity of approximately $500,000.
EUA Cogenex revenues decreased by $23.2 million in 1996. This decrease
was due primarily to lower project sales of approximately $18.8 million, the
absence of cogeneration revenues which amounted to $5.5 million in 1995,
resulting from EUA Cogenex's decision to discontinue cogeneration operations
in September 1995, and decreased Renova revenues of $7.9 million. These
decreases were offset somewhat by increased revenues of Cogenex-West, EUA
Citizens and EUA Day aggregating $8.8 million.
Core Electric Business kWh Sales
Primary kWh sales of electricity by EUA's Core Electric Business Unit increased
1.2% in 1997 compared to the prior year. This change was led by increases of
2.4% in the residential and industrial customer classes. Total energy sales
increased 4.6% in 1997, due mainly to increased sales to NEPOOL and increased
short-term unit contract energy sales. These NEPOOL interchange and short-term
unit contract sales essentially recover fuel costs and have little or no
earnings impacts.
Primary kWh sales of electricity increased by 1.1% in 1996 compared to 1995,
led by a 2.6% gain in sales to our residential customers. Total energy sales
including NEPOOL interchange and short-term unit contract sales increased by
2.0%.
Expenses
Fuel and Purchased Power: The EUA System's most significant expense items
continue to be fuel and purchased power expenses of our Core Electric Business
which together comprised about 45% of total operating expenses in 1997.
Percentage changes in kWh Sales by class of customer for the past two years
were as follows:
Percent Increase (Decrease) from Prior Year
1997 1996
Residential 2.4 2.6
Commercial (0.7) (0.5)
Industrial 2.4 0.1
Other Electric Utilities (9.0) 15.7
Other 7.4 2.6
Total Primary Sales 1.2 1.1
Losses and Company Use 5.1 (8.6)
Total System Requirements 1.4 0.7
Unit Contracts 33.7 16.2
Total Energy Sales 4.6 2.0
Fuel expense of the Core Electric Business increased by approximately $18.6
million or 20.1% in 1997, due primarily to a 4.6% increase in total energy
generated and purchased. Outages of nuclear units in 1997 contributed to a
greater dependence on higher cost fossil fuels for energy requirements,
resulting in an increase in average fuel costs of 16.3% in 1997. The increase
of $1.3 million or 1.4% in 1996, was due primarily to a 2.0% increase in total
energy generated and purchased.
Purchased Power demand expense increased approximately $700,000 or less
than 1% in 1997. This change is primarily due to increased billings from the
Pilgrim and Maine Yankee nuclear units and Potter #2 fossil unit aggregating
$6.5 million. These increases were offset by decreased billings from
Connecticut Yankee and Ocean State Power (OSP) of approximately $3.0 million
and $2.8 million, respectively. Purchased Power demand expense decreased $6.8
million or 5.4% in 1996. The decrease is due primarily to the impact of lower
billings from the Pilgrim nuclear unit of approximately $4.2 million, which
included a prior period refund, and decreased billings from OSP and Maine
Yankee aggregating $2.5 million.
Other Operation and Maintenance (O&M): O&M expenses for 1997 increased by
$14.4 million or 8.0% compared to 1996. Total O&M expenses are comprised of
three components: Direct Controllable, Indirect and Energy Related.
O&M expenses by component for 1997, 1996 and 1995 were as follows:
($ in millions) 1997 1996 1995
Direct Controllable $ 89.1 $ 87.5 $ 83.4
Indirect 51.1 36.7 41.3
Energy Related 52.7 55.7 62.7
Total O&M $ 192.9 $ 179.9 $ 187.4
Direct Controllable expenses of our Core Electric and Corporate Business units
represent 45.9% of total 1997 O&M expenses and include expense items such as
salaries, fringe benefits, insurance and maintenance. In 1997, direct
expenses increased approximately $1.6 million compared to 1996, primarily due
to increased legal expenses in 1997. In 1996 direct expenses increased by
$4.1 million due primarily to incremental storm expenses related to an unusual
number of severe storms which struck our retail service territories in that
year, costs related to the electric industry restructuring activities and
increased assessments by the Federal Energy Regulatory Commission (FERC).
Indirect expenses include items over which we have limited short-term control.
Indirects include such expense items as O&M expenses related to Montaup
Electric Company's (Montaup) joint ownership interests in generating facilities
such as Seabrook I and Millstone 3 (see Note H of Notes to Consolidated
Financial Statements for other jointly-owned units), power contracts where
transmission rental fees are fix ed and C&LM expenses that are fully recovered
in revenues. Indirect expenses increased by approximately $14.4 million in
1997. This change was primarily due to increased jointly owned unit expense of
approximately $9.0 million, of which approximately $5.0 million is related to
the Millstone 3 outage and the remainder is due to increased expenses related
to the scheduled maintenance outages at the Canal and Seabrook units. Also
impacting the change were increased C&LM expenses of approximately $3.3
million, approximately $1.2 million of transmission expenses related to new
transmission tariffs implemented by FERC in 1997 to accommodate utility
industry restructuring, and increased pension related expenses of approximately
$700,000. Indirect expenses decreased by $4.6 million in 1996. The decrease
included lower C&LM and Montaup power contract expenses aggregating $6.4
million, somewhat offset by jointly owned unit expenses, which included
incremental outage costs of Millstone 3.
The Energy Related component relates to O&M expenses of our Energy Related
Business unit where changes are tied to changes in business activity. EUA
Cogenex continues to be the most active of our Energy Related businesses and
incurred 92% of the total O&M expenses of this business unit in 1997. Energy
Related expenses decreased by approximately $3.0 million in 1997. This
decrease was due primarily to decreased employee levels and other ongoing cost
control efforts of the EUA Cogenex Division of approximately $2.2 million,
decreased expenses of Renova of approximately $1.6 million, resulting from
decreased operating activity, offset by increased expenses of Cogenex-West of
approximately $300,000 as a result of increased marketing activity . Energy
Related expenses decreased by $7.0 million in 1996. The change included
decreases in EUA Cogenex sales-related expenses of $10.8 million, decreased
Renova costs of goods sold of $5.6 million and the absence of cogeneration
related expenses , which amounted to $4.6 million in 1995. EUA Energy
Investment Corporation (EUA Energy Investment) expenses decreased by $400,000
in 1996. These decreases were offset somewhat by the June 1996 EUA Cogenex
charge of $5.9 million and increased expenses of Cogenex-West and EUA Citizens
aggregating $7.9 million.
Voluntary Retirement Incentives: In June 1997, an early retirement offer was
accepted by a group of nine employees who were eligible for but not offered a
Voluntary Retirement Incentive offer completed in 1995. The pre-tax cost of
the 1997 offer, recorded in the second quarter, was approximately $1.4 million.
The 1995 Voluntary Retirement Incentive resulted in a pre-tax charge of $4.5
million.
"Note in margin: "Based on our 4% ownership share in the unit.""
Depreciation and Amortization: Depreciation and Amortization expense
increased by approximately $1.5 million in 1997 due primarily to higher
depreciable plant balances at our Core Electric companies and a $500,000
increase in EUA Cogenex depreciation directly related to increased project
revenue. Depreciation and Amortization expense in 1996 was relatively
unchanged from the 1995 level.
Income Taxes: EUA files a consolidated federal income tax return for the
EUA System. The composite federal and state effective income tax rate for 1997
was relatively unchanged at 35.8% versus to 35.1% in 1996.
Other Income (Deductions) - Net: Other Income and (Deductions) - Net
increased approximately $5.9 million in 1997. This was primarily due to the
net positive impact of the power marketing joint venture termination in 1997,
increased interest income related to the favorable resolution of a
Massachusetts corporate income tax dispute in 1997, and the impact of changes
to the EUA Cogenex pension and post-retirement welfare benefit plans offset by
gains recorded in 1996 from the sale of Seabrook II equipment jointly owned by
Montaup. Other Income and (Deductions) - Net increased $ 2.5 million in 1996.
Approximately $1.7 million of this increase was due to the sale of Seabrook II
equipment jointly owned by Montaup. In addition, an increase in EUA Cogenex
interest income was partially offset by the impact of the write-off of EUA
Cogenex's joint venture start-up costs, included in the June 1996 $5.9 million
charge.
Interest Charges: Net interest charges for 1997 were relatively unchanged
from the 1996 level. Decreased long-term debt interest resulting from normal
cash sinking fund payments was offset by higher interest expense related to
increased short-term debt and decreased capitalized interest by EUA Cogenex.
Net interest charges for 1996 decreased approximately $2.3 million from 1995
amounts. This decrease was primarily due to the December 1995 maturity of $25
million of 9-9 1/4% Unsecured Medium Term Notes and $10 million of 8.9% First
Mortgage and Collateral Trust Bonds of Eastern Edison Company (Eastern Edison),
offset somewhat by a decrease in capitalized interest by EUA Cogenex and higher
interest expense related to increased short-term debt.
Financial Condition and Liquidity: The EUA System's need for permanent capital
is primarily related to investments in facilities required to meet the needs of
its existing and future customers. These needs will diminish to the extent
that EUA divests all or a portion of its generation assets.
"Note in margin: "Internal generation of cash remains strong!""
Core Electric Business: For 1997, 1996 and 1995, Core Electric Business cash
construction expenditures were $21.9 million, $33.3 million, and $31.5 million,
respectively.
Internally generated funds available after the payment of dividends supplied
approximately 133%, 118%, and 210% of these cash construction requirements in
1997, 1996 and 1995, respectively. Various laws, regulations and contract
provisions limit the use of EUA's internally generated funds such that the
funds generated by one subsidiary are not generally available to fund the
operations of another subsidiary.
Cash construction expenditures of the Core Electric Business for 1998, 1999 and
2000 are estimated to be approximately $29.7 million, $25.2 million and $21.9
million, respectively, and are expected to be financed with internally
generated funds.
In addition to construction expenditures, projected requirements for scheduled
cash sinking fund payments and mandatory redemption of securities of the Core
Electric Business for 1998 through 2002 are $62.2 million, $11.6 million, $2.3
million, $4.1 million and $38.4 million, respectively.
Energy Related Business: Capital expenditures of our Energy Related Business
amounted to $51.9 million, $28.1 million and $44.7 million, in 1997, 1996 and
1995, respectively. Internally generated funds supplied 88%, 72% and 69%, of
cash capital requirements in 1997, 1996, and 1995, respectively. Estimated
capital expenditures of the Energy Related Business are $56.3 million, $67.2
million, and $69.5 million in 1998, 1999 and 2000, respectively. Internally
generated funds are expected to supply approximately 110% of 1998 estimated
capital requirements.
In addition to capital expenditures and energy related investments, projected
requirements for scheduled cash sinking fund payments and mandatory redemption
of securities of the Energy Related Business are $9.2 million in 1998 and 1999,
$59.2 million in 2000, $9.2 million in 2001 and $6.0 million in 2002.
On September 30, 1997, EUA Cogenex used short-term borrowings to fund the
maturity of $15 million of 7.22% Unsecured Notes.
Corporate: Construction activity of the Corporate Business unit is minimal.
Projected requirements for scheduled cash sinking fund payments for the
corporate operations for each of the five years following 1997 are $1.1
million.
Short-Term Lines of Credit: In July 1997, several EUA System companies
entered into a three-year revolving credit agreement allowing for borrowings
in aggregate of up to $120 million. As of December 31, 1997, various financial
institutions have committed up to $75 million under the revolving credit
facility.
Year-End Short-Term Debt outstanding by business unit:
($ in thousands) 1997 1996
Core Electric Business $ 7,075 $ 3,670
Energy Related Business 44,609 24,341
Corporate 9,800 23,837
Total $ 61,484 $ 51,848
EUA expects to repay the outstanding balances of short-term indebtedness
through internally generated funds.
Energy Related Businesses
Net Earnings and Earnings Per Share contributions of EUA's Energy Related
Businesses for 1997 and 1996 were as follows:
EUA Cogenex: EUA Cogenex provides energy efficiency products and energy
management services throughout North America. Strategic moves made in 1996
returned EUA Cogenex to profitability in 1997. EUA Cogenex's earnings
increased approximately $3.1 million in 1997 due largely to 1996 staff
reductions, the refocusing of its national sales force and benefits resulting
from changes to pension and post-retirement welfare plans in 1997.
EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which
developed and operate Units I and II of OSP, twin 250-megawatt gas-fired
generating units in northern Rhode Island. Both units have provided a premium
return since their respective in-service dates of December 31, 1990, and
October 1, 1991. The slight change in EUA Ocean State earnings contribution
was due to a lower investment base billed by the project in 1997.
EUA Energy Investment: EUA Energy Investment was organized to seek out
investments in energy related businesses. The change in Energy Investment's
earnings contribution was due to decreased losses at EUA TransCapacity, offset
by increased development costs at EUA BIOTEN.
1997 1996
Net Earnings Earnings Net Earnings Earnings
(Loss) (Loss) (Loss) (Loss)
(000's) Per Share (000's) Per Share
EUA Cogenex $ 202 $ 0.01 $ (2,850)(1) $(0.14)(1)
EUA Ocean State 3,967 0.19 4,152 0.20
EUA Energy Investment (3,741) (0.18) (3,990) (0.19)
EUA Energy Services (354) (0.02) (50) (0.00)
EUA Telecommunications (25) (0.00)
From Operations 49 0.00 (2,738) (0.13)
Cogenex Charge (3,672) (0.18)
Energy Related Business $ 49 $ 0.00 $(6,410) $(0.31)
(1) Excludes June 1996, after-tax charge to earnings of $3.7 million or
18 cents per share.
EUA Energy Services: The loss generated by EUA Energy Services was related to
startup costs of the now terminated power marketing joint venture with an
affiliate of Duke Energy Corporation.
EUA Telecommunications: The small loss generated by EUA Telecommunications is
related to startup costs of this subsidiary in 1997.
Electric Utility Industry Restructuring Unbundled Services: The electric
utility industry in both Massachusetts and Rhode Island, the states in
which EUA provides electric services, is transitioning from a traditional
rate regulated environment to a competitive marketplace. Traditional electric
utility services - generation, transmission and distribution - have been
unbundled into separate and distinct services. The generation, or supply,
function is now competitive with customers able to choose their own
electricity supplier at market prices. The transmission and
distribution functions remain regulated services. The local distribution
company is responsible for providing distribution services to the ultimate
electricity consumer within its franchised service territory and t he
transmission company is required to provide open access, non-discriminatory
transmission services to generation or supply companies.
Stranded Costs: Stranded costs represent prudently incurred costs of
generation which are now above their current economic value. In both
Massachusetts and Rhode Island (see discussions below) stranded costs have been
defined to include items such as above market net investments in generation
assets, generation related regulatory assets, nuclear decommissioning and above
market commitments under current power purchase contracts. A December 19, 1997
order from FERC provides Montaup, the EUA System's generation company, with
full recovery of its stranded costs. Stranded costs are recovered via a
Contract Termination Charge (CTC) under a contract termination agreement which
replaced the all-requirements contracts formerly in force between Montaup and
its retail affiliates. In its order, FERC approved settlement agreements
between Montaup, its retail affiliates and consumer representatives in
Massachusetts and Rhode Island. Both states' regulatory bodies have approved
retail settlements in accordance with enabling state legislation. At December
31, 1997 Montaup estimated its stranded costs, including unmitigated investment
in owned generation, generation related regulatory assets, above-market
purchase power commitments, nuclear decommissioning and transition expenses to
be approximately $1 billion on a present value basis. This estimate is subject
to significant uncertainties including the future market price of electricity.
See "Divestiture" below for a discussion of stranded cost mitigation.
"Note in margin: "The key to an open competitive market among electricity
providers.""
Rhode Island - Retail: On August 7, 1996, the Governor of Rhode Island signed
into law the Utility Restructuring Act of 1996 (URA). The URA provides for
customer choice of electricity supplier in several phases commencing July 1,
1997 for certain customers and culminating with choice for all customers by
July 1, 1998, or sooner. Under the URA, the local distribution company retains
the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who do not choose an alternative supplier, the local distribution company must
arrange for standard offer service. Distribution companies are providers of
last resort service for customers who are unable to obtain their own supply.
The URA provides for full recovery of stranded costs, through a
non-bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The costs of net, above-market generation assets and
regulatory assets will be recovered, with a return, through a fixed component
of the transition charge from January 1, 1998, through December 31, 2009. A
variable component of the transition charge will recover, on a reconciling
basis, among other things, nuclear decommissioning and above market purchased
power commitments from January 1, 1998, through the life of the respective unit
or contract. The URA also provides for commitments to demand side management
initiatives and renewables, low-income customer protections, divestiture of at
least 15% of owned non-nuclear generating units as a valuation basis for
mitigation of stranded cost recovery, and performance-based ratemaking (PBR)
standards for electric distribution companies to be in effect
until the end of 1998. These performance-based standards provide for a 6%
minimum and an approximate 12% maximum allowed return on equity for Blackstone
Valley Electric Company (Blackstone) and Newport Electric Corporation
(Newport), EUA's Rhode Island Distribution Companies (R.I. Distribution
Companies). In addition, the URA provides for adjustments to electric
distribution companies' base rates using the prior year's Consumer Price Index
for 1997 and 1998 and other performance factors. Under this provision of the
law, rates were increased 1.3% for customers of both Blackstone and Newport
effective January 1, 1998.
In February 1997, Blackstone, Newport and Montaup reached a settlement in
principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the Rhode Island Public Utilities Commission (RIPUC),
outlining the terms of the settlement. The settlement was submitted to the
RIPUC in two separate filings which were approved on April 21, 1997 and
December 17, 1997, respectively. In addition to complying with the URA, the
settlement, similar in many respects to the settlement negotiated in
Massachusetts, described below, provided for a 4% rate reduction for Newport's
customers and a 13% rate reduction for Blackstone's customers effective
January 1, 1998, amendments to Blackstone and Newport power contracts with
Montaup to replace all-requirements provisions with a CTC concurrent with
retail access and the filing of a plan to divest all of Montaup's generating
assets. The net proceeds of the divestiture will be used to mitigate the
amount of Montaup's stranded costs to be recovered through the CTC. See
"Divestiture" below for a discussion of Montaup's divestiture process.
On December 17, 1997, the RIPUC approved a retail settlement which included
a distribution rate freeze through December 31, 2000, except for any temporary
credit or surcharge resulting from PBR implementation or the standard offer
reconciliation, and retail access for all customers commencing January 1, 1998.
In addition to the approval of wholesale power contract amendments by FERC,
received on December 19, 1997 (See "FERC -Wholesale" below), any disposition of
generation assets resulting from the agreements or the URA would also require
the approval of the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935.
Massachusetts - Retail: On December 23, 1996, Eastern Edison and Montaup
reached an agreement in principle with the Attorney General of Massachusetts
and the Massachusetts Department of Energy Resources (MADOER) and filed a MOU
with the Massachusetts Department of Telecommunications and Energy (DTE)
(formerly the Department of Public Utilities) outlining the terms of a plan,
similar in many aspects to the URA, which would allow retail customers to
choose their supplier of electricity in 1998 an d provide Eastern Edison and
Montaup full recovery of stranded costs. On May 16, 1997 an Offer of
Settlement was filed with the DTE.
The Offer of Settlement provided all of Eastern Edison's customers the ability
to choose an alternative supplier of electricity beginning as soon as January
1, 1998. Until a customer chooses an alternative supplier, that customer would
receive standard offer service which would be priced to guarantee at least a
10% reduction in electricity rates. Eastern Edison would be required to
arrange for standard offer service through December 31, 2004 and would purchase
power for standard offer service from suppliers through a competitive bidding
process. Montaup has guaranteed standard offer supply at a fixed price
schedule for the duration of the standard offer period. For competitive
suppliers to be eligible to provide supplies for standard offer service, their
prices must be competitive with the fixed prices guaranteed by Montaup. In the
event that some, or all, of the standard offer requirement is not awarded to
competitive suppliers, Montaup has an obligation to provide such requirement at
the indicated fixed price schedule, so called backstop service. This backstop
service will be assigned proportionately to purchasers of Montaup's generating
capacity. The agreement is also designed to achieve full divestiture of
Montaup's generating assets via implementation of a plan, that would require
(1) functional separation by Montaup of its generating and transmission
businesses, and (2) full market valuation and sale of all non-nuclear
generating assets through an auction or equivalent process.
"Note in margin "Rhode Island leads the way to competition...""
On March 1, 1998, concurrent with retail choice in Massachusetts, Montaup's
FERC-approved, all-requirements wholesale contract with Eastern Edison was
terminated. In its place, Montaup is billing Eastern Edison a CTC designed to
recover, among other things, Montaup's stranded costs. Eastern Edison recovers
the CTC through a non-bypassable transition access charge to all of its
distribution customers. The transition access charge will be reduced by the
fair market value of Montaup's generating assets as determined by selling,
spinning off, or otherwise disposing of such generating facilities. See
"Divestiture" below.
Embedded costs associated with generating plants and regulatory assets are
recovered, with a return, over a period of twelve years ending December 31,
2009. Purchased power contracts and nuclear decommissioning costs are
recovered as incurred over the life of those obligations, a period expected to
extend beyond twelve years. The initial transition access charge is set at
3.04 cents per kWh through December 31, 2000, and is expected to decline
thereafter.
The agreement also establishes a performance component for Eastern Edison,
incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates are frozen until December 31,
2000. Subsequent to the commencement of retail choice, Eastern Edison's annual
return on equity is subject to a floor of 6% and a ceiling of 11.75%.
On November 25, 1997, the Governor of Massachusetts signed the Electric
Industry Restructuring Act (the Act) into law. The Act directed the DTE to
require electric companies to accommodate retail access to generation services
and choice of supplier by March 1, 1998 and to require electric companies to
file restructuring plans to do so. The Act also provides for a 10% reduction
in electric rates commencing March 1, 1998 and an additional 5% reduction,
adjusted for inflation, commencing September 1, 1999. The additional 5%
reduction may be accomplished with benefits from asset divestiture and/or
securitization.
On December 23, 1997, the DTE approved the Settlement as being in substantial
compliance with the Act. Retail access commenced on March 1, 1998 for Eastern
Edison's retail customers.
"Note in margin: "...followed closely by Massachusetts""
In January 1998, several parties filed motions for reconsideration of Eastern
Edison's approved settlement agreement and motions to extend the judicial
appeal period with the DTE. The motions for reconsideration claim that
provisions of the approved plan involving consumer rates, cost recovery,
energy efficiency and reliability do not meet standards set forth in the Act.
The DTE denied one party's motions and that party has appealed the DTE's
ruling to the Massachusetts Supreme Judicial Court. Management cannot predict
the ultimate outcome of the pending motions for reconsideration, or judicial
appeal.
The Office of the Attorney General has certified a referendum petition to
repeal the Act as a matter appropriate for a referendum initiative. A petition
was filed with the Election Division of the Office of the Secretary of State in
February 1998. A question on repealing the Act will be presented to voters on
the November 1998 ballot. EUA and the electric industry in Massachusetts will
actively oppose repeal. Management cannot predict the outcome of the November
ballot question.
FERC - Wholesale: On May 1, 1997, Montaup and the R.I. Distribution Companies
jointly filed amendments to their FERC-approved all-requirements power
contracts. The filing included a calculation for a CTC to recover stranded
costs and a provision for standard offer service for resale to retail customers
who do not choose an alternate generation supplier as discussed under
"Massachusetts-Retail" above. These provisions replaced the services offered
by the all-requirements contracts upon full retail access pursuant to the URA.
The filing also included hold harmless provisions for Montaup's other wholesale
customers and for retail customers of the R.I. Distribution Companies and lost
revenue provisions, which allow for recovery of any of Montaup's lost revenues
for the period from the initial phases of retail access in Rhode Island through
completion of Montaup's divestiture process. This filing allowed the R.I.
Distribution Companies to implement on July 1, 1997, the phase-in provisions of
the URA and prevented any cross-subsidies by their retail customers who were
excluded from the groups of customers given retail choice prior to January 1,
1998 and by Montaup's other customers.
On May 30, 1997, elements of the Massachusetts Settlement Agreement, including
the CTC calculation, which fall under the jurisdiction of FERC were filed with
FERC.
The May 1st and May 30th filings were consolidated by FERC and on October 29,
1997, settlement agreements among Montaup, its affiliated and non-affiliated
customers, the Massachusetts Attorney General, the MADOER, the RIDIV and RIPUC
were submitted for FERC approval. These settlements represent a comprehensive
resolution of federal/wholesale issues of electric utility industry
restructuring based on the settlement agreements in Massachusetts and Rhode
Island. FERC approved the settlements on December 19, 1997, accommodating
retail choice for EUA's retail customers in Massachusetts and Rhode Island.
"Note in margin: "We chose to negotiate rather than litigate""
Divestiture: Montaup began marketing its portfolio of generation assets in
July 1997, and subsequently received bids from a number of potential
purchasers. On January 23, 1998, based on a review of the offers and
discussions with potential purchasers, Montaup announced that it was reopening
the sales process on the majority of its generating assets. The process is
expected to require four to six months to execute a purchase and sale
agreement. The net proceeds of the sale, as defined in the settlement
agreements, will be used to mitigate Montaup's CTC to its retail affiliates via
a Residual Value Credit (RVC). The RVC will reduce the fixed component of the
CTC for the net proceeds, with a return, in equal annual amounts over the
period commencing on the date the RVC is implemented through December 31, 2009.
Subject to regulatory approvals, Montaup anticipates the sale will be completed
in early 1999.
Accounting Issues: Historically, electric rates have been designed to recover
a utility's full cost of providing electric service including recovery of
investment in plant assets. Also, in a regulated environment, electric
utilities are subject to certain accounting rules that are not applicable to
other industries. These accounting rules allow regulated companies, in
appropriate circumstances, to establish regulatory assets and liabilities,
which defer the current financial impact of certain costs that are expected to
be recovered in future rates. The SEC has raised issues concerning the
continued applicability of these standards with certain other electric
utilities in other states facing restructuring.
In July 1997, the Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) reached a consensus regarding certain issues raised related
to the application of Statement of Financial Accounting Standards No. 71
(FAS71), "Accounting for the Effects of Certain Types of Regulation." The EITF
determined that when sufficient detail is available for an enterprise to
reasonably determine, from legislation and enabling rate orders, how the
transition plan will affect the separable portion of its business being
deregulated, the enterprise should discontinue the application of FAS71 to that
deregulated portion of its business. The EITF also concluded that utilities
can continue to carry previously recorded regulatory assets on t heir balance
sheet if regulators have guaranteed a regulated cash flow stream to recover the
cost of those assets.
In light of approved restructuring settlement agreements and restructuring
legislation in both Massachusetts and Rhode Island, EUA has determined that
Montaup no longer will apply the provisions for FAS71 to the generation portion
of its business. Due to the recoverability of regulatory assets granted in the
approved restructuring plans, EUA believes that the discontinuation of FAS71
for the generation portion of Montaup's business will not have a material
impact on EUA's results of operation or financial condition. EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.
In addition, if legislative or regulatory changes and/or competition result in
electric rates which do not fully recover a company's costs, a write-down of
plant assets could be required pursuant to Financial Accounting Standard No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." EUA does not anticipate any write-down of plant
assets as a result of approved restructuring plans or enacted legislation at
this time.
Environmental Matters
EUA's Core Electric Business subsidiaries and other companies owning generating
units from which power is obtained are subject, like other electric utilities,
to environmental and land use regulations at the federal, state and local
levels. The federal Environmental Protection Agency (EPA), and certain state
and local authorities, have jurisdiction over releases of pollutants,
contaminants and hazardous substances into the environment and have broad
authority to set rules and regulations in connection therewith, such as the
Clean Air Act Amendments of 1990, which could require installation of pollution
control devices and remedial actions. In 1994, EUA instituted an environmental
audit program to ensure compliance with environmental laws and regulations and
to identify and reduce liability with respect to those requirements.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by such authorities. The EUA System
typically provides for the disposal of such substances through licensed
contractors, but statutory provisions generally impose potential joint and
several responsibility on the generators of the wastes for clean-up costs.
Subsidiaries of EUA have been notified with respect to a number of sites where
they may be responsible for such costs, including sites where they may have
joint and several liability with other responsible parties. It is the policy
of the EUA System companies to notify liability insurers and to initiate
claims. However, EUA is unable to predict whether liability, if any, will be
assumed by, or can be enforced against, insurance carriers in these matters.
As of December 31, 1997, the EUA System had incurred costs of approximately
$6.7 million in connection with these sites. These amounts have been financed
primarily by internally generated cash. The EUA System is currently amortizing
substantially all of its incurred costs over a five-year period consistent with
prior regulatory recovery periods and is recovering certain of those costs in
rates.
EUA estimates that additional costs of up to $1.3 million may be incurred at
these sites through 1998 by its subsidiaries. Estimates beyond 1998 cannot be
made since site studies, which are the basis of these estimates, have not been
completed.
"Note in margin: "Program is an essential element in our environmental
stewardship policy""
In addition to the previously discussed costs, Blackstone is currently
litigating responsibility for clean-up costs and related interest aggregating
$5.9 million. The clean-up costs were incurred by the Commonwealth of
Massachusetts at a site in which Blackstone has been named as a responsible
party. See Note J of "Notes to Consolidated Financial Statements" for further
discussion.
A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found everywhere there is electricity. Research to date has not conclusively
established a dire ct causal relationship between EMF exposure and human
health. Additional studies, which are intended to provide a better
understanding of the subject, are continuing. Management cannot predict the
ultimate outcome of the EMF issue.
Nuclear Power Issues
Montaup has a 4.01% ownership interest in Millstone 3, an 1154-mw nuclear unit
that is jointly owned by a number of New England utilities, including
subsidiaries of Northeast Utilities (Northeast). Subsidiaries of Northeast are
the lead participants in Millstone 3. On March 30, 1996, it was necessary to
shut down the unit following an engineering evaluation which determined that
four safety-related valves would not be able to perform their design function
during certain postulated events.
The Nuclear Regulatory Commission (NRC) has raised numerous issues with respect
to the unit and certain of the other nuclear units operated by Northeast. The
NRC informed Northeast that it was establishing a Special Projects Office to
oversee inspection and licensing activities at Millstone and directed Northeast
to submit a plan for disposition of safety issues raised by employees and
retain an independent third-party to oversee implementation of this plan.
In March of 1997, Northeast announced that Millstone 3 had been designated as
the lead unit in the recovery process of the three Millstone nuclear units that
are currently out of service. Millstone 3 is the largest of the three units
currently out of service, and its return to service will most benefit the
energy needs of the New England region.
On January 8, 1998, Northeast announced that Millstone 3 was "physically ready
for restart" indicating that virtually all of the restart-required physical
work had been completed. Northeast indicated that a small amount of systems
work needs to be completed prior to restart. Various NRC and independent
inspections are required prior to restart. EUA cannot predict when the plant
will be restarted. While Millstone 3 is out of service, Montaup will continue
to incur incremental replacement power costs estimated at up to $1 million per
month.
Montaup has been paying its share of Millstone 3's O&M expenses on a
reservation of right basis. The fact that Montaup makes payment for these
expenses is not an admission of financial responsibility for expenses incurred
or to be incurred due to the outage.
In August 1997, nine non-operating owners, including Montaup, who together own
approximately 19.5% of Millstone 3, filed a demand for arbitration against
Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company
(WMECO) as well as lawsuits against Northeast and its Trustees. CL&P and
WMECO, owners of approximately 65% of Millstone 3, are Northeast subsidiaries
which agreed to be responsible for the proper operation of the unit.
The non-operating owners of Millstone 3 claim that Northeast and its
subsidiaries failed to comply with NRC regulations, failed to operate the
facility in accordance with good utility operating practice and attempted to
conceal their activities from the non-operating owners and the NRC. The
arbitration and lawsuits seek to recover costs associated with replacement
power and O&M costs resulting from the shutdown of Millstone 3. The non-
operating owners conservatively estimate that their losses will exceed $200
million.
EUA cannot predict the ultimate outcome of the NRC inquiries or legal
proceedings brought against CL&P, WMECO and Northeast or the impact which they
may have on Montaup and the EUA System.
On August 6, 1997, as the result of an economic evaluation, the Maine Yankee
Board of Directors voted to permanently close that nuclear plant. Montaup has
a 4.0% equity ownership in Maine Yankee with a book value of approximately $3.2
million at December 31, 1997. Montaup's share of the total estimated costs for
the permanent shutdown, decommissioning, and recovery of the remaining
investment in Maine Yankee, is approximately $35.4 million and is included with
Other Liabilities on the Consolidated Balance Sheet for the period ending
December 31, 1997. Also, due to anticipated recoverability, a regulatory asset
has been recorded for the same amount and is included with Other Assets. The
recovery of this estimated amount is subject to approval of FERC. Montaup
cannot predict the ultimate outcome of FERC's review.
Also, as a result of the shutdown, Montaup and the other equity owners of Maine
Yankee have been notified by the Secondary Purchasers that they will no longer
make payments for purchased power to Maine Yankee. The Secondary Purchase
Contracts are be tween the equity owners as a group and 30 municipalities
throughout New England. The equity owners are currently making payments to
Maine Yankee to cover the payments that would be made by the municipals.
"Note in margin: "To reduce continued additional costs of outage and recover
funds we've already spent""
On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation of
Arbitration to the equity owners of Maine Yankee. On December 15, 1997, the
equity owners as a group filed at FERC a Complaint and Petition for
Investigation, Contract Modification, and Declaratory Order. The equity owners
are seeking an order from FERC declaring that the Secondary Purchasers remain
responsible for payments due under the Purchase Contracts and directing the
Secondary Purchasers to make such payments. The equity owners also seek a
modification of the Purchase Contracts to extend the termination date or
otherwise to ensure that the equity owners may fully recover from the Secondary
Purchasers a share of the costs of shutting down and decommissioning the Maine
Yankee plant that is proportional to the Secondary Purchasers' entitlements to
energy from the plant. Management does not believe that this contract issue
will have a material effect on EUA's future operating results or financial
position and cannot predict its ultimate outcome at this time.
Recent actions by the NRC, some of which are cited above, indicate that the NRC
has become more critical and active in its oversight of nuclear power plants.
EUA is unable to predict at this time, what, if any, ramifications these NRC
actions will h ave on any of the other nuclear power plants in which Montaup
has an ownership interest or power contract.
Montaup is recovering through rates its share of estimated decommissioning
costs for the Millstone 3 and Seabrook I nuclear generating units. Montaup's
share of the currently allowed estimated total costs to decommission Millstone
3 is approximately $21.9 million in 1997 dollars and Seabrook I is
approximately $13.7 million in 1997 dollars. These figures are based on
studies performed for the lead owners of the units. Montaup also pays into
decommissioning reserves, pursuant to contractual arrangements, at other
nuclear generating facilities in which it has an equity ownership interest or
life-of-unit entitlement. Such expenses are currently recovered through rates.
In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee,
individually, as well as a number of other utilities, filed suit in federal
appeals court seeking a court order to require the Department of Energy (DOE)
to immediately establish a program for the disposal of spent nuclear fuel.
Yankee Atomic and Connecticut Yankee are also seeking damages of approximately
$70 million and $90 million, respectively. Under the Nuclear Waste Policy Act
of 1992, the DOE was to provide for the disposal of radioactive wastes and
spent nuclear fuel starting in 1998 and has collected funds from owners of
nuclear facilities to do so. Management cannot predict the ultimate outcome of
this issue.
Year 2000 Issue
EUA has conducted a comprehensive review of its computer systems to identify
the systems that could be affected by the Year 2000 Issue and is developing an
implementation plan to resolve the issue. The Year 2000 Issue is the result of
computer programs being written using two digits rather than four to define the
applicable year. Any programs that have time-sensitive software may recognize
a date using "00" as the year 1900 rather than the year 2000. This could
result in a major system failure or miscalculations. EUA believes that, with
modifications to existing software and conversions to new software, the Year
2000 problem will not pose significant operational problems for its computer
systems as so modified and converted. It is anticipated that all reprogramming
efforts will be complete by the spring of 1999, allowing adequate time for
testing. In addition, notices have been sent to EUA's primary processing
vendors seeking assurance that plans are being developed to address processing
of transactions in the year 2000. Management does not believe the year 2000
compliance expense will be material to EUA's future operating results or future
financial condition.
New Accounting Standards
In June 1997 the FASB issued Statement No. 130, "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive income and its
components (revenues, expenses, gains, and losses) in a set of general-purpose
financial statements. This Statement requires that all items that are required
to be recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with the same
prominence as other financial statements. This Statement is effective for
fiscal years beginning after December 15, 1997, and EUA will adopt Statement
130 in the first quarter of 1998.
Other
EUA occasionally makes forward-looking projections of expected future
performance or statements of our plans and objectives. These forward-looking
statements may be contained in filings with the SEC, press releases and oral
statements. Actual results could differ materially from these statements.
Therefore, no assurances can be given that such forward-looking statements and
estimates will be achieved.
"Management's Discussion and Analysis of Financial Condition and Review of
Operations" provides a summary of information regarding the Company's financial
condition and results of operation and should be read in conjunction with the
"Consolidated Financial Statements" and "Notes to Consolidated Financial
Statements" to arrive at a more complete understanding of such matters.
Financial Table of Contents
Consolidated Statements of Income 30
Consolidated Statements of Cash Flows 31
Consolidated Balance Sheets 32
Consolidated Statements of Retained Earnings 33
Consolidated Statements of Equity Capital and Preferred Stock 33
Consolidated Statements of Indebtedness 34
Notes to Consolidated Financial Statements 35
Report of Independent Accountants 44
Report of Management 44
Quarterly Financial and Common Share Information 45
Consolidated Operating and Financial Statistics 46
Shareholder Information 48
Trustees and Officers Inside Back Cover
<TABLE>
Consolidated Statements of Income
<CAPTION>
($ in thousands except Common Shares and per Share Amounts)
Years Ended December 31, 1997 1996 1995
<S> <C> <C> <C>
OPERATING REVENUES $ 568,513 $ 527,068 $ 563,363
OPERATING EXPENSES:
Fuel 110,724 92,166 90,888
Purchased Power-Demand 119,485 118,830 125,616
Other Operation 162,464 154,831 163,907
Voluntary Retirement Incentives 1,416 4,505
Maintenance 30,432 25,047 23,468
Depreciation and Amortization 46,941 45,478 45,492
Taxes - Other Than Income 24,021 23,933 20,744
Income Taxes 14,223 10,942 17,015
Total Operating Expenses 509,706 471,227 491,635
Operating Income 58,807 55,841 71,728
Equity in Earnings of Jointly
Owned Companies 9,466 10,698 12,063
Allowance for Other Funds Used
During Construction 162 452 538
Loss on Disposal of Cogeneration
Operations (18,086)
Income Tax Impact of Loss on
Disposal of Cogeneration
Operations 7,588
Other Income (Deductions) - Net 10,986 5,054 2,574
Income Before Interest Charges 79,421 72,045 76,405
INTEREST CHARGES:
Interest on Long-Term Debt 32,198 34,035 38,216
Amortization of Debt Expense
and Premium - Net 2,548 2,620 2,752
Other Interest Expense 5,245 4,199 3,167
Allowance for Borrowed Funds
Used During Construction (Credit) (835) (1,735) (2,677)
Net Interest Charges 39,156 39,119 41,458
Net Income 40,265 32,926 34,947
Preferred Dividends of Subsidiaries 2,305 2,312 2,321
Consolidated Net Earnings $ 37,960 $ 30,614 $ 32,626
Average Common Shares Outstanding 20,435,997 20,436,217 20,238,961
Consolidated Basic and Diluted
Earnings per Share $ 1.86 $ 1.50 $ 1.61
Dividends Paid per Share $ 1.66 $ 1.645 $ 1.585
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Years Ended December 31, ($ in thousands) 1997 1996 1995
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 40,265 $ 32,926 $ 34,947
Adjustments to Reconcile Net Income
to Net Cash Provided from Op. Act.:
Depreciation and Amortization 51,615 50,690 52,413
Amortization of Nuclear Fuel 1,067 1,676 3,647
Deferred Taxes (6,317) 11,610 (985)
Non-cash Expenses/(Gains) on Sales
Inv. in Energy Savings Projects 15,993 8,262 (1,264)
Loss on Disposal of Cog. Ops. 18,086
Investment Tax Credit, Net (1,201) (1,207) (1,212)
Allowance for Other Funds
Used During Construction (162) (452) (538)
Collections and Sales of Project
Notes and Leases Receivable 19,148 7,776 17,748
Other - Net (5,726) 6,373 5,129
Changes in Operating Assets and Liabilities:
Accounts Receivable (2,494) (5,777) 5,729
Materials and Supplies 2,929 2,385 (1,280)
Accounts Payable 1,225 (1,958) 1,543
Taxes Accrued 59 (1,539) (1,921)
Other - Net (664) 4,930 (19,079)
Net Cash Provided from
Operating Activities 115,737 115,695 112,963
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (76,118) (62,730) (77,923)
Collections on Notes and Lease
Receivables of EUA Cogenex 10,076 3,665 3,125
Proceeds from Disposal of
Cogeneration Assets 11,501
Other Investments 312 (3,889) (2,300)
Net Cash (Used in) Investing
Activities (65,730) (62,954) (65,597)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuances:
Common Shares 5,985
Redemptions:
Long-Term Debt (28,617) (20,617) (42,725)
Preferred Stock (90) (100)
Prem.on Reacquisition and Fin. Exp. (15) (63)
EUA Common Share Dividends Paid (33,924) (33,618) (32,050)
Subsidiary Preferred Dividends Paid (2,305) (2,314) (2,324)
Net Increase in Short-Term Debt 9,636 12,308 7,862
Net Cash (Used in)
Financing Activities (55,210) (44,346) (63,415)
NET (DECREASE) INCREASE IN CASH AND
TEMPORARY CASH INVESTMENTS: (5,203) 8,395 (16,049)
Cash and Temporary Cash Investments at
Beginning of Year 12,455 4,060 20,109
Cash and Temporary Cash Investments at
End of Year 7,252 12,455 4,060
Cash Paid during the year for:
Interest (Net of Amounts Capitalized) $55,172 $ 40,658 $ 39,306
Income Taxes $28,921 $ 11,530 $ 9,412
Conversion of Investments in Energy Savings Projects
to Notes and Leases Receivable $ 5,404 $ 7,779 $ 19,324
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Balance Sheets
<CAPTION>
Years Ended December 31, ($ in thousands) 1997 1996
<S> <C> <C>
ASSETS
Utility Plant and Other Investments:
Utility Plant in Service $ 1,079,361 $ 1,067,056
Less Accumulated Provisions for
Depreciation and Amortization 376,722 350,816
Net Utility Plant in Service 702,639 716,240
Construction Work in Progress 5,538 3,839
Net Utility Plant 708,177 720,079
Non-utility Property - Net 71,516 72,653
Investments in Jointly Owned Companies 69,749 71,626
Other 62,834 68,031
Total Utility Plant and Other Investments 912,276 932,389
Current Assets:
Cash and Temporary Cash Investments 7,252 12,455
Accounts Receivable:
Customers, Net 64,214 66,089
Accrued Unbilled Revenues 14,103 10,282
Other 14,329 13,782
Notes Receivable 27,693 24,691
Materials and Supplies (at average cost):
Fuel 4,304 6,924
Plant Materials and Operating Supplies 6,897 7,207
Other Current Assets 7,177 7,668
Total Current Assets 145,969 149,098
Other Assets 212,507 175,542
Total Assets $ 1,270,752 $ 1,257,029
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 373,467 $ 371,813
Non-Redeemable Preferred Stock
of Subsidiaries - Net 6,900 6,900
Redeemable Preferred Stock
of Subsidiaries - Net 27,612 27,035
Long-Term Debt - Net 332,802 406,337
Total Capitalization 740,781 812,085
Current Liabilities:
Short-Term Debt 61,484 51,848
Long-Term Debt Due Within One Year 72,518 27,512
Accounts Payable 35,036 33,811
Taxes Accrued 3,063 3,004
Interest Accrued 8,624 9,612
Other Current Liabilities 33,327 26,772
Total Current Liabilities 214,052 152,559
Other Liabilities 152,526 123,209
Accumulated Deferred Taxes 163,393 169,176
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization $ 1,270,752 $ 1,257,029
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
Years Ended December 31, ($ in thousands) 1997 1996 1995
<S> <C> <C> <C>
Retained Earnings - Beginning of Year $ 52,404 $ 56,228 $ 56,617
Consolidated Net Earnings 37,960 30,614 32,626
Total 90,364 86,842 89,243
Dividends Paid - EUA Common Shares 33,924 33,618 32,050
Other 378 820 965
Retained Earnings - Accumulated since
June 1991 Accounting Reorganization $ 56,062 $ 52,404 $ 56,228
</TABLE>
<TABLE>
Consolidated Statements of Equity Capital & Preferred Stock
<CAPTION>
Years Ended December 31, ($ in thousands) 1997 1996
<S> <C> <C>
EASTERN UTILITIES ASSOCIATES:
Common Shares:
$5 par value 36,000,000 shares authorized, 20,435,997 shares outstanding
in 1997 and 1996 $ 102,180 $ 102,180
Other Paid-In Capital 219,156 221,160
Common Share Expense (3,931) (3,931)
Retained Earnings - Accumulated since June
1991 Accounting Reorganization 56,062 52,404
Total Common Equity 373,467 371,813
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES:
Non-Redeemable Preferred:
Blackstone Valley Electric Company:
4.25% $100 par value 35,000 shares <F1> 3,500 3,500
5.60% $100 par value 25,000 shares <F1> 2,500 2,500
Premium 129 129
Newport Electric Corporation:
3.75% $100 par value 7,689 shares <F1> 769 769
Premium 2 2
Total Non-Redeemable Preferred Stock 6,900 6,900
Redeemable Preferred:
Eastern Edison Company:
65/8% $100 par value 300,000 shares <F2> 30,000 30,000
Expense, Net of Premium (335) (335)
Preferred Stock Redemption Costs (2,053) (2,630)
Total Redeemable Preferred Stock 27,612 27,035
Total Preferred Stock of Subsidiaries $ 34,512 $ 33,935
<FN>
<F1> Authorized and Outstanding.
<F2> Authorized 400,000 shares. Outstanding 300,000 at December 31, 1997.
</FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
<TABLE>
Consolidated Statements of Indebtedness
<CAPTION>
Years Ended December 31, ($ in thousands) 1997 1996
<S> <C> <C>
EUA Service Corporation:
10.2% Secured Notes due 2008 $ 7,900 $ 10,100
EUA Cogenex Corporation:
7.22% Unsecured Notes due 1997 15,000
7.0% Unsecured Notes due 2000 50,000 50,000
9.6% Unsecured Notes due 2001 12,800 16,000
10.56% Unsecured Notes due 2005 28,000 31,500
EUA Ocean State Corporation:
9.59% Unsecured Notes due 2011 28,590 31,067
Blackstone Valley Electric Company:
First Mortgage Bonds:
9 1/2% due 2004 (Series B) 10,500 12,000
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds due 2014(1) 6,500 6,500
Eastern Edison Company
First Mortgage and Collateral Trust Bonds:
5 7/8% due 1998 20,000 20,000
5 3/4% due 1998 40,000 40,000
7.78 % Secured Medium Term Notes due 2002 35,000 35,000
6 7/8% due 2003 40,000 40,000
6.35% due 2003 8,000 8,000
8.0% due 2023 40,000 40,000
Pollution Control Revenue Bonds:
5 7/8% due 2008 40,000 40,000
Newport Electric Corporation:
First Mortgage Bonds:
9.0% due 1999 1,386 1,386
9.8% due 1999 8,000 8,000
8.95% due 2001 2,600 3,250
Small Business Administration Loan:
6.5% due 2005 628 719
Variable Rate Revenue Refunding Bonds due 2011 <F1> 7,925 7,925
Unamortized (Discount) - Net (509) (598)
405,320 433,849
Less Portion Due Within One Year 72,518 27,512
Total Long-Term Debt - Net $ 332,802 $ 406,337
<FN>
<F1> Weighted average interest rate was 3.7% for 1997 and 3.5% for 1996.
</FN>
The accompanying notes are an integral part of the financial statements.
</TABLE>
(A) Nature of Operations and Summary of Significant Accounting Policies:
General: Eastern Utilities Associates (EUA) is a diversified energy services
holding company. Its subsidiaries are principally engaged in the generation,
transmission, distribution and sale of electricity; energy related services
such as energy management; and promoting the conservation and efficient use of
energy.
Estimates: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Basis of Consolidation: The consolidated financial statements include the
accounts of EUA and all subsidiaries. All material intercompany transactions
between the consolidated subsidiaries have been eliminated.
System of Accounts: The accounts of EUA and its consolidated subsidiaries are
maintained in accordance with the uniform system of accounts prescribed by the
regulatory bodies having jurisdiction.
Jointly Owned Companies: Montaup Electric Company (Montaup) follows the
equity method of accounting for its stock ownership investments in jointly
owned companies including four regional nuclear generating companies.
Montaup's investments in these nuclear generating companies range from 2.5% to
4.5%. Three of the four facilities have been permanently shut down and are in
the process of decommissioning. Montaup is entitled to electricity produced
from the remaining facility based on its ownership interest and is billed for
its entitlement pursuant to a contractual agreement which is approved by the
Federal Energy Regulatory Commission (FERC).
In December 1996, the Board of Directors of Connecticut Yankee voted to retire
the generating station. Connecticut Yankee certified to the Nuclear Regulatory
Commission (NRC) that it had permanently closed power generation operations and
removed fuel from the reactor. Montaup has a 4.5% equity ownership in
Connecticut Yankee. Montaup's share of the total estimated costs for the
permanent shutdown, decommissioning, and recovery of the investment in
Connecticut Yankee is approximately $27.4 mil lion and is included with Other
Liabilities on the Consolidated Balance Sheet as of December 31, 1997. Also,
due to recoverability, a regulatory asset has been recorded for the same amount
and is included with Other Assets. The recovery of this estimated amount,
elements of which have been disputed by certain intervening parties, is subject
to approval of FERC. Montaup cannot predict the ultimate outcome of FERC's
review.
In August 1997, as the result of an economic evaluation, the Maine Yankee Board
of Directors voted to permanently close that nuclear plant. Montaup has a 4.0%
equity ownership in Maine Yankee. Montaup's share of the total estimated costs
for the permanent shutdown, decommissioning, and recovery of the remaining
investment in Maine Yankee is approximately $35.4 million and is included with
Other Liabilities on the Consolidated Balance Sheet as of December 31, 1997.
Also, due to recoverability, a regulatory asset has been recorded for the same
amount and is included with Other Assets. The recovery of this estimated
amount, elements of which have been disputed by certain intervening parties,
is subject to approval of FERC. Montaup cannot predict the ultimate outcome of
FERC's review.
Montaup also has a stock ownership investment of 3.27% in each of two companies
which own and operate certain transmission facilities between the Hydro Quebec
electric system and New England.
EUA Ocean State Corporation (EUA Ocean State) follows the equity method of
accounting for its 29.9% partnership interest in the Ocean State Power Project
(OSP). Also, EUA Energy Investment follows the equity method of accounting for
its 40% partners hip interest in BIOTEN, G.P. and for its 20% stock ownership
in Separation Technologies, Inc. These ownership interests and Montaup's stock
ownership investments are included in "Investments in Jointly Owned Companies"
on the Consolidated Balance Sheet.
Plant and Depreciation: Utility plant is stated at original cost. The cost of
additions to utility plant includes contracted work, direct labor and material,
allocable overhead, allowance for funds used during construction and indirect
charges for engineering and supervision. For financial statement purposes,
depreciation is computed on the straight-line method based on estimated useful
lives of the various classes of property. On a consolidated basis, provisions
for depreciation on utility plant were equivalent to a composite rate of
approximately 3.6% in 1997, 3.7% in 1996, and 3.6% in 1995, based on the
average depreciable property balances at the beginning and end of each year.
Beginning in 1998, coincident with billing a contract termination charge (CTC)
to its retail affiliates, Montaup will commence depreciating its investment in
generation related assets recoverable through the CTC over a twelve-year
period. Non-utility property and equipment of EUA Cogenex Corporation (EUA
Cogenex) is stated at original cost. For financial statement purposes,
depreciation on office furniture and equipment, computer equipment and real
property is computed on the straight-line method based on estimated useful
lives ranging from five to forty years. Project equipment is depreciated over
the term of the applicable contracts or based on the estimated useful lives,
whichever is shorter, ranging from five to fifteen years.
Other Assets: The components of Other Assets at December 31, 1997 and 1996 are
detailed as follows:
($ in thousands) 1997 1996
Regulatory Assets:
Unamortized losses on reacquired debt $ 12,299 $ 14,088
Unrecovered plant and
decommissioning costs 68,345 41,914
Deferred FAS 109 costs (Note B) 57,732 58,712
Deferred FAS 106 costs 3,310 4,054
Mendon Road judgment (Note J) 6,154 6,154
Other regulatory assets 15,524 6,363
Total regulatory assets 163,364 131,285
Other deferred charges and assets:
Split dollar life insurance premiums 15,502 7,699
Unamortized debt expenses 3,954 4,625
Goodwill 6,642 6,848
Other 23,045 25,085
Total Other Assets $ 212,507 $ 175,542
Notes to Consolidated Financial Statements (continued)
December 31, 1997, 1996 and 1995
Regulatory Accounting: EUA's Core Electric companies are subject to certain
accounting rules that are not applicable to other industries. These accounting
rules allow regulated companies, in appropriate circumstances, to establish
regulatory assets and liabilities which defer the current financial impact of
certain costs that are expected to be recovered in future rates. In light of
approved restructuring settlement agreements and restructuring legislation in
both Massachusetts and Rhode Island, EUA has determined that Montaup no longer
will apply the provisions of Financial Accounting Standards Board's (FASB)
Statement of Financial Accounting Standards No. 71 (FAS71), "Accounting for the
Effects of Certain Types of Regulation" for the generation portion of its
business. Due to the recoverability of regulatory assets granted in the
approved restructuring plans, EUA believes that the discontinuation of FAS71
for the generation portion of Montaup's business will not have a material
impact on EUA's results of operation or financial condition. EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.
Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest:
AFUDC represents the estimated cost of borrowed and equity funds used to
finance the EUA System's construction program. In accordance with regulatory
accounting, AFUDC is capitalized as a cost of utility plant in the same manner
as certain general and administrative costs. AFUDC is not an item of current
cash income but is recovered over the service life of utility plant in the form
of increased revenues collected as a result of higher depreciation expense.
The combined rate used in calculating AFUDC was 8.0% in 1997, 9.0% in 1996 and
9.2% in 1995. The caption "Allowance for Borrowed Funds Used During
Construction" also includes interest capitalized for non-regulated entities in
accordance with FASB Statement No. 34.
Operating Revenues: Utility revenues are based on billing rates authorized by
applicable federal and state regulatory commissions. Eastern Edison Company
(Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) (collectively, the Retail Subsidiaries) accrue
the estimated amount of unbilled revenues at the end of each month to match
costs and revenues more closely. Montaup recognizes revenues when billed. In
1998, Montaup and the Retail Subsidiaries also began accruing revenues
consistent with provisions of approved settlement agreements and enabling state
legislation.
EUA Cogenex's revenues are recognized based on financial arrangements
established by each individual contract. Under paid-from-savings contracts,
revenues are recognized as energy savings are realized by customers. Revenue
from the sale of energy savings projects and sales-type leases are recognized
when the sales are complete. Interest on the financing portion of the
contracts is recognized as earned at rates established at the outset of the
financing arrangement. All construction and installation costs are recognized
as contract expenses when the contract revenues are recorded. In circumstances
in which material uncertainties exist as to contract profitability, cost
recovery accounting is followed and revenues received under such con tracts are
first accounted for as recovery of costs to the extent incurred.
Federal Income Taxes: EUA and its subsidiaries generally reflect in income the
estimated amount of taxes currently payable, and provide for deferred taxes on
certain items subject to temporary timing differences to the extent permitted
by the various regulatory agencies. EUA's rate-regulated subsidiaries
amortize previously deferred investment tax credits (ITC) over the productive
lives of the related assets. Beginning in 1998, Montaup will amortize
previously deferred ITC related to generation investments recoverable through
the CTC over a twelve-year period.
Cash and Temporary Cash Investments: EUA considers all highly liquid
investments and temporary cash investments with a maturity of three months or
less when acquired to be cash equivalents.
(B) Income Taxes:
EUA adopted FASB Statement No. 109, "Accounting for Income Taxes" (FAS109),
which requires recognition of deferred income taxes for temporary differences
that are reported in different years for financial reporting and tax purposes
using the liability method. Under the liability method, deferred tax
liabilities or assets are computed using the tax rates that will be in effect
when temporary differences reverse. Generally, for regulated companies, the
change in tax rates may not be immediately recognized in operating results
because of ratemaking treatment and provisions in the Tax Reform Act of 1986.
Total deferred tax assets and liabilities for 1997 and 1996 are comprised
as follows:
Deferred Tax Deferred Tax
Assets Liabilities
($ in thousands) 1997 1996 1997 1996
Plant Related Plant Related
Differences $18,947 $19,816 Differences $191,274 $190,155
Alternative Refinancing
Minimum Tax 852 Costs 1,406 1,623
NOL
Carryforward 2,294 1,655 Pensions 1,500 1,313
Pensions 4,868 4,012
Acquisitions 3,650 3,965
Other 14,264 5,657 Other 13,236 12,042
Total $44,023 $35,957 Total $207,416 $205,133
As of December 31, 1997 and 1996, EUA has recorded on its Consolidated Balance
Sheet a regulatory liability to ratepayers of approximately $18.8 million and
$21.2 million, respectively. These amounts primarily represent excess deferred
income taxes resulting from the reduction in the federal income tax rate and
also include deferred taxes provided on investment tax credits. Also at
December 31, 1997 and 1996, a regulatory asset of approximately $57.7 million
and $58.7 million, respectively, has been recorded, representing the cumulative
amount of federal income taxes on temporary depreciation differences which were
previously flowed through to ratepayers.
Notes to Consolidated Financial Statements (continued)
December 31, 1997, 1996 and 1995
Components of income tax expense for the year 1997, 1996, and 1995 are as
follows:
($ in thousands) 1997 1996 1995
Federal:
Current $ 17,249 $ (231) $ 10,335
Deferred (4,901) 9,838 6,456
Investment Tax Credit, Net (1,120) (1,125) (1,130)
11,228 8,482 15,661
State:
Current 3,623 2,823 2,579
Deferred (628) (363) (1,225)
2,995 2,460 1,354
Charged to Operations 14,223 10,942 17,015
Charged to Other Income:
Current 9,142 4,798 4,353
Deferred (789) 2,135 (6,217)
Investment Tax Credit, Net (81) (82) (82)
8,272 6,851 (1,946)
Total Income Tax Expense $ 22,495 $ 17,793 $ 15,069
Total income tax expense was different from the amounts computed
by applying federal income tax statutory rates to book income subject
to tax for the following reasons:
($ in thousands) 1997 1996 1995
Federal Income Tax Computed at Statutory Rates $ 21,966 $ 17,751 $ 17,506
(Decrease) Increase in Tax from:
Equity Component of AFUDC (57) (189) (187)
Depreciation Differences (12) 2 118
Amortization and Utilization of ITC (1,201) (1,207) (1,212)
State Taxes, Net of Federal Income Tax Benefit 2,092 1,952 (44)
Other (293) (516) (1,112)
Total Income Tax Expense $ 22,495 $ 17,793 $ 15,069
(C) Capital Stock:
There was no change in the number of common shares outstanding during 1997.
The changes in the number of common shares outstanding and related increases in
Other Paid-In Capital during the years ended December 31, 1996, and 1995 were
as follows:
Number of Common Shares Issued
Dividend Highland
Reinvestment and Energy Common Other
and Employee Group Shares Paid-In
Savings Acquisition At Par (000) Capital (000)
1996 (767) $ (4) $ 4
1995 323,526 176,258 2,499 7,683
In October 1995, FASB issued Statement No. 123, "Accounting for Stock-Based
Compensation" (FAS123). This Statement establishes a fair-value based method
of accounting for stock compensation plans. As permitted, the Company accounts
for its stock-based compensation, as discussed below, using the method
prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees" (APB25).
The Company established a Restricted Stock Plan in 1989. Under the Restricted
Stock Plan, executives and certain key employees may be granted restricted
common shares of the Company. In 1997 and 1995, approximately 95,000 shares
and 61,000 shares, respectively, of restricted common shares, valued at
approximately $2.4 million and $1.4 million, respectively, were granted.
The shares issued are restricted for a period ranging from two to five years
and all shares are subject to forfeiture if specified employment services are
not met. There are no exercise prices related to these share grants. During
the applicable restriction period, the recipient has all the voting, dividend,
and other rights of a record holder except that the shares are nontransferable.
The annual compensation expense related to these grant awards was immaterial
for 1997, 1996, and 1995. There are no material differences in the Company
recording its annual compensation expense under APB25 from the requirements
under FAS123.
The preferred stock provisions of the Retail Subsidiaries place certain
restrictions upon the payment of dividends on common stock by each company.
At December 31, 1997 and 1996, each company was in excess of the minimum
requirements which would make these restrictions effective.
In the event of involuntary liquidation, the holders of non-redeemable
preferred stock of the Retail Subsidiaries are entitled to $100 per share plus
accrued dividends. In the event of voluntary liquidation, or if redeemed at
the option of these companies, each share of the non-redeemable preferred
stock is entitled to accrued dividends plus the following:
Company Issue Amount
Blackstone: 4.25% issue $104.40
5.60% issue 103.82
Newport: 3.75% issue 103.50
(D) Redeemable Preferred Stock:
Eastern Edison's 6 5/8% Preferred Stock issue is entitled to an annual
mandatory sinking fund sufficient to redeem 15,000 shares commencing September
1, 2003. The redemption price is $100 per share plus accrued dividends. All
outstanding shares of the 6 5/8% issue are subject to mandatory redemption on
September 1, 2008, at a price of $100 per share plus accrued dividends. In the
event of liquidation, the holders of Eastern Edison's 6 5/8% Preferred Stock
are entitled to $100 per share plus accrued dividends.
(E) Long-Term Debt:
The various mortgage bond issues of Blackstone, Eastern Edison, and Newport are
collateralized by substantially all of their utility plant.
In addition, Eastern Edison's bonds are collateralized by securities of
Montaup, which are wholly-owned by Eastern Edison, in the principal amount of
approximately $236 million.
Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable
Letter of Credit which expires on January 21, 1999. The letter of credit
permits an extension of one year upon mutual agreement of the bank and
Blackstone.
Newport's Variable Rate Electric Energy Facilities Revenue Refunding Bonds are
collateralized by an irrevocable Letter of Credit which expires on January 6,
1999, and permits an extension of one year upon mutual agreement of the bank
and Newport. EUA Service Corporation's (EUA Service) 10.2% Secured Notes due
2008 are collateralized by certain real estate and property of the company.
In September, EUA Cogenex used short-term borrowings to redeem $15 million of
7.22% Unsecured Notes at maturity.
The EUA System's aggregate amount of current cash sinking fund requirements and
maturities of long-term debt, (excluding amounts that may be satisfied by
available property additions) for each of the five years following 1997 are:
$72.5 million in 19 98, $21.9 million in 1999, $62.5 million in 2000, $14.3
million in 2001 and $45.5 million in 2002.
EUA Cogenex was not in compliance with the interest coverage covenant contained
in certain of its unsecured note agreements at December 31, 1997. EUA Cogenex
has reached agreement with lenders to modify the interest coverage covenant
contained in these note agreements through January 1, 1999, and to waive the
default. EUA Cogenex expects to be in compliance during 1998.
(F) Fair Value Of Financial Instruments:
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate:
Cash and Temporary Cash Investments: The carrying amount approximates fair
value because of the short-term maturity of these instruments.
Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair
value of these assets are based on market rates of similar securities.
Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the
System's redeemable preferred stock and long-term debt were based on quoted
market prices for such securities at December 31, 1997 and 1996.
The estimated fair values of the System's financial instruments at December 31,
1997 and 1996, were as follows:
Carrying Amount Fair Value
($ in thousands) 1997 1996 1997 1996
Cash and Temporary
Cash Investments $ 7,252 $ 12,455 $ 7,252 $ 12,455
Long-Term Notes Receivable
and Net Investment
in Sales-Type Leases 46,192 52,599 47,200 54,869
Redeemable Preferred Stock 30,000 30,000 31,613 30,300
Long-Term Debt 405,829 434,447 429,035 450,419
(G) Lines Of Credit:
In July 1997, several EUA System companies entered into a three-year revolving
credit agreement allowing for borrowings in aggregate of up to $120 million.
As of December 31, 1997, various financial institutions have committed up to
$75 million under the revolving credit facility. At December 31, 1997 under
the revolving credit agreement the EUA System had short-term borrowings
available of approximately $13.5 million. During 1997, the weighted average
interest rate for short-term borrowings was 5.6%.
(H) Jointly Owned Facilities:
At December 31, 1997, in addition to the stock ownership interests discussed in
Note A, Nature of Operations and Summary of Significant Accounting Policies -
Jointly Owned Companies, Montaup and Newport had direct ownership interests in
the following electric generating facilities:
Accumulated Net
Utility Provision for Utility Construction
Percent Plant in Depreciation Plant in Work in
($ in thousands) Owned Service & Amortization Service Progress
Montaup:
Canal Unit 2 50.00% $ 85,750 $ 44,498 $ 41,252 $ 227
Wyman Unit 4 1.96% 4,054 2,253 1,801
Seabrook Unit I 2.90% 194,679 34,400 160,279 325
Millstone Unit 3 4.01% 178,918 54,844 124,074 285
Newport:
Wyman Unit 4 0.67% 1,315 768 547
The foregoing amounts represent Montaup's and Newport's interest in each
facility, including nuclear fuel where appropriate, and are included on the
like-captioned lines on the Consolidated Balance Sheet. At December 31, 1997,
Montaup's total net in vestment in nuclear fuel of the Seabrook and Millstone
Units amounted to $2.2 million and $1.8 million, respectively.
Montaup's and Newport's shares of related operating and maintenance expenses
with respect to units reflected in the preceding table are included in the
corresponding operating expenses.
(I) Financial Information By Business Segments:
The Core Electric Business includes results of the electric utility operations
of Blackstone, Eastern Edison, Newport and Montaup.
Energy Related Business includes results of our diversified energy-related
subsidiaries, EUA Cogenex, EUA Ocean State, EUA Energy Investment Corporation
(EUA Energy), EUA Energy Services and EUA Telecommunications.
Corporate results include the operations of EUA Service and EUA Parent.
<TABLE>
<CAPTION>
Pre-Tax Depreciation Cash Equity in
Operating Operating Income and Construction Subsidiary
($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings
<S> <C> <C> <C> <C> <C> <C>
Year Ended
December 31, 1997
Core Electric $ 506,696 $ 78,795 $20,303 $36,069 $21,870 $ 1,599
Energy Related 61,817 (3,785) 547 10,858 51,941 7,867
Corporate (1,980) 1,645 14 2,307
Total $ 568,513 $ 73,030 $22,495 $46,941 $76,118 $ 9,466
Year Ended
December 31, 1996
Core Electric $ 470,719 $ 80,042 $21,039 $35,178 $ 33,337 $ 1,587
Energy Related 56,349 (11,536) (3,888) 10,290 28,121 9,111
Corporate (1,723) 642 10 1,272
Total $ 527,068 $ 66,783 $17,793 $45,478 $ 62,730 $ 10,698
Year Ended
December 31, 1995
Core Electric $ 483,864 $ 86,505 $20,724 $34,218 $ 31,466 $ 1,646
Energy Related 79,499 3,377 (5,658) 11,265 44,684 10,417
Corporate (1,139) 3 9 1,773
Total $ 563,363 $ 88,743 $15,069 $45,492 $ 77,923 $12,063
</TABLE>
Years ended December 31, ($ in thousands) 1997 1996
Total Plant and Other Investments
Core Electric $ 703,132 $ 715,796
Energy Related 187,752 196,236
Corporate 21,392 20,357
Total Plant and Other Investments 912,276 932,389
Other Assets
Core Electric 257,888 232,443
Energy Related 73,109 66,212
Corporate 27,479 25,985
Total Other Assets 358,476 324,640
Total Assets $1,270,752 $1,257,029
(J) Commitments And Contingencies:
Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs:
The owners (or lead participants) of the nuclear units in which Montaup has
an interest have made, or expect to make, various arrangements for the
acquisition of uranium concentrate, the conversion, enrichment, fabrication and
utilization of nuclear fuel and the disposition of that fuel after use. The
owners (or lead participants) of United States nuclear units have entered into
contracts with the Department of Energy (DOE) for disposal of spent nuclear
fuel in accordance with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA
requires (subject to various contingencies) that the federal government design,
license, construct and operate a permanent repository for high level
radioactive wastes and spent nuclear fuel and establish a prescribed fee for
the disposal of such wastes and nuclear fuel. The NWPA specifies that the DOE
provide for the disposal of such waste and spent nuclear fuel starting in 1998.
Objections on environmental and other grounds have been asserted against
proposals for storage as well as disposal of spent nuclear fuel. The DOE now
estimates that a permanent disposal site for spent fuel will not be ready to
accept fuel for storage or disposal until as late as the year 2010. In early
1998 a number of utilities filed suit in federal appeals court seeking, among
other things, an order requiring the DOE to immediately establish a program for
the disposal of spent nuclear fuel. Montaup owns a 4.01% interest in Millstone
3 and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the
units, indicates that Millstone 3 has sufficient on-site storage facilities
which, with rack additions, can accommodate its spent fuel for the projected
life of the unit. At the Seabrook Project, there is on-site storage capacity
which, with rack additions, will be sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest. These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners or power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through rates.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone 3 is $21.9 million in
1997 dollars, and Seabrook I is $13.7 million in 1997 dollars. These figures
are based on studies performed for the lead owners of the units. Montaup also
pays into decommissioning reserves pursuant to contractual arrangements with
other nuclear generating facilities in which it has an equity ownership
interest or life of the unit entitlement. Such expenses are currently
recoverable through rates.
Pensions: EUA maintains a noncontributory defined benefit pension plan
covering most of the employees of the EUA System (Retirement Plan). Retirement
Plan benefits are based on years of service and average compensation over the
four years prior to retirement. It is the EUA System's policy to fund the
Retirement Plan on a current basis in amounts determined to meet the funding
standards established by the Employee Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including amounts
related to the 1997 and 1995 voluntary retirement incentive offers, for 1997,
1996 and 1995 included the following components:
($ in thousands) 1997 1996 1995
Service cost-benefits earned
during the period $ 2,816 $ 3,126 $ 2,776
Interest cost on projected
benefit obligations 10,116 9,765 9,391
Actual (return) on assets (29,898) (16,451) (36,220)
Net amortization and deferrals 16,347 4,060 24,392
Net periodic pension
(income) expense (619) 500 339
Voluntary Retirement Incentive 1,653
Subsidiary curtailment (131)
Total periodic pension
(income) expense $ (750) $ 500 $ 1,992
Assumptions used to determine pension costs:
Discount Rate 7.50% 7.25% 8.25%
Compensation Increase Rate 4.25% 4.25% 4.75%
Long-Term Return on Assets 9.50% 9.50% 9.50%
The following table sets forth the actuarial present value of benefit
obligations and funded status at December 31, 1997, 1996 and 1995:
($ in thousands) 1997 1996 1995
Accumulated benefit obligations
Vested $ (126,302) $ (118,739) $(117,060)
Non-vested (266) (254) (271)
Total $ (126,568) $ (118,993) $ (117,331)
Projected benefit obligations $ (144,915) $ (136,286) $ (135,415)
Plan assets at fair value,
primarily stocks and bonds 182,795 161,300 152,308
Unrecognized net (gain) (41,399) (29,963) (21,769)
Unamortized net assets at January 1 3,832 4,513 4,939
Net pension assets (liability) $ 313 $ (436) $ 63
The discount rate used to determine pension obligations, effective January 1,
1998 was changed to 7.25% and was used to calculate the plan's funded status at
December 31, 1997.
The voluntary retirement incentives also resulted in $1.3 million and $1.6
million of non-qualified pension benefits which were expensed in 1997 and 1995.
At December 31, 1997, approximately $2.6 million was included in other
liabilities for these unfunded benefits.
EUA also maintains non-qualified supplemental retirement plans for certain
officers and trustees of the EUA System (Supplemental Plans). Benefits
provided under the Supplemental Plans are based primarily on compensation at
retirement date. EUA maintains life insurance on certain participants of the
Supplemental Plans to fund in whole, or in part, its future liabilities under
the Supplemental Plans. As of December 31, 1997, approximately $5.7 million
was included in accrued expenses and other liabilities for these plans.
Expenses related to the Supplemental Plans were $1.9 million in 1997, and $1.5
million in both 1996 and 1995. EUA also provides a defined contribution 401(k)
savings plan for substantially all employees. EUA's matching percentage of
employees' voluntary contributions to the plan, amounted to $1.5 million in
1997, $1.3 million in 1996, and $1.4 million in 1995.
Post-Retirement Benefits: Retired employees are entitled to participate in
health care and life insurance benefit plans. Health care benefits are subject
to deductibles and other limitations. Health care and life insurance benefits
are partially funded by EUA System companies for all qualified employees.
The EUA System adopted Statement of Financial Accounting Standard No. 106,
"Accounting for Post-Retirement Benefits Other Than Pensions," (FAS106) as of
January 1, 1993. This standard establishes accounting and reporting standards
for such post-retirement benefits as health care and life insurance. Under
FAS106 the present value of future benefits is recorded as a periodic expense
over employee service periods through the date they become fully eligible for
benefits. With respect to periods prior to adopting FAS106, EUA elected to
recognize accrued costs (the Transition Obligation) over a period of 20 years,
as permitted by FAS106. The resultant annual expense, including amortization
of the Transition Obligation and net of capitalized and deferred amounts, was
approximately $6.1 million in 1997, $6.1 million in 1996, and $6.3 million in
1995.
The total cost of post-retirement benefits other than pensions, including
amounts related to the 1997 and 1995 voluntary retirement incentive offers,
for 1997, 1996 and 1995 includes the following components:
($ in thousands) 1997 1996 1995
Service cost $ 949 $ 1,123 $ 996
Interest cost 4,434 4,449 4,822
Actual (return) on plan assets (1,433) (253) (671)
Amortization of transition obligation 3,289 3,313 3,312
Other amortizations & deferrals - net (663) (1,211) (970)
Net periodic post-retirement benefit cost 6,576 7,421 7,489
Voluntary Retirement Incentives 172 832
Subsidiary curtailment (548)
Total periodic post-retirement
benefit costs $ 6,200 $ 7,421 $ 8,321
Assumptions used to determine post-retirement benefit costs
Discount rate 7.50% 7.25% 8.25%
Health care cost trend rate
- near-term 7.00% 9.00% 11.00%
- long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.25% 4.75%
Long-term return on assets
- union 8.75% 8.50% 8.50%
- non-union 7.75% 7.50% 5.50%
Reconciliation of funded status:
($ in thousands) 1997 1996 1995
Accumulated post-retirement
benefit obligation (APBO):
Retirees $(38,701) $(36,518) $(40,817)
Active employees fully
eligible for benefits (6,753) (5,952) (9,760)
Other active employees (19,372) (19,652) (20,115)
Total $(64,826) $(62,122) $(70,692)
Plan assets at fair value, primarily
notes and bonds 23,729 17,743 12,614
Unrecognized transition obligation 49,335 53,001 56,314
Unrecognized net loss (gain) (16,233) (17,551) (7,575)
(Accrued)/prepaid post-retirement
benefit cost $ (7,995) $ (8,929) $ (9,339)
The discount rate used to determine post-retirement benefit obligations
effective January 1, 1998 was changed to 7.25% and was used to calculate the
funded status of post-retirement benefits at December 31, 1997.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1997 by $800,000 and
increase the total accumulated post-retirement benefit obligation by $7.2
million.
The EUA System has also established separate irrevocable external Voluntary
Employees' Beneficiary Association Trust Funds for union and non-union
retirees. Contributions to the funds commenced in March 1993 and totaled
approximately $7.1 million in 1997, $7.8 million in 1996 and $7.1 million
during 1995.
Long-Term Purchased Power Contracts: The EUA System is committed under long-
term purchased power contracts, expiring on various dates through September
2021, to pay demand charges whether or not energy is received. Under terms in
effect at December 31, 1997, the aggregate annual minimum commitments for such
contracts are approximately $114 million in 1998, $110 million in 1999, $107
million in 2000, $108 million in 2001, $108 million in 2002, and will aggregate
$1.0 billion for the ensuing years. In addition, the EUA System is required to
pay additional amounts depending on the actual amount of energy received under
such contracts. The demand costs associated with these contracts are reflected
as Purchased Power-Demand on the Consolidated Statement of Income. Such costs
are currently recoverable through rates.
Environmental Matters: There is an extensive body of federal and state
statutes governing environmental matters, which permit, among other things,
federal and state authorities to initiate legal action providing for liability,
compensation, cleanup, and emergency response to the release or threatened
release of hazardous substances into the environment and for the cleanup of
inactive hazardous waste disposal sites which constitute substantial hazards.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by the United States Environmental Protection
Agency (EPA) as well as state and local authorities. The EUA System generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs. Subsidiaries
of EUA have been notified with respect to a number of sites where they may be
responsible for such costs, including sites where they may have joint and
several liability with other responsible parties. It is the policy of the EUA
System companies to notify liability insurers and to initiate claims. EUA is
unable to predict whether liability, if any, will be assumed by, or can be
enforced against, the insurance carriers in these matters.
On December 13, 1994, the United States District Court for the District of
Massachusetts (District Court) issued a judgment against Blackstone, finding
Blackstone liable to the Commonwealth of Massachusetts (Commonwealth) for the
full amount of response costs incurred by the Commonwealth in the cleanup of a
by-product of manufactured gas at a site at Mendon Road in Attleboro,
Massachusetts. The judgment also found Blackstone liable for interest and
litigation expenses calculated to the date of judgment. The total liability is
approximately $5.9 million, including approximately $3.6 million in interest
which has accumulated since 1985. Due to the uncertainty of the ultimate
outcome of this proceeding and anticipated recoverability, Blacks tone recorded
the $5.9 million District Court judgment as a deferred debit. This amount is
included with Other Assets on the Consolidated Balance Sheet at December 31,
1997 and 1996.
Blackstone filed a Notice of Appeal of the District Court's judgment and filed
its brief with the United States Court of Appeals for the First Circuit (First
Circuit) on February 24, 1995. On October 6, 1995, the First Circuit vacated
the District Court's judgment and ordered the District Court to refer the
matter to the EPA to determine whether the chemical substance, ferric
ferrocyanide (FFC), contained within the by-product is a hazardous substance.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue
on the judgment amount.
On January 28, 1994, Blackstone filed a complaint in the District Court,
seeking, among other relief, contribution and reimbursement from Stone &
Webster Inc., of New York City and several of its affiliated companies (Stone &
Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any
damages incurred by Blackstone regarding the Mendon Road site. On November 7,
1994, the Court denied motions to dismiss the complaint which were filed by
Stone & Webster and Valley. This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is a hazardous substance.
In addition, Blackstone has notified certain liability insurers and has filed
claims with respect to the Mendon Road site, as well as other sites.
Blackstone reached settlement with one carrier for reimbursement of legal costs
related to the Mendon Road case. In January 1996, Blackstone received the
proceeds of the settlement.
As of December 31, 1997, the EUA System had incurred costs of approximately
$6.7 million (excluding the $5.9 million Mendon Road judgment) in connection
with the investigation and clean-up of these sites, substantially all of which
relate to Blackstone. These amounts have been financed primarily by internally
generated cash. Blackstone is currently amortizing all of its incurred costs
over a five-year period consistent with prior regulatory recovery periods and
is recovering certain of those costs in rates.
EUA estimates that additional costs of up to $1.3 million (excluding the $5.9
million Mendon Road judgment) may be incurred at these sites through 1998,
substantially all of which relates to sites at which Blackstone is a
potentially responsible part y. Estimates beyond 1998 cannot be made since
site studies, which are the basis of these estimates, have not been completed.
As a result of the recoverability of cleanup costs in rates and the uncertainty
regarding both its estimated liability, as well as its potential contributions
from insurance carriers and other responsible parties, EUA does not believe
that the ultimate impact of the environmental costs will be material to the
financial position of the EUA System or to any individual subsidiary and thus
no loss provision is required at this time.
The Clean Air Act Amendments created new regulatory programs and generally
updated and strengthened air pollution control laws. These amendments expanded
the regulatory role of the EPA regarding emissions from electric generating
facilities and a host of other sources. EUA System generating facilities were
first affected in 1995, when EPA regulations took effect for facilities owned
by the EUA System. Montaup's coal-fired Somerset Unit 6 is utilizing lower
sulfur content coal to meet the 1995 air standards. EUA does not anticipate
the impact from the Amendments to be material to the financial position of the
EUA System.
In July 1997, the EPA issued a new and more stringent rule covering ozone
particulate matter which is to be followed by promulgation of more stringent
ozone and particulate matter standards. The effect that such standards will
have on the EUA System cannot be determined by management at this time.
Eastern Edison, Montaup, the Massachusetts Attorney General and Division of
Energy Resources entered into a settlement regarding electric utility industry
restructuring in Massachusetts. The settlement includes a plan for emissions
reductions relate d to Montaup's Somerset Station Units 5 and 6, and to
Montaup's 50% ownership share of Canal Electric's Unit 2. The basis for SO2
and NOx emission reductions in the proposed settlement is an allowance cap
calculation. Montaup may meet its allowance caps by any combination of control
technologies, fuel switching, operational changes, and/or the use of purchased
or surplus allowances. The settlement was approved by FERC on December 19,
1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight northeast states including
Massachusetts and Rhode Island, issued recommendations for NOx controls for
existing utility boiler s required to meet the ozone non-attainment
requirements of the Clean Air Act. The NESCAUM recommendations are more
restrictive than the Clean Air Act requirements. The Massachusetts Department
of Environmental Management has amended its regulation s to require that
Reasonably Available Control Technology (RACT) be implemented at all stationary
sources potentially emitting 50 tons or more per year of NOx. Similar
regulations have been issued in Rhode Island. Montaup has initiated
compliance, through, among other things, selective noncatalytic reduction
processes.
A number of scientific studies in the past several years have examined the
possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. On October 31, 1996, the National Academy of Sciences issued a
literature review of all research to date, Possible Health Effects of Exposure
to Residential Electric and Magnetic Fields. Its most widely reported
conclusion stated, "No clear, convincing evidence exists to show that
residential exposures to EMF are a threat to human health." Additional studies,
which are intended to provide a better understanding of EMF, are continuing.
Some states have enacted regulations to limit the strength of magnetic fields
at the edge of transmission line rights-of-way. Rhode Island has enacted a
statute which authorizes and directs the Energy Facility Siting Board to
establish rules and regulations governing construction of high voltage
transmission lines of 69 kv or more. Management cannot predict the ultimate
outcome of the EMF issue.
Guarantee of Financial Obligations: EUA has guaranteed or entered into equity
maintenance agreements in connection with certain obligations of its
subsidiaries. EUA has guaranteed the repayment of EUA Cogenex's $28.0 million,
10.56% unsecured long-term notes due 2005 and EUA Ocean State's $28.6 million,
9.59% unsecured long-term notes due 2011. In addition, EUA has entered into
equity maintenance agreements in connection with the issuance of EUA Service's
10.2% Secured Notes and EUA Cogenex's 9.6% Unsecured Notes. Under the December
1992 settlement agreement with EUA Power, EUA reaffirmed its guarantee of up to
$10 million of EUA Power's share of the decommissioning costs of Seabrook I and
any costs of cancellation of Seabrook I or Seabrook II. EUA guaranteed this
obligation in 1990 in order to secure the release to EUA Power of a $10 million
fund established by EUA Power at the time EUA Power acquired its Seabrook
interest. EUA has not provided a reserve for this guarantee because management
believes it unlikely that EUA will ever be required to honor the guarantee.
Montaup is a 3.27% equity participant in two companies which own and operate
transmission facilities interconnecting New England and the Hydro Quebec system
in Canada. Montaup has guaranteed approximately $4.5 million of the
outstanding debt of these two companies. In addition, Montaup and Newport have
minimum rental commitments which total approximately $12 million and $1.5
million, respectively under a noncancelable transmission facilities support
agreement for years subsequent to 1997.
Other: In the fourth quarter of 1996 EUA Cogenex was notified by
Ridgewood/Mass. Corporation that it intended to seek damages related to
certain claims and alleged misrepresentations by EUA Cogenex regarding the sale
of its cogeneration portfolio. As part of the "Agreement for Assignment for
Beneficial Interests," Ridgewood exercised these rights under the mandatory
arbitration clause contained within said agreement. A date has not been
determined for the arbitration proceedings at this time. EUA Cogenex has filed
a counter-claim against Ridgewood for its failure to pay for certain
transitional expenses as stipulated in the "Assignment Agreement." In 1997, the
American Arbitration Association set a preliminary hearing date of June 14,
1998. Management cannot determine at this time the ultimate outcome of these
proceedings.
On January 10, 1997, the Internal Revenue Service (IRS) issued a report in
connection with its examination of the consolidated income tax returns of EUA
for 1992 and 1993. The report includes an adjustment to disallow EUA's
inclusion of its investment in EUA Power's Preferred Stock as a deduction in
determining Excess Loss Account (ELA) taxable income relating to the redemption
of EUA Power's Common and Preferred Stock in 1993. The IRS has taken the
position that the redemption of the Preferred Stock resulted in a capital loss
transaction and not a deduction in determining ELA. The Company disagrees with
the IRS's position and filed a protest in March 1997. On February 24, 1998,
EUA met with an IRS appeals officer to discuss resolution of this matter and
awaits a decision. EUA believes that it will ultimately prevail in this
matter. However, if the ultimate resolution of this matter is a favorable
decision for the IRS and EUA has not generated sufficient capital gain
transactions to offset the capital loss then EUA would be required to record a
charge that could have a material impact on financial results in the year of
the charge but would not materially impact the financial position of the
company.
In early 1997, ten plaintiffs brought suit against numerous defendants,
including EUA, for injuries and illness allegedly caused by exposure to
asbestos over approximately a thirty-year period, at premises, including some
owned by EUA companies. The total damages claimed in all of these complaints
was $25 million in compensatory and punitive damages, plus exemplary damages an
d interest and costs. Each complaint names between fifteen and twenty-eight
defendants, including EUA. These complaints have been referred to the
applicable insurance companies. Counsel has been retained by the insurers and
is actively defending all cases. Three cases have been dismissed as against
the EUA Companies, with prejudice. EUA cannot predict the ultimate outcome of
this matter at this time.
The Office of the Attorney General has certified a referendum petition to
repeal the Massachusetts Electric Industry Restructuring Act as a matter
appropriate for a referendum initiative. A petition was filed with the
Election Division of the Office of the Secretary of State in February 1998. A
question on repealing the Act will be presented to voters on the November 1998
ballot. EUA and the electric industry in Massachusetts will actively oppose
repeal. Management cannot predict the outcome of the November ballot question.
Report of Independent Accountants
To the Trustees and Shareholders of Eastern Utilities Associates
We have audited the accompanying consolidated balance sheets and consolidated
statements of equity capital and preferred stock and indebtedness of Eastern
Utilities Associates and subsidiaries (the Company) as of December 31, 1997 and
1996, and the r elated consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1997.
These financial statements are the responsibility of the Company's management.
Our responsibility is to ex press an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of the
Company as of December 31, 1997 and 1996, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting principles.
/s/Coopers & Lybrand L.L.P.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 3, 1998
Report of Management
The management of Eastern Utilities Associates is responsible for the
consolidated financial statements and related information included in this
annual report. The financial statements are prepared in accordance with
generally accepted accounting principles and include amounts based on the best
estimates and judgments of management, giving appropriate consideration to
materiality. Financial information included elsewhere in this annual report is
consistent with the financial statements.
The EUA System maintains an accounting system and related internal controls
which are designed to provide reasonable assurances as to the reliability of
financial records and the protection of assets. The System's staff of internal
auditors conducts reviews to maintain the effectiveness of internal control
procedures.
Coopers & Lybrand L.L.P., an independent accounting firm, is engaged by EUA to
audit and express an opinion on our financial statements. Their audit includes
a review of internal controls to the extent required by generally accepted
auditing standards for such audit.
The Audit Committee of the Board of Trustees, which consists solely of outside
Trustees, meets with management, internal auditors and Coopers & Lybrand L.L.P.
to discuss auditing, internal controls and financial reporting matters. The
internal audit ors and Coopers & Lybrand L.L.P. have free access to the Audit
Committee without management present.
<TABLE>
Quarterly Financial and Common Share Information (unaudited)
($ in thousands except per Share and Share Price Amounts)
<CAPTION>
Earnings per Dividends Common Share
Consolidated Average Paid per Market Price
Operating Operating Net Net Common Common
Revenues Income Income Earnings Share Share High Low
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FOR THE QUARTERS
ENDED 1997:
December 31 $ 145,878 $ 15,378 $11,158 $10,582 $ 0.52 $ 0.415 26 5/8 20 1/8
September 30 142,026 15,896 11,542 10,966 0.54 0.415 19 15/16 18 7/16
June 30 138,856 11,327 6,510 5,933 0.29 0.415 18 1/2 16 3/8
March 31 141,753 16,206 11,055 10,479 0.51 0.415 19 5/8 17 1/4
FOR THE QUARTERS
ENDED 1996:
December 31 $ 138,407 $ 14,208 $ 8,312 $ 7,735 $ 0.38 $ 0.415 17 1/2 16
September 30 131,076 13,328 9,389 8,811 0.43 0.415 19 1/2 14 3/4
June 30 122,785 10,024 3,299 2,720 0.13 0.415 21 7/8 18 1/2
March 31 134,800 18,281 11,926 11,348 0.56 0.40 24 1/4 20 5/8
</TABLE>
<TABLE>
Consolidated Operating and Financial Statistics
<CAPTION>
Years Ended December 31, 1997 1996 1995 1994 1993 1992 1987
<S> <C> <C> <C> <C> <C> <C> <C>
ENERGY GENERATED
AND PURCHASED (millions of kWh):
Generated
- by Somerset Station 845 719 679 658 319 936 1,294
- by Nuclear Units 570 977 752 1,008 1,033 1,050 390
- by Jointly-Owned Units 1,350 848 1,410 1,615 1,809 2,105 2,050
- by Life of the Unit Contracts 805 526 236 648 602 793 569
- by Newport 1 1
Interchange with NEPOOL 372 381 573 295 360 157 236
Purchased Power - Unit Power 1,514 1,765 1,463 1,526 1,396 1,489 207
Total Generated and Purchased 5,456 5,216 5,113 5,750 5,520 6,531 4,746
OPERATING REVENUES
($ in thousands):
Residential $ 203,315 $ 192,569 $ 193,233 $ 190,662 $ 189,470 $ 176,538 $ 124,047
Commercial 168,680 164,096 169,841 169,241 179,145 170,034 114,857
Industrial 82,587 80,417 83,061 81,500 81,445 76,946 72,218
Other Electric Utilities 6,035 5,411 5,447 4,900 5,098 5,103 18,740
Other 25,574 14,281 17,482 17,282 21,790 21,314 11,192
Total Primary Sales Revenues 486,191 456,774 469,064 463,585 476,948 449,935 341,054
Unit Contracts 20,505 13,945 14,800 26,213 22,617 47,875 23,372
Non-Electric 61,817 56,349 79,499 74,480 66,912 44,154 2,703
Total Operating Revenues $ 568,513 $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964 $ 367,129
ENERGY SALES (millions of kWh):
Residential 1,783 1,740 1,697 1,678 1,624 1,575 1,328
Commercial 1,653 1,665 1,674 1,671 1,704 1,704 1,325
Industrial 889 868 867 850 816 785 863
Other Electric Utilities 79 86 75 74 61 68 365
Other 142 132 128 137 147 147 28
Total Primary Sales 4,546 4,491 4,441 4,410 4,352 4,279 3,909
Losses and Company Use 219 208 227 233 247 241 231
Total System Requirements 4,765 4,699 4,668 4,643 4,599 4,520 4,140
Unit Contracts 691 517 445 1,107 921 2,011 606
Total Energy Sales 5,456 5,216 5,113 5,750 5,520 6,531 4,746
NUMBER OF CUSTOMERS:
Residential 272,608 270,319 268,203 263,054 259,654 257,026 221,480
Commercial 27,599 27,331 27,401 29,004 30,805 32,851 25,480
Industrial 1,810 1,779 1,685 1,603 1,294 1,197 1,237
Other Electric Utilities 8 8 8 12 12 15 7
Other 34 34 34 34 34 34 29
Total Customers 302,059 299,471 297,331 293,707 291,799 291,123 248,233
Average Annual Revenue
per Residential Customer ($) 746 712 720 725 730 687 560
Average Annual Use per Residential
Customer (kWh) 6,540 6,437 6,327 6,379 6,254 6,128 5,996
AVERAGE REVENUE
PER KWH (cent):
Residential 11.40 11.06 11.39 11.36 11.67 11.21 9.34
Commercial 10.20 9.86 10.15 10.13 10.51 9.98 8.67
Industrial 9.29 9.26 9.58 9.59 9.98 9.80 8.37
</TABLE>
<TABLE>
Consolidated Operating and Financial Statistics
<CAPTION>
Years Ended December 31, 1997 1996 1995 1994 1993 1992 1987
<S> <C> <C> <C> <C> <C> <C> <C>
CAPITALIZATION ($ in thousands):
Bonds - Net $ 215,252 $ 277,313 $ 279,374 $ 288,449 $ 300,389 $ 306,898 $ 267,500
Other Long-Term Debt - Net 117,550 129,024 155,497 166,963 196,427 156,060 211,717
Total Long-Term Debt - Net 332,802 406,337 434,871 455,412 496,816 462,958 479,217
Preferred Stock - Net 34,512 33,935 33,155 32,290 31,953 44,346 44,931
Common Equity 373,467 371,813 375,229 365,443 333,165 266,855 285,383
Total Capitalization $ 740,781 $ 812,085 $ 843,255 $ 853,145 $ 861,934 $ 774,159 $ 809,531
CAPITALIZATION RATIOS (%):
Long-Term Debt 45 50 52 53 57 60 59
Preferred Stock 5 4 4 4 4 6 6
Common Equity 50 46 44 43 39 34 35
COMMON SHARE DATA:
Earnings per Average
Common Share ($) 1.86 1.50 1.61 2.41 2.44 2.00 3.46
Dividends per Share ($) 1.66 1.645 1.585 1.515 1.42 1.36 2.27
Payout (%) 89.2 109.7 98.4 62.9 58.2 68.0 65.6
Average Common
Shares Outstanding 20,435,997 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224 12,596,381
Total Common Shares
Outstanding 20,435,997 20,435,997 20,436,764 19,936,980 19,032,598 17,237,788 12,966,062
Book Value per Share ($) 18.27 18.19 18.36 18.33 17.50 15.48 22.01
Percent Earned On Average
Common Equity 10.2 8.2 8.8 13.6 15.0 13.2 17.1
Market Price ($):
High 26 5/8 24 1/4 25 27 3/8 29 7/8 25 1/4 40 1/2
Low 16 3/8 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8 24
Year End 26 1/4 17 3/8 23 5/8 22 28 24 3/4 28
Miscellaneous ($ in thousands):
Total Construction Expenditures ($) 76,280 63,182 78,461 50,870 76,770 71,914 126,856
Cash Construction Expenditures ($) 76,118 62,730 77,923 50,519 76,391 71,365 68,929
Internally Generated Funds ($) 85,637 77,545 90,883 79,274 79,691 48,933 14,554
Internally Generated Funds as
a % of Cash Construction (%) 112.5 123.6 116.6 156.9 104.3 68.6 21.1
Installed Capability - mw 1,075<F1> 1,208 1,191 1,212 1,256<F2> 1,325 1,091
Less: Unit Contract Sales - mw 35 60 35 85 85 85 108
System Capability - mw 1,040 1,148 1,156 1,127 1,171 1,240 983
System Peak Demand - mw 933 854 931 921 854 849 782
Reserve Margin (%) 11.5 34.4 24.2 22.4 37.1 46.1 25.8
System Load Factor (%) 58.3 62.6 57.2 57.5 61.5 57.5 60.4
Sources of Energy (%):
Nuclear 17.0 29.0 28.2 33.8 34.0 34.1 15.1
Coal 17.9 14.7 14.7 11.7 5.4 18.6 31.1
Oil 31.2 19.8 25.5 20.0 28.3 12.7 53.8
Gas 28.2 30.8 26.5 28.4 26.0 29.3
Other 5.7 5.7 5.1 6.1 6.3 5.3
Cost of Fuel (Mills per kWh):
Nuclear 5.7 5.0 6.3 6.1 7.5 7.7 9.2
Coal 18.6 19.6 20.3 20.9 24.1 21.2 20.5
Oil 31.0 37.7 30.2 27.1 25.5 26.0 28.3
Gas 16.4 14.4 14.3 14.1 15.1 13.0
All Fuels Combined 19.2 16.7 16.7 14.5 15.5 14.8 23.0
<FN>
<F1> Due to the extended outage of the Milestone 3 Nuclear Unit, our 46 mw
ownership share was not included in installed capability.
<F2> Excludes the 69 mw Somerset Station Unit #5 which was placed in
deactivated reserve on January 25, 1994.
</FN>
</TABLE>
Shareholder Information
Shares of Eastern Utilities Associates are listed on the New York and Pacific
Stock Exchanges, under the ticker symbol EUA. As of February 1, 1998, there
were 11,130 common shareholders of record.
Form 10-K
A copy of EUA's 1997 Annual Report on Form 10K filed with the Securities and
Exchange Commission is available to shareholders without charge by writing to
us.
Annual Meeting
The 1998 Annual Meeting of Shareholders will be held on
Monday, May 18, 1998, at 9:30 a.m., in the
Enterprise Room, 5th Floor
State Street Bank and Trust Company
225 Franklin Street
Boston, Massachusetts
Registrar, Transfer Agent and Dividend Disbursing Agent for Common and
Preferred Shares
Investor Relations
The First National Bank of Boston
c/o Boston EquiServe
P.O. Box 8040
Boston, MA 02266-8040
1-800-736-3001 (Toll-Free)
Lost or Stolen Stock Certificates
If your stock certificate is lost, destroyed or stolen, you should notify the
transfer agent immediately so a "stop transfer" order can be placed on the
missing certificate. The transfer agent then will send you the required
documents to obtain a re placement certificate.
Dividends
Schedule of anticipated record and payment dates for 1998 dividends on EUA
Common Shares:
Record Payment
January 30 February 17
May 1 May 15
July 31 August 15
November 2 November 16
Direct Deposit Plan
EUA Shareholders have the option of having their EUA dividends deposited
directly into their bank accounts. If you wish to participate, contact EUA
investor relations at 1-800-736-3001 (Toll-Free).
Replacement of Dividend Checks
If you do not receive your dividend check within ten business days after the
dividend payment date, or if your check is lost, destroyed or stolen, you
should notify the disbursing agent in writing for a replacement.
Dividend Reinvestment and Common
Share Purchase Plan
A Dividend Reinvestment and Common Share Purchase Plan is available to all
registered shareholders and EUA System company employees. It is a simple and
convenient method of purchasing additional shares of EUA common stock.
Participants also may make cash payments to purchase additional shares. You
may obtain complete details by writing to Clifford J. Hebert Jr., Vice
President - Finance & Treasurer at the address shown below under "Financial
Community Inquiries."
Duplicate Mailings
Duplicate mailings are costly. Shareholders may be receiving duplicate copies
of annual and quarterly reports due to multiple stock accounts in the same
household. To eliminate additional mailings of these reports, please write to
us and enclose label(s) or label information from the duplicate reports.
Dividend checks and proxy material will continue to be sent for each account on
record.
EUA is required by law to create a separate account for each name when stock is
held in similar but different names (e.g., John A. Smith, J. A. Smith, John A.
and Mary K. Smith, etc.). Please contact the Company for instructions if you
wish to consolidate multiple accounts.
Financial Community Inquiries
Institutional investors and securities analysts should direct
inquiries to:
Clifford J. Hebert, Jr., Vice President - Finance & Treasurer
EUA Service Corporation
Post Office Box 2333
Boston, MA 02107
(617) 357-9590
The name Eastern Utilities Associates is the designation of the Trustees for
the time being under a Declaration of Trust dated April 2, 1928, as amended.
All persons dealing with Eastern Utilities Associates must look solely to the
trust property for the enforcement of any claims against Eastern Utilities
Associates, as neither the Trustees, Officers nor Shareholders assume any
personal liability for obligations entered into on behalf of Eastern Utilities
Associates.
Internet Address
Visit EUA's Home Page on the World Wide Web at:
http://www.eua.com
"Picture of a Customer with a note " "Every customer, every employee,
every shareholder at Eastern Utilities makes a difference...""
EUA System Officers
Trustees
Russell A. Boss (A, P)
President and Chief Executive Officer
A. T. Cross Company
Lincoln, Rhode Island
Paul J. Choquette, Jr. (C, F)
Chairman and Chief Executive Officer
Gilbane Building Company
Providence, Rhode Island
Peter S. Damon (A, P)
President and Chief Executive Officer
Bank of Newport
Newport, Rhode Island
Peter B. Freeman (F, P)
Corporate Director and Trustee
Providence, Rhode Island
Larry A. Liebenow (A, C)
President and Chief Executive Officer
Quaker Fabric Corporation
Fall River, Massachusetts
Jacek Makowski (F, P)
Chairman, Poseidon Resources Corporation
Stamford, Connecticut
Wesley W. Marple, Jr. (A, C)
Professor of Business Administration
Northeastern University
Boston, Massachusetts
Donald G. Pardus
Chairman of the Board of Trustees and
Chief Executive Officer of the Association
Margaret M. Stapleton (A, F)
Vice President
John Hancock Mutual Life Insurance Company
Boston, Massachusetts
John R. Stevens
President and Chief Operating Officer of the Association
W. Nicholas Thorndike (C, F)
Corporate Director and Trustee
Brookline, Massachusetts
A Indicates member of Audit Committee
C Indicates member of Compensation and Nominating Committee
F Indicates member of Finance Committee
P Indicates member of Pension Trust Committee
Donald G. Pardus
Chairman of the Board of Trustees and
Chief Executive Officer
John R. Stevens
President and Chief Operating Officer
John D. Carney
Executive Vice President
Robert G. Powderly
Executive Vice President
Clifford J. Hebert, Jr.
Treasurer and Secretary
Donald T. Sena
Assistant Treasurer
Company Profile
Blackstone Valley Electric Company (Blackstone or the Company) is a retail
electric utility company. Blackstone supplies retail electric service to
approximately 85,000 customers in the cities of Central Falls, Pawtucket and
Woonsocket, and four surrounding towns in northern Rhode Island.
Blackstone is a wholly owned subsidiary of Eastern Utilities Associates (EUA).
EUA owns directly all of the shares of common stock of Blackstone, Eastern
Edison Company (Eastern Edison) and Newport Electric Corporation (Newport).
These EUA subsidiaries are collectively referred to as the Retail Subsidiaries.
Eastern Edison and Newport are retail electric utility companies operating in
southeastern Massachusetts and south coastal Rhode Island, respectively.
Eastern Edison owns all of the permanent securities of Montaup Electric Company
(Montaup), a generation and transmission company, which supplies electricity to
Blackstone, to Eastern Edison, to Newport and to two unaffiliated utilities for
resale. EUA also owns directly all of the shares of common stock of EUA
Service Corporation (EUA Service), EUA Cogenex Corporation (EUA Cogenex), EUA
Energy Investment Corporation (EUA Energy), EUA Ocean State Corporation (EUA
Ocean State), EUA Energy Services, Inc. (EUA Energy Services) and EUA
Telecommunications Corporation (EUA Telecommunications). EUA Service provides
various accounting, financial, engineering, planning, data processing and other
services to all EUA System companies. EUA Cogenex is an energy services
company. EUA Energy was organized to invest in energy related projects. EUA
Ocean State owns a 29.9% interest in Ocean State Power's two gas-fired
generating units in northern Rhode Island. EUA Energy Services markets energy
and energy related services. EUA Telecommunications provides
telecommunications and information services. The holding company system of
EUA, the Retail Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy,
EUA Ocean State, EUA Energy Services, and EUA Telecommunications is referred to
as the EUA System. The Core Electric Business consists of the Retail
Subsidiaries and Montaup. See Electric Utility Industry Restructuring for a
discussion of changes taking place in the utility industry in the
territories serviced by EUA's Core Electric Business.
Form 10-K
A copy of EUA's, Eastern Edison's and Blackstone's Co-Registrant 1997
Annual Report on Form 10-K, which is filed with the Securities and Exchange
Commission, is available without charge by contacting us at:
EUA Service Corporation
Post Office Box 2333
Boston, MA 02107
(617) 357-9590
Internet Address
Visit EUA's Home Page on the worldwide web at: http://www.eua.com.
MARKET FOR BLACKSTONE'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of Blackstone's common stock is owned beneficially and of record by
EUA.
The dividends paid on common stock during the past two years are as
follows:
Dividends Paid Dividends Paid
1997 Per Share 1996 Per Share
First Quarter $4.75 First Quarter $5.91
Second Quarter 4.75 Second Quarter 6.34
Third Quarter 4.75 Third Quarter 6.34
Fourth Quarter 4.75 Fourth Quarter 6.34
No dividend may be paid on the common stock unless full dividends on the
outstanding preferred stock for all past and the current quarterly dividend
periods have been paid or declared and set apart for payment. Blackstone's
First Mortgage Indenture and Deed of Trust securing its First Mortgage Bonds
contains provisions which restrict the payment by Blackstone of cash dividends
on its common stock. See Notes C and D of Notes to Financial Statements and
Management's Discussion and Analysis of Financial Condition and Review of
Operations under Financial Condition and Liquidity.
SELECTED FINANCIAL DATA
For the Years Ended December 31,
(In Thousands) 1997 1996 1995 1994 1993
Operating Revenues $140,258 $136,911 $140,861 $140,611 $143,666
Net Earnings 5,357 3,776 4,009 3,438 4,069
Total Assets 130,833 132,313 129,835 121,413 114,552
Capitalization:
Long-Term Debt-Net 33,500 35,000 36,500 38,000 39,500
Non-Redeemable Preferred
Stock (including premium) 6,130 6,130 6,130 6,130 6,130
Common Equity 38,092 36,232 37,045 37,180 35,378
Total Capitalization $ 77,722 $ 77,362 $ 79,675 $ 81,310 $ 81,008
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND REVIEW OF OPERATIONS
Overview
Net Earnings for 1997 increased approximately $1.6 million to $5.4 million
compared to 1996. Net Earnings for 1997 include a one-time charge of
approximately $260,000, on an after-tax basis, related to the costs of a
voluntary retirement incentive offer (VRI) recorded in 1997, discussed below.
Kilowatthour (kWh) sales of electricity for 1997 increased by 2.6% as compared
to 1996, led by increased sales to residential and commercial customers of 4.8%
and 2.6%, respectively.
Net Earnings for 1996 decreased approximately $200,000 to $3.8 million
compared to those of 1995. Earnings for 1995 include a one-time charge of
approximately $550,000, on an after-tax basis, related to the costs of the
1995 VRI. KWh sales of electricity for 1996 decreased by 1.3% as compared to
1995, largely due to milder weather. Sales to commercial and industrial
customers decreased by 3.0% and 2.5%, respectively, in 1996.
Comparison of Financial Results
Operating Revenues
Operating Revenues increased by approximately $3.3 million or 2.4% in 1997
as compared to 1996. This change was primarily due to recoveries of increased
conservation and load management (C&LM) expenses of approximately $800,000
(discussed below), an approximate 1.9% base rate increase effective January 1,
1997 pursuant to the Utility Restructuring Act of 1996 (URA), offset by
recoveries of lower purchased power expense (see discussions below).
Operating Revenues for 1996 decreased by approximately $4.0 million as
compared to those of 1995. This change was primarily due to recoveries of
lower purchased power and C&LM expenses, as discussed below, and decreased kWh
sales.
Voluntary Retirement Incentives
In June 1997, an early retirement offer was accepted by a group of
employees who were eligible for, but not offered, a VRI offer completed in
1995, resulting in a charge of approximately $400,000 (approximately $260,000
after-tax) to the Company's second quarter 1997 earnings.
Expenses
Purchased Power expense, recovered through Blackstone's purchased power
adjustment clause, represented 69% of total 1997 operating expense. Purchased
Power expense decreased approximately $700,000 or less than 1% in 1997 as
compared to 1996. As of August 1, 1997, pursuant to the URA, certain
commercial and industrial customers of Blackstone were given the opportunity to
choose alternate electricity suppliers, reducing purchased power requirements
and expense in 1997 as compared to 1996. Offsetting these decreases was an
increase of 16.3% in the average cost of fuel of Montaup, the Company's power
supplier. Outages at nuclear units, in which Montaup has an interest
contributed to a greater dependence on higher costing fossil fuels for its
energy requirements.
Purchased power expense decreased approximately $4.7 million or 4.9% in 1996 as
compared to 1995. Impacting purchased power expense in 1996 was a decrease in
C&LM expenses of approximately $3.1 million, which were included in purchased
power expenses in 1995 but included in Other Operation and Maintenance expense
in 1996, and decreased kWh requirements.
Other Operation and Maintenance expenses are comprised of two components,
Direct Controllable and Indirect. Direct Controllable expenses include expense
items such as salaries, fringe benefits, insurance, maintenance, etc. Indirect
expenses include items over which the Company has limited short-term control
including expenses related to accounting standards such as Statement of
Financial Accounting Standard No. 106, "Employers' Accounting for Post-
Retirement Benefits Other Than Pensions" (FAS106).
Other Operation and Maintenance expenses, including affiliated company
transactions, for 1997 increased approximately $800,000 or 3.4% as compared to
1996. This change was primarily due to increased C&LM expenses in 1997 which
are fully recoverable through rates. Other Operation and Maintenance expenses,
including affiliated company transactions, for 1996 increased by approximately
$2.7 million or 13.8% when compared to 1995. This change is primarily due to
an increase of $1.4 million in C&LM expenses recorded as Other Operation and
Maintenance expenses, a decrease in capitalized costs of approximately $500,000
and an increase in FAS106 expense of approximately $200,000. Also impacting
1996 results were increases in the provision for uncollectible accounts, legal
and storm related expenses aggregating approximately $700,000.
Taxes Other than Income decreased by approximately $200,000 or 2.0% in
1997 as compared to 1996 and approximately $300,000 or 3.6% in 1996 as compared
to 1995. These decreases were due primarily to 1% decreases in the Rhode
Island Gross Receipts Tax billed to industrial customers in both 1997 and 1996.
As of July 1997, the Rhode Island Gross Receipts Tax was no longer billed to
industrial customers of Blackstone.
Net Interest charges for 1997 increased by approximately $300,000 or 8.5%
as compared to 1996. This increase was primarily due to increased short-term
borrowings and increased intercompany interest expense offset by lower interest
on long-term debt due to reductions in long-term debt balances resulting from
required sinking fund payments. Net interest charges for 1996 decreased by
approximately $300,000 or 6.3%, primarily due to interest on decreased long-
term debt balances and decreased customer deposits interest.
Financial Condition and Liquidity
The Company is required to make capital expenditures in order to meet the
needs of its existing and future customers. For 1997, 1996 and 1995, the
Company's cash construction expenditures were $3.8 million, $4.2 million, and
$5.1 million, respectively. Internally generated funds provided approximately
164%, 104% and 134% of cash construction requirements in 1997, 1996 and 1995,
respectively.
Cash Construction expenditures are expected to be $4.3 million in 1998,
$6.4 million in 1999 and $4.6 million in 2000, and are expected to be financed
with internally generated funds. Traditionally, construction requirements in
excess of internally generated funds are obtained through short-term borrowings
which are ultimately funded with permanent capital.
In July 1997, several EUA System companies, including Blackstone, entered
into a three-year revolving credit agreement allowing for borrowings in
aggregate of up to $120 million. As of December 31, 1997, various financial
institutions have committed up to $75 million under the revolving credit
facility. At December 31, 1997, under the revolving credit agreement, the EUA
System had short-term borrowings available of approximately $13.5 million.
Blackstone had $1.4 million of short-term borrowings outstanding at year end
1997 and approximately $700,000 at year end 1996.
Blackstone's requirements for sinking fund payments and redemption of
securities for the five years following 1997 are $1.5 million in each of 1998,
1999 and 2000, and $3.3 million in each of 2001 and 2002.
Electric Utility Industry Restructuring Initiatives
Unbundled Services:
The electric utility industry in both Massachusetts and Rhode Island, the
states in which EUA provides electric services, is transitioning from a
traditional rate regulated environment to a competitive marketplace.
Traditional electric utility services - generation, transmission and
distribution - have been unbundled into separate and distinct services. The
generation, or supply, function is now competitive with customers able to
choose their own electricity supplier at market prices. The transmission and
distribution functions remain regulated services. The local distribution
company is responsible for providing distribution services to the ultimate
electricity consumer within its franchised service territory and the
transmission company is required to provide open access, non-discriminatory
transmission services to generation or supply companies.
Stranded costs:
Stranded costs represent prudently incurred costs of generation which are
now above their current economic value. In Rhode Island (see discussion below)
stranded costs have been defined to include items such as above market net
investments in generation assets, generation related regulatory assets, nuclear
decommissioning and above market commitments under current power purchase
contracts. A December 19, 1997 order from Federal Energy Regulatory Commission
(FERC) provides Montaup, the EUA System's generation company, with full
recovery of its stranded costs. Stranded costs are recovered, via a Contract
Termination Charge (CTC) under a contract termination agreement which
replaced the all-requirements contracts between Montaup and its retail
affiliates including Blackstone. In its order, FERC approved settlement
agreements between Montaup, its retail affiliates and consumer representatives
in Massachusetts and Rhode Island. Both states' regulatory bodies have
approved retail settlements in accordance with enabling state legislation.
Rhode Island-Retail:
On August 7, 1996, the Governor of Rhode Island signed into law the
Utility Restructuring Act of 1996 (URA). The URA provided for customer choice
of electricity supplier in several phases commencing July 1, 1997 for certain
customers and culminating with choice for all customers by July 1, 1998, or
sooner. Under the URA, the local distribution company retains the
responsibility of providing distribution services to the ultimate electricity
consumer within its franchised service territory. For customers who do not
choose an alternative supplier, the local distribution company must arrange for
standard offer service. Distribution companies are providers of last resort
service for customers who are unable to obtain their own supply.
The URA provides for full recovery of stranded costs, through a non-
bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The costs of net, above-market generation assets and
regulatory assets will be recovered, with a return, through a fixed component
of the transition charge from January 1, 1998, through December 31, 2009. A
variable component of the transition charge will recover, on a reconciling
basis, among other things, nuclear decommissioning and above market purchased
power commitments from January 1, 1998, through the life of the respective unit
or contract. The URA also provides for commitments to demand side management
initiatives and renewables, low-income customer protections, divestiture of at
least 15% of owned non-nuclear generating units as a valuation basis for
mitigation of stranded cost recovery, and performance-based ratemaking (PBR)
standards for electric distribution companies to be in effect until the end of
1998. These performance-based standards provide for a 6% minimum and an
approximate 12% maximum allowed return on equity for Blackstone. In addition,
the URA provides for adjustments to electric distribution companies' base rates
using the prior year's Consumer Price Index for 1997 and 1998 and other
performance factors. Under this provision of the law, base rates were
increased 1.3% for customers of Blackstone effective January 1, 1998.
In February 1997, Blackstone, Newport and Montaup reached a settlement in
principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the Rhode Island Public Utilities Commission
(RIPUC) outlining the terms of the settlement. The settlement was submitted to
the RIPUC in two separate filings which were approved on April 21, 1997 and
December 17, 1997, respectively. In addition to complying with the URA, the
settlement provided for a 13% rate reduction for Blackstone's customers
effective January 1, 1998, amendments to Blackstone's power contract with
Montaup to replace all-requirements provisions with a CTC commensurate with
retail access and the filing of a plan to divest all of Montaup's generating
assets. The net proceeds of the divestiture will be used to mitigate
the amount of Montaup's stranded costs to be recovered through the CTC. See
"Divestiture" below for a discussion of Montaup's divestiture process.
On December 17, 1997, the RIPUC approved a retail settlement which
included a distribution rate freeze through December 31, 2000, except for any
temporary credit or surcharge resulting from PBR implementation or the standard
offer reconciliation, and retail access for all customers commencing January 1,
1998. In addition to the approval of wholesale power contract amendments
by FERC, received on December 19, 1997, any disposition of generation assets
resulting from the agreements or the URA would also require the approval of the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935.
FERC-Wholesale:
On May 1, 1997, Montaup and Blackstone jointly filed amendments to their
FERC-approved all-requirements power contract. The filing included a
calculation for a CTC to recover stranded costs and a provision for standard
offer service for resale to retail customers who do not choose an alternate
generation supplier. These provisions replaced the services offered by the
all-requirements contracts upon full retail access pursuant to the URA. The
filing also included hold harmless provisions for Montaup's other wholesale
customers and for retail customers of Blackstone and lost revenue provisions
which allow for recovery of any of Montaup's lost revenues during the initial
phases of retail access in Rhode Island through completion of Montaup's
divestiture process. This filing allowed Blackstone to implement on July 1,
1997, the phase-in provisions of the URA and prevented any cross-subsidies by
their retail customers who were excluded from the groups of customers given
retail choice prior to January 1, 1998 and by Montaup's other customers.
On October 29, 1997, settlement agreements among Montaup, its affiliated
and non-affiliated customers, the Massachusetts Attorney General, the MADOER,
the RIDIV and RIPUC were submitted for FERC approval. These settlements
represent a comprehensive resolution of federal/wholesale issues of electric
utility industry restructuring based on the settlement agreements in Rhode
Island and Massachusetts. FERC approved the settlements on December 19, 1997,
accommodating retail choice for EUA's retail customers in Massachusetts and
Rhode Island.
Divestiture:
Montaup began marketing its portfolio of generation assets in July 1997,
and subsequently received bids from potential purchasers. On January 23, 1998,
based on EUA's review of the offers and discussion with potential purchasers,
Montaup announced that it was reopening the sales process on the majority of
its generating assets. The process is expected to require four to six months
to execute a purchase and sale agreement. The net proceeds of the sale, as
defined in the settlement agreements, will be used to mitigate Montaup's CTC to
its retail affiliates via a Residual Value Credit (RVC). The RVC will reduce
the fixed component of the CTC for the net proceeds, with a return, in equal
annual amounts over the period commencing on the date the RVC is implemented
through December 31, 2009. Subject to regulatory approvals, Montaup
anticipates the sale will be completed in early 1999.
Accounting Issues:
Historically, electric rates have been designed to recover a utility's
full cost of providing electric service including recovery of investment in
plant assets. Also, in a regulated environment, electric utilities are subject
to certain accounting rules that are not applicable to other industries. These
accounting rules allow regulated companies, in appropriate circumstances, to
establish regulatory assets and liabilities, which defer the current financial
impact of certain costs that are expected to be recovered in future rates. The
SEC has raised issues concerning the continued applicability of these standards
with certain other electric utilities in other states facing restructuring.
In July 1997, the Financial Accounting Standards Board's (FASB) Emerging
Issues Task Force (EITF) reached a consensus regarding certain issues raised
related to the application of Statement of Financial Accounting Standards No.
71 (FAS71), "Accounting for the Effects of Certain Types of Regulation." The
EITF determined that when sufficient detail is available for an enterprise to
reasonably determine, from legislation and enabling rate orders, how the
transition plan will affect the separable portion of its business being
deregulated, the enterprise should discontinue the application of FAS71 to that
deregulated portion of its business. The EITF also concluded that utilities
can continue to carry previously recorded regulatory assets on their balance
sheet if regulators have guaranteed a regulated cash flow stream to recover the
cost of those assets. Blackstone believes its retail distribution business
continues to meet the criteria for continued application of FAS71.
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover a company's costs, a write-
down of plant assets could be required pursuant to Financial Accounting
Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed Of." EUA does not anticipate any write-
down of plant assets as a result of approved restructuring plans or enacted
legislation at this time.
Environmental Matters
Blackstone and other companies owning generating units from which power is
obtained are subject, like other electric utilities, to environmental and land
use regulations at the federal, state and local levels. The federal
Environmental Protection Agency (EPA), and certain state and local authorities,
have jurisdiction over releases of pollutants, contaminants and hazardous
substances into the environment and have broad authority to set rules and
regulations in connection therewith, such as the Clean Air Act Amendments of
1990, which could require installation of pollution control devices
and remedial actions. In 1994, EUA instituted an environmental audit program
designed for Montaup and the Retail Subsidiaries, including Blackstone, to
ensure compliance with environmental laws and regulations and to identify and
reduce liability with respect to those requirements.
Because of the nature of Blackstone's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by such authorities. Blackstone generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs. Blackstone
has been notified with respect to a number of sites where they may be
responsible for such costs, including sites where they may have joint
and several liability with other responsible parties. It is the policy of the
EUA System companies to notify liability insurers and to initiate claims,
however, Blackstone is unable to predict whether liability, if any, will be
assumed by, or can be enforced against, the insurance carriers in these
matters.
As of December 31, 1997, Blackstone had incurred costs of approximately
$6.7 million, in connection with these sites. These amounts have been financed
primarily by internally generated cash. Blackstone is currently recovering
certain of its incurred environmental costs in rates. As a result of
the recoverability in current rates of environmental costs, and the uncertainty
regarding both its estimated liability, as well as potential contributions from
insurance carriers, Blackstone does not believe that the ultimate impact of
environmental costs will be material to its financial position and thus, no
loss provision is required at this time.
Blackstone estimates that additional costs of up to $1.3 million may be
incurred at these sites through 1998. Estimates beyond 1998 cannot be made
since site studies, which are the basis of these estimates, have not been
completed.
In addition to the previously discussed costs, Blackstone is currently
litigating responsibility for clean-up costs and related interest aggregating
$5.9 million. The cleanup cost were incurred by the Commonwealth of
Massachusetts at a site in which Blackstone has been named as the responsible
party. See Note H of "Notes to Financial Statements" for further discussion.
A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found wherever there is electricity. While some of the studies have indicated
some association between exposure to EMF and health effects, many others have
indicated no direct association. On October 31, 1996, the National Academy of
Sciences issued a literature review of all research to date, Possible Health
Effects of Exposure to Residential Electric and Magnetic Fields. Its most
widely reported conclusion stated, "No clear, convincing evidence exists to
show that residential exposures to EMF are a threat to human health."
Additional studies, which are intended to provide a better understanding of
EMF, are continuing. Management cannot predict the ultimate outcome of the EMF
issue.
Year 2000 Issue
Blackstone has conducted a comprehensive review of its computer systems to
identify the systems that could be affected by the Year 2000 Issue and is
developing an implementation plan to resolve the issue. The Year 2000 Issue is
the result of computer programs being written using two digits rather than four
to define the applicable year. Any programs that have time-sensitive software
may recognize a date using "00" as the year 1900 rather than the year 2000.
This could result in a major system failure or miscalculations. Blackstone
believes that, with modifications to existing software and conversions to new
software, the Year 2000 problem will not pose significant operational problems
for its computer systems as so modified and converted. It is anticipated that
all reprogramming efforts will be complete by the spring of 1999, allowing
adequate time for testing. In addition, notices have been sent to Blackstone's
primary processing vendors seeking assurance that plans are being developed to
address processing of transactions in the year 2000. Management does
not believe the year 2000 compliance expense will be material to Blackstone's
future operating results or future financial condition.
New Accounting Standards
In June 1997 the FASB issued Statement No. 130, "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive income and its
components (revenues, expenses, gains, and losses) in a set of general-purpose
financial statements. This Statement requires that all items that are required
to be recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with the same
prominence as other financial statements. This Statement is effective for
fiscal years beginning after December 15, 1997, and Blackstone will adopt
Statement 130 in the first quarter of 1998.
Other
Blackstone occasionally makes forward-looking projections of expected
future performance or statements of our plans and objectives. These forward-
looking statements may be contained in filings with the SEC, press releases and
oral statements. Actual results could differ materially from these statements,
therefore, no assurances can be given that such forward-looking statements and
estimates will be achieved.
Management's Discussion and Analysis of Financial Condition and Review of
Operations provides a summary of information regarding the Company's financial
condition and results of operation and should be read in conjunction with the
"Financial Statements" and "Notes to Financial Statements" in arriving at a
more complete understanding of such matters.
Financial Table of Contents
Statements of Income. .. . . . . . . . . . . . . . . 12
Statements of Retained Earnings . . . . . . . . . . . 12
Statements of Cash Flows . . . . . . . . . . . . . 13
Balance Sheets . . . . . . . . . . . . . . . . . . 14
Statements of Capitalization . .. . . . . . . . . . . 15
Notes to Financial Statements . . . . . . . . . . . . 17
Report of Independent Accountants . . . . . . . . . . . . 29
Blackstone Valley Electric Company
Statements of Income
Years Ended December 31,
(In Thousands)
1997 1996 1995
Operating Revenues $ 140,258 $ 136,911 $ 140,861
Operating Expenses:
Purchased Power (principally from
an affiliate) 90,327 91,016 95,725
Other Operation and Maintenance 11,682 11,781 10,938
Affiliated Company Transactions 10,943 10,092 8,280
Voluntary Retirement Incentive 363 0 912
Depreciation 5,725 5,594 5,501
Taxes - Other than Income 8,340 8,506 8,821
Income and Deferred Taxes 3,326 2,156 2,347
Total Operating Expenses 130,706 129,145 132,524
Operating Income 9,552 7,766 8,337
Allowance for Other Funds Used During
Construction 50 33
Other Income (Deductions) - Net 195 30 (38)
Income Before Interest Charges 9,747 7,846 8,332
Interest Charges:
Interest on Long-Term Debt 3,186 3,313 3,481
Other Interest Expense 996 524 612
Allowance for Borrowed Funds Used
During Construction (Credit) (81) (56) (59)
Net Interest Charges 4,101 3,781 4,034
Net Income 5,646 4,065 4,298
Preferred Dividend Requirements 289 289 289
Net Earnings Applicable to Common Stock $ 5,357 $ 3,776 $ 4,009
Statements of Retained Earnings
Years Ended December 31,
(In Thousands)
1997 1996 1995
Retained Earnings - Beginning of Year $ 9,121 $ 9,934 $ 10,069
Net Income 5,646 4,065 4,298
Total 14,767 13,999 14,367
Dividends Paid:
Preferred 289 289 289
Common 3,497 4,589 4,144
Retained Earnings - End of Year $ 10,981 $ 9,121 $ 9,934
The accompanying notes are an integral part of the financial statements.
Blackstone Valley Electric Company
Statements of Cash Flows
Years Ended December 31,
(In Thousands)
1997 1996 1995
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 5,646 $ 4,065 $ 4,298
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 6,184 5,976 5,953
Deferred Taxes (1,667) (561) 1,200
Investment Tax Credit, Net (181) (182) (183)
Allowance for Funds Used During Construction (50) (34)
Other - Net (1,768) (555) 643
Net Changes in Operating Assets and Liabilities:
Accounts Receivable 238 2,389 (2,324)
Materials and Supplies 113 66 (172)
Accounts Payable (7,977) (383) 7,540
Accrued Taxes 650 (362) 337
Other - Net 6,762 740 (7,239)
Net Cash Provided from Operating Activities 8,000 11,143 10,019
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (3,769) (4,196) (5,064)
Net Cash (Used in) Investing Activities (3,769) (4,196) (5,064)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (1,500) (1,500) (1,500)
Common Share Dividends Paid (3,497) (4,589) (4,144)
Preferred Dividends Paid (289) (289) (289)
Net Increase (Decrease) in Short-Term Debt 665 (524) 1,259
Net Cash (Used in) Financing Activities (4,621) (6,902) (4,674)
Net (Decrease) Increase in Cash (390) 45 281
Cash and Temporary Cash Investments at
Beginning of Year 798 753 472
Cash and Temporary Cash Investments at
End of Year $ 408 $ 798 $ 753
Cash paid during the year for:
Interest (Net of Amounts Capitalized) $ 3,436 $ 3,390 $ 3,565
Income Taxes $ 4,906 $ 3,301 $ 690
The accompanying notes are an integral part of the financial statements.
Blackstone Valley Electric Company
Balance Sheets
December 31,
(In Thousands)
ASSETS
1997 1996
Utility Plant and Other Investments:
Utility Plant $ 141,609 $ 139,366
Less Accumulated Provision for Depreciation 55,851 51,952
Net Utility Plant 85,758 87,414
Non-Utility Property - Net 45 46
Total Utility Plant and Other Investments 85,803 87,460
Current Assets:
Cash and Temporary Cash Investments 408 798
Accounts Receivable:
Customers, Net 11,394 11,141
Accrued Unbilled Revenue 1,584 1,196
Others 1,631 2,541
Associated Companies 513 482
Plant Materials and Operating Supplies
(at average cost) 759 873
Other Current Assets 395 417
Total Current Assets 16,684 17,448
Other Assets (Note A) 28,346 27,405
Total Assets $ 130,833 $ 132,313
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 38,092 $ 36,232
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt 33,500 35,000
Total Capitalization 77,722 77,362
Current Liabilities:
Long-Term Debt Due Within One Year 1,500 1,500
Notes Payable 1,400 735
Accounts Payable:
Public 960 509
Associated Companies 8,332 16,759
Customer Deposits 1,049 1,113
Taxes Accrued 2,065 1,415
Dividends Accrued 72 72
Interest Accrued 842 899
Other Current Liabilities 8,017 1,157
Total Current Liabilities 24,237 24,159
Deferred Credits:
Unamortized Investment Credit 2,380 2,561
Mendon Road Contingency Reserve 7,065 6,716
Other Deferred Credits 7,532 7,286
Total Deferred Credits 16,977 16,563
Accumulated Deferred Taxes 11,897 14,229
Commitments and Contingencies (Note H)
Total Liabilities and Capitalization $ 130,833 $ 132,313
The accompanying notes are an integral part of the financial statements.
Blackstone Valley Electric Company
Statements of Capitalization
December 31,
(In Thousands)
1997 1996
Common Stock, $50 par value, authorized 233,000
shares, issued and outstanding 184,062 shares $ 9,203 $ 9,203
Other Paid-in Capital 17,908 17,908
Retained Earnings 10,981 9,121
Total Common Equity 38,092 36,232
Non-Redeemable Cumulative Preferred Stock:
4.25%, $100 par value, 35,000 shares (1) 3,500 3,500
5.60%, $100 par value, 25,000 shares (1) 2,500 2,500
Premium 130 130
Total Non-Redeemable Cumulative Preferred Stock 6,130 6,130
Long-Term Debt:
First Mortgage Bonds:
9 1/2% due 2004 (Series B) 10,500 12,000
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds Due 2014 (2) 6,500 6,500
35,000 36,500
Less Portion Due Within One Year 1,500 1,500
Total Long-Term Debt 33,500 35,000
Total Capitalization $ 77,722 $ 77,362
(1) Authorized and Outstanding.
(2) Weighted average interest rate was 3.7% for 1997 and 3.5% for 1996.
The accompanying notes are an integral part of the financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 1997, 1996 and 1995
(A) Nature of Operations and Summary of Significant Accounting Policies:
General: Blackstone Valley Electric Company (Blackstone or the Company) is
principally engaged in the distribution and sale of electric energy.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
The accounting policies and practices of Blackstone are subject to
regulation by the Federal Energy Regulatory Commission (FERC) and the Rhode
Island Public Utilities Commission (RIPUC) with respect to its rates and
accounting. Blackstone conforms with generally accepted accounting
principles, as applied in the case of regulated public utilities, and conforms
with the accounting requirements and ratemaking practices of the RIPUC. A
description of the significant accounting policies follows.
Transactions with Affiliates: The Company is a wholly-owned subsidiary of
EUA. In addition to its investment in the Company, EUA has interests in other
retail and wholesale utility companies, a service corporation, and five other
non-utility companies.
Transactions between Blackstone and other affiliated companies include the
following: purchased power costs billed by Montaup of approximately $90,276,000
in 1997, $90,970,000 in 1996 and $95,683,000 in 1995; accounting, engineering
and other services rendered by EUA Service of approximately $12,608,000 in
1997, $11,923,000 in 1996 and $10,448,000 in 1995; and operating revenue from
the rental of transmission facilities to Montaup of approximately $3,124,000 in
1997, $2,501,000 in 1996 and $3,047,000 in 1995. Transactions with affiliated
companies are subject to review by applicable regulatory commissions.
Utility Plant and Depreciation: Utility plant is stated at original cost.
The cost of additions to utility plant includes contracted work, direct labor
and material, allocable overhead, allowance for funds used during construction
and indirect charges for engineering and supervision. For financial statement
purposes, depreciation is computed on the straight-line method based on
estimated useful lives of the various classes of property. Provisions for
depreciation were equivalent to a composite rate of approximately 3.9% in 1997,
1996 and 1995, based on the average depreciable property balances at the
beginning and end of each year.
Other Assets: The components of Other Assets at December 31, 1997 and 1996
are detailed as follows:
(In Thousands)
1997 1996
Regulatory Assets:
Unamortized losses on reacquired debt $ 394 $ 425
Deferred SFAS 109 costs (Note B) 7,211 7,487
Deferred SFAS 106 costs 727 872
Mendon Road Judgment (Note H) 6,154 6,154
Other regulatory assets 1,551 1,234
Total regulatory assets 16,037 16,172
Other deferred charges and assets:
Unamortized debt expenses 587 639
Mendon Road Escrow 7,065 6,716
Other 4,657 3,878
Total Other Assets $28,346 $27,405
Regulatory Accounting: Blackstone is subject to certain accounting rules that
are not applicable to other industries. These accounting rules allow regulated
companies, in appropriate circumstances, to establish regulatory assets and
liabilities, which defer the current financial impact of certain costs
that are expected to be recovered in future rates. Blackstone believes that
its operations continue to meet the criteria established in these accounting
standards.
Allowance for Funds Used During Construction (AFUDC): AFUDC represents the
estimated cost of borrowed and equity funds used to finance the Company's
construction program. In accordance with regulatory accounting, AFUDC is
capitalized, as a cost of utility plant, in the same manner as certain general
and administrative costs. AFUDC is not an item of current cash income, but is
recovered over the service life of utility plant in the form of increased
revenues collected as a result of higher depreciation expense. The rate used
in calculating AFUDC was 7.1% in 1997, 9.4% in 1996 and 8.6% in 1995.
Operating Revenues: Revenues are based on billing rates authorized by the
RIPUC. The Company follows the policy of accruing the estimated amount of
unbilled base rate revenues for electricity provided at the end of the month to
more closely match costs and revenues. Through 1997, the Company accrued the
difference between fuel and purchased power costs incurred and fuel and
purchased power costs billed to its customers. In 1998, the Company began
accruing revenues consistent with provisions of approved settlement agreements
and state legislation.
Income Taxes: The general policy of Blackstone with respect to accounting
for federal and state income taxes is to reflect in income the estimated amount
of taxes currently payable, as determined from the EUA consolidated tax return
on an allocated basis, and to provide for deferred taxes on certain items
subject to temporary differences to the extent permitted by the regulatory
commissions.
Blackstone has provided deferred income taxes on certain income and
expense items that are accounted for in different periods for financial
accounting purposes than for income tax purposes. Prior to 1987, AFUDC and
certain costs for pensions, employee benefits and payroll-related insurances
and payroll taxes applicable to construction activity, which were included in
utility plant, were deducted for income tax purposes. Deferred taxes on these
amounts and on certain differences created by the use of different depreciation
methods in the years prior to 1981 have not been provided. The tax benefits on
these items have been flowed through in accordance with approved rate orders of
the RIPUC.
As permitted by the regulatory commissions, it is the policy of the
Company to defer recognition of annual investment tax credits and to amortize
these credits over the productive lives of the related assets.
Cash and Temporary Cash Investments: Blackstone considers all highly liquid
investments and temporary cash investments with a maturity of three months or
less when acquired to be cash equivalents.
(B) Income Taxes:
Components of income and deferred tax expense for the years 1997, 1996,
and 1995 are as follows:
____________________________________________________________________________
(In Thousands) 1997 1996 1995
Federal:
Current $5,202 $2,901 $1,329
Deferred (1,580) (531) 1,133
Investment Tax Credit, Net (181) (182) (184)
$3,441 $2,188 $2,278
State:
Current 3 2 1
Deferred (118) (34) 68
(115) (32) 69
Charged to Operations 3,326 2,156 2,347
Charged to Other Income:
Current 143 40 3
Total $3,469 $2,196 $2,350
Total income tax expense was different than the amounts computed by
applying federal income tax statutory rates to book income subject to tax for
the following reasons:
________________________________________________________________________
(In Thousands) 1997 1996 1995
Federal Income Tax Computed
at Statutory Rates $3,190 $2,191 $2,327
(Decreases) Increases in Tax from:
Equity Component of AFUDC (17) (12)
Consolidated Tax Savings (32) (15)
Depreciation Differences 256 283 262
Amortization and Utilization of ITC (181) (182) (184)
State Taxes, Net of Federal
Income Tax Benefit (74) (21) 45
Cost of Removal (67)
Other 278 (26) (6)
Total Income Tax Expense $3,469 $2,196 $2,350
(B) Income Taxes (continued)
Blackstone adopted Statement of Financial Accounting Standard No. 109,
"Accounting for Income Taxes" (FAS109) which required recognition of deferred
income taxes for temporary differences that are reported in different years for
financial reporting and tax purposes using the liability method. Under the
liability method, deferred tax liabilities or assets are computed using the tax
rates that will be in effect when the temporary differences reverse.
Generally, for regulated companies, the change in tax rates may not be
immediately recognized in operating results because of rate making treatment
and provisions in the Tax Reform Act of 1986. Total deferred tax assets and
liabilities for 1997 and 1996 are comprised as follows:
Deferred Tax Deferred Tax
Assets Liabilities
($000) ($000)
1997 1996 1997 1996
Plant Related Plant Related
Differences $1,489 $1,581 Differences $14,490 $ 14,593
Pensions 602 425 Refinancing
Other 2,872 773 Costs 138 144
Total $4,963 $2,779 Pensions 513 436
Other 1,719 1,832
Total $16,860 $17,005
Blackstone has recorded on its Balance Sheets as of December 31, 1997 and
1996 a regulatory liability to ratepayers of approximately $3.4 million and
$3.0 million, respectively. This amount primarily represents excess deferred
income taxes resulting from the reduction in the federal income tax rate and
also includes deferred taxes provided on investment tax credits. Also at
December 31, 1997 and 1996, a regulatory asset of approximately $7.2 million
and $7.5 million, respectively, has been recorded, representing the cumulative
amount of federal income taxes on temporary depreciation differences which were
previously flowed through to ratepayers.
(C) Capital Stock:
There were no changes in the number of shares of common or preferred stock
during the years ended December 31, 1997, 1996, and 1995.
In the event of involuntary liquidation, the holders of non-redeemable
preferred stock of Blackstone are entitled to $100 per share plus accrued
dividends. In the event of voluntary liquidation, or if redeemed at the option
of the Company, each share of the non-redeemable preferred stock is entitled to
accrued dividends and to: 4.25% issue, $104.40; 5.60% issue, $103.82.
Under the terms and provisions of the First Mortgage Indenture and of the
issues of preferred stock of Blackstone, certain restrictions are placed upon
the payment of dividends on common stock by the Company. At the years ended
December 31, 1997 and 1996, the respective capitalization ratios were in excess
of the minimum which would make these restrictions effective.
(D) Retained Earnings:
Under the provisions of Blackstone's First Mortgage Indenture, retained
earnings in the amount of $5,984,441 were unrestricted as to the payment of
cash dividends on its common stock at December 31, 1997.
(E) Long-Term Debt:
Blackstone's First Mortgage Bonds are collateralized by substantially all
of its utility plant.
Blackstone's Variable Rate Demand Bonds are collateralized by an
irrevocable letter of credit which expires on January 21, 1999. The letter of
credit permits extensions on an annual basis upon mutual agreement of the bank
and Blackstone.
The aggregate amount of Blackstone's cash sinking fund requirements and
maturities for long-term debt for each of the five years following 1997 is $1.5
million in each of 1998, 1999, 2000, and $3.3 million in each of 2001 and 2002.
(F) Lines of Credit:
In July 1997, several EUA System companies, including Blackstone, entered
into a three-year revolving credit agreement allowing for borrowings in
aggregate of up to $120 million. As of December 31, 1997, various financial
institutions have committed up to $75 million under the revolving credit
facility. In accordance with the revolving credit agreement, commitment fees
are required to maintain certain lines of credit. At December 31, 1997 under
the revolving credit agreement, the EUA System had short-term borrowings
available of approximately $13.5 million. Blackstone had $1.4 million of
short-term borrowings outstanding at December 31, 1997. During 1997,
Blackstone's weighted average interest rate for short-term borrowings was 5.8%.
(G) Fair Value of Financial Instruments:
The following methods were used to estimate the fair value of each class
of financial instruments for which it is practicable to estimate.
Cash and Temporary Cash Investments: The carrying amount approximates
fair value because of the short-term maturity of those instruments.
Long-Term Debt: The fair value of the Company's long-term debt was based
on quoted market prices for such securities.
The estimated fair values of the Company's financial instruments at
December 31, 1997 and 1996 were as follows (In Thousands):
<TABLE>
Carrying Amount Fair Value
<CAPTION>
1997 1996 1997 1996
<S> <C> <C> <C> <C>
Cash and Temporary Cash Investments $ 408 $ 798 $ 408 $ 798
Long-Term Debt $35,000 $36,500 $36,363 $37,596
</TABLE>
(H) Commitments and Contingencies:
Pensions: Blackstone participates with other EUA System companies in a non-
contributory, defined benefit pension plan covering substantially all of their
employees (Retirement Plan). Retirement Plan benefits are based on years of
service and average compensation over the four years prior to retirement.
It is the EUA System's policy to fund the Retirement Plan on a current basis in
amounts determined to meet the funding standards established by the Employee
Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including amounts
related to the 1997 and 1995 voluntary retirement incentive offers, for 1997,
1996 and 1995 included the following components ($ In Thousands):
1997 1996 1995
Service cost - benefits earned
during the period $ 651 $ 664 $ 606
Interest cost on projected
benefit obligations 2,448 2,373 2,346
Actual (return) loss on assets (7,696) (4,216) (9,560)
Net amortization and deferrals 4,242 1,063 6,470
Net periodic pension income $ (355) $ (116) $ (138)
Voluntary retirement incentive 410
Total periodic pension income $(355) $ (116) $ 272
Assumptions used to determine pension cost:
Discount Rate 7.50% 7.25% 8.25%
Compensation Increase Rate 4.25% 4.25% 4.75%
Long-Term Return on Assets 9.50% 9.50% 9.50%
The discount rate used to determine pension obligations, effective January
1, 1998 was changed to 7.25%. The funded status of the Retirement Plan cannot
be presented separately for Blackstone as it participates in the Retirement
Plan with other subsidiaries of EUA.
The voluntary retirement incentives also resulted in approximately
$281,000 and $310,000 of non-qualified pension benefits which were expensed in
1997 and 1995, respectively. At December 31, 1997, approximately $169,000 is
included in other liabilities for these unfunded benefits.
EUA also maintains non-qualified supplemental retirement plans for certain
officers of the EUA System (Supplemental Plans). Benefits provided under the
Supplemental Plans are based primarily on compensation at retirement date. EUA
maintains life insurance on the participants of the Supplemental Plans to fund
in whole, or in part, its future liabilities under the Supplemental Plans. For
the years ended December 31, 1997, 1996 and 1995, Blackstone's portion of
expenses related to the Supplemental Plans were approximately $322,000,
$284,000, and $306,000, respectively.
The Company also provides a defined contribution 401(k) savings plan for
substantially all employees. The Company's matching percentage of employees'
voluntary contributions to the plan, amounted to approximately $113,000 in
1997, approximately $111,000 in 1996, and approximately $148,000 in 1995.
Post-Retirement Benefits: Retired employees are entitled to participate in
health care and life insurance benefit plans. Health care benefits are subject
to deductibles and other limitations. Health care and life insurance benefits
are partially funded by Blackstone for all qualified employees.
Blackstone adopted FAS106, "Employers' Accounting for Post-Retirement
Benefits Other Than Pensions," as of January 1, 1993. This standard
establishes accounting and reporting standards for such post-retirement
benefits as health care and life insurance. Under FAS106 the present value of
future benefits is recorded as a periodic expense over employee service periods
through the date they become fully eligible for benefits. With respect to
periods prior to adopting FAS106, EUA elected to recognize accrued costs (the
Transition Obligation) over a period of 20 years, as permitted by FAS106. The
resultant annual expense, including amortization of the Transition Obligation
and net of capitalized and deferred amounts, was approximately $1.4 million in
1997, $1.5 million in 1996, and $1.3 million in 1995.
The total cost of Post-Retirement Benefits other than Pensions, including
amounts related to the 1997 and 1995 Voluntary Retirement Incentive offers, for
1997, 1996 and 1995 includes the following components ($ In Thousands):
1997 1996 1995
Service cost $ 202 $ 216 $ 191
Interest cost 1,050 1,060 1,170
Actual return on plan assets (304) (6) (111)
Amortization of transition obligation 836 835 829
Net other amortization & deferrals (117) (274) (239)
Net periodic post-retirement benefit costs 1,667 1,831 1,840
Voluntary retirement incentive 40 90
Total periodic post-retirement benefit costs $1,707 $1,831 $ 1,930
Assumptions:
Discount rate 7.50% 7.25% 8.25%
Health care cost trend rate-near-term 7.00% 9.00% 11.00%
Health care cost trend rate-long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.25% 4.75%
Rate of return on plan assets 7.75% 7.50% 5.50%
Reconciliation of funded status:
($ In Thousands) 1997 1996 1995
Accumulated post-retirement benefit obligation (APBO):
Retirees $(7,181) $ (7,045) $ (8,235)
Active employees fully eligible for benefits (1,706) (1,543) (2,825)
Other active employees (2,135) (2,413) (3,052)
Total $(11,022) $(11,001) $(14,112)
Fair Value of assets (primarily notes and bonds) 2,408 1,573 924
Unrecognized transition obligation 10,662 11,372 12,083
Unrecognized net (gain) loss (5,816) (5,551) (2,217)
(Accrued) prepaid post-retirement ben. cost $ (3,768) $ (3,607) $ (3,322)
The discount rate used to determine post-retirement benefit obligations,
was changed to 7.25% effective January 1, 1998, and was used to calculate the
funded status of Post-Retirement benefits at December 31, 1997.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1997 by approximately
$173,000 and increase the total accumulated post-retirement benefit obligation
by $1.1 million.
Blackstone has also established an irrevocable external Voluntary
Employee's Beneficiary Association (VEBA) Trust Fund. Contributions to the
VEBA fund commenced in March 1993 and totaled approximately $1.2 million during
1997 and 1996 and $1.1 million during 1995.
Environmental Matters: The Comprehensive Environmental Response,
Compensation Liability Act of 1980, as amended by the Superfund Amendments and
Reauthorization Act of 1986, and certain similar state statutes authorize
various governmental authorities to seek court orders compelling responsible
parties to take cleanup action at disposal sites which have been determined by
such governmental authorities to present an imminent and substantial danger to
the public and to the environment because of an actual or threatened release of
hazardous substances. Because of the nature of Blackstone's business, various
by-products and substances are produced or handled which are classified as
hazardous under the rules and regulations promulgated by the EPA as well as
state and local authorities. Blackstone generally provides for the disposal
of such substances through licensed contractors, but these statutory provisions
generally impose potential joint and several responsibility on the generators
of the wastes for cleanup costs. Blackstone has been notified with respect to
a number of sites where they may be responsible for such costs, including sites
where they may have joint and several liability with other responsible parties.
It is the policy of Blackstone to notify liability insurers and to initiate
claims. However, it is not possible at this time to predict whether liability,
if any, will be assumed by, or can be enforced against, the insurance carriers
in these matters.
On December 13, 1994, the United States District Court for the District of
Massachusetts (District Court) issued a judgment against Blackstone, finding
Blackstone liable to the Commonwealth of Massachusetts (Commonwealth) for the
full amount of response costs incurred by the Commonwealth in the cleanup of a
by-product of manufactured gas at a site at Mendon Road in Attleboro,
Massachusetts. The judgment also found Blackstone liable for interest and
litigation expenses calculated to the date of judgment. The total liability is
approximately $5.9 million, including approximately $3.6 million in interest
which has accumulated since 1985. Due to the uncertainty of the ultimate
outcome of this proceeding and anticipated recoverability, Blackstone recorded
the $5.9 million District Court judgment as a deferred debit. This amount is
included with Other Assets on the Balance Sheet at December 31, 1997 and 1996.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue
on the judgment amount.
Blackstone filed a Notice of Appeal of the District Court's judgment and
filed its brief with the United States Court of Appeals for the First Circuit
(Circuit Court) on February 24, 1995. On October 6, 1995, the Circuit Court
vacated the District Court's $5.9 million judgement to refer the matter to the
EPA to determine whether the chemical substance ferric ferrocyanide (FFC)
contained within the by-product is a hazardous substance.
Given the present posture of the case, Blackstone may not be liable to
reimburse the Commonwealth for the Mendon Road cleanup costs if the EPA
determines that FFC is not a hazardous substance. On January 9, 1997,
Blackstone met with representatives of EPA and the Commonwealth to discuss the
procedure EPA would follow in resolving the FFC issue. In January 1997,
Blackstone submitted written comments which were followed by the Commonwealth's
written reply in March 1997. Both parties submitted additional memoranda to
EPA during remainder of the year. The EPA will now determine whether FFC is a
hazardous substance. Further court proceedings are likely.
On January 28, 1994, Blackstone filed a complaint in the Massachusetts
District Court, seeking, among other relief, contribution and reimbursement
from Stone & Webster Inc., of New York City and several of its affiliated
companies (Stone & Webster), and Valley Gas Company of Cumberland, Rhode
Island (Valley) for any damages incurred by Blackstone regarding the Mendon
Road site. On November 7, 1994, the Court denied motions to dismiss the
complaint filed by Stone & Webster and Valley. This proceeding was stayed in
December 1995 pending final EPA determination as to whether FFC is a hazardous
substance.
In addition, Blackstone has notified certain liability insurers and has
filed claims with respect to the Mendon Road site, as well as other sites.
Blackstone reached settlement with one carrier for reimbursement of legal costs
related to the Mendon Road case. In January 1996, Blackstone received the
proceeds of the settlement.
As of December 31, 1997, Blackstone had incurred costs of approximately
$6.7 million (excluding the $5.9 million Mendon Road judgment) in connection
with the investigation and cleanup of these sites. These amounts have been
financed primarily by internally generated cash. Blackstone is currently
amortizing all of its incurred costs over a five-year period consistent with
prior regulatory recovery periods and is recovering certain of those costs in
rates. The Company estimates that additional costs of up to approximately $1.3
million (excluding the $5.9 million Mendon Road judgment) may be incurred at
these sites through 1998 by it and the other responsible parties. Estimated
amounts after 1998 are not now determinable since site studies, which are the
basis of these estimates, have not been completed.
As a result of the recoverability of cleanup costs in rates and the
uncertainty regarding both its estimated liability, as well as potential
contributions from insurance carriers and other responsible parties, Blackstone
does not believe that the ultimate impact of the environmental costs will be
material to its financial position and thus, no loss provision is required at
this time.
A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found wherever there is electricity. While some of the studies have indicated
some association between exposure to EMF and health effects, many others have
indicated no direct association. On October 31, 1996, the National Academy of
Sciences issued a literature review of all research to date, Possible Health
Effects of Exposure to Residential Electric and Magnetic Fields. Its most
widely reported conclusion stated, "No clear, convincing evidence exists to
show that residential exposures to EMF are a threat to human health."
Additional studies, which are intended to provide a better understanding of
EMF, are continuing.
Some states have enacted regulations to limit the strength of EMF at the
edge of transmission line rights-of-way. The Rhode Island legislature has
enacted a statute which authorizes and directs the Rhode Island Energy Facility
Siting Board to establish rules and regulations governing construction of high
voltage transmission lines of 69 kv or more. In addition, an energy facility
siting application, in Rhode Island must include, when applicable, any current
independent, scientific research pertaining to EMF exposure for review by the
Board. Management cannot predict the impact, if any, that legislation or other
developments concerning EMF may have on Blackstone.
Other: In early 1997, ten plaintiffs brought suit against numerous
defendants, including EUA, for injuries and illness allegedly caused by
exposure to asbestos over approximately a thirty-year period, at premises,
including some owned by EUA companies. The total damages claimed in all of
these complaints was $25 million in compensatory and punitive damages, plus
exemplary damages and interest and costs. Each complaint names between fifteen
and twenty-eight defendants, including EUA. These complaints have been
referred to the applicable insurance companies. Counsel has been retained
by the insurers and is actively defending all cases. Three cases have been
dismissed as against EUA companies, with prejudice. EUA cannot predict the
ultimate outcome of this matter at this time.
Report of Independent Accountants
To the Directors and Shareholder of
Blackstone Valley Electric Company:
We have audited the accompanying balance sheets and statements of
capitalization of Blackstone Valley Electric Company (the Company) as of
December 31, 1997 and 1996, and the related statements of income, retained
earnings and cash flows for each of the three years in the period ended
December 31, 1997. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Company as of December 31,
1997 and 1996, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 3, 1998
Company Profile
Eastern Edison Company (Eastern Edison or the Company) is a retail
electric utility company. Eastern Edison supplies retail electric service to
approximately 184,000 customers in 22 cities and towns in southeastern
Massachusetts. The largest communities served are the cities of Brockton and
Fall River, Massachusetts. Eastern Edison is a wholly owned subsidiary of
Eastern Utilities Associates (EUA). EUA owns directly all of the shares of
common stock of Eastern Edison, Blackstone Valley Electric Company (Blackstone)
and Newport Electric Corporation (Newport). These EUA subsidiaries are
collectively referred to as the Retail Subsidiaries. Blackstone and
Newport are retail electric utility companies operating in northern Rhode
Island and south coastal Rhode Island, respectively. Eastern Edison owns all
of the permanent securities of Montaup Electric Company (Montaup), a generation
and transmission company, which supplies electricity to Eastern Edison, to
Blackstone, to Newport and to two unaffiliated utilities for resale. EUA also
owns directly all of the shares of common stock of EUA Service Corporation (EUA
Service), EUA Cogenex Corporation (EUA Cogenex), EUA Energy Investment
Corporation (EUA Energy), EUA Ocean State Corporation (EUA Ocean State), EUA
Energy Services Corporation (EUA Energy Services), and EUA Telecommunications
Corporation (EUA Telecommunications). EUA Service provides various accounting,
financial, engineering, planning, data processing and other services to all EUA
System companies. EUA Cogenex is an energy services company. EUA Energy was
organized to invest in energy related projects. EUA Ocean State owns a 29.9%
interest in Ocean State Power's two gas-fired generating units in northern
Rhode Island. EUA Energy Services owns an interest in a limited liability
company which markets energy and energy services. EUA Telecommunications
provides telecommunications and information services. The holding company
system of EUA, the Retail Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA
Energy, EUA Ocean State, EUA Energy Services, and EUA Telecommunications is
referred to as the EUA System. The Core Electric Business consists of the
Retail Subsidiaries and Montaup. See Electric Utility Industry Restructuring
for a discussion of changes taking place in the utility industry in the
territories served by EUA's Core Electric Business.
Form 10-K
A copy of EUA's, Eastern Edison's and Blackstone's Co-Registrant 1997
Annual Report on Form 10-K, which is filed with the Securities and Exchange
Commission, is available without charge by contacting us at:
EUA Service Corporation
Post Office Box 2333
Boston, MA 02107
(617) 357-9590
Internet Address
Visit EUA's Home Page on the worldwide web at: http://www.eua.com. MARKET FOR
EASTERN EDISON'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of Eastern Edison's common stock is owned beneficially and of record
by Eastern Utilities Associates (EUA).
The dividends paid on Eastern Edison's common stock during the past two
years are as follows:
Dividends Paid Dividends Paid
1997 Per Share 1996 Per Share
First Quarter $2.70 First Quarter $2.87
Second Quarter 2.70 Second Quarter 3.00
Third Quarter 2.70 Third Quarter 3.00
Fourth Quarter 2.70 Fourth Quarter 3.00
In January of 1997, a special common stock dividend was declared
and paid in the amount of $17
million.
No dividend may be paid on Eastern Edison's common stock unless
full dividends on Eastern Edison's outstanding Preferred Stock for
all past and the current quarterly dividend periods have been paid or
declared and set apart for payment, nor may any dividends be paid on
Eastern Edison's common stock if Eastern Edison is in default on any
sinking fund obligation provided for its Preferred Stock. See also
Notes C, D and E of Notes to Consolidated Financial Statements.
SELECTED CONSOLIDATED FINANCIAL DATA
For the Years Ended December 31,
(In Thousands) 1997 1996 1995 1994 1993
____________________________________________________________________________
Operating Revenues $435,014 $404,808 $420,069 $418,424 $417,021
Net Earnings 27,059 30,983 31,455 31,395 28,145
Total Assets 777,124 775,082 739,198 756,045 742,273
Capitalization:
Long-Term Debt-Net 162,491 222,402 222,313 229,224 264,134
Redeemable Preferred
Stock-Net 27,612 27,035 26,218 25,257 24,824
Common Equity 218,468 240,213 244,368 225,064 223,005
Total Capitalization $408,571 $489,650 $492,899 $479,545 $511,963
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND REVIEW OF OPERATIONS
Overview
Consolidated Net Earnings were approximately $27.1 million in 1997, a
decrease of $3.9 million or 12.7% as compared to 1996 Consolidated Net Earnings
of approximately $31.0 million. The 1997 results include the impacts of
increased jointly owned units expenses, primarily related to the extended
Millstone 3 outage, and increased expenses due to a June 1997 voluntary
retirement incentive offer (VRI) discussed below.
1996 Consolidated Net Earnings of approximately $31.0 million decreased
$0.5 million, or 1.5% compared to those of 1995 which included a one-time
charge of approximately $1.5 million, on an after tax basis, related to the
1995 VRI. The 1996 results were impacted by increased expenses related to an
unusual number of severe storms which struck Eastern Edison's service
territory during 1996 and increased legal expenses, partially offset by a
decrease in interest expense from debt issues that matured in 1995.
Comparison of Financial Results
Operating Revenues
Operating Revenues of approximately $435.0 million increased approximately
$30.2 million or 7.5% as compared to 1996. This change was primarily due to
increased recoveries of purchased power, fuel and conservation and load
management (C&LM) expenses aggregating approximately $23.2 million. Also
impacting revenues was increased base rate recoveries and increased short-term
contract demand sales.
Operating Revenues for 1996 decreased by approximately $15.3 million, as
compared to 1995. The change was primarily due to recoveries of decreased C&LM
and purchased power expenses aggregating approximately $14.0 million and
decreased contract demand sales of $1.6 million.
Voluntary Retirement Incentives
In June of 1997, an early retirement offer was accepted by a group of
employees who were eligible for, but not offered a VRI completed in 1995,
resulting in a charge of approximately $700,000 (approximately $500,000 after-
tax) to second quarter 1997 earnings.
Expenses
The Company's most significant expense items continue to be fuel and
purchased power expenses which together comprised about 59% of total operating
expenses for 1997. Fuel expense increased by approximately $18.6 million or
20.1% as compared to 1996. Outages of nuclear units in 1997 contributed to a
greater dependence on higher cost fossil fuels for energy requirements,
resulting in an increase in average fuel costs of 16.3% in 1997. Also
impacting fuel expense was an increase in total energy generated and purchased
of 4.6% in 1997 due mainly to increased sales to NEPOOL and increased short-
term unit contract energy sales. Fuel expense increased by $1.3 million or
1.4% in 1996 as compared to 1995 due to primarily to a 2.0% increase in total
energy generated and purchased.
Purchased Power demand expense increased approximately $600,000 or less
than 1% in 1997. This change is primarily due to increased billings from the
Pilgrim and the Maine Yankee Nuclear Units and the Potter #2 Fossil Unit
aggregating approximately $6.5 million. These increases were offset by
decreased billings from Connecticut Yankee and Ocean State Power Project (OSP)
of approximately $3.0 million and approximately $2.8 million, respectively.
Purchased Power demand expense decreased $6.8 million or 5.4% in 1996. The
decrease was due primarily to the impact of lower billings from the
Pilgrim nuclear unit of approximately $4.2 million which included a prior
period refund of approximately $2.0 million, and decreased billings from the
OSP and Maine Yankee aggregating $2.5 million.
Other Operation and Maintenance expenses (O&M) are comprised of two
components, Direct Controllable and Indirect. Direct Controllable expenses
include expense items such as salaries, fringe benefits, insurance,
maintenance, etc. Indirect expenses include items over which the Company has
limited short-term control and include such expense items as Montaup's joint
ownership interests in generating facilities such as Seabrook I and Millstone
3, power contracts where transmission rental fees are fixed, conservation and
load management expenses that are fully recovered in revenues and expenses
related to accounting standards such as Statement of Financial Accounting
Standard No. 106, "Employers' Accounting for Post Retirement Benefits Other
Than Pensions" (FAS106).
Other O&M expenses, including affiliated company transactions, increased
approximately $14.1 million or 15.3% in 1997. This change was primarily due to
increased jointly owned unit expense of approximately $9.0 million, of which
$5.0 million is related to the Millstone 3 outages and the remainder is due to
increased expenses related to the scheduled maintenance outages at the Canal
and Seabrook units. Also impacting the change was increased C&LM expenses of
approximately $1.8 million, increased legal expenses of approximately $1.3
million and $1.2 million of transmission expenses related to new transmission
tariffs implemented by FERC in 1997 to accommodate utility industry
restructuring. Other O&M expenses, including affiliated company transactions,
decreased by $4.8 million or 5% in 1996. The change was primarily due to
decreased C&LM expenses of $7.7 million, lower power contract and transmission
expenses of Montaup and effective cost control efforts aggregating $1.1
million. Offsetting these decreases somewhat were increases in storm related,
legal and jointly owned unit expenses aggregating $4.5 million.
Financial Condition and Liquidity
Eastern Edison's and Montaup's need for permanent capital is primarily
related to the construction of facilities required to meet the needs of
existing and future customers. For 1997, 1996 and 1995, Eastern Edison's and
Montaup's combined cash construction expenditures were $15.7 million, $26.0
million, and $23.4 million, respectively. Internally generated funds provided
approximately 123%, 118% and 236% of these combined cash construction
requirements in 1997, 1996 and 1995, respectively.
Cash construction expenditures are expected to be approximately $22.7
million in 1998, $16.1 million in 1999, and $14.5 million in 2000, and are
expected to be financed with internally generated funds.
In the utility industry, cash construction requirements not met with
internally generated funds are obtained through short-term borrowings which are
ultimately funded with permanent capital. In July 1997, several EUA System
companies; including Eastern Edison and Montaup, entered into a three-year
revolving credit agreement allowing for borrowings in aggregate of up to $120
million. As of December 31, 1997 various financial institutions have committed
up to $75 million under the revolving credit facility. At December 31, 1997
under the revolving credit agreement the EUA System had short-term borrowings
available of approximately $13.5 million. At December 31, 1997, Eastern
Edison had $4.7 million of outstanding short-term debt and Montaup had no
outstanding short-term debt.
In addition to construction expenditures, projected requirements for
maturing long-term debt securities through 2002 are $60 million in 1998 and $35
million in 2002. The Company has no sinking fund requirements through the
year 2002.
Electric Utility Industry Restructuring Initiatives
Unbundled Services:
The electric utility industry in both Massachusetts and Rhode Island, the
states in which EUA provides electric services, is transitioning from a
traditional rate regulated environment to a competitive marketplace.
Traditional electric utility services - generation, transmission and
distribution - have been unbundled into separate and distinct services. The
generation, or supply, function is now competitive with customers able to
choose their own electricity supplier at market prices. The transmission and
distribution functions remain regulated services. The local distribution
company is responsible for providing distribution services to the ultimate
electricity consumer within its franchised service territory and the
transmission company is required to provide open access, non-discriminatory
transmission services to generation or supply companies.
Stranded Costs:
Stranded costs represent prudently incurred costs of generation which are
now above their current economic value. In both Massachusetts and Rhode Island
(see discussions below) stranded costs have been defined to include items such
as above market net investments in generation assets, generation related
regulatory assets, nuclear decommissioning and above market commitments under
current power purchase contracts. A December 19, 1997 order from FERC provides
Montaup, with full recovery of its stranded costs. Stranded costs are
recovered, via a Contract Termination Charge (CTC) under a contract termination
agreement which replaced the all-requirements contracts formerly in force
between Montaup and its retail affiliates. In its order, FERC approved
settlement agreements between Montaup, its retail affiliates and consumer
representatives in Massachusetts and Rhode Island. Both states' regulatory
bodies have approved retail settlements in accordance with enabling state
legislation. At December 31, 1997 Montaup estimated its stranded costs,
including unmitigated investment in owned generation, generation-related
regulatory assets, above-market purchase power commitments, nuclear
decommissioning and transition expenses to be approximately $1 billion on a
present value basis. This estimate is subject to significant uncertainties
including the future market price of electricity. See "Divestiture" below for
a discussion of stranded cost mitigation.
Rhode Island - Retail:
On August 7, 1996, the Governor of Rhode Island signed into law the
Utility Restructuring Act of 1996 (URA). The URA provides for customer choice
of electricity supplier in several phases commencing July 1, 1997 for certain
customers and culminating with choice for all customers by July 1, 1998, or
sooner. Under the URA, the local distribution company retains the
responsibility of providing distribution services to the ultimate electricity
consumer within its franchised service territory. For customers who do not
choose an alternative supplier, the local distribution company must arrange
for standard offer service. Distribution companies are providers of last
resort service for customers who are unable to obtain their own supply.
The URA provides for full recovery of stranded costs, through a non-
bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The costs of net, above-market generation assets and
regulatory assets will be recovered, with a return, through a fixed component
of the transition charge from January 1, 1998, through December 31, 2009. A
variable component of the transition charge will recover, on a reconciling
basis, among other things, nuclear decommissioning and above market purchased
power commitments from January 1, 1998, through the life of the respective
unit or contract. The URA also provides for commitments to demand side
management initiatives and renewables, low-income customer protections,
divestiture of at least 15% of owned non-nuclear generating units as a
valuation basis for mitigation of stranded cost recovery, and performance-
based ratemaking (PBR) standards for electric distribution companies to be in
effect until the end of 1998.
In February 1997, Blackstone, Newport and Montaup reached a settlement in
principle with the Rhode Island Division of Public Utilities and Carriers
(RIDIV) and the state's Attorney General and filed a Memorandum of
Understanding (MOU) with the Rhode Island Public Utilities Commission (RIPUC),
outlining the terms of the settlement. The settlement was submitted to the
RIPUC in two separate filings which were approved on April 21, 1997 and
December 17, 1997, respectively. In addition to complying with the URA, the
settlement, similar in many respects to the settlement negotiated in
Massachusetts, described below, provided for, among other things, amendments to
Blackstone and Newport power contracts with Montaup to replace all-requirements
provisions with a CTC commensurate with retail access and the filing of a plan
to divest all of Montaup's generating assets. The net proceeds of the
divestiture will be used to mitigate the amount of Montaup's stranded costs to
be recovered through the CTC. See "Divestiture" below for a discussion of
Montaup's divestiture process.
On December 17, 1997, the RIPUC approved a retail settlement which
included a distribution rate freeze through December 31, 2000, except for any
temporary credit or surcharge resulting from PBR implementation or the standard
offer reconciliation, and retail access for all customers commencing January 1,
1998. In addition to the approval of wholesale power contract amendments by
FERC, received on December 19, 1997 (See "FERC -Wholesale" below), any
disposition of generation assets resulting from the agreements or the URA would
also require the approval of the Securities and Exchange Commission (SEC) under
the Public Utility Holding Company Act of 1935.
Massachusetts - Retail:
On December 23, 1996, Eastern Edison and Montaup reached an agreement in
principle with the Attorney General of Massachusetts and the Massachusetts
Department of Energy Resources (MADOER) and filed a MOU with the Massachusetts
Department of Telecommunications and Energy (DTE) (formerly the Department of
Public Utilities) outlining the terms of a plan, similar in many aspects to
the URA, which would allow retail customers to choose their supplier of
electricity in 1998 and provide Eastern Edison and Montaup full recovery of
stranded costs. On May 16, 1997 an Offer of Settlement was filed with the DTE.
The Offer of Settlement provided all of Eastern Edison's customers the
ability to choose an alternative supplier of electricity beginning as soon as
January 1, 1998. Until a customer chooses an alternative supplier, that
customer would receive standard offer service which would be priced to
guarantee at least a 10% reduction in electricity rates. Eastern Edison would
be required to arrange for standard offer service through December 31, 2004 and
would purchase power for standard offer service from suppliers through a
competitive bidding process. Montaup has guaranteed standard offer supply
at a fixed price schedule for the duration of the standard offer period. For
competitive suppliers to be eligible to provide supplies for standard offer
service, their prices must be competitive with the fixed prices guaranteed by
Montaup. In the event that some, or all, of the standard offer requirement is
not awarded to competitive suppliers, Montaup has an obligation to provide such
requirement at the indicated fixed price schedule, so called backstop service.
This backstop service will be assigned proportionately to purchasers of
Montaup's generating capacity. The agreement is also designed to achieve full
divestiture of Montaup's generating assets via implementation of a plan, that
would require (1) functional separation by Montaup of its generating and
transmission businesses, and (2) full market valuation and sale of all non-
nuclear assets through an auction or equivalent process.
On March 1, 1998, commensurate with retail choice in Massachusetts
Montaup's FERC-approved, all-requirements wholesale contract with Eastern
Edison was terminated. In its place, Montaup is billing Eastern Edison a CTC
designed to recover, among other things, Montaup's stranded costs. Eastern
Edison recovers the CTC through a non-bypassable transition access charge to
all of its distribution customers. The transition access charge will be
reduced by the fair market value of Montaup's generating assets as determined
by selling, spinning off, or otherwise disposing of such generating facilities.
See "Divestiture" below.
Embedded costs associated with generating plants and regulatory assets are
recovered, with a return, over a period of twelve years ending December 31,
2009. Purchased power contracts and nuclear decommissioning costs are
recovered as incurred over the life of those obligations, a period expected
to extend beyond twelve years. The initial transition access charge is set at
3.04 cents per kWh through December 31, 2000, and is expected to decline
thereafter.
The agreement also establishes a performance component for Eastern Edison,
incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates are frozen until December 31,
2000. Subsequent to the commencement of retail choice, Eastern Edison's
annual return on equity is subject to a floor of 6% and a ceiling of 11.75%.
On November 25, 1997, the Governor of Massachusetts signed the Electric
Industry Restructuring Act (the Act) into law. The Act directed the DTE to
require electric companies to accommodate retail access to generation services
and choice of supplier by March 1, 1998 and to require electric companies to
file restructuring plans to do so. The Act also provides for a 10% reduction
in electric rates commencing March 1, 1998 and an additional 5% reduction,
adjusted for inflation, commencing September 1, 1999. The additional 5%
reduction may be accomplished with benefits from asset divestiture and/or
securitization.
On December 23, 1997 the DTE approved the Settlement as being in
substantial compliance with the Act. Retail access commenced on March 1, 1998
for Eastern Edison's retail customers.
In January 1998, several parties filed motions for reconsideration of
Eastern Edison's approved settlement agreement and motions to extend the
judicial appeal period with the DTE. The motions for reconsideration claim
that provisions of the approved plan involving consumer rates, cost recovery,
energy efficiency and reliability do not meet standards set forth in the Act.
The DTE denied one party's motions and that party has appealed the DTE's ruling
to the Massachusetts Supreme Judicial Court. Management cannot predict the
ultimate outcome of the pending motions for reconsideration or judicial
appeal.
The Office of the Attorney General has certified a referendum petition to
repeal the Act as a matter appropriate for a referendum initiative. A petition
was filed with the Election Division of the Office of the Secretary of State in
February 1998. A question on repealing the Act will be presented to voters on
the November 1998 ballot. EUA and the electric industry in Massachusetts will
actively oppose repeal. Management cannot predict the outcome of the November
ballot question.
FERC - Wholesale:
On May 1, 1997, Montaup and the R.I. Distribution Companies jointly filed
amendments to their FERC-approved all-requirements power contracts. The filing
included a calculation for a CTC to recover stranded costs and a provision for
standard offer service for resale to retail customers who do not choose an
alternate generation supplier as discussed under "Massachusetts-Retail" above.
These provisions replaced the services offered by the all-requirements
contracts upon full retail access pursuant to the URA. The filing also
included hold harmless provisions for Montaup's other wholesale customers
and for retail customers of the R.I. Distribution Companies and lost revenue
provisions, which allow for recovery of any of Montaup's lost revenues for the
period from the initial phases of retail access in Rhode Island through
completion of Montaup's divestiture process. This filing allowed the R.I.
Distribution Companies to implement on July 1, 1997, the phase-in provisions of
the URA and prevented any cross-subsidies by their retail customers who were
excluded from the groups of customers given retail choice prior to January 1,
1998 and by Montaup's other customers.
On May 30, 1997, elements of the Massachusetts Settlement Agreement,
including the CTC calculation, which fall under the jurisdiction of FERC were
filed with FERC.
The May 1st and May 30th filings were consolidated by FERC and on October
29, 1997, settlement agreements among Montaup, its affiliated and non-
affiliated customers, the Massachusetts Attorney General, the MADOER, the RIDIV
and RIPUC were submitted for FERC approval. These settlements represent a
comprehensive resolution of federal/wholesale issues of electric utility
industry restructuring based on the settlement agreements in Massachusetts and
Rhode Island. FERC approved the settlements on December 19, 1997,
accommodating retail choice for EUA's retail customers in Massachusetts and
Rhode Island.
Divestiture:
Montaup began marketing its portfolio of generation assets in July 1997,
and subsequently received bids from a number of potential purchasers. On
January 23, 1998, based on a review of the offers and discussions with
potential purchasers, Montaup announced that it was reopening the sales
process on the majority of its generating assets. The process is expected to
require four to six months to execute a purchase and sale agreement. The net
proceeds of the sale, as defined in the settlement agreements, will be used to
mitigate Montaup's CTC to its retail affiliates via a Residual Value Credit
(RVC). The RVC will reduce the fixed component of the CTC for the net
proceeds, with a return, in equal annual amounts over the period commencing on
the date the RVC is implemented through December 31, 2009. Subject to
regulatory approvals, Montaup anticipates the sale will be completed in early
1999.
Accounting Issues:
Historically, electric rates have been designed to recover a utility's
full cost of providing electric service including recovery of investment in
plant assets. Also, in a regulated environment, electric utilities are subject
to certain accounting rules that are not applicable to other industries. These
accounting rules allow regulated companies, in appropriate circumstances, to
establish regulatory assets and liabilities, which defer the current financial
impact of certain costs that are expected to be recovered in future rates. The
SEC has raised issues concerning the continued applicability of these standards
with certain other electric utilities in other states facing restructuring.
In July 1997, the Financial Accounting Standards Board's (FASB) Emerging
Issues Task Force (EITF) reached a consensus regarding certain issues raised
related to the application of Statement of Financial Accounting Standards No.
71 (FAS71), "Accounting for the Effects of Certain Types of Regulation." The
EITF determined that when sufficient detail is available for an enterprise to
reasonably determine, from legislation and enabling rate orders, how the
transition plan will affect the separable portion of its business being
deregulated, the enterprise should discontinue the application of FAS71 to
that deregulated portion of its business. The EITF also concluded that
utilities can continue to carry previously recorded regulatory assets on their
balance sheet if regulators have guaranteed a regulated cash flow stream to
recover the cost of those assets.
In light of approved restructuring settlement agreements and restructuring
legislation in both Massachusetts and Rhode Island, EUA has determined that
Montaup no longer will apply the provisions for FAS71 to the generation portion
of its business. Due to the recoverability of regulatory assets granted in the
approved restructuring plans, EUA believes that the discontinuation of FAS71
for the generation portion of Montaup's business will not have a material
impact on EUA's results of operation or financial condition. EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover a company's costs, a write-
down of plant assets could be required pursuant to Financial Accounting
Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of." EUA does not anticipate any write-down
of plant assets as a result of approved restructuring plans or enacted
legislation at this time.
Environmental Matters
Eastern Edison, Montaup and other companies owning generating units from
which power is obtained are subject, like other electric utilities, to
environmental and land use regulations at the federal, state and local levels.
The federal Environmental Protection Agency (EPA), and certain state and local
authorities, have jurisdiction over releases of pollutants, contaminants and
hazardous substances into the environment and have broad authority to set rules
and regulations in connection therewith, such as the Clean Air Act Amendments
of 1990, which could require installation of pollution control devices
and remedial actions. In 1994, EUA instituted an environmental audit program
designed to ensure compliance with environmental laws and regulations and to
identify and reduce liability with respect to those requirements.
Because of the nature of Eastern Edison's and Montaup's business, various
by-products and substances are produced or handled which are classified as
hazardous under the rules and regulations promulgated by such authorities.
Eastern Edison and Montaup typically provide for the disposal of such
substances through licensed contractors, but statutory provisions generally
impose potential joint and several responsibility on the generators of the
wastes for cleanup costs. In the past Eastern Edison and Montaup had been
notified with respect to a number of sites where they were allegedly
responsible for such costs, including sites where they allegedly had joint and
several liability with other responsible parties. Eastern Edison and Montaup
are currently not involved in any environmental site investigations.
It is the policy of the EUA System companies to notify liability insurers and
to initiate claims related to such costs.
A number of scientific studies in the past several years have examined the
possibility of health effects from electric and magnetic fields (EMF) that are
found wherever there is electricity. While some of the studies have indicated
some association between exposure to EMF and health effects, many others
have indicated no direct association. On October 31, 1996, the National
Academy of Sciences issued a literature review of all research to date,
"Possible Health Effects of Exposure to Residential Electric and Magnetic
Fields." Its most widely reported conclusion stated, "No clear, convincing
evidence exists to show that residential exposures to EMF are a threat to human
health." Additional studies, which are intended to provide a better
understanding of EMF, are continuing. Management cannot predict the ultimate
outcome of the EMF issue.
Nuclear Power Issues
Montaup has a 4.01% ownership interest in Millstone 3, an 1154-mw nuclear
unit that is jointly owned by a number of New England utilities, including
subsidiaries of Northeast Utilities (Northeast). Subsidiaries of Northeast
are the lead participants in Millstone 3. On March 30, 1996, it was necessary
to shut down the unit following an engineering evaluation which determined that
four safety-related valves would not be able to perform their design function
during certain postulated events.
The Nuclear Regulatory Commission (NRC) has raised numerous issues with
respect to the unit and certain of the other nuclear units operated by
Northeast. The NRC informed Northeast that it was establishing a Special
Projects Office to oversee inspection and licensing activities at Millstone and
directed Northeast to submit a plan for disposition of safety issues raised by
employees and retain an independent third-party to oversee implementation of
this plan.
In March of 1997, Northeast announced that Millstone 3 had been designated
as the lead unit in the recovery process of the three Millstone nuclear units
that are currently out of service. Millstone 3 is the largest of the three
units currently out of service, and its return to service will most benefit the
energy needs of the New England region.
On January 8, 1998, Northeast announced that Millstone 3 was "physically
ready for restart" indicating that virtually all of the restart-required
physical work had been completed. Northeast indicated that a small amount of
systems work needs to be completed prior to restart. Various NRC and
independent inspections are required prior to restart. EUA cannot predict when
the plant will be restarted. While Millstone 3 is out of service, Montaup will
continue to incur incremental replacement power costs estimated at up to $1
million per month.
Montaup has been paying its share of Millstone 3's O&M expenses on a
reservation of right basis. The fact that Montaup makes payment for these
expenses is not an admission of financial responsibility for expenses incurred
or to be incurred due to the outage.
In August 1997, nine non-operating owners, including Montaup, who together
own approximately 19.5% of Millstone 3, filed a demand for arbitration against
Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company
(WMECO) as well as lawsuits against Northeast and its Trustees. CL&P and
WMECO, owners of approximately 65% of Millstone 3, are Northeast subsidiaries
which agreed to be responsible for the proper operation of the unit.
The non-operating owners of Millstone 3 claim that Northeast and its
subsidiaries failed to comply with NRC regulations, failed to operate the
facility in accordance with good utility operating practice and attempted to
conceal their activities from the non-operating owners and the NRC. The
arbitration and lawsuits seek to recover costs associated with replacement
power and O&M costs resulting from the shutdown of Millstone 3. The non-
operating owners conservatively estimate that their losses will exceed $200
million.
Montaup cannot predict the ultimate outcome of the NRC inquiries or legal
proceedings brought against CL&P, WMECO and Northeast or the impact which they
may have on Montaup and the EUA system.
On August 6, 1997, as the result of an economic evaluation, the Maine
Yankee Board of Directors voted to permanently close that nuclear plant.
Montaup has a 4.0% equity ownership in Maine Yankee with a book value of
approximately $3.2 million at December 31, 1997. Montaup's share of
the total estimated costs for the permanent shutdown, decommissioning, and
recovery of the remaining investment in Maine Yankee, is approximately $35.4
million and is included with Other Liabilities on the Consolidated Balance
Sheet for the period ending December 31, 1997. Also, due to anticipated
recoverability, a regulatory asset has been recorded for the same amount and is
included with Other Assets. The recovery of this estimated amount is subject
to approval of FERC. Montaup cannot predict the ultimate outcome of FERC's
review.
Also, as a result of the shutdown, Montaup and the other equity owners of
Maine Yankee have been notified by the Secondary Purchasers that they will no
longer make payments for purchased power to Maine Yankee. The Secondary
Purchase Contracts are between the equity owners as a group and 30
municipalities throughout New England. The equity owners are currently making
payments to Maine Yankee to cover the payments that would be made by the
municipals.
On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation
of Arbitration to the equity owners of Maine Yankee. On December 15, 1997, the
equity owners as a group filed at FERC a Complaint and Petition for
Investigation, Contract Modification, and Declaratory Order. The equity
owners are seeking an order from FERC declaring that the Secondary Purchasers
remain responsible for payments due under the Purchase Contracts and directing
the Secondary Purchasers to make such payments. The equity owners also seek a
modification of the Purchase Contracts to extend the termination date or
otherwise to ensure that the equity owners may fully recover from the Secondary
Purchasers a share of the costs of shutting down and decommissioning the Maine
Yankee plant that is proportional to the Secondary Purchasers' entitlements to
energy from the plant. Management does not believe that this contract issue
will have a material effect on EUA's future operating results or financial
position and cannot predict its ultimate outcome at this time.
Recent actions by the NRC, some of which are cited above, indicate that
the NRC has become more critical and active in its oversight of nuclear power
plants. EUA is unable to predict at this time, what, if any, ramifications
these NRC actions will have on any of the other nuclear power plants in
which Montaup has an ownership interest or power contract.
Montaup is recovering through rates its share of estimated decommissioning
costs for the Millstone 3 and Seabrook I nuclear generating units. Montaup's
share of the currently allowed estimated total costs to decommission Millstone
3 is approximately $21.9 million in 1997 dollars and Seabrook I is
approximately $13.7 million in 1997 dollars. These figures are based on
studies performed for the lead owners of the units. Montaup also pays into
decommissioning reserves, pursuant to contractual arrangements, at other
nuclear generating facilities in which it has an equity ownership interest or
life-of-unit entitlement. Such expenses are currently recovered through rates.
In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee,
individually, as well as a number of other utilities, filed suit in federal
appeals court seeking a court order to require the Department of Energy (DOE)
to immediately establish a program for the disposal of spent nuclear fuel.
Yankee Atomic and Connecticut Yankee are also seeking damages of approximately
$70 million and $90 million, respectively. Under the Federal Energy Policy Act
of 1992 and Nuclear Waste Policy Act, the DOE was to provide for the disposal
of radioactive wastes and spent nuclear fuel starting in 1998 and has collected
funds from owners of nuclear facilities to do so. Management cannot predict
the ultimate outcome of this issue.
Year 2000 Issue
The Company has conducted a comprehensive review of its computer systems
to identify the systems that could be affected by the Year 2000 Issue and is
developing an implementation plan to resolve the issue. The Year 2000 Issue is
the result of computer programs being written using two digits rather than four
to define the applicable year. Any programs that have time-sensitive software
may recognize a date using "00" as the year 1900 rather than the year 2000.
This could result in a major system failure or miscalculations. The Company
believes that, with modifications to existing software and conversions to new
software, the Year 2000 problem will not pose significant operational problems
for its computer systems as so modified and converted. It is anticipated that
all reprogramming efforts will be complete by the spring of 1999, allowing
adequate time for testing. In addition, notices have been sent to the
Company's primary processing vendors seeking assurance that plans are being
developed to address processing of transactions in the year 2000. Management
does not believe the year 2000 compliance expense will be material to the
Company's future operating results or future financial condition.
New Accounting Standards
In June 1997 the FASB issued Statement No. 130, "Reporting Comprehensive
Income," which establishes standards for reporting comprehensive income and its
components (revenues, expenses, gains, and losses) in a set of general-purpose
financial statements. This Statement requires that all items that are required
to be recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with the same
prominence as other financial statements. This Statement is effective for
fiscal years beginning after December 15, 1997, and the Company will adopt
Statement 130 in the first quarter of 1998.
Other
The Company occasionally makes forward-looking projections of expected
future performance or statements of our plans and objectives. These forward-
looking statements may be contained in filings with the SEC, press releases and
oral statements. Actual results could differ materially from these statements.
Therefore, no assurances can be given that such forward-looking statements and
estimates will be achieved.
Management's Discussion and Analysis of Financial Condition and Review of
Operations provides a summary of information regarding the Company's financial
condition and results of operation and should be read in conjunction with the
"Consolidated Financial Statements" and "Notes to Consolidated Financial
Statements" in arriving at a more complete understanding of such matters.
Financial Table of Contents
Consolidated Statements of Income. . . . . . . . . . 16
Consolidated Statements of Retained Earnings . . . . . . 16
Consolidated Statements of Cash Flow . . . . . . . . . 17
Consolidated Balance Sheets . . . . . . . . . . . . . . 18
Consolidated Statements of Capitalization . . . . . . . 19
Notes to Consolidated Financial Statements . . . . . . . 21
Report of Independent Accountants . . . . . . . . . . . 36
Eastern Edison Company and Subsidiary
Consolidated Statements of Income
Years Ended December 31,
(In Thousands)
1997 1996 1995
Operating Revenues:
From Affiliated Companies $ 127,882 $ 127,981 $ 133,388
Other 307,132 276,827 286,681
Total Operating Revenues 435,014 404,808 420,069
Operating Expenses:
Fuel 110,717 92,159 90,881
Purchased Power - Demand 119,434 118,843 125,594
Other Operation and Maintenance 78,232 66,311 73,638
Affiliated Company Transactions 28,119 25,908 23,386
Voluntary Retirement Incentive 737 2,413
Depreciation and Amortization 27,489 26,810 26,039
Taxes - Other than Income 10,844 10,705 10,233
- Income 14,247 16,058 15,653
Total Operating Expenses 389,819 356,794 367,837
Operating Income 45,195 48,014 52,232
Equity in Earnings of Jointly Owned Comp. 1,599 1,587 1,646
Allowance for Other Funds Used During
Construction 162 365 473
Other Income (Deductions) - Net 666 1,583 407
Income Before Interest Charges 47,622 51,549 54,758
Interest Charges:
Interest on Long-Term Debt 15,006 15,233 18,277
Other Interest Expense 3,792 3,653 3,541
Allowance for Borrowed Funds Used During
Construction (Credit) (223) (308) (503)
Net Interest Charges 18,575 18,578 21,315
Net Income 29,047 32,971 33,443
Preferred Dividend Requirements 1,988 1,988 1,988
Consolidated Net Earnings Applicable to
Common Stock $ 27,059 $ 30,983 $ 31,455
Consolidated Statements of Retained Earnings
Years Ended December 31,
(In Thousands)
1997 1996 1995
Retained Earnings - Beginning of Year $ 120,724 $ 124,878 $ 105,574
Net Income 29,047 32,971 33,443
Amortization of Preferred Stock
Redemption Premium (577) (817) (961)
Total 149,194 157,032 138,056
Dividends Paid:
Preferred 1,988 1,988 1,988
Common 48,227 34,320 11,190
Retained Earnings - End of Year $ 98,979 $ 120,724 $ 124,878
The accompanying notes are an integral part of the financial statements.
Eastern Edison Company and Subsidiary
Consolidated Statements of Cash Flows
Years Ended December 31,
(In Thousands)
1997 1996 1995
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 29,047 $ 32,971 $ 33,443
Adjustments to Reconcile Net Income
to Net Cash Provided by Operating Activities:
Depreciation and Amortization 28,592 28,607 29,852
Amortization of Nuclear Fuel 1,067 1,676 3,647
Deferred Taxes (4,872) 5,217 2,694
Investment Tax Credit, Net (935) (939) (942)
Allowance for Funds Used During Constr. (162) (365) (473)
Other - Net (4,215) (2,333) 1,219
Changes to Operating Assets and Liabilities:
Accounts Receivable 10,038 (1,862) (7,055)
Fuel, Materials and Supplies 2,666 673 (1,678)
Accounts Payable 3,088 186 827
Accrued Taxes (653) (241) 1,807
Other - Net (2,282) 9,266 (6,630)
Net Cash Provided from Operating Activities 61,379 72,856 56,711
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (15,662) (26,006) (23,423)
Decrease in Other Investments 219 148
Net Cash (Used in) Investing Activities (15,443) (25,858) (23,423)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt 0 (7,000) (35,000)
Common Stock Dividends Paid (48,227) (34,320) (11,190)
Preferred Dividends Paid (1,988) (1,988) (1,988)
Net Increase (Decrease) in Short Term
Debt 2,635 (2,118) 4,158
Net Cash (Used in) Financing Activities (47,580) (45,426) (44,020)
Net (Decrease) Increase in Cash
and Temporary Cash Investments (1,644) 1,572 (10,732)
Cash and Temporary Cash Investments at
Beginning of Year 2,105 533 11,265
Cash and Temporary Cash Investments at
End of Year $ 461 $ 2,105 $ 533
Cash paid during the year for:
Interest (Net of Amounts Capitalized) $ 13,993 $ 15,241 $ 18,343
Income Taxes $ 21,291 $ 13,267 $ 9,044
The accompanying notes are an integral part of the financial statements.
Eastern Edison Company and Subsidiary
Consolidated Balance Sheets
December 31,
(In Thousands)
ASSETS
1997 1996
Utility Plant and Other Investments:
Utility Plant $ 825,238 $ 817,992
Less Accumulated Provision for Depreciation 279,711 261,464
Net Utility Plant 545,527 556,528
Non-Utility Property - Net 2,705 2,705
Investment in Jointly Owned Companies 13,524 13,210
Other Investments (at cost) 55 95
Total Utility Plant and Other Investments 561,811 572,538
Current Assets:
Cash and Temporary Cash Investments 461 2,105
Accounts Receivable:
Customers 27,801 27,633
Others 4,486 3,464
Accrued Unbilled Revenue 8,490 8,376
Associated Companies 14,143 25,486
Fuel (at average cost) 4,248 6,844
Plant Materials and Operating Supplies (at aver. cost) 3,734 3,805
Prepayments and Other Current Assets 3,688 3,598
Total Current Assets 67,051 81,311
Other Assets (Note A) 148,262 121,233
Total Assets $ 777,124 $ 775,082
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 218,468 $ 240,213
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redemption Cost (2,053) (2,630)
Long-term Debt - Net 162,491 222,402
Total Capitalization 408,571 489,650
Current Liabilities:
Long-term Debt Due Within One Year 60,000
Notes Payable 4,675 2,040
Accounts Payable:
Public 27,113 27,391
Associated Companies 7,317 3,950
Customer Deposits 1,258 1,153
Taxes Accrued 2,325 2,977
Interest Accrued 4,923 4,895
Other Current Liabilities 13,753 16,081
Total Current Liabilities 121,364 58,487
Other Liabilities 68,345 41,914
Deferred Credits:
Unamortized Investment Credit 15,967 16,903
Other Deferred Credits 23,402 25,689
Total Deferred Credits 39,369 42,592
Accumulated Deferred Taxes 139,475 142,439
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization $ 777,124 $ 775,082
The accompanying notes are an integral part of the financial statements.
Eastern Edison Company and Subsidiary
Consolidated Statements of Capitalization
December 31,
(In Thousands)
1997 1996
Common Stock:
$25 par value, authorized and outstanding
2,891,357 shares $ 72,284 $ 72,284
Other Paid-In Capital 47,249 47,249
Common Stock Expense (44) (44)
Retained Earnings 98,979 120,724
Total Common Equity 218,468 240,213
Redeemable Preferred Stock:
6 5/8%, $100 par value, 300,000 shares (1) 30,000 30,000
Expense, Net of Premium (335) (335)
Preferred Stock Redemption Cost (2,053) (2,630)
Total Redeemable Preferred Stock 27,612 27,035
Long-Term Debt:
First Mortgage and Collateral Trust Bonds:
5 7/8% due 1998 20,000 20,000
6 7/8% due 2003 40,000 40,000
8% due 2023 40,000 40,000
5 3/4% due 1998 40,000 40,000
6.35% due 2003 8,000 8,000
7.78% Secured Medium-Term Notes due 2002 35,000 35,000
Pollution Control Revenue Bond:
5 7/8% due 2008 40,000 40,000
Unamortized (Discount) - Net (509) (598)
222,491 222,402
Less Portion Due Within One Year 60,000
Total Long-Term Debt 162,491 222,402
Total Capitalization $ 408,571 $ 489,650
(1) Authorized and Outstanding.
The accompanying notes are an integral part of the financial statements.
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EASTERN EDISON COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1997, 1996, and 1995
(A) Nature of Operations and Summary of Significant Accounting Policies:
General: Eastern Edison Company (Eastern Edison or the Company) and its
wholly owned subsidiary, Montaup Electric Company (Montaup) are principally
engaged in the generation, transmission, distribution and sale of electric
energy.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
The accounting policies and practices of Eastern Edison and of Montaup are
subject to regulation by the Federal Energy Regulatory Commission (FERC) and
the Massachusetts Department of Telecommunications and Energy (formerly
Massachusetts Department of Public Utilities) with respect to their rates and
accounting. Eastern Edison and Montaup conform with generally accepted
accounting principles, as applied in the case of regulated public utilities,
and conform with the accounting requirements and ratemaking practices of the
regulatory authority having jurisdiction.
Principles of Consolidation: The consolidated financial statements include
the accounts of Eastern Edison and its subsidiary, Montaup. All material
intercompany balances and transactions have been eliminated in consolidation.
Jointly Owned Companies: Montaup Electric Company (Montaup) follows the
equity method of accounting for its stock ownership investments in jointly
owned companies including four regional nuclear generating companies.
Montaup's investments in these nuclear generating companies range from 2.5% to
4.5%. Three of the four facilities have been permanently shut down and are in
the process of decommissioning. Montaup is entitled to electricity produced
from the remaining facility based on its ownership interest and is billed for
its entitlement pursuant to a contractual agreement which is approved by FERC.
In December 1996, the Board of Directors of Connecticut Yankee voted to
retire the generating station. Connecticut Yankee certified to the Nuclear
Regulatory Commission (NRC) that it had permanently closed power generation
operations and removed fuel from the reactor. Montaup has a 4.5% equity
ownership in Connecticut Yankee. Montaup's share of the total estimated costs
for the permanent shutdown, decommissioning, and recovery of the investment in
Connecticut Yankee is approximately $27.4 million and is included with Other
Liabilities on the Consolidated Balance Sheet as of December 31, 1997. Also,
due to recoverability, a regulatory asset has been recorded for the same amount
and is included with Other Assets. The recovery of this estimated amount,
elements of which have been disputed by certain intervening parties, is subject
to approval of FERC. Montaup cannot predict the ultimate outcome of FERC's
review.
In August 1997, as the result of an economic evaluation, the Maine Yankee
Board of Directors voted to permanently close that nuclear plant. Montaup has
a 4.0% equity ownership in Maine Yankee. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning, and recovery of
the remaining investment in Maine Yankee is approximately $35.4 million and is
included with Other Liabilities on the Consolidated Balance Sheet as of
December 31, 1997. Also, due to recoverability, a regulatory asset has been
recorded for the same amount and is included with Other Assets. The recovery
of this estimated amount, elements of which have been disputed by certain
intervening parties, is subject to approval of FERC. Montaup cannot predict
the ultimate outcome of FERC's review.
Montaup also has a stock ownership investment of 3.27% in each of the two
companies which own and operate certain interconnection facilities used to
transmit hydroelectric power between the Hydro-Quebec Electric System and New
England.
Transactions with Affiliates: Eastern Edison is a wholly owned subsidiary of
Eastern Utilities Associates (EUA). In addition to its investment in Eastern
Edison, EUA has interests in two other retail companies, a service corporation,
and five other non-utility companies.
Transactions between Montaup and other affiliated companies include the
following: sales of electricity by Montaup to Blackstone Valley Electric
Company (Blackstone) and Newport Electric Corporation (Newport) aggregating
approximately $127,882,000 in 1997, $127,536,000 in 1996, and $133,841,000 in
1995; accounting, engineering and other services rendered by EUA Service
Corporation to Eastern Edison and Montaup of approximately $32,190,000,
$30,886,000, and $29,264,000, in 1997, 1996 and 1995, respectively; and
operating expense from the rental of transmission and generation facilities by
Blackstone and Newport to Montaup aggregating approximately $4,197,000 in 1997,
$3,960,000 in 1996, and $4,351,000 in 1995. Transactions with affiliated
companies are subject to review by applicable regulatory commissions.
Utility Plant and Depreciation: Utility plant is stated at original cost.
The cost of additions to utility plant includes contracted work, direct labor
and material, allocable overhead, allowance for funds used during construction
and indirect charges for engineering and supervision. For financial statement
purposes, depreciation is computed on the straight-line method based on
estimated useful lives of the various classes of property. Provisions for
depreciation, on a consolidated basis, were equivalent to a composite rate of
approximately 3.2% in 1997, 1996 and 1995 based on the average depreciable
property balances at the beginning and end of each year. Beginning in 1998,
coincident with billing a contract termination charge (CTC) to its retail
affiliates, Montaup will commence depreciating its investment in generation
related assets recoverable through the CTC over a twelve-year period.
Other Assets: The components of Other Assets at December 31, 1997 and 1996
are detailed as follows:
(In Thousands) 1997 1996
Regulatory Assets:
Unamortized losses on reacquired debt $ 11,588 $ 13,277
Unrecovered plant and
decommissioning cost 68,345 41,914
Deferred SFAS 109 costs (Note B) 46,806 47,326
Deferred SFAS 106 costs (Note J) 1,726 2,153
Other regulatory assets 5,875 4,886
Total regulatory assets 134,340 109,556
Other deferred charges and assets:
Unamortized debt expenses 2,092 2,456
Other 11,830 9,221
Total Other Assets $148,262 $121,233
Regulatory Accounting: Eastern Edison and Montaup are subject to certain
accounting rules that are not applicable to other industries. These accounting
rules allow regulated companies, in appropriate circumstances, to establish
regulatory assets and liabilities which defer the current financial impact of
certain costs that are expected to be recovered in future rates. In light of
approved restructuring settlement agreements and restructuring legislation in
both Massachusetts and Rhode Island, the Company has determined that Montaup no
longer will apply the provisions of Financial Accounting Standards Board's
(FASB) Statement of Financial Accounting Standards No. 71 (FAS71), "Accounting
for the Effects of Certain Types of Regulation" to the generation portion of
its business. Due to the recoverability of regulatory assets granted in the
approved restructuring plans, the company believes that the discontinuation of
FAS71 for the generation portion of Montaup's business will not have a material
impact on the Company's results of operation or financial condition. The
Company believes its transmission and retail distribution businesses continue
to meet the criteria for continued application of FAS71.
Allowance for Funds Used During Construction (AFUDC): AFUDC represents the
estimated cost of borrowed and equity funds used to finance Eastern Edison's
and Montaup's construction program. In accordance with regulatory accounting,
AFUDC is capitalized, as a cost of utility plant, in the same manner as certain
general and administrative costs. AFUDC is not an item of current cash income,
but is recovered over the service life of utility plant in the form of
increased revenues collected as a result of higher depreciation expense. The
combined rate used in calculating AFUDC was 8.2% in 1997; 8.9% in 1996, and
9.4% in 1995.
Operating Revenues: Revenues are based on billing rates authorized by
applicable federal and state regulatory commissions. Eastern Edison accrues
the estimated amount of unbilled revenues at the end of each month to match
costs and revenues more closely. Montaup recognizes revenues when billed. In
1998, Eastern Edison and Montaup also began accruing revenues consistent with
provisions of approved settlement agreements and the Massachusetts Electric
Industry Restructuring Act.
Income Taxes: The general policy of Eastern Edison and Montaup with respect
to accounting for federal and state income taxes is to reflect in income the
estimated amount of taxes currently payable, as determined from the EUA
consolidated tax return on an allocated basis, and to provide for deferred
taxes on certain items subject to temporary differences to the extent permitted
by the various regulatory commissions. As permitted by the regulatory
commissions, it is the policy of Eastern Edison and Montaup to defer
recognition of the annual investment tax credits and to amortize these credits
over the productive lives of the related assets. Beginning in 1998, Montaup
will amortize previously deferred ITC related to generation investments
recoverable through the CTC over a twelve-year period.
Cash and Temporary Cash Investments: Eastern Edison and Montaup consider all
highly liquid investments and temporary cash investments with a maturity of
three months or less, when acquired, to be cash equivalents.
(B) Income Taxes:
Components of income tax expense for the years 1997, 1996, and 1995 are as
follows:
_________________________________________________________________________
(In Thousands) 1997 1996 1995
Federal:
Current $16,427 $ 9,111 $11,387
Deferred (4,031) 5,152 3,679
Investment Tax Credit, Net (935) (939) (942)
$11,461 $13,324 $14,124
State:
Current 3,505 2,612 2,447
Deferred (719) 122 (918)
2,786 2,734 1,529
Charged to Operations 14,247 16,058 15,653
Charged to Other Income:
Current 1,175 1,233 522
Deferred (219) (67) (67)
Total $15,203 $17,224 $16,108
Total income tax expense was different than the amounts computed by
applying federal income tax statutory rates to book income subject to tax for
the following reasons:
______________________________________________________________________________
(In Thousands) 1997 1996 1995
Federal Income Tax Computed
at Statutory Rates $15,487 $17,568 $17,343
(Decreases) Increases in Tax from:
Equity Component of AFUDC (56) (128) (165)
Consolidated Tax Savings (156) (108)
Depreciation Differences (348) (452) (264)
Amortization and Utilization
of ITC (935) (939) (942)
State Taxes, Net of Federal
Income Tax Benefit 1,919 1,897 (2,625)
Cost of Removal 58
Other (864) (566) 2,811
Total Income Tax Expense $15,203 $17,224 $16,108
Eastern Edison and Montaup adopted Statement of Financial Accounting
Standard No. 109, "Accounting for Income Taxes" (FAS109) which required
recognition of deferred income taxes for temporary differences that are
reported in different years for financial reporting and tax purposes using the
liability method. Under the liability method, deferred tax liabilities or
assets are computed using the tax rates that will be in effect when temporary
differences reverse. Generally, for regulated companies, the change in tax
rates may not be immediately recognized in operating results because of rate
making treatment and provisions in the Tax Reform Act of 1986. The total
deferred tax assets and liabilities at December 31, 1997 and 1996 are comprised
as follows (In Thousands):
Deferred Tax Deferred Tax
Assets Liabilities
1997 1996 1997 1996
Plant Related Plant Related
Differences $11,997 $13,490 Differences $154,025 $153,471
Alternative Refinancing
Minimum Tax 412 Costs 1,264 1,471
Pensions 1,837 1,299 Pensions 987 877
Other 5,974 1,040 Other 3,007 2,507
Total $19,808 $16,241 Total $159,283 $158,326
As of December 31, 1997 and 1996, the Company had recorded on its
Consolidated Balance Sheet a regulatory liability to ratepayers of
approximately $15.2 million and $18.0 million, respectively. This amount
primarily represents excess deferred income taxes resulting from the
reduction in the federal income tax rate and also includes deferred taxes
provided on investment tax credits. Also at December 31, 1997 and 1996, a
regulatory asset of approximately $46.8 million and $47.3 million,
respectively, has been recorded, representing the cumulative amount of federal
income taxes on temporary depreciation differences which were previously flowed
through to ratepayers.
(C) Capital Stock:
There were no changes in the number of shares of common or preferred stock
during the years ended December 31, 1997, 1996 and 1995.
Under the terms and provisions of the issues of preferred stock of Eastern
Edison, certain restrictions are placed upon the payment of dividends on common
stock by Eastern Edison. At December 31, 1997, 1996 and 1995, the respective
capitalization ratios were in excess of the minimum requirements which would
make these restrictions effective.
(D) Redeemable Preferred Stock
Eastern Edison's 6-5/8% Preferred Stock issue is entitled to an annual
mandatory sinking fund sufficient to redeem 15,000 shares commencing September
1, 2003. The redemption price is $100 per share plus accrued dividends. All
outstanding shares of the 6-5/8% issue will be subject to mandatory redemption
on September 1, 2008 at a price of $100 per share plus accrued dividends.
In the event of liquidation, the holders of Eastern Edison's 6-5/8%
Preferred Stock are entitled to $100 per share plus accrued dividends.
(E) Retained Earnings:
Under the provisions of Eastern Edison's Indenture securing the First
Mortgage and Collateral Trust Bonds, retained earnings in the amount of
$96,218,056 as of December 31, 1997 were unrestricted as to the payment of cash
dividends on its Common Stock.
(F) Long-Term Debt:
The various mortgage bond issues of Eastern Edison are collateralized by
substantially all of their utility plant. In addition, Eastern Edison's bonds
are collateralized by securities of Montaup, which are wholly-owned by Eastern
Edison, in the principal amount of approximately $236 million.
The Company's aggregate amount of current cash sinking fund requirements
and maturities of long-term debt, (excluding amounts that may be satisfied by
available property additions) for each of the five years following 1997 are:
$60 million in 1998, and none in 1999, 2000, 2001 and $35 million in 2002.
(G) Lines of Credit:
In July 1997, several EUA System companies, including Eastern Edison,
entered into a three-year revolving credit agreement allowing for borrowings in
aggregate of up to $120 million. As of December 31, 1997, various financial
institutions have committed up to $75 million under the revolving credit
facility. At December 31, 1997, under the revolving credit agreement the EUA
System had short-term borrowings available of approximately $13.5 million.
Eastern Edison had $4.7 million of outstanding short-term debt at December 31,
1997. In accordance with the revolving credit agreement commitment fees are
required to maintain certain lines of credit. During 1997, the weighted
average interest rate for short-term borrowings by the Company was 5.8%.
(H) Jointly Owned Facilities:
At December 31, 1997, in addition to the stock ownership interests
discussed in Note A, Summary of Significant Accounting Policies - Jointly Owned
Companies, Montaup had direct ownership interests in the following electric
generating facilities:
Accumulated
Provision For Net Construc-
Utility Depreciation Utility tion
Percent Plant in and Plant in Work in
Owned Service Amortization Service Progress
($ In Thousands):
Montaup:
Canal Unit 2 50.00% $ 85,750 $ 44,498 $ 41,252 $ 227
Wyman Unit 4 1.96% 4,054 2,253 1,801
Seabrook Unit I 2.90% 194,679 34,400 160,279 325
Millstone Unit 3 4.01% 178,918 54,844 124,074 285
The foregoing amounts represent Montaup's interest in each facility,
including nuclear fuel where appropriate, and are included on the like-
captioned lines on the Consolidated Balance Sheet. At December 31, 1997,
Montaup's total net investment in nuclear fuel of the Seabrook and Millstone
units amounted to $2.2 million and $1.8 million, respectively. Montaup's
shares of related operating and maintenance expenses with respect to units
reflected in the table above are included in the corresponding operating
expenses on the Consolidated Statement of Income.
(I) Fair Value of Financial Instruments:
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate:
Cash and Temporary Cash Investments: The carrying amount approximates
fair value because of the short-term maturity of those instruments.
Redeemable Preferred Stock and Long-Term Debt: The fair value of the
Company's redeemable preferred stock and long-term debt were based on quoted
market prices for such securities.
The estimated fair values of the Company's financial instruments at
December 31, 1997 and 1996 were as follows (In Thousands):
Carrying Amount Fair Value
1997 1996 1997 1996
Cash and Temporary Cash Investments $ 461 $ 2,105 $ 461 $ 2,105
Redeemable Preferred Stock 30,000 30,000 31,613 30,300
Long-Term Debt $223,000 $223,000 $235,190 $225,870
(J) Commitments and Contingencies:
Nuclear Fuel Disposal and Nuclear Decommissioning Costs: The owners (or lead
participants) of the nuclear units in which Montaup has an interest have made,
or expect to make, various arrangements for the acquisition of uranium
concentrate, the conversion, enrichment, fabrication and utilization of nuclear
fuel and the disposition of that fuel after use. The owners (or lead
participants) of United States nuclear units have entered into contracts with
the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance
with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject
to various contingencies) that the federal government design, license,
construct and operate a permanent repository for high level radioactive
wastes and spent nuclear fuel and establish a prescribed fee for the disposal
of such wastes and nuclear fuel. The NWPA specifies that the DOE provide for
the disposal of such waste and spent nuclear fuel starting in 1998. Objections
on environmental and other grounds have been asserted against proposals for
storage as well as disposal of spent nuclear fuel. The DOE now estimates that
a permanent disposal site for spent fuel will not be ready to accept fuel for
storage or disposal until as late as the year 2010. In early 1998 a number of
utilities filed suit in federal appeals court seeking, among other things, an
order requiring the DOE to immediately establish a program for the disposal
of spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9%
interest in Seabrook I. Northeast Utilities, the operator of the units,
indicates that Millstone 3 has sufficient on-site storage facilities which,
with rack additions, can accommodate its spent fuel for the projected life
of the unit. At the Seabrook Project, there is on-site storage capacity which,
with rack additions, will be sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest. These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners or power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through rates.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone 3 is $21.9 million in
1997 dollars, and Seabrook I is $13.7 million in 1997 dollars. These figures
are based on studies performed for the lead owners of the units. Montaup also
pays into decommissioning reserves pursuant to contractual arrangements with
other nuclear generating facilities in which it has an equity ownership
interest or life of the unit entitlement. Such expenses are currently
recoverable through rates.
Pensions: Eastern Edison and Montaup participate with the other EUA
System companies in a non-contributory defined benefit pension plan covering
substantially all of their employees (Retirement Plan). Retirement Plan
benefits are based on years of service and average compensation over the four
years prior to retirement. It is the EUA System's policy to fund the
Retirement Plan on a current basis in amounts determined to meet the funding
standards established by the Employee Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including amounts
related to the 1997 and 1995 voluntary retirement incentive offers, for 1997,
1996 and 1995 includes the following components ($ In Thousands):
1997 1996 1995
Service cost - benefits earned during
the period $ 1,689 $ 1,713 $ 1,504
Interest cost on projected benefit
obligation 6,021 5,767 5,575
Actual (return) loss on assets (18,178) (10,036) (22,158)
Net amortization and deferrals 9,891 2,407 14,855
Net periodic pension income $ (577) $ (149) $ (224)
Voluntary retirement incentive 857
Total periodic pension (income) expense $ (577) $ (149) $ 633
Assumptions used to determine pension cost:
1997 1996 1995
Discount Rate 7.50% 7.25% 8.25%
Compensation Increase Rate 4.25% 4.25% 4.75%
Long-Term Return on Assets 9.50% 9.50% 9.50%
The discount rate used to determine pension obligations was changed to
7.25% effective January 1, 1998. The funded status of the Retirement Plan
cannot be presented separately for Eastern Edison and Montaup as they
participate in the Retirement Plan with other subsidiaries of EUA.
The voluntary retirement incentives also resulted in non-qualified pension
benefits of approximately $752,000 and $800,000 in 1997 and 1995, respectively.
At December 31, 1997, approximately $448,000 is included in other liabilities
for these unfunded benefits.
EUA also maintains non-qualified supplemental retirement plans for certain
officers and trustees of the EUA System (Supplemental Plans). Benefits
provided under the Supplemental Plans are based primarily on compensation at
retirement date. EUA maintains life insurance on the participants of the
Supplemental Plans to fund in whole, or in part, its future liabilities under
the Supplemental Plans. For the years ended December 31, 1997, 1996 and 1995
Eastern Edison's and Montaup's expenses related to the Supplemental Plan were
approximately $805,000, $717,000 and $825,000, respectively.
The Company also provides a defined contribution 401(k) savings plan for
substantially all employees. The Company's matching percentage of employees'
voluntary contributions to the plan, amounted to approximately $321,000 in
1997, $306,000 in 1996, and approximately $369,000 in 1995.
Post-Retirement Benefits: Retired employees are entitled to participate in
health care and life insurance benefit plans. Health care benefits are subject
to deductibles and other limitations. Health care and life insurance benefits
are partially funded by EUA System companies for all qualified employees.
Eastern Edison and Montaup adopted FAS106, "Employers' Accounting for
Post-Retirement Benefits Other Than Pensions," as of January 1, 1993. This
standard establishes accounting and reporting standards for such post-
retirement benefits as health care and life insurance. Under FAS106 the
present value of future benefits is recorded as a periodic expense over
employee service periods through the date they become fully eligible for
benefits. With respect to periods prior to adopting FAS106, EUA elected to
recognize accrued costs (the Transition Obligation) over a period of 20 years,
as permitted by FAS106. The resultant annual expense, including amortization
of the Transition Obligation and net of amounts capitalized and deferred, was
approximately $3.9 million in 1997, $3.6 million in 1996 and $4.0 million in
1995.
The total cost of Post-Retirement Benefits other than Pensions, including
amounts related to the 1997 and 1995 voluntary retirement incentive offers, for
1997, 1996 and 1995 includes the following components (In Thousands):
1997 1996 1995
Service cost $587 $637 $565
Interest cost 2,701 2,688 2,926
Actual return on plan assets (775) (115) (388)
Amortization of transition obligation 1,952 1,955 1,965
Net other amortization & deferrals (407) (721) (632)
Net periodic post-retirement benefit costs 4,058 4,444 4,436
Voluntary retirement incentive 102 470
Total post-retirement benefit costs $4,160 $4,444 $4,906
Assumptions:
Discount rate 7.50% 7.25% 8.25%
Health care cost trend rate - near-term 7.00% 9.00% 11.00%
- long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.25% 4.75%
Rate of return on plan assets - union 8.50% 8.50% 8.50%
- non-union 7.50% 7.50% 5.50%
Reconciliation of funded status:
1997 1996 1995
(In Thousands)
Accumulated post-retirement benefit obligation (APBO):
Retirees $(20,819) ($19,864) $(23,223)
Active employee fully eligible for benefits (1,551) (1,728) (3,649)
Other active employees (6,101) (6,031) (7,711)
Total (28,471) (27,623) (34,583)
Fair Value of assets (primarily notes and bonds) 6,991 5,161 3,830
Unrecognized transition obligation 24,463 26,095 27,726
Unrecognized net gain (8,924) (9,297) (2,142)
(Accrued) prepaid post-retirement benefit cost $(5,941) $5,664 $ (5,169)
The discount rate and compensation increase rates used to determine post-
retirement benefit obligations was changed to 7.25% effective January 1, 1998,
and was used to calculate the funded status of Post-Retirement Benefits at
December 31, 1997.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1997 by approximately
$299,000 and increase the total accumulated post-retirement benefit obligation
by approximately $2.9 million.
Eastern Edison and Montaup have also established an irrevocable external
Voluntary Employees' Beneficiary Association (VEBA) Trust Fund. Contributions
to the VEBA fund commenced in March 1993 and contributions were made totaling
approximately $2.9 million in 1997 and 1996, and $3.2 million in 1995.
Long-Term Purchased Power Contracts: Montaup is committed under long-term
purchased power contracts, expiring on various dates through September 2021, to
pay demand charges whether or not energy is received. Under terms in effect at
December 31, 1997, the aggregate annual minimum commitments for such contracts
are approximately $114 million in 1998, $110 million in 1999, $107 million in
2000, $108 million in 2001, $108 million in 2002, and will aggregate $1.0
billion for the ensuing years. In addition, the EUA System is required to pay
additional amounts depending on the actual amount of energy received under such
contracts. The demand costs associated with these contracts are reflected as
Purchased Power-Demand on the Consolidated Statement of Income. Such costs are
currently recoverable through rates.
Environmental Matters: There is an extensive body of federal and state
statutes governing environmental matters, which permit, among other things,
federal and state authorities to initiate legal action providing for liability,
compensation, cleanup, and emergency response to the release or threatened
release of hazardous substances into the environment and for the cleanup of
inactive hazardous waste disposal sites which constitute substantial hazards.
Because of the nature of the Eastern Edison business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by the United States Environmental Protection
Agency (EPA) as well as state and local authorities. The Company generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs. In the past,
Eastern Edison and Montaup had been notified with respect to a number of sites
where they were allegedly responsible for such costs, including sites where
they allegedly had joint and several liability with other responsible parties.
Eastern Edison and Montaup are currently not involved in any environmental site
investigation. It is the policy of Eastern Edison and Montaup to notify
liability insurers and to initiate claims. The costs incurred in connection
with these sites have been financed primarily with internally generated cash.
As a general matter Eastern Edison and Montaup would seek to recover costs
relating to environmental proceedings in their rates. Montaup is currently
recovering certain of the incurred costs in its rates.
The Clean Air Act Amendments created new regulatory programs and generally
updated and strengthened air pollution control laws. These amendments expanded
the regulatory role of the EPA regarding emissions from electric generating
facilities and a host of other sources. EUA System generating facilities were
first affected in 1995, when EPA regulations took effect for facilities.
Montaup's coal-fired Somerset Unit 6 is utilizing lower sulfur content coal to
meet the 1995 air standards. EUA does not anticipate the impact from the
Amendments to be material to the financial position of the EUA System.
In July, the EPA issued a new and more stringent rule covering ozone
particulate matter which is to be followed by promulgation of more stringent
ozone and particulate matter standards. The effect that such standards will
have on the EUA System cannot be determined by management at this time.
Eastern Edison, Montaup, the Massachusetts Attorney General and Division
of Energy Resources entered into a settlement regarding electric utility
industry restructuring in Massachusetts. The settlement includes a plan for
emissions reductions related to Montaup's Somerset Station Units
5 and 6, and to Montaup's 50% ownership share of Canal Electric's Unit 2. The
basis for SO2 and NOx emission reductions in the proposed settlement is an
allowance cap calculation. Montaup may meet its allowance caps by any
combination of control technologies, fuel switching, operational changes,
and/or the use of purchased or surplus allowances. The settlement was approved
by FERC on December 19, 1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight northeast states including
Massachusetts and Rhode Island, issued recommendations for NOx controls for
existing utility boilers required to meet the ozone non-attainment requirements
of the Clean Air Act. The NESCAUM recommendations are more restrictive than
the Clean Air Act requirements. The Massachusetts Department of Environmental
Management has amended its regulations to require that Reasonably Available
Control Technology (RACT) be implemented at all stationary sources potentially
emitting 50 tons or more per year of NOx. Similar regulations have been issued
in Rhode Island. Montaup has initiated compliance, through, among other
things, selective noncatalytic reduction processes.
A number of scientific studies in the past several years have examined the
possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. On October 31, 1996, the National Academy of Sciences issued a
literature review of all research to date, Possible Health Effects of Exposure
to Residential Electric and Magnetic Fields. Its most widely reported
conclusion stated, "No clear, convincing evidence exists to show that
residential exposures to EMF are a threat to human health." Additional studies,
which are intended to provide a better understanding of EMF, are continuing.
Some states have enacted regulations to limit the strength of magnetic
fields at the edge of transmission line rights-of-way. Rhode Island has
enacted a statute which authorizes and directs the Energy Facility Siting Board
to establish rules and regulations governing construction of high voltage
transmission lines of 69 kv or more. Management cannot predict the ultimate
outcome of the EMF issue.
Guarantee of Financial Obligations: Montaup is a 3.27% equity participant in
two companies which own and operate transmission facilities interconnecting New
England and the Hydro Quebec system in Canada. Montaup has guaranteed
approximately $4.5 million of the outstanding debt of these two companies. In
addition, Montaup has a minimum rental commitment which totals approximately
$12.0 million under a noncancellable transmission facilities support agreement
for years subsequent to 1997.
Other: In early 1997, ten plaintiffs brought suit against numerous
defendants, including EUA, for injuries and illness allegedly caused by
exposure to asbestos over approximately a thirty-year period, at premises,
including some owned by EUA companies. The total damages claimed in all
of these complaints was $25 million in compensatory and punitive damages, plus
exemplary damages and interest and costs. Each names between fifteen and
twenty-eight defendants, including EUA. These complaints have been referred to
the applicable insurance companies. Counsel has been retained by the insurers
and is actively defending all cases. Three cases have been dismissed
as against EUA companies with prejudice. EUA cannot predict the ultimate
outcome of this matter at this time.
The Office of the Attorney General has certified a referendum petition to
repeal the Massachusetts Electric Industry Restructuring Act as a matter
appropriate for a referendum initiative. A petition was filed with the
Election Division of the Office of the Secretary of State in February
1998. A question on repealing the Act will be presented to voters on the
November 1998 ballot.
EUA and the electric industry in Massachusetts will actively oppose repeal.
Management cannot predict the outcome of the November ballot question.
Report of Independent Accountants
To the Directors and Shareholder of
Eastern Edison Company and Subsidiary:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Eastern Edison Company and its subsidiary (the
Company) as of December 31, 1997 and 1996, and the related consolidated
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1997. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Company as of December 31,
1997 and 1996, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 3, 1998
To the Trustees and Shareholders of
Eastern Utilities Associates:
We consent to the incorporation by reference in the registration statements of
Eastern Utilities Associates on Forms S-4 and S-8 (File No. 33-50099 and 33-
49897, respectively) of our reports dated March 3, 1998, on our audits of the
consolidated financial statements and financial statement schedules of Eastern
Utilities Associates and subsidiaries as of December 31, 1997 and 1996, and
for the years ended December 31, 1997, 1996 and 1995, which reports are
incorporated by reference or included in this Annual Report on Form 10-K.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 16, 1998
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