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, 1996
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)
Washington Highway
Lincoln, Rhode Island 02865
Telephone (401) 333-1400
0-8480 Eastern Edison Company 04-1123095
(A Massachusetts Corporation)
110 Mulberry Street
Brockton, Massachusetts 02403
Telephone (508) 580-1213
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 17, 1997:
Eastern Utilities Associates Common Shares, $5 par value - $370,402,446
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 17, 1997: 20,435,997
Blackstone Valley Electric Company Common Shares
Outstanding at March 17, 1997: 184,062
Eastern Edison Company Common Shares
Outstanding at March 17, 1997: 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, 1996, are incorporated by reference into Part II.
Portions of the Eastern Utilities Associates Proxy Statement dated March 26,
1997 are incorporated by reference into Part III.
EASTERN UTILITIES ASSOCIATES
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
1996 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 Utility Restructuring Act of 1996 . . . .5
Massachusetts Restructuring Settlement . . . . . . . .6
Other. . . . . . . . . . . . . . . . . . . . . . . . .8
General - EUA Cogenex . . . . . . . . . . . . . . . . . . .8
Construction . . . . . . . . . . . . . . . . . . . . . . 11
Construction Program - EUA:. . . . . . . . . . . . . 11
Construction Program - Blackstone. . . . . . . . . . 11
Construction Program - Eastern Edison. . . . . . . . 12
Fuel for Generation . . . . . . . . . . . . . . . . . . . 12
Nuclear Power Issues . . . . . . . . . . . . . . . . . . 14
General . . . . . . . . . . . . . . . . . . . . . . 14
Decommissioning. . . . . . . . . . . . . . . . . . . 15
Yankee Atomic. . . . . . . . . . . . . . . . . . . . 16
Connecticut Yankee . . . . . . . . . . . . . . . . . 16
Recent NRC Actions . . . . . . . . . . . . . . . . . 16
Millstone III . . . . . . . . . . . . . . . . . 16
Maine Yankee. . . . . . . . . . . . . . . . . . 17
General . . . . . . . . . . . . . . . . . . . . 18
Public Utility Regulation . . . . . . . . . . . . . . . . 18
Rates . . . . . . . . . . . . . . . . . . . . . . . . . 20
FERC Proceedings . . . . . . . . . . . . . . . . . . 22
Massachusetts Proceedings. . . . . . . . . . . . . . 22
Rhode Island Proceedings . . . . . . . . . . . . . . 24
Environmental Regulation . . . . . . . . . . . . . . . . 27
General. . . . . . . . . . . . . . . . . . . . . . . 27
Electric and Magnetic Fields . . . . . . . . . . . . 28
Water Regulation . . . . . . . . . . . . . . . . . . 28
Air Regulation . . . . . . . . . . . . . . . . . . . 29
Environmental Regulation of Nuclear Power . . . . . . . . 31
Item 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . 32
Power Supply . . . . . . . . . . . . . . . . . . . . . . 32
Other Property. . . . . . . . . . . . . . . . . . . . . . 34
Item 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . 34
Rate Proceeding . . . . . . . . . . . . . . . . . . . . . 34
Environmental Proceedings . . . . . . . . . . . . . . . . 35
EUA WestCoast L.P.. . . . . . . . . . . . . . . . . . . . 38
Ridgewood . . . . . . . . . . . . . . . . . . . . . . . . 39
Other Proceedings . . . . . . . . . . . . . . . . . . . . 39
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS. 40
Executive Officers of Eastern Utilities Associates . . . 40
PART II
Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS. . . . . . . . . . . . . . . . . . . . . . . 41
Item 6. SELECTED FINANCIAL DATA. . . . . . . . . . . . . . . 42
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . .42
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . 42
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURES . . . . . . . .42
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Eastern Utilities Associates . . . . . . . . . . . . . . .42
Blackstone and Eastern Edison. . . . . . . . . . . . . . .43
Item 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . 44
Eastern Utilities Associates . . . . . . . . . . . . . . .44
Blackstone and Eastern Edison. . . . . . . . . . . . . . .45
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT . . . . . . . . . . . . . . . . . . . . . 45
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . 45
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K . . . . . . . . . . . . . . . . . . . . . .46
(a)(1) Financial Statements . . . . . . . . . . . . . . .46
(a)(2) Financial Statement Schedules . . . . . . . . . . .46
(a)(3) Exhibits (*denotes filed herewith). . . . . . . . .46
(b) Reports on Form 8-K. . . . . . . . . . . . . . . . .60
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Report of Independent Accountants . . . . . . . . . . . . . . 70
Consent of Independent Accountants . . . . . . . . . . . . . . 72
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 Nova EUA Nova, a division of EUA Cogenex
EUA Energy EUA Energy Investment Corporation
EUA Ocean State EUA Ocean State Corporation
EUA Service EUA Service Corporation
EUA Energy Services EUA Energy Services Corporation
Montaup Montaup Electric Company
Newport Newport Electric Corporation
Registrants EUA, Blackstone and Eastern Edison
Retail Subsidiaries Blackstone, Eastern Edison and Newport
Non-Affiliated Companies
Great Bay Power Great Bay Power Corporation (formerly EUA
Power Corporation)
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
Energy Policy Act Energy Policy Act of 1992
EPA Federal Environmental Protection Agency
FAS106 Statement No. 106 "Employer's Accounting for
Post-Retirement Benefits Other Than
Pensions"
FERC Federal Energy Regulatory Commission
IRS Internal Revenue Service
MADEP Massachusetts Department of Environmental
Protection
MDPU Massachusetts Department of Public
Utilities
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
RCRA Resource Conservation and Recovery Act of
1976
RIDEM Rhode Island Department of Environmental
Management
RIDPUC Rhode Island Division of Public Utilities
and Carriers
RIPUC Rhode Island Public Utilities Commission
SEC Securities and Exchange Commission
TEC-RI The Energy Counsel of Rhode Island
TSCA Toxic Substances Control Act
Other
AFUDC Allowance for Funds Used During
Construction
BTU British Thermal Unit
C&LM Conservation and Load Management
DSM Demand Side Management
EMF Electric and Magnetic Fields
EWG Exempt Wholesale Generator
IPP Independent Power Producer
GLOSSARY OF DEFINED TERMS (Cont'd)
Other (continued)
kWh Kilowatthour
MBTU Millions of British Thermal Units
MOU Memorandum of Understanding
mw Megawatt
NEPOOL New England Power Pool
PCB Polychlorinated Biphenyls
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
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
and EUA Service. 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 owns an interest in a limited liability company which markets
energy and energy related services. The holding company system of EUA,
the Retail Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy, EUA
Ocean State and EUA Energy Services 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. The Energy Related Business
includes EUA Cogenex, EUA Energy, EUA Ocean State and EUA Energy Services. The
Corporate Business is made up of EUA and EUA Service.
General - Core Electric Business
As of December 31, 1996, the number of regular employees in the core
electric and corporate business units was 1,032. Blackstone had 106 regular
non-union employees. Eastern Edison and Montaup had 303 regular employees.
Newport and EUA Service employed 59 and 564, respectively, at December 31,
1996. Labor bargaining unit contracts covering approximately 142 employees of
Eastern Edison in the Fall River area and of Montaup, and 55 employees of
Newport expire in June 1997, March 1998 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 734,000. At December 31, 1996,
Core Electric Business served approximately 299,000 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, 1996, 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 459,000. At December 31, 1996, Eastern Edison served
approximately 182,000 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.
For 1996, 1995 and 1994, the Core Electric Business accounted for
approximately 89%, 86% and 87%, respectively, of total operating revenues of
the EUA System. The remaining balance of operating revenues during these
periods were primarily attributable to EUA Cogenex.
Montaup currently supplies the Retail Subsidiaries with nearly 100% of
each company's electric requirement under FERC approved all-requirements
contracts. It is anticipated, subject to regulatory approval, that Montaup
will replace the all-requirements contract with a contract termination
agreement that would provide Montaup recovery of its stranded costs (see
Electric Utility Industry Restructuring below). About 48% of the 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).
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.
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. See
Electric Utility Industry Restructuring below for a discussion of emerging
competition and unbundling issues.
At the wholesale, or supply level, Montaup faces new sources of
competition in part as a result of PURPA, the Energy Policy Act and other
policies being implemented by the MDPU and considered by the RIPUC relating to
the solicitation of competitive proposals for new generation sources. 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. 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 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. 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 MDPU and the RIPUC have implemented regulations
which require utilities to integrate least-cost planning with competitive
proposals to meet requirements for new generation. Both states have also
approved 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 Public Utility Regulation below).
On April 24, 1996, FERC issued orders on its March 24, 1995 Notice of
Proposed Rulemaking (NOPR). FERC's purpose in proposing the new rules was to
encourage competition in the bulk power market. FERC's April 24th actions
include:
- order No. 888, a final rule requiring open access transmission and
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.
Utilities must take transmission service for their own wholesale
transactions under the terms and conditions of the tariff;
- establishing the right and a mechanism for recovery of prudently
incurred stranded costs by public utilities and transmitting utilities;
which arise as a result of wholesale open access;
- order No. 889, a final rule requiring public utilities to implement
standards of conduct and an Open Access Same-time Information System
(OASIS). Utilities must obtain information about their transmission the
same way as their competitors through the OASIS;
- 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.
Open-access transmission tariffs for point-to-point and 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 June 14,
1996 and remains pending before the Commission. Montaup amended its filing in
July 1996 to modify its terms and conditions in conformance with FERC's order.
FERC has taken no action on these filings. These tariffs are in compliance
with FERC's April 24th rulings.
EUA remains committed to achieving a fair and equitable transition to a
competitive electric utility marketplace. Montaup will face increased
competition in the wholesale generating, or supply market, primarily based on
price, from QFs and EWGs and in the future could be affected by such
competition supplying generation to its customers. More recently, non-utility
power marketers have become active, engaging in new and creative power
transactions. Power marketers are likely to become more prevalent in the
market as transmission access opens up and opportunities arise, due to price
differentials, to move power inter-regionally. See Electric Utility Industry
Restructuring, "Rhode Island Utility Restructuring Act of 1996" and
"Massachusetts Restructuring Settlement" for a discussion of divestiture plans
of Montaup.
The EUA System companies are members of NEPOOL, which is open to any
person or organization engaged in the electric utility business such as
investor-owned, municipal, and cooperative utilities as well as non-utilities
and others such as brokers and marketers. The systems making up NEPOOL own or
purchase the output from virtually all the generation in New England. Since
the EUA System operates an integrated transmission system which, in turn, is
connected to the New England 345 kv grid at three locations, NEPOOL treats the
EUA System as one consolidated participant. This is consistent with the EUA
System's planning and resource management perspective. The objectives of
NEPOOL are: (a) to assure that the bulk power supply of New England and any
adjoining areas served by participants conforms to proper standards of
reliability, and (b) to attain maximum practicable economy in the bulk power
supply consistent with all proper standards of reliability and to provide for
equitable sharing of the resulting benefits and costs. These objectives
are accomplished through joint planning, central dispatching, coordinated
construction, operation, and maintenance of electric generation and
transmission facilities, cooperation in environmental matters, and through
effective coordination with other power pools and utilities situated in the
United States and Canada.
The NEPOOL agreement imposes obligations concerning generating capacity
reserve and the right to use major transmission lines, and provides for central
dispatch of the generating capacity of NEPOOL's members with the objective of
achieving reliable and economical use of the region's facilities. Pursuant to
the NEPOOL agreement, interchange sales to NEPOOL are made at a price
approximately equal to the fuel cost for generation without contribution to the
support of fixed charges. The capacity responsibilities of Montaup and the
Retail Subsidiaries under the NEPOOL agreement are based on an allocated share
of a New England capacity requirement which is determined for each period on
the basis of certain regional reliability criteria. Because of its
participation in NEPOOL, the EUA System's operating revenues and costs are
affected to some extent by the operations of other members. A comprehensive
review of the NEPOOL agreement was initiated in 1994 and continued until late
1996. On December 31, 1996 a restated NEPOOL agreement was filed with the
FERC. The new agreement implements key changes in the operation of NEPOOL.
The major areas of change are in the formation of an Independent System
Operator (ISO) and in the shifting from cost-based pricing to market-based
pricing. As proposed in the new agreement, NEPOOL participants will be able to
compete for sale and purchase of seven products: (1) installed capability, (2)
operable capability, (3) energy, (4) 10-minute spinning reserve, (5) 10-minute
non-spinning reserve, (6) 30-minute operating reserve, and (7) automatic
generation control. If approved by the FERC, competition for all seven
products could begin by July 1, 1997.
Electric Utility Industry Restructuring:
Unbundled Services:
The electric industry is in a period of transition from a traditional rate
regulated environment to a competitive marketplace. Initiatives supported by
EUA in both Massachusetts and Rhode Island provide for the functional and
corporate unbundling of traditional electric utility services - generation,
transmission and distribution - into separate and distinct services. The
generation, or supply function will be truly competitive with customers
choosing their own electricity supplier at open market prices. The
transmission and distribution functions will remain regulated services. The
local distribution company will retain the responsibility of providing
distribution services to the ultimate electricity consumer within its
franchised service territory and the transmission company will be required to
provide open access, non-discriminatory transmission services to generation or
supply companies. For customers who choose not to choose, the local
distribution company will arrange for supply at a non-discriminatory, "standard
offer" price. Distribution companies will also be providers of last resort,
required to arrange for supply, at prevailing market prices, for customers who
are unable to obtain a supplier of electricity.
Stranded Costs:
"Stranded costs" represent historic costs of generation 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. It is anticipated that Montaup, the EUA
System's generation company, will fully recover its "stranded costs" via a
contract termination charge under a contract termination agreement which will
replace the all-requirements contracts currently in force.
Rhode Island Utility Restructuring Act of 1996:
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 commencing July 1, 1997 for large manufacturing customers,
certain new commercial and industrial customers, and State of Rhode Island
accounts. Load accounting for no more than 10% of an electric distribution
company's total kWh sales is to be released to retail access under this
provision. An additional 10% of kWh sales is to be released to retail access
by permitting municipal and smaller manufacturers to choose an electricity
supplier commencing January 1, 1998. By July 1, 1998 or sooner, all customers
will have retail access. This legislation provides for full recovery of
"stranded costs" billed to distribution companies - Blackstone and Newport in
the case of EUA - via a non-bypassable transition charge to ultimate
electricity consumers, initially set at 2.8 cents per kWh through December 31,
2000 and divestiture of at least 15% of owned non-nuclear generating units as a
valuation basis for mitigation of stranded cost recovery. The net costs of
above-market generation assets and regulatory assets will be recovered, with a
return, through the fixed component of the transition charge from July 1, 1997
through December 31, 2009. The initial return on equity will be set at one
percentage point plus the average return on BBB rated long term utility bonds
issued during the six month period ended December 31, 1996. Upon completion of
required divestiture, the return on equity will be that allowed to the
wholesale power supplier's affiliated distribution company as of December 31,
1995, which is approximately 11.4% for both Blackstone and Newport. The
variable component of the transition charge will recover, on a reconciling
basis, among other things, nuclear decommissioning and above market purchased
power commitments from July 1, 1997 through the life of the respective unit or
contract.
The URA also provides for, among other things, commitments to demand side
management initiatives and renewables, low income customer protections and
performance based regulation for electric distribution companies. Under
performance based regulation, rates are set for a specified period - two years,
under the URA - during which the utility is encouraged to manage its costs
prudently to earn a premium profit while being penalized for not achieving
specific agreed-upon regulated performance objectives. Utility returns, or
earnings, would be subject to a guaranteed floor of 6% and a ceiling of
approximately 12% for Blackstone and Newport. Utilities which manage well
can keep some of their savings; those that manage poorly are penalized by lower
earnings and/or pre-determined penalty charges.
The implementation of the URA will require approvals from applicable
regulatory agencies, including FERC, the RIPUC, and the SEC. EUA believes that
the URA settles much of the uncertainty regarding "stranded cost" recovery
related to serving the customers of Blackstone and Newport.
In February 1997, Blackstone , Newport and Montaup reached a settlement
with the RIDPUC and the Rhode Island Attorney General. The settlement, to be
formally submitted to the RIPUC in March 1997, complies with the URA and is
similar in many respects to the settlement negotiated in Massachusetts,
described below, including an immediate 10% rate reduction and the filing of a
plan to divest all of Montaup's generating assets.
Massachusetts Restructuring Settlement:
On December 23, 1996, Eastern Edison and Montaup Electric reached an
agreement in principle with the Attorney General of Massachusetts and the
Massachusetts Division of Energy Resources on a plan which would allow retail
customers to choose their supplier of electricity in 1998 and provide Eastern
Edison and Montaup full recovery of "stranded costs," which are prudently
incurred embedded costs they would have been entitled to recover but cannot
because of competitive market pressures. A formal plan is expected to be filed
for approval with the MDPU in March of 1997.
The agreement envisions that all of Eastern Edison's customers will have
the ability to choose an alternative supplier of electricity beginning on
January 1, 1998. Until a customer chooses an alternative supplier, that
customer would receive "Standard Offer" service which would be priced to
guarantee that customer at least a ten percent savings from today's electricity
prices. Eastern Edison would be required to arrange for "Standard Offer"
service and would purchase power for "Standard Offer" service from suppliers
through a competitive bidding process. The agreement is also designed
to achieve full divestiture of Montaup's generating assets via implementation
of a plan, to be submitted to the MDPU by July 1, 1997, that would require (1)
separation by Montaup of its generating and transmission businesses and (2)
full market valuation and sale of all generating assets through an auction or
equivalent process, to be conducted by an independent third party.
Upon the commencement of retail choice in Massachusetts, Montaup's
wholesale contract with Eastern Edison would be terminated. In return, the
cost of Montaup's above market, embedded generation commitments to serve
Eastern Edison's customers would be recovered, with a return, through a non-
bypassable transition access charge to all Eastern Edison customers. The
transition access charge would 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.
Embedded costs associated with generating plants and regulatory assets
would be recovered, with a return, over a period of 12 years, with an initial
return on equity of 8.92 percent. Purchased power contracts and nuclear
decommissioning costs would be recovered as incurred over the life of
those obligations, a period expected to extend beyond 12 years. The initial
transition access charge would be set at 3.04 cents per kWh through December
31, 2000, and is expected to decline thereafter. As the transition access
charge declines during the twelve-year transition period, Montaup would earn
mitigation incentives in the form of additional cash revenues which would
effectively increase its return on equity above the initial 8.92 percent.
The agreement also establishes performance-based regulation for Eastern
Edison. Under the agreement, Eastern Edison's distribution rates would be
frozen until December 31, 2000. Subsequent to the commencement of retail
choice, Eastern Edison's annual return on equity would be subject to a floor of
6 percent and a ceiling of 11.75 percent. If Eastern Edison's return on equity
so calculated is below 6 percent, it would be authorized to increase its rates
to provide sufficient revenues to increase Eastern Edison's return on equity to
6 percent. If Eastern Edison's calculated return is above 11 percent, it would
be required to reduce its rates by an amount necessary to reduce its calculated
return on equity between 11 and 12.5 percent by 50 percent and the earnings
above 12.5 percent by 100 percent. No adjustment would be made if the
calculated return on equity falls between 6 percent and 11 percent.
In addition to MDPU approval of the formal plan, implementation of the
plan is also subject to the approval of FERC. Any disposition of generation
assets would also require the approval of the SEC under the 1935 Act.
While removing much of the uncertainty about how EUA will be impacted by
Electric Utility Restructuring, the agreements, if approved, are expected to
have an estimated negative impact on EUA System earnings in 1998 of between 10%
to 12%.
Other:
Historically, electric rates have been designed to recover a utility's
full costs of providing electric service including recovery of investment in
plant assets, known as cost-of-service rate making. 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. EUA believes that its Core
Electric operations continue to meet the criteria established in these
accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in EUA no longer meeting the criteria of
certain accounting standards which could trigger the discontinuance of
Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (FAS71). Should it be required to
discontinue the application of FAS71, EUA would be required to take an
immediate write down of the affected assets in accordance with FAS101,
"Accounting for the Discontinuation of Application of FAS71."
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover the 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" (FAS121) issued in March 1995.
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.
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 "Standard
Offer 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.
EUA Cogenex's principal markets include institutional, commercial,
industrial and government entities, and through its EUA Citizens Conservation
Services subsidiary, public and private multi-family housing.
In September 1995, EUA announced that EUA Cogenex was discontinuing its
cogeneration operations because overall, the cogeneration portfolio had not
performed up to expectations. EUA Cogenex's total net investment in its
cogeneration portfolio was $29.2 million. The decision to discontinue its
cogeneration operations resulted in a one-time, after-tax charge of
approximately $10.5 million, or 52 cents per share, to 1995 earnings.
Difficulties in turning project proposals into signed contracts, the
virtual elimination of utility sponsored DSM programs and the termination of
the AYP Capital and Westar 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 current 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 an effort to revitalize its sales activity, EUA Cogenex has replaced
virtually all of its sales staff with individuals possessing more experience
and proven sales capability in the energy efficiency market. EUA Cogenex also
reduced its year-end 1995 employee level by 22% through a combination of
attrition and a 1996 year-end workforce reduction. 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 improve the performance of its
sales activity.
EUA Cogenex also operates a lighting services division, EUA Nova, and a
controls division, EUA Day. EUA Cogenex restructured its Nova Division in 1996
because of changing market conditions. EUA Nova 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, 1996, EUA Cogenex employed 213 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 potential 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 addition, the move toward electric
industry deregulation has also resulted in a reduction of electric utility
sponsored DSM programs which has resulted in a reduction of EUA Cogenex's
revenues.
As of December 31, 1996, 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,
1996 1995 1994
(In Thousands)
Operating Revenues $ 56,317 $ 79,499 $ 74,480
Pre-tax (Loss) Income $(10,186)(1) $(13,885)(2) $ 7,266
Net (Loss) Earnings $ (6,522)(1) $ (7,904)(2) $ 4,171
Total Assets $195,161 $199,115 $ 211,310
(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.
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, 1996 (Exhibit 13-1.03 filed herewith).
Construction
Construction Program - EUA:
The EUA System's cash construction expenditures for the year ended
December 31, 1996 were approximately $62.7 million.
Planned cash construction expenditures for 1997, 1998 and 1999 as set
forth below, are estimated to total $207.6 million.
EUA SYSTEM CONSTRUCTION PROGRAM
(In Thousands)
1997 1998 1999 3-Yr. Total
Generation $ 7,290 $ (a) $ (a) $ 7,290
Transmission 2,002 996 791 3,789
Distribution 14,362 15,143 15,598 45,103
General (177) 445 459 727
Total Utility Construction
Requirements 23,477 16,584 16,848 56,909
EUA Cogenex Capital
Requirements 34,637 41,500 49,800 125,937
EUA Energy Investment
Capital Requirements 15,257 5,219 4,287 24,763
Total $ 73,371 $ 63,303 $ 70,935 $207,609
(a) As discussed under Electric Utility Industry Restructuring "Rhode Island
Utility Restructuring Act of 1996" and "Massachusetts Restructuring
Settlement," to the extent that Montaup disposes all its generation assets,
no capital additions would be required.
Construction Program - Blackstone:
Blackstone's cash construction expenditures for the year ended December
31, 1996 were approximately $4.2 million, related primarily to its electric
distribution system.
Planned cash construction expenditures for 1997, 1998 and 1999, as set
forth below, are estimated to total $13.1 million.
BLACKSTONE CONSTRUCTION PROGRAM
(In Thousands)
1997 1998 1999 3-Yr. Total
Transmission $ 437 $ 230 $ 237 $ 904
Distribution 3,673 4,098 4,221 11,992
General 48 63 65 176
Total $ 4,158 $4,391 $4,523 $13,072
Construction Program - Eastern Edison:
Eastern Edison's cash construction expenditures for the year ended
December 31, 1996 were approximately $26.0 million.
Cash construction expenditures of Eastern Edison and Montaup for 1997,
1998 and 1999 as set forth below, are estimated to total $36.0 million.
<TABLE>
EASTERN EDISON CONSTRUCTION PROGRAM
(In Thousands)
<CAPTION>
1997 1998 1999 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 $ $7,284 $ $ <F1> $ $ <F1> $ $7,284 $7,284
Transmission 879 566 408 350 420 125 1,707 1,041 2,748
Distribution 8,792 9,070 9,343 27,205 27,205
General (687) (650) 58 60 (569) (650) (1,219)
Total $8,984 $7,200 $ 9,536 $ 350 $ 9,823 $ 125 $28,343 $7,675 $36,018
<FN>
<F1> As discussed under Electric Utility Industry Restructuring "Rhode Island
Utility Restructuring Act of 1996" and "Massachusetts Restructuring
Settlement," to the extent that Montaup disposes all its generation
assets, no capital additions would be required.
</FN>
</TABLE>
Fuel for Generation
The Retail Subsidiaries currently rely primarily on power purchased from
Montaup to meet their electric energy requirements (See Electric Utility
Industry Restructuring above). Power purchases 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.
The rates charged by Montaup for power sold to the Retail Subsidiaries are
those on file with FERC and are substantially the same as those charged by
Montaup for power sold to its unaffiliated customers. Changes in the cost to
Montaup of power from units in which it has interests are reflected in the cost
of power purchased by the Retail Subsidiaries. The Retail Subsidiaries recover
their cost of fuel and purchased power through the operation of revenue
adjustment clauses which are designed to provide timely recovery of such costs.
For 1996, the EUA System's sources of energy, by fuel type, were as
follows: 31% gas, 29% nuclear, 20% oil, 15% coal and 5% other. During 1996,
Montaup had an average inventory of 56,944 tons of coal for its steam
generating unit at the Somerset Station, the equivalent of 68 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 $49.90
per ton in 1996 which is equivalent to oil at $12.16 per barrel. This was the
same as 1995. 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 2,102 barrels and 45,070 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 $22.27 per barrel and
$17.19 per barrel in 1996, respectively. Montaup also maintained an average
inventory of jet oil of 3,573 barrels at an average cost per barrel of $25.83
during 1996 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 1996 year-end coal inventory of approximately 82,000
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 contracts with a supplier for up to 100% of the fuel-oil requirements of
Canal Unit Nos. 1 and 2 for the period ending December 31, 1997 with an option
of extending the contracts through March 31, 1998. 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 1996, the cost of oil
per barrel at Canal averaged $18.67. Additionally, Canal has a contract with a
gas supplier for approximately 70% of Canal 2's daily gas requirements. Canal
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 1994 through
1996, together with the weighted average cost of all fuels, are set forth
below:
Mills* per kWh
1996 1995 1994
Nuclear . . . . . . . . . 5.0 6.3 6.1
Gas . . . . . . . . . 14.4 14.3 14.1
Coal . . . . . . . . . 19.6 20.3 20.9
Oil . . . . . . . . . 37.7 30.2 27.1
All fuels . . . . . . . . . 16.7 16.7 14.5
*One Mill is 1/10 of one cent
The rate schedules of Montaup and the Retail Subsidiaries are designed to
pass on to customers the increases and decreases in fuel costs and the cost of
purchased power, subject to review and approval by appropriate regulatory
authorities (see Rates below).
OSP has two gas supply contracts which expire December 14, 2009 and
September 29, 2010, respectively, for its two 250 mw generators. The cost of
gas for 1996 averaged $1.20 per MBTU or approximately 10.0 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
as late as the year 2010. Montaup owns a 4.01% interest in Millstone III and a
2.9% interest in Seabrook I. Northeast Utilities, the operator of the units,
indicates that Millstone III 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 fuel rates and will be collected through the contract termination
charge.
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 cancelled following
substantial construction delays and cost overruns as the result of licensing
problems, unanticipated construction defects 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, NRC regulations require that it be decontaminated of any residual
radioactivity sufficiently so that the property may be released 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:
Both of the operating nuclear generating companies in which Montaup has an
equity ownership interest (see Item 2. PROPERTIES -- Power Supply) have
developed their estimates of the cost of decommissioning its unit and have
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, these companies re-estimate the cost of decommissioning and apply 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 "Yankee Atomic", and "Connecticut Yankee"
below).
Montaup is recovering through rates its share of estimated decommissioning
costs for Millstone III and Seabrook I. Montaup's share of the current
estimate of total costs to decommission Millstone III is $18.6 million in 1996
dollars, and Seabrook I is $13.1 million in 1996 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.
Yankee Atomic:
On February 26, 1992, Yankee Atomic announced that it would permanently
cease power operation of Yankee Rowe and began preparing for an orderly
decommissioning of the facility. Montaup has a 4.5% equity ownership in Yankee
Atomic with a book value of approximately $1.1 million at December 31, 1996.
Under the terms of its purchased power contract with the facility, Montaup must
pay its proportionate share of unrecovered costs and expenses incurred after
the plant is retired. In December 1992, Yankee Atomic received FERC
authorization to recover essentially all unrecovered assets and all costs
incurred after the February 26, 1992 shutdown decision until the plant is
decommissioned. Montaup's share of all unrecovered assets and the total
estimated costs to decommission the unit aggregated approximately $7.8 million
at December 31, 1996.
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 $4.8 million at December 31, 1996.
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. As a
result of the analysis, work at the plant had slowed pending a final board
decision. In December 1996, the Board of Directors 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. Connecticut Yankee has two years to submit its decommissioning plan
to the NRC. The preliminary estimate of the sum of future payments for the
permanent shutdown, decommissioning, and recovery of the remaining investment
in Connecticut Yankee, is approximately $758 million. Montaup's share of the
total estimated costs is $34.1 million.
Recent NRC Actions:
Millstone III
Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw
nuclear unit that is jointly owned by a number of New England utilities,
including subsidiaries of Northeast Utilities (Northeast). Northeast is the
lead participant in Millstone III, and on March 30, 1996, Northeast determined
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 NRC has raised numerous issues with respect to Millstone III 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" above).
In July 1996 Northeast reported that it has been responding to a series of
requests from the NRC seeking assurance that the Millstone III unit will be
operated in accordance with the terms of its operating license and other NRC
requirements and regulations and dealing with a series of issues that Northeast
has identified in the course of these reviews. Providing these assurances and
addressing these issues will be components of an Operational Readiness Plan
(ORP) to be developed for the Millstone III unit. The ORP for Millstone III
was submitted to the NRC on July 2, 1996 and is presently being implemented.
On October 18 1996, the NRC informed Northeast that it will establish a
Special Projects Office to oversee inspection and licensing activities at
Millstone. The Special Projects Office will be responsible for (1) licensing
and inspection activities at Northeast's Connecticut plants, (2) oversight
of an independent corrective action verification program; (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.
On October 24, 1996 the NRC issued another order directing that prior to
restart of Millstone III, Northeast submit a plan for disposition of safety
issues raised by employees and retain an independent third-party to oversee
implementation of this plan. This third-party oversight will continue until
the situation is corrected. There is no estimate of how long this will take.
Northeast Management has indicated it cannot presently estimate the effect
these efforts will have on the timing of restarts or what additional costs, if
any, these developments may cause.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $0.4 million to $0.8 million per month.
Montaup bills its replacement power costs through its fuel adjustment clause, a
wholesale tariff jurisdictional to the FERC. However, there is no comparable
clause in Montaup's FERC-approved rates which at this time would permit Montaup
to recover its share of the incremental operation and maintenance costs
incurred by Northeast.
EUA cannot predict the ultimate outcome of the NRC inquiries or the impact
which they may have on Montaup and the EUA system. Montaup is also evaluating
its rights and obligations under the various agreements relating to the
ownership and operation of Millstone III.
Maine Yankee
On June 7, 1996, the NRC commissioned an independent Safety Assessment
Team to assess the conformance of the Maine Yankee Atomic Power Station to its
design and licensing basis. Montaup holds a 4.0% ownership interest in the
Maine Yankee Unit.
On October 7, 1996, the NRC released an Independent Safety Assessment
(ISA) report. In evaluating the Plant's conformance to its licensing basis,
the report concluded that Maine Yankee was in general conformance with its
licensing basis although significant items of nonconformance were identified
stemming from two closely related root causes: (1) economic pressure to be a
low-cost energy provider had limited available resources to address corrective
actions and some improvements and (2) a questioning culture was lacking, which
had resulted in a failure to identify or promptly correct significant problems
in areas perceived by Maine Yankee to be of low safety significance.
A letter to Maine Yankee from the Chair of the NRC, accompanying the ISA
report directed Maine Yankee to provide to the NRC its plans for addressing the
root causes of the deficiencies identified by the ISA.
In December, 1996 the unit was shut down for inspections and repairs to
resolve cable-separation and associated issues. While the plant has been out
of service, Maine Yankee, having previously detected indications of minor
leakage in a small number of the plant's 38,000 fuel rods, used the opportunity
to inspect the Plant's 217 fuel assemblies. As a result of the inspection,
Maine Yankee determined that several fuel assemblies that contained leaking
rods should be replaced and has commenced that process. On January 29, 1997
the NRC announced that it had placed the unit on its "watch list." The
operator expects the Plant to remain out of service until the fuel-assembly
replacement and a thorough inspection of the Plant's electrical cabling are
completed and associated issues resolved, and restarting the Plant is approved
by the NRC. The operator cannot now predict how long it will take to complete
those processes.
In February 1997, Maine Yankee and Entergy Nuclear, Inc. signed a contract
for Entergy to provide management services including plant operations at the
Maine Yankee plant through September 1997. Maine Yankee and Entergy have been
discussing the possibilities of a longer term contract.
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 MDPU 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.
The MDPU and RIPUC have approved a Memorandum of Understanding (MOU)
between Eastern Edison, Blackstone, Newport and Montaup. The MOU establishes a
framework for a coordinated, regional review of the resource planning and
procurement process of those companies. It is 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 will file with the MDPU and
Blackstone and Newport will file with the RIPUC an integrated resource plan
concurrently. The MOU outlines a mechanism and a timetable by which the reviews
by the two commissions will be coordinated and any inconsistencies among the
decisions by the state commissions will be resolved.
In conjunction with its approval of the MOU, the MDPU granted Eastern
Edison and Montaup an exemption from the MDPU'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 is not expected to have 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. Massachusetts is currently reviewing the
need for its review of load forecasting and resource planning, recognizing that
resource procurement is now a competitive function. As competition becomes
more prevalent in the electric industry, it is anticipated that regulatory
review 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 MDPU in the case of Eastern Edison and with the RIPUC in the case of
Blackstone and Newport. For the 12 months ended December 31, 1996, 62% of
EUA's consolidated revenues were subject to the jurisdiction of FERC, 15% to
that of the MDPU and 12% 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, 1996, 80.6% of Eastern Edison's
consolidated revenues were subject to the jurisdiction of the FERC and 19.4% to
MDPU. 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):
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Applied For Effective<F1> Return on
Annual Annual Common
Revenue Date Revenue Date Equity %
Federal
- Montaup
M-14 $ (10,133) 3/21/94 $(13,992) 8/9/94<F2> 11.10 <F3>
Massachusetts
None
Rhode Island
- Blackstone
RIPUC - 2045
- Phase III 353 11/1/94<F4> 353 1/1/95
- Phase IV 152 10/23/95<F5> 152 1/1/96
RIPUC - 2498 3,094 11/15/96<F6> 2,821 1/1/97
- Newport
RIPUC - 2045
- Phase III 417 11/1/94<F4> 417 1/1/95
- Phase IV 179 10/23/95<F5> 179 1/1/96
RIPUC - 2498 1,437 11/15/96<F6> 1,425 1/1/97
____________________
<FN>
Notes:
<F1> Per final order or settlement agreement.
<F2> Settlement Agreement with all parties with an annual reduction of
$13,992,000 with billing credits to Middleboro over the period January
1995 through October 1999 totaling $496,000.
<F3> Rate used for AFUDC calculation purposes. Settlement contains no specific
finding on allowed common equity return.
<F4> RIPUC Docket No. 2045 was a generic docket for all Rhode Island utilities
reviewing FAS106 expenses. The effective amount represents the revenue
requirement for one-third of the tax deductible amount of the FAS106
expenses (see Rhode Island Proceedings below). As this was a single issue
proceeding, the RIPUC made no revisions to the allowed return on common
equity.
<F5> The revenue requirement represents 14.3% of the total FAS106 incremental
tax deductible amount to be recovered in each of the next seven years.
This annual revenue requirement recovers, over seven years, the FAS106
incremental tax deductible costs which were deferred by the companies in
Phases I&II and will be eliminated after the seven-year recovery.
<F6> 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 Consumer Price
Index for the most recent 12 months ended September 30, 1996.
</FN>
</TABLE>
FERC Proceedings:
On May 21, 1994 Montaup filed a rate application with FERC to reduce
annual revenues by $10.1 million. This request was intended to match more
closely Montaup's revenues with its decreasing cost of doing business resulting
from, among other things, a reduced rate base, lower capital costs and
successful cost control efforts. The application also included a request for
recovery of all of Montaup's FAS106 expenses as provided in FERC's generic
order of December 1992, including a five-year amortization of previously
deferred FAS106 costs. Also incorporated in this filing was a request to make
Newport an all requirements customer of Montaup. Settlement agreements were
certified by FERC with all intervenors with an annual base rate reduction of
approximately $14 million annually, (inclusive of the filed $10.1 million
reduction) effective as of August 1994.
On February 20, 1996, Montaup filed an application with FERC for network
and point-to-point transmission service tariffs. FERC required this tariff
application before granting a concurrent application of Duke/Louis Dreyfus
Energy Services (New England) L.L.C. for permission to charge market based
rates.
On July 9, 1996 Montaup refiled the application to conform with FERC open
access terms and conditions. On January 21, 1997 the application was refiled
to conform with the NEPOOL open access tariff. FERC has not yet acted upon the
filings.
Massachusetts Proceedings:
The MDPU has put all companies on notice that it expects them..."to
consider mergers or acquisitions in order to further optimize least-cost
planning efforts and better fulfill their obligations to serve." Thereafter,
the MDPU instituted an investigation, which was concluded on August 3, 1994,
for the purpose of establishing, among other things, guidelines and standards
for acquisitions and mergers of utilities and evaluating proposals regarding
the recovery of costs associated with such activities. It is not possible to
predict what effects, if any, the MDPU proceeding will have on the EUA System.
In December 1994, the MDPU approved a request made by Eastern Edison to
recover through a reconciling adjustment factor a portion of "lost base
revenues." Lost base revenue represents amounts the company would have
collected if it had not offered demand-side management and conservation and
load management programs to its customers.
On September 20, 1994, the MDPU issued a notice of inquiry and order
seeking comments on incentive regulation (MDPU 94-58). The inquiry was to
focus on incentive regulation, sometimes referred to as performanced-based
regulation, to replace in whole or in part its existing cost-of-service/rate-
of-return regulatory framework. Comments were filed by Eastern Edison and
other interested persons. On February 24, 1995, the MDPU issued an order
relating to implementation of incentive regulation. In the order, the MDPU
strongly encouraged all jurisdictional electric utilities to devise and propose
incentive plans. The objective of incentive regulation is to "provide market-
place benefits to consumers through (1) more efficient utility operations, (2)
stronger utility incentives for better cost control, and (3) enhanced
opportunities for lower rates." While no timetable was specified, the MDPU
stated the largest utilities should commence the incentive plan design process
as soon as possible. EUA cannot predict what effect, if any, the MDPU's order
will have on the EUA System. However, Eastern Edison's December 23, 1996
settlement agreement with Massachusetts Department of Energy Resources and that
State's Attorney General, expected to be formally submitted to the MDPU in
March 1997, contains performance based regulation standards. (See Electric
Utility Industry Restructuring under "Massachusetts Restructuring Settlement"
above).
On February 10, 1995, the MDPU issued a notice of inquiry and order on
electric industry restructuring (MDPU 95-30). The investigation was
established to determine: (1) how a restructuring of the Massachusetts electric
industry would promote competition and economic efficiency while expanding
opportunities that would benefit consumers, (2) whether and how to extend to
customers the option of choosing their own electric suppliers; (3) how such a
restructuring could be implemented; and (4) the appropriate regulatory
mechanisms to apply to a restructured electric industry.
After initial and second round comments were received, the MDPU held
hearings and issued its order on August 16, 1995. The order facilitates
increased competition by requiring investor-owned electric utilities to
unbundle their rates, provide consumers with accurate price signals, and enable
customer choice that allows consumers to purchase generation services
separately from transmission and distribution services. The order provides for
the recovery of net, non-mitigatable stranded costs that will result from the
transition from a regulated to a competitive industry structure.
The order sets forth the MDPU's overall goals for a restructured industry,
the essential characteristics of a restructured industry, as well as principles
to be considered in the transition to a restructured industry. Given the
complexity of the issues, the MDPU supported the multiple requests from
reviewers for a period during which participants can negotiate settlements.
The MDPU stated that consensus and settlements are more likely than litigation
to advance the restructuring process, and directed each company to undertake
negotiations with all interested participants to develop a plan for moving
toward competition in generation and retail customer choice, to decide the
amount and develop a mechanism for stranded cost recovery, and establish
unbundled rates. A collaborative group representing the full spectrum of MDPU
95-30 participants has been meeting in Massachusetts to discuss these issues.
The MDPU noted that while the concepts of competition and customer choice are
fundamental to restructuring, and the basic principles will apply to all
restructuring proposals, specific company corporate structures, service
territories, rate structures and stranded costs may require individual
consideration.
The MDPU established a specific schedule for restructuring proposals.
Massachusetts Electric Company, Boston Edison Company, and Western
Massachusetts Electric Company were required to file their settlements and
proposals by February 16, 1996. The remaining electric utilities are required
to file their settlements and proposals within three months of the issuance of
MDPU orders related to the restructuring proposals of the former three
companies. Companies are required to file the following information: (1) a
plan for moving from the current regulated industry structure to a competitive
generation market and to increased customer choice; (2) illustrative rates and
supporting information that indicate unbundled charges for generation,
distribution, transmission, and ancillary services; (3) an identifiable charge
reflective of the level of stranded costs to be recovered with all necessary
supporting information; and (4) a plan for incentive regulation in the
transmission and distribution systems. Eastern Edison filed its restructuring
plan on February 16, 1996 which was assigned MDPU Docket No. 96-24. A public
hearing was held on March 6, 1996. See Electric Utility Industry Restructuring
under "Massachusetts Restructuring Settlement" for a discussion of the December
23, 1996 settlement among Eastern Edison, Montaup, Massachusetts Department of
Energy Resources and the Massachusetts Attorney General. A formal settlement
plan under Docket No. 96-24 is expected to be filed with the MDPU in March
1997.
On December 30, 1996 the MDPU issued its Model Rules in Docket # 96-100,
the second phase of its investigation of the restructuring of the electric
utility industry in Massachusetts and proposed legislation for consideration by
the Massachusetts Legislature that would provide the MDPU with the mandate to
implement these rules. The MDPU has indicated that its overall goal is to
develop an efficient industry structure and regulatory framework that minimizes
costs to consumers while maintaining safe and reliable electric service with
minimum impact on the environment. Consistent with the overall goal, the Model
Rules provide for, among other things:
- customer choice of electricity supplier with local distribution
companies guaranteeing default service including continuation of low
income protections and discounts;
- independent central regional transmission system operator;
- non-discriminatory open access transmission;
- functional separation of distribution, generation and transmission;
- distribution services remain a regulated monopoly;
- commitment to significant environmental improvement;
- funding mechanism to provide financial support for renewable and
emerging technologies and continuation of demand-side management
programs;
- reasonable opportunity for recovery of stranded costs; and
- standards of conduct for distribution companies and their competitive
affiliates.
While Eastern Edison believes that its December 23, 1996 agreement with
the Attorney General and the Division of Energy Resources is consistent with
the requirements of these Model Rules, it is of the opinion that the MDPU has
the authority to approve the agreement without the need of additional
legislation or officially promulgating these Model Rules. See Electric Utility
Industry Restructuring, under "Massachusetts Restructuring Settlement," with
respect to settlement negotiations.
Rhode Island Proceedings:
On April 7, 1992, the RIPUC initiated generic Docket No. 2045 pertaining
to the FAS106 issue for all Rhode Island utility companies. On June 26, 1992,
Newport and Blackstone filed proposed rate increases to reflect the impact of
FAS106 of approximately $1.3 million and $2.7 million, respectively. An order
was issued on December 11, 1992 granting recovery of a tax deductible amount of
FAS106 phased into rates over a three-year period with the initial one-third to
be recovered no earlier than the first fiscal year beginning after December 15,
1992, and the deferrals of the first two years recovered in rates over the
seven-year period following the three-year phase-in. On December 21, 1992,
Newport and Blackstone filed compliance rates representing phase one of the
three-year phase-in. The Phase I revenue requirement, representing one third
of the incremental FAS106 tax deductible amount for Blackstone and Newport was
calculated to be $353,000 and $417,000, respectively. Phase II compliance was
filed November 1, 1993. The revenue requirement, representing two thirds of
the incremental FAS106 tax deductible expense for Blackstone and Newport was
calculated to be $706,000 and $834,000, respectively. Phase III compliance was
filed November 1, 1994. The revenue requirement, representing the full phase-
in of the incremental FAS106 tax deductible expense for Blackstone and Newport
were calculated to be $1,059,000 and $1,251,000, respectively. Phase IV
compliance was filed on October 23, 1995, recovering deferred amounts over 7
years, 14.3% each year starting January 1, 1996. The RIPUC also ordered that
all amounts recovered be placed in trusts permitted by the IRS which will
maximize tax deductibility.
Also, on January 14, 1994, the RIPUC issued a written order establishing
Docket No. 2167 for a Comprehensive Review of Newport's rate design. A
prehearing conference was held on February 8, 1994 at which time a schedule for
pre-filing testimony was established.
On May 20, 1994, Newport filed its Cost of Service Study (COSS) analysis
of the rates of return by customer class and an alternative rate design
proposal. The RIDPUC filed its recommendations with regard to cost allocation
and rate design on June 23, 1994. The United States Navy, Newport's largest
customer, filed its recommendations on June 24, 1994. On July 29, 1994 the
Company filed a Stipulation and Settlement Agreement (SSA) which had been
executed by the RIDPUC and TEC-RI. The parties signing the SSA agreed on
certain rate class revenue changes. While the settling parties did not agree
with the COSS techniques utilized by Newport, they agreed to accept the SSA
rather than litigating with respect to what might be deemed appropriate study
allocators and techniques. The rate class revenue changes generally reduce,
although they do not eliminate, inequities in the class rate of return.
Newport agreed to perform a new COSS to be submitted no later than July 1,
1996. At an open meeting on October 28, 1994, the RIPUC found that the SSA is
reasonable and in the best interests of the ratepayers. Rates established in
compliance with the RIPUC's October 28, 1994 finding, were effective January 1,
1995.
In December 1994, the United States Navy, filed a petition for a writ of
certiorari with the Rhode Island Supreme Court to review the RIPUC's decision.
A second motion to stay was filed by the Navy on December 21, 1995. On June
28, 1996 Newport filed its 1995 COSS and on July 8, 1996 the U.S. Navy filed a
Motion for Expedited Hearing. The RIDPUC took the position that the RIPUC's
order in Docket No. 2167 neither required nor set any timetable for additional
rate changes. The RIDPUC also indicated that it took no position regarding
either the merits of the COSS or the Navy's request for an expedited hearing.
The RIDPUC, at the RIPUC's request reviewed the results of the COSS as well as
the allocation methodologies employed. Additionally, the RIDPUC explored the
propriety of the Navy's request in light of the filing of unbundled rates
required to be made effective by the Restructuring Act of 1996. On February 3,
1997 the Navy filed a stipulation to withdraw the writ of certiori it had filed
in December 1994.
On June 27, 1994 TEC-RI petitioned the RIDPUC to investigate the propriety
of "the current bundled electric rates," and what might be required to
transition "... from a fully regulated to a more competitive retail electric
industry". A RIDPUC hearing officer was appointed on July 24, 1994 and Docket
No. D-94-9 was established. Blackstone and Newport were parties to the
proceeding.
Initial and reply comments were submitted to a comprehensive list of
issues. Many of the comments addressed a broad restructuring of the electric
utility industry. When the parties met on January 9, 1995, they decided that
TEC-RI's proposal for a "cooperative collaborative process," including the
RIDPUC as a party, rather than a litigated proceeding before the RIDPUC hearing
officer, was appropriate. Hence, the Rhode Island Collaborative
(Collaborative) was formed.
On May 12, 1995, the Collaborative submitted a Report and Set of
Interdependent Principles to the RIPUC. The 17 Interdependent Principles
represented the Collaborative's underpinnings for any restructuring proposal.
The Collaborative requested that the RIPUC establish a docket and conduct a
hearing to explore the settlement principles with a view to issuing an order
indicating whether the principles "provide a suitable basis for further
detailed negotiation by the parties, or in what respects they require
modification" and setting a deadline for the submission of a more detailed
proposal for restructuring.
The RIPUC responded to the Collaborative's request by creating Docket No.
2320, taking administrative notice of Docket No. D-94-9, and declaring that all
parties to the Division docket would be treated as intervenors in this docket.
The RIPUC conducted a technical conference on July 6, 1995 and a Public hearing
on July 11, 1995. On July 19, 1995 three of the principles were modified to
address concerns expressed by the RIPUC at the technical conference. On July
25, 1995, the Collaborative provided additional information on the principle
concerning renewables, and requested that the RIPUC approve the principles in
full.
On August 16, 1995, the RIPUC accepted the principles as modified,
deleting the principle concerning renewables and adding a principle concerning
negotiation. The Collaborative was directed to proceed with negotiations to
quantify specific issues involving competition and open access as well as the
other issues presented in the principles. A Collaborative Progress Report was
filed in February, 1996. Blackstone and Newport have been active participants
in the ongoing collaborative meetings. As a result of legislative actions and
the passing of the URA, Docket No. 2320 was formally closed and the
collaborative was disbanded.
In February 1997 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. Management cannot predict the ultimate outcome of this
investigation.
The RIPUC opened Docket No. 2514 to investigate the restructuring plan
filed by Blackstone and Newport on December 27, 1996 in compliance with the
URA. Hearings are scheduled to be held during April 1997. On February 28,
1997, Blackstone, Newport and Montaup reached settlement with the RIDPUC and
the Rhode Island Attorney General with regard to implementation of a
restructuring plan for Blackstone, Newport and Montaup. In addition to
complying with the URA, the settlement provides for an immediate 10% rate
reduction and a commitment by Montaup to file a plan by July 1, 1997 to divest
all of its generating assets. Management cannot predict the ultimate outcome
of this investigation. See Electric utility Industry Restructuring under
"Rhode Island Utility Restructuring Act of 1996" for a discussion of the URA
and settlement agreement.
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, an environmental audit program designed to ensure compliance
with environmental laws and regulations and to identify and reduce liability
was instituted for Montaup and the Retail Subsidiaries.
Federal, Massachusetts and Rhode Island legislation requires consideration
of reports evaluating environmental impact of large projects as a prerequisite
to the granting of various permits and licenses with a view of limiting such
impact. 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 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 in which Montaup and Newport 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.
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.
The EPA has issued regulations relating to the generation, transportation,
storage and disposal of certain wastes under RCRA; in Massachusetts, the
requirements are implemented and enforced by the MADEP, whereas in Rhode
Island, RIDEM implements and enforces its own regulations under a state statute
comparable to RCRA as well as pursuant to EPA authorization.
There is an extensive body of federal and state statutes governing
environmental matters, including CERCLA, as amended by the Superfund Amendments
and Reauthorization Act of 1986; in Massachusetts, Chapter 21E, and, in Rhode
Island, the "Industrial Property Site Remediation and Reuse Act" (Brownfields
Legislation) 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. Under CERCLA, Chapter 21E, and the
Rhode Island Brownfields Legislation, joint and several liability for cleanup
costs may be imposed on, 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 Brownfields Legislation. As a rule, the subsidiaries
employ licensed contractors to dispose of such materials. See Item 3. LEGAL
PROCEEDINGS -- Environmental Proceedings.
The EPA, pursuant to TSCA, regulates the use, storage, and disposal of
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 PCB and which may be subject to
regulations pursuant to TSCA.
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. Rhode Island 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, Rhode Island requires that,
in the context of reviewing an energy facility siting application, the
applicant submit for review by the Board, when applicable, any current
independent, scientific research pertaining to EMF exposure. 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 is to restore and
maintain the chemical, physical, and biological integrity of the nation's
navigable waters. The elimination of pollutant discharges (including heat)
into navigable waters is one goal aimed at achieving this objective. Another
step mandated by the Federal Water Pollution Control Act was the creation of a
rigorous permit program. All water 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.
Standards have been established to control the dredging and filling of
wetlands under the Federal Water Pollution Control Act, the Massachusetts
Wetland Protection Act, 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.
Under the Massachusetts Water Management Act, the MADEP is responsible for
promulgating regulations relating to water usage and conservation.
Most of the generating units from which Montaup obtains power operate
under permits which limit their effluent discharges into water and which
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.
The Oil Pollution Act of 1990 was passed after several major oil spills
occurred in waters of the United States. The primary intent of this
legislation is to mandate strong contingency plans to prevent releases of oil
and to require that sufficient resources are in place and ready to respond to
any release. The Somerset plant has an approved plan which is in place and
operational. EPA, United States Coast Guard, RIDEM, and MADEP have a number of
other rules in place, such as EPA's Spill Prevention, Countermeasures and
Control Plan regulations, which are designed to minimize the release of oil and
other substances into navigable waters and the environment.
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). The Canal Station
Unit 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. Congress passed amendments to the Clean Air Act in 1990 which
created additional regulatory programs and generally updated and strengthened
air pollution control laws. These amendments expand the regulatory role of the
EPA regarding emissions from 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, tightens the emission limits imposed 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 by the end of 1999. The control program establishes a
national cap of 8.90 million tons per year for SO2 emissions. Beginning in the
year 2000, the EPA will issue 8.90 million SO2 allowances to utilities
annually. The SO2 allowance program will not affect Montaup's Somerset Station
or Canal Unit 2 until January 1, 2000.
Massachusetts MADEP regulations establish 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 federal
standards, Montaup would not be required to meet this SO2 emission level until
the year 2000 as a result of Title IV of the Clean Air Act. However,
Massachusetts MADEP regulations require compliance five years earlier. 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 substituting lower sulfur content fuels.
Other provisions of the Clean Air Act Amendments will likely impact
Montaup. Title I of the Act sets a strategy for states to move toward
attaining national air quality standards, with the emphasis on meeting the
ozone standard. Ozone relates directly to the nation's smog problem. NOx is
one of the precursors of ozone formation. Title I requires additional controls
on industrial sources of NOx including utility power plants. The Act creates
the Northeast Ozone Transport Region, covering the area from Virginia to Maine,
including Massachusetts and Rhode Island. Areas within the transport region
will become subject to enhanced controls on NOx emissions.
In April 1992, NESCAUM, an environmental advisory group for eight
Northeast states including Massachusetts and Rhode Island issued
recommendations for nitrogen oxide controls for existing utility boilers
required to meet the ozone non-attainment requirements of the Clean Air Act
Amendments. The NESCAUM recommendations are more restrictive 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 initiated compliance through,
among other things, selective, noncatalytic reduction processes. MADEP has
proposed regulations which would require additional NOx emission reductions
beginning on May 1, 1999. Montaup is evaluating its compliance options under
this proposed regulation.
Title V of the Clean Air Act Amendments provides EPA with broad new
permitting authority, with the goal of having states begin to issue federally
enforceable operating permits in 1995 which will outline limits and conditions
necessary to comply with all applicable air requirements. The Clean Air Act
Amendments' permitting program will be phased in over a couple of years.
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. This application is still under DEP review. Although individual
sources will be required to pay fees to the various states which will
administer the program, the impact of these requirements is not expected to
have a material financial impact on the EUA System.
On November 27, 1996, the EPA announced that, under the Clean Air Act, it
was proposing to toughen the nation's ozone standards as well as the
particulate matter standards. The states will be responsible for writing plans
to bring themselves into compliance. States would have until the year 2000
to submit ozone plans and until the year 2002 to submit particulate plans.
After that, the states will have a few more years to meet the established
goals. At this time, management is unable to predict the financial impact this
rule might have on the EUA system, once it is issued in its final form. Once
the public comment period is completed, the EPA plans to promulgate final rules
in June 1997.
On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney
General and Division of Energy Resources reached a settlement in principle
regarding electric utility restructuring in the State of Massachusetts. The
proposed 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. Within this allowance
cap, the following commitments were made:
- 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;
- On January 1, 2000, Somerset Units 5 & 6 will comply with an annual SO2
emission rate of 0.30 lbs/mmBtu;
- On January 1, 2000, Units 5 & 6 will comply with a 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).
The cost Unit 6 must incur to comply with this NOx limit is capped at
$405,000 per year until January 1, 2003. Unit 5, if reactivated, will
comply with the above NOx limit with no cost cap; and
- On January 1, 2010, Canal Electric's Unit #2 will comply with an SO2
emission rate of 0.30 lbs/mmBtu, and a NOx emission rate of 0.15
lbs/mmBtu, on an annual basis; this commitment was made only for
Montaup's 50% ownership share of Canal 2.
The formal settlement is expected to be submitted to the MDPU in March
1997.
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.
In some environmental areas the NRC and the EPA have overlapping
jurisdiction. Thus, NRC regulations are subject to all conditions imposed by
the EPA and a variety of federal environmental statutes, including obtaining
permits for the discharge of pollutants (including heat) into the nation's
navigable waters. In addition, the EPA has established standards, and is in
the process of reviewing existing standards, for certain toxic air pollutants,
including radionuclides, under the Clean Air Act Amendments which apply to NRC-
licensed facilities. In fact, in December of 1996, the EPA issued a final
rule rescinding previously published limitations on radionuclide emissions to
ambient air, as applied to NRC or NRC Agreement state licensed facilities other
than commercial nuclear power reactors. The EPA has also promulgated
environmental radiation protection standards for nuclear power plants. These
standards regulate the doses of radiation received by the general public.
The NWPA provides for development by the federal government of facilities
for the disposal or permanent storage of civilian nuclear waste. For further
details about NWPA, see Fuel for Generation above. The NRC has also
promulgated regulations regarding the disposal of nuclear waste materials
designed to protect the public from radiological dangers.
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, in delays or cancellation of
construction of planned improvements, or in modification or termination of
existing facilities.
Item 2. PROPERTIES
Power Supply
Montaup currently supplies the EUA System with nearly 100% of its electric
requirements. Newport became an all-requirements customer of Montaup on May
21, 1994. At the same time, Montaup assumed all of Newport's power contracts
and began leasing all of Newport's generation facilities and a portion of
Newport's transmission facilities. In 1996, 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) 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. Current forecasts
indicate that the combination of company owned generation, current long-term
purchased power contracts, expected short-term power opportunities, and the
System's C&LM programs, should meet EUA System capacity requirements. See
Electric Utility Industry Restructuring under "Rhode Island Utility
Restructuring Act of 1996" and "Massachusetts Restructuring Settlement" for a
discussion of plans to divest all of Montaup's generating assets.
The 1996 peak EUA System demand was approximately 854 mw experienced on
August 6, 1996.
<TABLE>
<CAPTION>
EUA SYSTEM CAPABILITY
GENERATING UNITS IN SERVICE AS OF DECEMBER 31, 1996
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. 100.00 110.00 110.00 0.00 110.00
1970 SOMERSET J1 JET OIL MONTAUP ELECTRIC CO. 100.00 22.00 22.00 0.00 22.00
1971 SOMERSET J2 JET OIL MONTAUP ELECTRIC CO. 100.00 21.20 21.20 0.00 21.20
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 8.80 8.80 0.00 8.80
1978 ELDRED DIESEL NEWPORT ELECTRIC CORP. 100.00 8.25 8.25 0.00 8.25
SUBTOTAL: 171.49 0.00 171.49
JOINT OWNERSHIP:
1976 CANAL 2 NO. 6 OIL CANAL ELECTRIC COMPANY 50.00 586.00 293.00 60.03 232.97
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 45.93
1990 SEABROOK NUCLEAR NORTH ATLANTIC ENERGY CORP 2.90 1162.00 33.70 0.00 33.70
SUBTOTAL: 388.93 60.03 328.90
EQUITY OWNERSHIP:
1972 MAINE YANKEE NUCLEAR MAINE YANKEE ATOMIC POWER 3.59 879.00 31.57 0.00 31.57
1972 VERMONT YANKEE NUCLEAR VT. YANKEE NUCLEAR POWER 2.25 531.00 11.95 0.00 11.95
SUBTOTAL: 43.52 0.00 43.52
PURCHASED POWER:
1968 CANAL 1 NO. 6 OIL CANAL ELECTRIC COMPANY 25.00 562.00 140.50 0.00 140.50
1972 PILGRIM 1 NUCLEAR BOSTON EDISON COMPANY 11.00 670.11 73.71 0.00 73.71
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 22.73 110.00 25.00 0.00 25.00
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 22.77 57.10 13.00 0.00 13.00
1974 BEAR SWAMP GT1 HYDRO NEW ENGLAND POWER 5.09 294.50 15.00 0.00 15.00
1974 BEAR SWAMP GT2 HYDRO NEW ENGLAND POWER 5.10 294.00 15.00 0.00 15.00
1990 OSP 1 GAS OCEAN STATE POWER 28.00 287.00 80.36 0.00 80.36
1991 OSP 2 GAS OCEAN STATE POWER 28.00 287.00 80.36 0.00 80.36
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. 5.88 170.00 10.00 0.00 10.00
1970 NU JETS JET OIL NORTHEAST UTILITIES 25.61 97.60 25.00 0.00 25.00
SUBTOTAL: 554.75 0.00 554.75
HYDRO QUEBEC ENTITLEMENT:
1991 HYDRO QUEBEC I&II HYDRO HQ / NEPOOL 4.06 1215.00 49.31 0.00 49.31
SUBTOTAL: 49.31 0.00 49.31
TOTAL GROSS SYSTEM CAPABILITY (MW) -------------------- 1,208.00
LESS: UNIT CONTRACT SALES (MW) --------------- 60.03
TOTAL NET SYSTEM CAPABILITY (MW) ------------- 1,147.97
</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.)
Other Property
The EUA System owns approximately 4,600 miles of transmission and
distribution lines and approximately 85 substations located in the cities and
towns served.
Blackstone owns approximately 1,000 miles of transmission and distribution
lines and approximately 23 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 1996 Annual Report (Exhibit 13-1.01 filed herewith) regarding
encumbrances.
Eastern Edison and Montaup own approximately 3,200 miles of transmission
and distribution lines and approximately 48 substations located in the cities
and towns served. See Note F of Notes to Consolidated Financial Statements in
Eastern Edison's 1996 Annual Report (Exhibit 13-1.08 filed herewith) regarding
encumbrances.
Newport owns approximately 400 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, 1996, (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, 1996, (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 may now be 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. As a result, Blackstone expects to be offered a de
minimis party buyout settlement from the major members of the site PRPs.
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
Mass. Gen. 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 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 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/Knoll 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/Knoll 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. Blackstone retained the services of
Atlantic Environmental Services to conduct the site assessment pursuant to the
Massachusetts Contingency Plan and on August 15, 1996 Blackstone signed an
amended Administrative Consent Order Tier IB permit. It is expected that
Atlantic will begin the site assessment work in the Spring 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 waste removed from the Mendon Road site,
ferric ferrocyanide (FFC), was not "hazardous" within the meaning of CERCLA or
Mass. Gen. Laws Chapter 21E and 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. If the EPA determines that FFC is
not 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. 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 to be followed
by the Commonwealth's written reply. EPA will then 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.
Blackstone's Complaint also seeks a declaratory judgment that Stone & Webster
and Valley owned and/or operated a coal gasification plant on Tidewater Street
in Pawtucket (the Tidewater Plant) where the coal gasification waste allegedly
was generated, and that they individually or collectively arranged for the
disposal of such waste at Mendon Road. 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.
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/Knoll, Cumberland, and
Woonsocket Sites.
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 10 acres), the
No. 1 Station owned by Blackstone (approximately 10 acres), and land formerly
owned by Blackstone that was sold in 1968 to the City of Pawtucket
(approximately 10 acres). RIDEM told Blackstone that the site contained
hazardous wastes 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 Hazardous 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. Field work was completed in September 1996.
RIDEM is currently reviewing the draft Remedial Investigation Report. It is
expected that RIDEM will order further investigation and remedial clean up.
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. If Blackstone convinces EPA 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 pursue its legal
remedies in district court in Massachusetts to convince the court that FFC is
not a hazardous substance.
On January 10, 1997, Blackstone, Valley, and a representative of RIDEM met
at Valley's Woonsocket property, which is the site of a former manufactured gas
plant owned by Blackstone's and Valley's predecessor, Blackstone Valley Gas &
Electric company and its predecessor, the Woonsocket Gas Company. It is
anticipated the RIDEM will order Blackstone and Valley to conduct a site
assessment of the site in 1997.
4. Montaup and EUA Service received a Notice of Responsibility on July 27,
1987, from the MADEP for suspected hazardous material at a site owned by
Montaup on Hortonville Road in Swansea, Massachusetts. Montaup has completed
investigative and remedial actions in accordance with new Massachusetts
Contingency Plan regulations. The total cost of the cleanup was less than
$150,000.
5. During March-April 1990, Eastern Edison conducted a limited
environmental investigation (Phase I study) of a portion of its Dupont
Substation in Brockton, Massachusetts. During the investigation, Eastern
Edison notified the MADEP that it had encountered oils and PCBs. On May 3,
1990, the MADEP notified Eastern Edison of its liability for releases of oil
and/or hazardous materials at the site, and requested a copy of the Phase I
study. Following its review of the Phase I study on January 23, 1991, the
MADEP issued a Notice of Responsibility to Eastern Edison requiring a Phase II
- - - Comprehensive Site Investigation. A scope of work for the Phase II study was
submitted on April 12, 1991. In August 1994 a transition statement issued by
MADEP reclassifying the site from a Tier IA site to a Tier IB site was signed
by Eastern Edison and submitted to MADEP. That reclassification enabled
the site to be investigated and cleaned up under the guidance of a licensed
site professional without MADEP approval for each action taken. Cleanup
activities were completed in 1996 in accordance with DEP regulations and an
Activity and Use Limitation was filed for the site. The total cost of the
cleanup was approximately $550,000.
6. In November 1996, oily deposits containing PCB were found in the Canal
Electric gas pipeline lateral and certain in-plant equipment. This
contamination was a result of a malfunction of a shut-off valve in the meter
station outside of Canal plant's jurisdiction. Cleanup and improvement costs
are estimated to be between $500,000 and $1 million. Pending final cost
allocation and reimbursement, Montaup's share of the costs is expected to be
minimal. The cleanup is scheduled for completion in the first quarter of
1997.
Blackstone, Eastern Edison, Montaup and EUA Service are unable to predict
the outcome of any of the foregoing environmental matters or to estimate the
potential costs which may ultimately result. It is the policy of these
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 liability,
if any, will be assumed by, or can be enforced against, the insurance carriers
in these matters. 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, 1996, the EUA System has incurred costs of
approximately $5.7 million (excluding the Mendon Road judgment) in connection
with the foregoing environmental matters. EUA estimates that additional
expenditures (excluding the Mendon Road judgment) may be incurred through
1998 of up to $2.8 million, substantially all of which relate to Blackstone.
As a general matter, the EUA System will seek to recover costs relating to
environmental proceedings in their rates. Blackstone is recovering in rates
certain of its incurred costs over a five-year period. Montaup is currently
recovering certain of its incurred costs in its 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.
EUA WestCoast L.P.
In June 1993, EUA WestCoast L.P., a partnership in which EUA Cogenex is
the managing partner, filed a lawsuit against the contractors responsible for
the design and construction of a 1.5 mw cogeneration facility, as well as the
surety which issued a performance bond guaranteeing construction. Certain
defendants in that action have filed cross-complaints against EUA WestCoast and
EUA Cogenex, seeking, among other things, approximately $300,000 for payments
withheld by EUA WestCoast due to the contractor's deficient performance,
contribution and indemnity. A contractor has also filed a cross-complaint
against the host. Additionally, the host has filed a cross-complaint against
EUA Cogenex and the other parties in the litigation, seeking approximately $7
million in damages arising principally from lost economic advantage. EUA
WestCoast filed its own cross complaint against the host affirmatively
seeking damages. The above litigation was settled in the fourth quarter of
1996. The settlement called for, among other things, a payment to EUA Cogenex
of $2.8 million and a general release by all parties to the lawsuit. The
settlement was enforced by the courts and payment was received in December
1996.
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.
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 only approximately $170,000 was 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 counter claims in
excess of $20 million and a request for treble damages. In response to the
counter claim, Eastern Edison paid MMLP approximately $192,000 as the amount
Eastern Edison considered to have been owed to MMLP. The Company is vigorously
defending itself from the counter claims. 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
is $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, and EUA is consulting with those insurers to
determine the availability and extent of coverage. EUA cannot predict the
ultimate outcome of this matter at this time.
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 17, 1997, 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
1997 Annual Meeting of Shareholders is scheduled to be held on May 19, 1997.
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
Richard M. Burns, 59 Comptroller since 1976; Assistant Secretary since
Comptroller 1978; and Assistant Treasurer since April 1986.
Chief Accounting Officer of EUA.
John D. Carney, 52 Executive Vice President since April 1995;
Executive Vice President President of Eastern Edison Company
since January 1990; President of Blackstone since
April 1995. Responsible for the day-to-day
activities of The EUA System's retail electric
operations.
Clifford J. Hebert, Jr., 49 Treasurer since April 1986; Secretary since May,
Treasurer and 1995. Responsible for financial, treasury and
Secretary corporate affairs of the EUA System .
Donald G. Pardus, 56 Chairman since July 1990; Chief Executive
Chairman of the Board, Officer since April 1989. Responsible for
Chief Executive Officer the overall management of the EUA System.
and Trustee
Robert G. Powderly, 49 Executive Vice President since April 1992;
Executive Vice President President of Newport Electric Corporation from
March 1990 to April 1992. Responsible for
purchasing, customer information services,
information systems, human resources, marketing
and rate activities of the EUA System.
John R. Stevens, 56 President since July 1990; Chief Operating
President, Chief Operating Officer since January 1990; Senior Executive Vice
Officer and Trustee President from January 1990 to July, 1990.
Responsible for retail operations and new
ventures of the EUA 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, 1996 (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 1996 Annual Reports (Exhibit 13-
1.01 and 13-1.08, respectively, filed herewith).
As of February 1, 1997 there were 11,978 EUA common shareholders of
record.
The closing price of EUA's Common Shares as reported by the Wall Street
Journal on March 17, 1997 was $18.125.
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, 1996, (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, 1996 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 11 through 24 in the 1996 EUA Annual Report to Shareholders, pages 3
through 7 in the 1996 Blackstone Annual Report and pages 3 through 10 in the
1996 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 26 through 41 in the 1996 EUA Annual Report to Shareholders, page 2
and pages 10 through 27 in the 1996 Blackstone Annual Report and, page 2 and
pages 13 through 33 in the 1996 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 19, 1997, and filed with the SEC
is incorporated herein by reference. See also "EXECUTIVE OFFICERS OF EASTERN
UTILITIES ASSOCIATES" following Item 4 herein.
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 17, 1997 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
Richard M. Burns, 59* Vice President, Assistant Treasurer and Assistant
Vice President Clerk/Assistant Secretary of Blackstone and
Eastern Edison since April 1986.
John D. Carney, 52* President and Director of Blackstone since April
Director and President 1995; President and Director of Eastern Edison
since January 1990.
David H. Gulvin, 62 Senior Vice President of Blackstone and Eastern
Senior Vice President Edison since April 1995; President of Blackstone
and Director from November 1989 to April 1995; Director of
Blackstone since November 1989. Director of
Eastern Edison since July 1995. Responsible for
corporate communications, consumer services,
marketing and rate activities.
Barbara A. Hassan, 47 Vice President of Blackstone since April 1995;
Vice President Vice President of Eastern Edison since January
1990. Responsible for the operation and
maintenance of the transmission and distribution
facilities.
Clifford J. Hebert, Jr., 49* Treasurer since April 1986 and Secretary/Clerk
Treasurer since April 1995 of both Blackstone and Eastern
and Secretary/Clerk Edison.
Michael J. Hirsh, 42 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, 46 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.
Donald G. Pardus, 56* 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, 49* Executive Vice President and Director since March
Director and Executive 1992 of both Blackstone and Eastern Edison.
Vice President
John R. Stevens, 56* 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 19, 1997 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 26, 1997,
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>
<S> <C> <C> <C>
Amount (number of
Name and Address of shares) and Nature of Percent of
Title of Class Beneficial Owner Beneficial Ownership Class
Common Stock Eastern Utilities Associates 2,891,357 of Eastern Edison* 100%
One Liberty Square 184,062 of Blackstone* 100%
Boston, Massachusetts
</TABLE>
_______________
*All shares, which are the only voting securities of Eastern Edison and
Blackstone, are registered in the name of the beneficial owner.
(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 19, 1997 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, 1996 (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, 1996.
Blackstone
Schedule II - Valuation and Qualifying Accounts for the three years
ended December 31, 1996.
(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. 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. 20-7511; 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).
- 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 - Note Purchase Agreement dated as of September 29, 1992 of EUA
Cogenex and the Prudential Life Insurance Company of America
(Exhibit 4-44, Form 10-K of EUA for 1992, File No. 1-5366).
4-4.10 - 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 and December 21, 1994
(Exhibit 10-4, Form 10-K of EUA for 1992, 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).
- 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, and October 15, 1982
(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).
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, and May 1, 1993, (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).
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 and December 21,
1990 (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).
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 by an amendment dated
July 21, 1989, and February 7, 1990 and a Supplemental Agreement
dated July 21, 1989 (Exhibit 10-104, Form 10-K of EUA for 1989,
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).
*10-37.05 - Amendment to 10-2.05 dated December 4, 1996.
*10-38.05 - Thirty-third Amendment to 10-14.05 dated December 31, 1996.
*10-39.05 - Seventh Amendment to 10-28.05 dated February 12, 1996.
*10-40.05 - Eighth Amendment to 10-28.05 dated February 12, 1996.
*10-41.05 - Third Amendment to 10-31.05 dated February 12, 1996.
*10-42.05 - Fourth Amendment to 10-31.05 dated February 12, 1996.
- 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 1996, 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 1996, 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 1996, 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) and EUA Energy Services, Inc.
(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 January 6, 1997, EUA filed a Current Report on Form 8-K with
respect to Item 5 (Other Events).
On January 6, 1997, Eastern Edison 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/ Richard M. Burns Comptroller March 17, 1997
Richard M. Burns (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 Stevens President and Chief Operating Officer
John R. Stevens (Principal Financial Officer) and Trustee
/s/ Richard M. Burns Comptroller
Richard M. Burns (Principal Accounting Officer)
Russell A. Boss Trustee
/s/Paul J. Choquette, Jr. Trustee
Paul J. Choquette, Jr.
March 17, 1997
/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
Wesley W. Marple, Jr. Trustee
Wesley W. Marple, Jr.
/s/Margaret M. Stapleton Trustee
Margaret M. Stapleton
/s/W. Nicholas Thorndike Trustee
W. Nicholas Thorndike
[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
BLACKSTONE VALLEY ELECTRIC COMPANY
By/s/ Richard M. Burns Vice President March 17, 1997
Richard M. Burns (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 Financial Officer)
/s/Richard M. Burns Vice President
Richard M. Burns (Principal Accounting Officer)
/s/John D. Carney President and Director
John D. Carney
/s/David H. Gulvin Senior Vice President
David H. Gulvin and Director March 17, 1997
/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 17, 1997
By/s/Richard M. Burns Vice President
Richard M. Burns (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 Financial Officer)
March 17, 1997
/s/Richard M. Burns Vice President
Richard M. Burns (Principal Accounting Officer)
/s/John D. Carney President and Director
John D. Carney
/s/David H. Gulvin Senior Vice President
David H. Gulvin and Director
/s/Robert G. Powderly Executive Vice President and
Robert G. Powderly Director
[This page left blank intentionally]
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, 1996:
Allowance for Doubtful Accounts $690 $1,754 $292 <F1> $1,760 <F2> $976
For the Year Ended December 31, 1995:
Allowance for Doubtful Accounts $629 $1,217 $287 <F1> $1,443 <F2> $690
For the Year Ended December 31, 1994:
Allowance for Doubtful Accounts $613 $1,141 $277 <F1> $1,402 <F2> $629
<FN>
<F1> Recoveries of accounts previously written off.
<F2> Principally Accounts Receivable written off.
</FN>
</TABLE>
<TABLE>
<CAPTION> Schedule II
Blackstone Valley Electric Company
Valuation and Qualifying Accounts
(In Thousands)
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, 1996:
Allowance for Doubtful Accounts $127 $800 $232 <F1> $1,008 <F2> $151
For the Year Ended December 31, 1995:
Allowance for Doubtful Accounts $125 $585 $217 <F1> $800 <F2> $127
For the Year Ended December 31, 1994:
Allowance for Doubtful Accounts $158 $710 $213 <F1> $956 <F2> $125
<FN>
<F1> Recoveries of accounts previously written off.
<F2> Principally Accounts Receivable written off.
</FN>
</TABLE>
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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 40 of the 1996 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.
/s/Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 5, 1997
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 27 of the 1996
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.
/s/Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 5, 1997
[This page left blank intentionally]
This Agreement, dated as of the 4th day of December,
1996, is entered into by and between Connecticut Yankee Atomic
Power Company ("Connecticut Yankee" or "Seller") and Montaup
Electric Company ("Purchaser").
For good and valuable consideration, the receipt of which is
hereby acknowledged, it is agreed as follows:
1. Basic Understandings
Connecticut Yankee was organized in 1952 to provide for the
supply of power to its sponsoring utility companies, including
the Purchaser (collectively the "Purchasers"). It constructed a
nuclear electric generating unit, having a net capability of
approximately 582 megawatts electric (the "Unit") at a site in
Haddam Neck, Connecticut. Connecticut Yankee was issued a full-
term, Facility Operating License for the Unit by the Nuclear
Regulatory Commission (which, together with any successor
agencies, is hereafter called the "NRC"), which license is now
stated to expire on June 29, 2007. The Unit has been in
commercial operation since January 1, 1968.
The Unit was conceived to supply economic power on a cost of
service formula basis to the Purchasers. Connecticut Yankee and
the Purchaser are parties to a power Contract dated as of July 1,
1964 ("Initial Power Contract"). Pursuant to the Initial Power
Contract and other similar contracts (collectively, the "Initial
Power Contracts") between Connecticut Yankee and the other
Purchasers, Connecticut Yankee contracted to supply to the
Purchasers all of the capacity and electric energy available from
the Unit for a term of thirty (30) years following January l,
1968.
Connecticut Yankee and the Purchaser are also parties to an
Additional Power Contract, dated as of April 30, 1984
("Additional Power Contract"). The Additional Power Contract and
other similar contracts (collectively, the "Additional Power
Contracts") between Connecticut Yankee and the other Purchasers
provide for an operative term stated to commence on January 1,
1998 (when the Initial Power Contracts terminate) and extending
until a date (the "End of Term Date") which is 30 days after the
later of the date on which the last of the financial obligations
of Connecticut Yankee has been extinguished or the date on which
Connecticut Yankee is finally relieved of any obligations under
the last of the licenses (operating or possessory) which it
holds, or hereafter receives, from the NRC with respect to the
Unit. The Additional Power Contracts also provide, in the event
of their earlier cancellation, for the survival of the
decommissioning cost obligation and for the applicable provisions
thereof to remain in effect to permit final billings of costs
incurred prior to such cancellation.
Pursuant to the Power Contract and the Additional Power
Contract, the Purchaser is entitled and obligated to take its
entitlement percentage of the capacity and net electrical output
of the Unit during the service life of the Unit and obligated
to pay therefor monthly its entitlement percentage of Connecticut
Yankee's cost of service, including decommissioning costs,
whether or not the Unit is operated.
Connecticut Yankee and the Purchaser are also parties to a
1987 Supplementary Power Contract, dated as of April l, 1987
("1987 Supplementary Power Contract"). The 1987 Supplementary
Power Contract and other similar contracts (collectively, the
"1987 Supplementary Power Contracts") between Connecticut Yankee
and the other Purchasers restate and supersede earlier
Supplementary Power Contracts and Agreements Amending
Supplementary Power Contracts between Connecticut Yankee and the
Purchasers. Pursuant to the 1987 Supplementary Power Contracts,
the Purchasers make monthly certain supplementary payments to
Connecticut Yankee during the terms of the Initial Power
Contracts and Additional Power Contracts.
On December 4, 1996, the board of directors of Connecticut
Yankee, after conducting a thorough review of the economics of
continued operation of the Unit for the remainder of the term of
the Facility Operating License for the Unit in light of other
alternatives available to Connecticut Yankee and the Purchasers,
determined that the Unit should be permanently shut down
effective December 4, 1996. The Purchaser concurs in that
decision.
As a consequence of the shutdown decision, Connecticut
Yankee and the Purchaser propose at this time to amend the 1987
Supplementary Power Contract and the Additional Power Contract in
various respects in order to clarify and confirm provisions for
the recovery under said contracts of the full costs previously
incurred by Connecticut Yankee in providing power from the Unit
during its useful life and of all costs of decommissioning the
Unit, including the costs of maintaining the Unit in a safe
condition following the shutdown and prior to its decontamination
and dismantlement.
Connecticut Yankee and each of the other Purchasers are
entering into agreements which are identical to this Agreement
except for necessary changes in the names of the parties.
2. Parties' Contractual Commitments
Connecticut Yankee reconfirms its existing contractual
obligations to protect the Unit, to maintain in effect certain
insurance and to prepare for and implement the decommissioning of
the Unit in accordance with applicable laws and regulations.
Consistent with public safety, Connecticut Yankee shall use its
best efforts to accomplish the shutdown of the Unit, the
protection and any necessary maintenance of the Unit after
shutdown and the decommissioning of the Unit in a cost-effective
manner and shall use its best efforts to ensure that any required
storage and disposal of the nuclear fuel remaining in the reactor
at shutdown and all spent nuclear fuel or other radioactive
materials resulting from operating of the Unit are accomplished
consistent with public health and safety considerations and at
the lowest practicable cost. The Purchaser reconfirms its
obligations under its Initial Power Contract, Additional Power
Contract and 1987 Supplementary Power Contract to pay its
entitlement percentage of Connecticut Yankee's costs as deferred
payment in connection with the capacity and net electrical output
of the Unit previously delivered by Connecticut Yankee and agrees
that the decision to shut down the Unit described in Section 1
hereof does not give rise to any cancellation right under Section
9 of the Initial Power Contract or Section 10 of the Additional
Power Contract.
Except as expressly modified by this Agreement, the
provisions of the Additional Power Contract and the 1987
Supplementary Power Contract remain in full force and effect,
recognizing that the mutually accepted decision to shut down the
Unit renders moot those provisions which by their terms relate
solely to continuing operation of the Unit.
3. Amendment of Payment Provisions of Additional Power Contract
and 1987 Supplementary Power Contract
A. Section 2 of the Additional Power Contract is hereby
amended by deleting the first two paragraphs thereof and by
inserting in lieu thereof the following:
This contract shall become effective upon
receipt by the Purchaser of notice that Connecticut
Yankee has entered into Additional Power Contracts, as
contemplated by Section 1 above, with each of the other
Purchasers. The operative term of this contract shall
commence on such date as may be authorized by the FERC
and shall terminate on the date (the "End of Term
Date") which is the later to occur of (i) 30 days after
the date on which the last of the financial obligations
of Connecticut Yankee which constitute elements of the
payment calculated pursuant to Section 7 of this
contract has been extinguished by Connecticut Yankee,
or (ii) 30 days after the date on which Connecticut
Yankee is finally relieved of all obligations under the
last of any licenses (operating and/or possessory)
which it now holds from, or which may hereafter be
issued to it by, the NRC with respect to the Unit under
applicable provisions of the Atomic Energy Act of 1954,
as amended from time to time (the "Act").
B. The second paragraph of Section 4 of the Additional
Power Contract is amended by deleting the phrase "Second
Supplementary Power Contracts" wherever it appears and inserting
in lieu thereof the phrase "1987 Supplementary Power Contracts".
C. The first paragraph of Section 7 of the Additional Power
Contract is amended to read as follows:
With respect to each month commencing on or after the
commencement of the operative term of this contract,
whether or not this contract continues fully or
partially in effect, the Purchaser will pay Connecticut
Yankee as deferred payment for the capacity and output
of the Unit provided to the Purchaser by Connecticut
Yankee prior to the permanent shutdown of the Unit on
December 4, 1996, to the extent not otherwise paid in
accordance with the Power Contract, but without
duplication:
D. The eighth paragraph of Section 7 of the Additional
Power Contract is amended by changing the period at the end to a
comma and inserting:
, but including for purposes of this contract:
(i) with respect to each month until the commencement
of decommissioning of the Unit, the Purchaser's
entitlement percentage of all expenses related to
the storage or disposal of nuclear fuel or other
radioactive materials, and all expenses related to
protection and maintenance of the Unit during such
period, including to the extent applicable all of the
various sorts of expenses included in the
definition of "Decommissioning Expenses", to the
extent incurred during the period prior to the
commencement of decommissioning;
(ii) with respect to each month until expenses
associated with disposal of pre-April 7, 1983
spent nuclear fuel have been fully covered by
amounts which have been collected from Purchasers
and paid to a segregated fund as contemplated by
Section 8 of the 1987 Supplementary Power
Contract, dated as of April 1, 1987, between
Connecticut Yankee and the Purchaser, as amended
(the "1987 Contract"), the Purchaser's entitlement
percentage of previously uncollected expenses
associated with disposal of such prior spent
nuclear fuel, as determined in accordance with
Section 10 of the 1987 Contract; and
(iii) with respect to each month until End of License
Term, the Purchaser's entitlement percentage of
monthly amortization of (a) the amount of any
unamortized deferred expenses, as permitted from
time to time by the Federal Energy Regulatory
Commission or its successor agency, plus (b) the
remaining unamortized amount of Connecticut
Yankee's investment in plant, nuclear fuel and
materials and supplies and other assets. Such
amortization shall be accrued at a rate sufficient
to amortize fully such unamortized deferred
expenses and Connecticut Yankee's investments in
plant, nuclear fuel and materials and supplies or
other assets over a period extending to June 29,
2007, provided, that if during any calendar month
ending on or before December 3, 2000 either of
the following events shall occur: (a) Connecticut
Yankee shall become insolvent or (b) Connecticut
Yankee shall be unable, from available cash or
other sources, to meet when due during such month
its obligations to pay principal, interest,
premium (if any) or other fees with respect to any
of its indebtedness of money borrowed, then
Connecticut Yankee may adjust upward the accrual
for amortization of the unrecovered investment for
such month to an amount not exceeding the
applicable maximum level specified in Appendix A
hereto, provided that concurrently therewith the
net Unit investment shall be reduced by an amount
equal to the amount of such adjustment.
As used herein, "End of License Term" means June 29,
2007 or such later date as may be fixed, by amendment
to the NRC Facility Operating License for the Unit, as
the end of the term of the Facility Operating License.
E. The definitions in Section 7 of the Additional Power
Contract and in Section 3 of the 1987 Supplementary Power
Contract of "Total Decommissioning Costs" and "Decommissioning
Expenses" are hereby amended to read as follows:
"Total Decommissioning Costs" for any month shall mean
the sum of (x) an amount equal to all accruals in such
month to any reserve, as from time to time established
by Connecticut Yankee and approved by its board of
directors, to provide for the ultimate payment of the
Decommissioning Expenses of the Unit, plus (y), during
the Decommissioning Period, the Decommissioning
Expenses for the month, to the extent such
Decommissioning Expenses are not paid with funds from
such reserve, plus (z) Decommissioning Tax Liability
for such month. It is understood (i) that funds
received pursuant to clause (x) may be held by
Connecticut Yankee or by an independent trust or other
separate fund, as determined by said board of
directors, (ii) that, upon compliance with applicable
regulatory requirements, the amount, custody and/or
timing of such accruals may from time to time during
the term hereof be modified by said board of directors
in its discretion or to comply with applicable
statutory or regulatory requirements or to reflect
changes in the amount, custody or timing of anticipated
Decommissioning Expenses, and (iii) that the use of the
term "to decommission" herein encompasses compliance
with all requirements of the NRC for permanent
cessation of operation of a nuclear facility and any
other activities reasonably related thereto, including
provision for the interim storage of spent nuclear
fuel.
"Decommissioning Expenses" shall include all expenses
of decommissioning the Unit, and all expenses relating
to ownership and protection of the Unit during the
Decommissioning Period, and shall also include the
following:
(1) All costs and expenses of any NRC-approved
method of removing the Unit from service,
including without limitation: dismantling,
moth balling and entombment of the Unit;
removing nuclear fuel and other radioactive
material to temporary and/or permanent
storage sites; construction, operation,
maintenance and dismantling of a spent fuel
storage facility; decontaminating, restoring
and supervising the site; and any costs and
expenses incurred in connection with
proceedings before governmental authorities
relating to any authorization to decommission
the Unit or remove the Unit from service;
(2) All costs of labor and services, whether
directly or indirectly incurred, including
without limitation, services of foremen,
inspectors, supervisors, surveyors,
engineers, security personnel, counsel and
accountants, performed or rendered in
connection with the decommissioning of the
Unit and the removal of the Unit from
service, and all costs of materials,
supplies, machinery, construction equipment
and apparatus acquired or used (including
rental charges for machinery, equipment or
apparatus hired) for or in connection with
the decommissioning of the Unit and the
removal of the Unit from service, and all
administrative costs, including services of
counsel and financial advisers of any
applicable independent trust or other
separate fund; it being understood that any
amount, exclusive of proceeds of insurance,
realized by Connecticut Yankee as salvage on
any machinery, construction equipment and
apparatus, the cost of which was charged to
Decommissioning Expense, shall be treated as
a reduction of the amounts otherwise
chargeable on account of the costs of
decommissioning of the Unit; and
(3) All overhead costs applicable to the Unit
during the Decommissioning Period, or accrued
during such period, including without
limiting the generality of the foregoing,
taxes (other than taxes on or in respect of
income), charges, license fees, excises and
assessments, casualties, health care costs,
pension benefits and other employee benefits,
surety bond premiums and insurance premiums.
F. Section 7 of the Additional Power Contract and
Section 3 of the 1987 Supplementary Power Contract are each
hereby amended by adding the following new paragraph after the
definition of "Decommissioning Tax Liability":
"Decommissioning Period" shall mean the period
commencing with the notification by Connecticut Yankee
to the NRC of a decision of the board of directors of
Connecticut Yankee to cease permanently the operation
of the Unit for the purpose of producing electric
energy and ending with the date when Connecticut Yankee
has completed the decommissioning of the Unit and the
restoration of the site and has been relieved of all
its obligations under the last of any licenses issued
to it by the NRC.
G. The first sentence of Section 8 of the Additional Power
Contract is hereby amended to read as follows:
Connecticut Yankee will bill the Purchaser, no later
than ten (10) days after the end of any month, for all
amounts payable by the Purchaser with respect to such
particular month pursuant to Section 7 hereof.
H. Section 8 of the Additional Power Contract and Section 4
of the 1987 Supplementary Power Contract are each amended to
delete the name "The Connecticut Bank and Trust
Company, National Association" and substitute "Fleet National
Bank."
I. Section 5 of the 1987 Supplementary Power Contract is amended to read
as follows:
5. Decommissioning Fund:
Connecticut Yankee agrees to pay to, or cause
to be paid to, the Connecticut Yankee Trust or any
successor trust approved by the board of directors
of Connecticut Yankee all funds collected pursuant
to Section 3 under clause (x) of the definition of
"Total Decommissioning Costs".
J. Section 10 of the Additional Power Contract is amended
to read as follows:
10. Cancellation of Contract.
If either
(i) the Unit is damaged to the extent of being completely or
substantially completely destroyed, or
(ii) The Unit is taken by exercise of the
right of eminent domain or a similar right or power,
then and in any such case, the Purchaser may cancel the
provisions of this contract, except that in all cases
other than those described in clause (ii) above, the
Purchaser shall be obligated to continue to make the
payments of Total Decommissioning Costs and the other
payments required by Section 7 and the provisions of
that Section and the related provisions of this
contract shall remain in full force and effect until
the End of Term Date, it being recognized that the
costs which Purchaser is required to pay pursuant to
Section 7 represent deferred payments in connection
with power heretofore delivered by Connecticut Yankee
hereunder. Such cancellation shall be effected by
written notice given by the Purchaser to Connecticut
Yankee. In the event of such cancellation, all
continuing obligations of the parties hereunder as to
subsequently incurred costs of Connecticut Yankee other
than the obligations of the Purchaser to continue to
make the payments required by Section 7 shall cease
forthwith. Notwithstanding the foregoing, the
applicable provisions of this contract shall continue
in effect after the cancellation hereof to the extent
necessary to permit final billings and adjustments
hereunder with respect to obligations incurred through
the date of cancellation and the collection thereof.
Any dispute as to the Purchaser's right to cancel this
contract pursuant to the foregoing provisions shall be
referred to arbitration in accordance with the
provisions of Section 13.
Notwithstanding anything in this contract
elsewhere contained, the Purchaser may cancel this
contract or be relieved of its obligations to make
payments hereunder only as provided in the next
receding paragraph of this Section 10. Further, if
for reasons beyond Connecticut Yankee's reasonable
control, deliveries are not made as contemplated by
this contract, Connecticut Yankee shall have no
liability to the Purchaser on account of such non-
delivery.
K. Section 2 of the 1987 Supplementary Power Agreement is
amended to change the date in the definitions of "operating
expenses" and "M" from "May 26, 2004" to "June 29, 2007".
5. Effective Date
This Agreement shall become effective upon receipt by the
Purchaser of notice that Connecticut Yankee has entered into 1996
Amendatory Agreements, as contemplated by Section 1 hereof, with
each of the other Purchasers.
6. Interpretation
The interpretation and performance of this Agreement shall
be in accordance with and controlled by the laws of the State of
Connecticut.
7. Addresses
Except as the parties may otherwise agree, any notice,
request, bill or other communication from one party to the other
relating to this Agreement, or the rights, obligations or
performance of the parties hereunder, shall be in writing and
shall be effective upon delivery to the other party. Any such
communication shall be considered as duly delivered when mailed
to the respective post office address of the other party shown
following the signatures of such other party hereto, or such
other post office address as may be designated by written notice
given in the manner as provided in this Section.
8. Corporate Obligations
This Agreement is the corporate act and obligation of the
parties hereto.
9. Counterparts
This Agreement may be executed in any number of counterparts
and each executed counterpart shall have the same force and
effect as an original instrument and as if all the parties to all
of the counterparts had signed the same instrument. Any
signature page of this Agreement may be detached from any
counterpart without impairing the legal effect of any signatures
thereon, and may be attached to another counterpart of this
Agreement identical in form hereto but having attached to it one
or more signature pages.
IN WITNESS WHEREOF, the parties have executed this
Amendatory Agreement by their respective duly authorized officers
as of the day and year first named above.
CONNECTICUT YANKEE ATOMIC POWER
COMPANY
By: /s/ John B. Keane
John B. Keane
Its Vice President and Treasurer
Address: 107 Selden Street
Berlin, CT 06037
MONTAUP ELECTRIC COMPANY
By: /s/ Donald G. Pardus
Donald G. Pardus
Its Chairman
Address: One Liberty Square
13th Floor
Boston, MA 02107
Appendix A to
1996 Amendatory Agreement
Maximum Depreciation Schedule
If the event occurs during the twelve
months ending: Maximum Amortization Accrual:
December 31, 1997 $100,000,000.00
December 31, 1998 $ 80,000,000.00
December 31, 1999 $ 40,000,000.00
December 31, 2000 $ 20,000,000.00
THIRTY-THIRD AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
THIS THIRTY-THIRD AGREEMENT, dated as of the 1st day of December, 1996,
is entered into by the signatory Participants for the amendment and
restatement by them of the New England Power Pool Agreement dated as of
September, 1, 1971 (the "NEPOOL Agreement"), as previously amended by thirty
(30) amendments, the most recent of which was dated as of September 1, 1995.
WHEREAS, the signatory Participants propose to restate the NEPOOL
Agreement to provide for a restructured New England Power Pool and to include
as part of such restated pool agreement a NEPOOL Open Access Transmission
Tariff (the "Tariff");
NOW THEREFORE, the signatory Participants hereby agree as follows:
SECTION I
AMENDMENT AND RESTATEMENT OF NEPOOL AGREEMENT
The NEPOOL Agreement as in effect on December 1, 1996 (the "Prior NEPOOL
Agreement") is amended and restated, as of the effective dates provided in
Section II, to read as provided in Exhibit A hereto (the "Restated NEPOOL
Agreement").
SECTION II
EFFECTIVENESS OF THE THIRTY-THIRD AGREEMENT
This Thirty-Third Agreement, and the amendment and restatement provided
for above, shall become effective as follows:
(1) Parts One, Two, Four and Five, of the Restated NEPOOL Agreement
and all of the provisions of the Tariff shall become effective,
and Sections 1 to 8, inclusive, 10, 11, 13, 14.2, 14.3, 14.4 and
16 of the Prior NEPOOL Agreement shall cease to b e in effect, on
March 1, 1997 or on such other date as the Federal Energy
Regulatory Commission ("Commission") shall provide that such
portion of the Restated NEPOOL Agreement shall become effective
(the "First Effective Date"); and
(2) the remaining portions of the Restated NEPOOL Agreement shall
become effective, and Sections 9, 12, 14.1, 14.5, 14.6, 14.7,
14.8 and 15 of the Prior NEPOOL Agreement together with the
related exhibits and supplements to the Prior NEPOOL Agreement
shall cease to be in effect, on July 1, 1997 or such other date
on or before January 1, 1998 as the NEPOOL Management Committee
may fix, after it has determined that the necessary detailed
criteria, rules and standards and computer programs to implement
such remaining portions of the Restated NEPOOL Agreement are in
place, or on such other date or dates as the Federal Energy
Regulatory Commission may fix, on its own or pursuant to the
request of the Management Committee, (the "Second Effective
Date").
SECTION III
INTENT OF AGREEMENT
This Thirty-Third Agreement is intended by the signatories hereto to
effect a comprehensive amendment and restatement of the NEPOOL Agreement and
to provide a regional open access transmission arrangement in accordance with
the Restated NEPOOL Agreement and the Tariff, which is Attachment B to the
Restated NEPOOL Agreement. Subject to the understandings expressed in the
balance of this Section and in Section IV, the signatories agree to support
the acceptance of the Thirty-Third Agreement by the Commission.
Subject to the understandings expressed in Section IV of this Agreement,
in entering into this Thirty-Third Agreement the signatories expressly
condition their commitment on acceptance of this Thirty-Third Agreement,
including the Restated NEPOOL Agreement and the Tariff, by the Commission and
any other regulatory body having jurisdiction without significant conditions
or modifications. If significant conditions are imposed or significant
modifications are required, the signatories reserve the right to renegotiate
the Thirty-Third Agreement as a whole or to terminate it.
SECTION IV
ALTERNATIVE AMENDMENTS
The signatories have been unable to reach final agreement on two aspects
of the transmission arrangements for a restructured NEPOOL which would be in
effect after the five-year Transition Period provided for in the Tariff, as
follows:
(a) the continued treatment of "grandfathered contracts" as Excepted
Transactions; and
(b) the continuance and treatment of Participant Regional Network
Service rates which differ from an average Regional Network
Service rate.
It is agreed that any Participant which signs this Agreement shall be entitled
to take any position before the Commission that it deems best with respect to
either of these two aspects of the transmission arrangements.
However, Participants signing this Agreement are requested to consider
the proposed treatment of these aspects of the transmission arrangements in
the following Alternate A and Alternate B and to indicate, if they are
willing, in the optional supplemental agreement on the signature page to this
Agreement their position on these alternates. The alternates are as follows:
Alternate A is as follows:
1. The introductory portion of paragraph (3) of Section 25 of the
Tariff shall be amended to read as follows:
(3) for the period from the effective date of the Tariff
until the termination of the transmission agreement or
the end of the Transition Period, whichever occurs
first:
2. The description of the "Participant RNS Rate" in Schedule 9 to
the Tariff shall be amended by modifying the proviso at the end of the second
sentence of paragraph (4) of the Schedule to read as follows:
provided that in no event shall its pre-1997 Participant RNS Rate be
less than 70% of the pre-1997 Pool PTF Rate until the end of Year
Five, and thereafter shall be equal to the pre-1997 Pool PTF Rate
for Year Six and thereafter.
and by amending the proviso at the end of the third sentence of paragraph (4)
of the Schedule to read as follows:
provided that in no event shall its pre-1997 Participant RNS Rate be
greater than 130% of the pre-1997 Pool PTF Rate until the end of
Year Five, and thereafter shall be equal to the pre-1997 Pool PTF
Rate for Year Six and thereafter.
Alternate B is as follows:
1. The introductory portion of paragraph (3) of Section 25 of the
Tariff shall be amended to read as follows:
(3) for the period from the effective date of this Tariff until the
termination of the transmission agreement:
2. The description of the "Participant RNS Rate" in Schedule 9 to the
Tariff shall be amended by modifying the proviso at the end of the second
sentence of paragraph (4) of the Schedule to read as follows:
provided that in no event shall its pre-1997 Participant RNS
Rate be less than 70% of the pre-1997 Pool PTF Rate until the
end of Year Five, and thereafter shall be no less than 50% of
the pre-1997 Pool PTF Rate for Year Six through Year Ten, and
shall be equal to the pre-1997 Pool PTF Rate for Year Eleven and
thereafter.
and by amending the proviso at the end of the third sentence of paragraph (4)
of the Schedule to read as follows:
provided that in no event shall its pre-1997 Participant RNS
Rate be greater than 130% of the pre-1997 Pool PTF Rate until
the end of Year Five and thereafter shall be no greater than
127% of the pre-1997 Pool PTF Rate for Year Six, 123% of the
pre-1997 Pool PTF Rate for Year Seven, 118% of the pre-1997 Pool
PTF Rate for Year Eight, 112% of the pre-1997 Pool PTF Rate for
Year Nine, 105% of the pre-1997 Pool PTF Rate for Year Ten, and
shall be equal to the pre-1997 Pool PTF Rate for Year Eleven a
and thereafter.
SECTION V
USAGE OF DEFINED TERMS
The usage in this Thirty-Third Agreement of terms which are defined in
the Prior NEPOOL Agreement shall be deemed to be in accordance with the
definitions thereof in the Prior NEPOOL Agreement.
SECTION VI
COUNTERPARTS
This Thirty-Third Agreement may be executed in any number of counterparts
and each executed counterpart shall have the same force and effect as an
original instrument and as if all the parties to all the counterparts had
signed the same instrument. Any signature page of this Thirty-Third Agreement
may be detached from any counterpart of this Thirty-Third Agreement without
impairing the legal effect of any signatures thereof, and may be attached to
another counterpart of this Thirty-Third Agreement identical in form thereto
but having attached to it one or more signature pages.
IN WITNESS WHEREOF, each of the signatories has caused a counterpart
signature page to be executed by its duly authorized representative, as of the
1st day of December, 1996.
COUNTERPART SIGNATURE PAGE
TO THIRTY-THIRD AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
DATED AS OF DECEMBER 1, 1996
The NEPOOL Agreement, being dated as of September 1, 1971, and being
previously amended by thirty (30) amendments the most recent of which was
dated as of September 1, 1995.
EASTERN UTILITIES ASSOCIATES COMPANIES
Blackstone Valley Electric Company
Eastern Edison Company
Montaup Electric Company
Newport Electric Company
(Participants)
By: /s/ Kevin A. Kirby
Name: Kevin A. Kirby
Title: Vice President
Address: 750 West Center Street
West Bridgewater, MA 02379-0543
SUPPLEMENTAL AGREEMENT WITH RESPECT TO ALTERNATES A & B
The undersigned agrees that either Alternate A or Alternate B as
described in Section IV of the foregoing Agreement will be acceptable to it if
chosen and accepted by the Commission without significant modifications.
Accordingly, the undersigned further agrees that in the event either Alternate
A or Alternate B, as described in Section IV of the foregoing Agreement, is
chosen and accepted without significant modifications by the Commission, the
Tariff shall be deemed to be automatically amended , effective 30 days after
the issuance of the Commission's order, to incorporate the accepted Alternate.
EASTERN UTILITIES ASSOCIATES COMPANIES
Blackstone Valley Electric Company
Eastern Edison Company
Montaup Electric Company
Newport Electric Company
(Participants)
By:
Name:
Title:
Address: 750 West Center Street
West Bridgewater, MA 02379-0543
SEVENTH AMENDMENT TO UNIT POWER AGREEMENT FOR
THE SALE OF UNIT CAPACITY AND ENERGY
FROM OCEAN STATE POWER TO MONTAUP ELECTRIC COMPANY
This Seventh Amendment is entered into this 12th day of February, 1996,
by and between Ocean State Power, a Rhode Island general partnership with its
principal office in Burrillville, Rhode Island ("Seller"), and Montaup
Electric Company, a Massachusetts corporation with its principal office in
Boston, Massachusetts ("Buyer").
WHEREAS, Seller and Buyer have entered into a Unit Power Agreement for
the Sale of Unit Capacity and Energy from Seller's combined-cycle generation
plant located in Burrillville, Rhode Island, dated as of May 14, 1986 (as
amended prior to the date hereof, the "Unit Power Agreement"); and
WHEREAS, Seller and Buyer propose to amend further the Unit Power
Agreement as set forth below.
NOW THEREFORE, in consideration of the mutual undertakings and
agreements contained in the Unit Power Agreement and in this Seventh
Amendment, Seller and Buyer hereby agree to amend the Unit Power Agreement as
follows:
1. Definitions. Unless otherwise defined herein, all capitalized
terms shall have the respective meanings ascribed to them in the Unit Power
Agreement as amended hereby, unless otherwise provided.
2. Amendment. The following new paragraph shall be inserted at the
end of Article 7.4:
Buyer and Seller agree that if (i) Seller computes the monthly
allowance for income taxes pursuant to Article 7.3(b)(2) of this Agreement on
the basis of an effective income tax rate (other than for federal income
taxes) that differs from the applicable income tax rate as determined by a
Competent Taxing Authority, or (ii) Seller's charges for state excise taxes
pursuant to Article 7.3(a)(4) of this Agreement differ from the actual
liability of Seller or partners in Seller as determined by a Competent Taxing
Authority, then Seller shall true-up any such difference, and shall either
refund to Buyer or collect from Buyer the Buyer's Share of the difference
between the amount previously billed and the amount of (a) the monthly
allowance under Article 7.3(b)(2) computed on the basis of such applicable
income tax rate, (b) the charges for taxes under Article 7.3(a)(4) based on
such actual tax liability of Seller or partners in Seller, and (c) interest
and penalties, if any, assessed (or credited in the case of overpayments) by a
Competent Taxing Authority with respect to such taxes. Notwithstanding
anything to the contrary in this Article 7.4, Seller shall true-up any such
tax allowance or charges with respect to any Contract Year at any time during
the term of this Agreement or after the termination of this Agreement,
irrespective of whether Seller previously had rendered recomputed bills
pursuant to Article 7.4; provided, however, that Seller shall render a
statement for such true-up not later than three months following a final and
non-appealable determination with respect to any such tax liabilities. Seller
(or partners in Seller as the case may be) agrees to take reasonable actions
to contest or challenge any assessment of taxes subject to true-up pursuant to
this paragraph, and the Operating Committee shall determine what reasonable
actions should be taken in this regard. For purposes of this Article 7.4,
"Competent Taxing Authority" shall mean any state taxing authority having
jurisdiction over Seller or partners in Seller with respect to corporate
income and corporate excise taxes, and "applicable income tax rate" shall mean
the effective rate of corporate income tax found to be applicable to Seller or
partners in Seller with respect to income of Seller.
3. Effectiveness. It shall be a condition precedent to the
effectiveness of this Seventh Amendment that Seller shall have obtained the
consent of the Majority Noteholders (as defined in the Note and Guaranty
Agreement, dated October 19, 1992) with respect to this Amendment.
IN WITNESS WHEREOF, Seller and Buyer have executed this Seventh
Amendment to the Unit Power Agreement for the Sale of Unit Capacity and Energy
from Ocean State Power to Montaup Electric Company, as of the date written
above.
OCEAN STATE POWER, a General
Partnership
By: JMC Ocean State
Corporation, a General
Partner
By: Michael McCleish
Title: Vice President
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Kevin A. Kirby
Vice President
EIGHTH AMENDMENT TO UNIT POWER AGREEMENT FOR
THE SALE OF UNIT CAPACITY AND ENERGY
FROM OCEAN STATE POWER TO NEWPORT ELECTRIC CORPORATION
This Eighth Amendment is entered into this 12th day of February, 1996, by
and between Ocean State Power, a Rhode Island general partnership with its
principal office in Burrillville, Rhode Island ("Seller"), and Montaup Electric
Company, a Massachusetts corporation with its principal office in Boston,
Massachusetts ("Buyer").
WHEREAS, Seller and Newport Electric Corporation ("Newport") entered into a
Unit Power Agreement for the Sale of Unit Capacity and Energy from Seller's
combined-cycle generating plant located in Burrillville, Rhode Island, dated as
of May 14, 1986 (as amended prior to the date hereof, the "Unit Power
Agreement"); and
WHEREAS, under a Consent, Assignment and Assumption Agreement dated March
13, 1994, Newport, with Seller's consent, assigned its rights and obligations
under the Unit Power Agreement to Buyer and Buyer assumed those obligations; and
WHEREAS, Seller and Buyer propose to amend further the Unit Power Agreement
as set forth below.
NOW THEREFORE, in consideration of the mutual undertakings and agreements
contained in the Unit Power Agreement and in this Eighth Amendment, Seller and
Buyer hereby agree to amend the Unit Power Agreement as follows:
1. Definitions. Unless otherwise defined herein, all capitalized terms
shall have the respective meanings ascribed to them in the Unit Power
Agreement, as amended hereby, unless otherwise provided.
2. Amendment. The following new paragraph shall be inserted at the end of
Article 7.4:
Buyer and Seller agree that if (i) Seller computes the monthly allowance
for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis of
an effective income tax rate (other than for federal income taxes) that differs
from the applicable income tax rate as determined by a Competent Taxing
Authority, or (ii) Seller's charges for state excise taxes pursuant to Article
7.3(a)(4) of this Agreement differ from the actual liability of Seller or
partners in Seller as determined by a Competent Taxing Authority, then Seller
shall true-up any such difference, and shall either refund to Buyer or collect
from Buyer the Buyer's Share of the difference between the amount previously
billed and the amount of (a) the monthly allowance under Article 7.3(b)( 7)
computed on the basis of such applicable income tax rate, (b) the charges for
taxes under Article 7.3(a)(4) based on such actual tax liability of Seller or
partners in Seller, and (c) interest and penalties, if any, assessed (or
credited in the case of overpayments) by a Competent Taxing Authority with
respect to such taxes. Notwithstanding anything to the contrary in this Article
7.4, Seller shall true-up any such tax allowance or charges with respect to any
Contract Year at any time during the term of this Agreement or after the
termination of this Agreement, irrespective of whether Seller previously had
rendered recomputed bills pursuant to Article 7.4; provided, however, that
Seller shall render a statement for such true-up not later than three months
following a final and non-appealable determination with respect to any such tax
liabilities. Seller (or partners in Seller as the case may be) agrees to take
reasonable actions to contest or challenge any assessment of taxes subject to
true-up pursuant to this paragraph, and the Operating Committee shall determine
what reasonable actions should be taken in this regard. For purposes of this
Article 7.4, "Competent Taxing Authority" shall mean any state taxing authority
having jurisdiction over Seller or partners in Seller with respect to corporate
income and corporate excise taxes, and "applicable income tax rate" shall mean
the effective rate of corporate income tax found to be applicable to Seller or
partners in Seller with respect to income of Seller.
3. Effectiveness. It shall be a condition precedent to the effectiveness of
this Eighth Amendment that Seller shall have obtained the consent of the
Majority Noteholders (as defined in the Note and Guaranty Agreement,
dated October 19, 1992) with respect to this Amendment.
IN WITNESS WHEREOF, Seller and Buyer have executed this Eighth Amendment to
the Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean
State Power to Newport Electric Corporation, as of the date written above.
OCEAN STATE POWER, a General
Partnership
By: JMC Ocean State
Corporation, a General
Partner
By: Michael McCleish
Title: Vice President
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Kevin A. Kirby
Vice President
THIRD AMENDMENT TO UNIT POWER AGREEMENT FOR
THE SALE OF UNIT CAPACITY AND ENERGY
FROM OCEAN STATE POWER II TO MONTAUP ELECTRIC COMPANY
This Third Amendment is entered into this 12th day of February, 1996, by
and between Ocean State Power II, a Rhode Island general partnership with its
principal office in Burrillville, Rhode Island ("Seller"), and Montaup
Electric Company, a Massachusetts corporation with its principal office in
Boston, Massachusetts ("Buyer").
WHEREAS, Seller and Buyer have entered into a Unit Power Agreement for
the Sale of Unit Capacity and Energy from Seller's combined-cycle generating
plant located in Burrillville, Rhode Island, dated as of September 28, 1988
(as amended prior to the date hereof, the "Unit Power Agreement"); and
WHEREAS, Seller and Buyer propose to amend further the Unit Power
Agreement as set forth below.
NOW THEREFORE, in consideration of the mutual undertakings and agreements
contained in the Unit Power Agreement and in this Third Amendment, Seller and
Buyer hereby agree to amend the Unit Power Agreement as follows:
1. Definitions. Unless otherwise defined herein, all capitalized terms
shall have the respective meanings ascribed to them in the Unit Power
Agreement, as amended hereby, unless otherwise provided.
2. Amendment. The following new paragraph shall be inserted at the end of
Article 7.4:
Buyer and Seller agree that if (i) Seller computes the monthly allowance
for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis
of an effective income tax rate (other than for federal income taxes) that
differs from the applicable income tax rate as determined by a Competent
Taxing Authority, or (ii) Seller's charges for state excise taxes pursuant to
Article 7.3(a)(4) of this Agreement differ from the actual liability of Seller
or partners in Seller as determined by a Competent Taxing Authority, then
Seller shall true-up any such difference, and shall either refund to Buyer or
collect from Buyer the Buyer's Share of the difference between the amount
previously billed and the amount of (a) the monthly allowance under Article
7.3(b)(2) computed on the basis of such applicable income tax rate, (b) the
charges for taxes under Article 7.3(a)(4) based on such actual tax liability
of Seller or partners in Seller, and (c) interest and penalties, if any,
assessed (or credited in the case of overpayments) by a Competent Taxing
Authority with respect to such taxes. Notwithstanding anything to the contrary
in this Article 7.4, Seller shall true-up any such tax allowance or charges
with respect to any Contract Year at any time during the term of this
Agreement or after the termination of this Agreement, irrespective of whether
Seller previously had rendered recomputed bills pursuant to Article 7.4;
provided, however, that Seller shall render a statement for such true-up not
later than three months following a final and non-appealable determination
with respect to any such tax liabilities. Seller (or partners in Seller as the
case may be) agrees to take reasonable actions to contest or challenge any
assessment of taxes subject to true-up pursuant to this paragraph, and the
Operating Committee shall determine what reasonable actions should be taken in
this regard. For purposes of this Article 7.4, "Competent Taxing Authority"
shall mean any state taxing authority having jurisdiction over Seller or
partners in Seller with respect to corporate income and corporate excise
taxes, and "applicable income tax rate" shall mean the effective rate of
corporate income tax found to be applicable to Seller or partners in Seller
with respect to income of Seller.
3. Effectiveness. It shall be a condition precedent to the effectiveness
of this Third Amendment that Seller shall have obtained the consent of the
Majority Noteholders (as defined in the Note and Guaranty Agreement, dated
October l9, 1992) with respect to this Amendment.
IN WITNESS WHEREOF, Seller and Buyer have executed this Third Amendment
to the Unit Power Agreement for the Sale of Unit Capacity and Energy from
Ocean State Power II to Montaup Electric Company, as of the date written
above.
OCEAN STATE POWER II, a General Partnership
By: JMC Ocean State Corporation, a General Partner
By: /s/ Michael McCleish
Title: Vice President
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Kevin A. Kirby
Vice President
FOURTH AMENDMENT TO UNIT POWER AGREEMENT FOR
THE SALE OF UNIT CAPACITY AND ENERGY
FROM OCEAN STATE POWER II TO NEWPORT ELECTRIC CORPORATION
This Fourth Amendment is entered into this 12th day of February, 1996, by
and between Ocean State Power II, a Rhode Island general partnership with its
principal office in Burrillville, Rhode Island ("Seller"), and Montaup
Electric Company, a Massachusetts corporation with its principal office in
Boston, Massachusetts ("Buyer").
WHEREAS, Seller and Newport Electric Corporation ("Newport") entered into
a Unit Power Agreement for the Sale of Unit Capacity and Energy from Seller's
combined-cycle generating plant located in Burrillville, Rhode Island, dated
as of July 12, 1988 (as amended prior to the date hereof, the "Unit Power
Agreement"); and
WHEREAS, under a Consent, Assignment and Assumption Agreement dated March
1, 1994, Newport, with Seller's consent, assigned its rights and obligations
under the Unit Power Agreement to Buyer and Buyer assumed those Obligations;
and
WHEREAS, Seller and Buyer propose to amend further the Unit Power
Agreement as set forth below.
NOW THEREFORE, in consideration of the mutual undertakings and agreements
contained in the Unit Power Agreement and in this Fourth Amendment, Seller and
Buyer hereby agree to amend the Unit Power Agreement as follows:
1. Definitions. Unless otherwise defined herein, all capitalized terms
shall have the respective meanings ascribed to them in the Unit Power
Agreement, as amended hereby, unless otherwise provided.
2. Amendment. The following new paragraph shall be inserted at the end of
Article 7.4:
Buyer and Seller agree that if (i) Seller computes the monthly allowance
for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis
of an effective income tax rate (other than for federal income taxes) that
differs from the applicable income tax rate as determined by a Competent
Taxing Authority, or (ii) Seller's charges for state excise taxes pursuant to
Article 7.3(a)(4) of this Agreement differ from the actual liability of Seller
or partners in Seller as determined by a Competent Taxing Authority, then
Seller shall true-up any such difference, and shall either refund to Buyer or
collect from Buyer the Buyer's Share of the difference between the amount
previously billed and the amount of (a) the monthly allowance under Article
7.3(b)(2) computed on the basis of such applicable income tax rate, (b) the
charges for taxes under Article 7.3(a)(4) based on such actual tax liability
of Seller or partners in Seller, and (c) interest and penalties, if any,
assessed (or credited in the case of overpayments) by a Competent Taxing
Authority with respect to such taxes. Notwithstanding anything to the contrary
in this Article 7.4, Seller shall true-up any such tax allowance or charges
with respect to any Contract Year at any time during the term of this
Agreement or after the termination of this Agreement, irrespective of whether
Seller previously had rendered recomputed bills pursuant to Article 7.4;
provided, however, that Seller shall render a statement for such true-up not
later than three months following a final and non-appealable determination
with respect to any such tax liabilities. Seller (or partners in Seller as the
case may be) agrees to take reasonable actions to contest or challenge any
assessment of taxes subject to true-up pursuant to this paragraph, and the
Operating Committee shall determine what reasonable actions should be taken in
this regard. For purposes of this Article 7.4, "Competent Taxing Authority"
shall mean any state taxing authority having jurisdiction over Seller or
partners in Seller with respect to corporate income and corporate excise
taxes, and "applicable income tax rate" shall mean the effective rate of
corporate income tax found to be applicable to Seller or partners in Seller
with respect to income of Seller.
3 . Effectiveness. It shall be a condition precedent to the effectiveness
of this Fourth Amendment that Seller shall have obtained the consent of the
Majority Noteholders (as defined in the Note and Guaranty Agreement, dated
October l9, 1992) with respect to this Amendment.
IN WITNESS WHEREOF, Seller and Buyer have executed this Fourth Amendment
to the Unit Power Agreement for the Sale of Unit Capacity and Energy from
Ocean State Power II to Newport Electric Corporation, as of the date written
above.
OCEAN STATE POWER II, a General Partnership
By: JMC Ocean State Corporation,
a General Partner,
By: /s/ Michael McCleish
Title: Vice President
MONTAUP ELECTRIC COMPANY
By: /s/ Kevin A. Kirby
Kevin A. Kirby
Vice President
Eastern Utilities
A diversified energy services
company leading the way
into the era of electric utility
competition
1996 Annual Report
EUA System Profile
Eastern Utilities Associates is a diversified energy services company whose
shares are traded on the New York and Pacific Stock Exchanges under the ticker
symbol EUA. Its subsidiaries are engaged in the generation, transmission,
distribution and sale of electricity, and energy-related services such as
energy management and conservation and efficient use of energy.
To better reflect the competitive business environment in which it operates,
EUA is organized in four distinct business units.
Core Electric Business
EUA's core electric business comprises two business units. The retail business
unit provides electric distribution service to approximately 299,000 customers
in southeastern Massachusetts, and northern and coastal Rhode Island. Electric
distribution subsidiaries are Blackstone Valley Electric Company, Eastern
Edison Company and Newport Electric Corporation. The wholesale business unit
is Montaup Electric Company, EUA's generation and transmission subsidiary,
which provides electricity at whole sale to the electric distribution
subsidiaries and two other non-affiliated municipal electric utilities, and
high voltage transmission services.
Energy Related Business
EUA's energy related business unit includes EUA Cogenex Corporation, EUA Ocean
State Corporation, EUA Energy Investment Corporation and EUA Energy Services
Corporation which owns our interest in Duke/Louis Dreyfus Energy Services (New
England) LLC, a power marketing partnership. EUA Cogenex is the most active
of our energy related companies with energy services contracts throughout the
United States and Canada. EUA Ocean State owns a 29.9% partnership interest
in the Ocean State Power electric generating station in northern Rhode Island.
EUA Energy Investment makes investments in energy related businesses.
Duke/Louis Dreyfus Energy Services plans to market energy and energy related
services in New England.
Corporate
The corporate business unit is made up of Eastern Utilities Associates - the
System's parent company - and EUA Service Corporation which provides
professional and technical services to all EUA System companies.
Cover:
The reorganization of our industry required the untiring efforts of many
members of the EUA team. Our employees are working together with all our
constituents to smooth the transition from monopoly to competition. The photos
in the continuum of this annual report reflect the diversity and diligence of
their contributions.
To Our Shareholders
Dear Shareholder:
1996 was a defining year for the electric utility industry in New England,
including Eastern Utilities Associates. It was a year in which we were
continually challenged to be flexible and innovative. Regulatory and
legislative initiatives addressing electric utility restructuring created an
atmosphere of uncertainty about the future. Massachusetts and Rhode Island,
the two states in which EUA's utility subsidiaries do business, are at the
forefront of electric utility industry restructuring. We took a proactive role
in working with all stakeholders in the restructuring process to bring about a
consensus that is fair to all. By year's end, there was no question that the
age of utility competition had arrived.
The uncertainty created by utility restructuring negatively impacted the
electric utility industry nationwide and particularly in New England. Coupled
with the poor performance of EUA Cogenex and EUA Energy Investment it led to
EUA's common shares underperforming during 1996.
The performance of our Energy Related Businesses was, for the most part, a
disappointment in 1996. While our EUA Ocean State subsidiary continued to
provide a significant contribution to earnings - our investments in EUA Cogenex
and EUA Energy Investment did not meet expectations and operated at a loss.
EUA's 1996 consolidated net earnings of $30.6 million represented a 6.2%
decrease from those in 1995, a year that was also disappointing. EUA Cogenex's
operating losses, which included a one-time charge of 18 cents per share, the
unusual number of severe storms which struck our service territory in 1996,
and increased outage costs related to the Millstone III nuclear generating
plant negatively impacted 1996 results.
While earnings were less than expected, EUA continues to maintain a strong cash
position. Cash flow per share for 1996 was $5.44. The EUA System continues
to generate more than 100% of its cash construction needs internally. This
strong cash flow, coupled with the underlying earnings of our Core Electric
Business, enabled us to increase the dividend by 3.8% in May, 1996 to its
current annual rate of $1.66 per share. Our goal has been to provide our
shareholders with annual dividend increase s, greater than the utility
industry average, while maintaining a conservative payout ratio. While our
goal has not changed we recognize that the developing competitive market for
both our Core Electric Business and diversified operations requires u s to
proceed cautiously.
The section following this letter entitled "The Competitive Revolution"
provides more detail on the regulatory and legislative initiatives impacting
our Core Electric Business and the competitive forces that have slowed the
progress of our Energy Related Businesses.
Not everything that happened during 1996 was negative. Teamwork enabled us to
meet the many challenges we faced in creative ways. (Teams of EUA employees
working together and with our customers appear in the photos running along
these pages.) Positive developments in 1996 included:
- The regulatory and legislative initiatives in Massachusetts and Rhode
Island are now taking shape, removing much of the uncertainty surrounding
utility restructuring and its impact on our Core Electric Business. Our
proactive involvement in the restructuring process, which led to settlement
agreements in Massachusetts and Rhode Island, and our role in building
consensus for Rhode Island's Utility Restructuring Act show that we are ready
to move into the competitive arena. Movement into the competitive arena may
result in EUA divesting its entire generation portfolio.
- We made strategic moves during 1996 to put Cogenex back on the path to
profitability. Enhancing and refocusing of the Cogenex sales and marketing
efforts in the third quarter and a workforce reduction at year's end, together
with additional cost saving measures, should help Cogenex return to
profitability in the second half of 1997.
- The development of a prototype biomass-fueled combustion turbine in
Tennessee by the BIOTEN general partnership, in which we hold a 40% interest.
Testing of the unit has been encouraging to date.
- The June purchase by our EUA Energy Investment subsidiary of a 20%
ownership interest in Separation Technologies, a Massachusetts company which
develops and installs high volume materials separation equipment using
proprietary technology. The company's patented system to separate unburned
carbon from coal ash provides coal-burning power plants with a marketable by-
product at the same time it reduces potential environmental consequences
associated with the disposal of high-carbon fly-ash. The system has been
proven in commercial use. Customer interest from throughout the United States
and Europe makes this an investment that has the potential of making a positive
contribution to earnings in 1997.
- Although TransCapacity, our subsidiary which develops gas industry
software, continued to operate at a loss during 1996, we are encouraged by
the fact that in late 1996 the Federal Energy Regulatory Commission (FERC)
issued new directives which require gas pipelines to phase in compliance with
electronic data interchange (EDI) regulations during April, May and June of
1997. TransCapacity's T/Nominatr TM product is in full compliance with these
mandated FERC standards for transporting natural gas. Pipeline compliance
with FERC mandates during the second quarter of 1997 will be critical to
TransCapacity's success.
The teamwork of our dedicated workforce in all aspects of our business enabled
EUA to successfully meet many of its challenges in this past tumultuous year.
That won't change. If anything, the need to find innovative ways to build our
business in t he competitive arena means we must continue our commitment to
finding creative ways to perform at ever higher levels.
We thank the employees who, as a team, restored power after 18 storms, worked
harder with fewer resources to continue to provide excellent customer service,
and who served on the restructuring teams that continued the reorganization of
our company in 1996. We are confident that this team effort will help us meet
the many challenges we will face as we go forward in the competitive era.
Your management team recognizes that 1996 was a disappointing year. Our team
is fully committed to reversing the downward trend in earnings and restoring
greater value to your EUA Common Shares.
Donald G. Pardus John R. Stevens
Chairman and Chief Executive Officer President and Chief Operating Officer
March 11, 1997
<TABLE>
Highlights
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
FINANCIAL DATA ($ in thousands)
Operating Revenues $ 527,068 $ 563,363 $ 564,278
Consolidated Net Earnings<F1> 30,614 32,626 47,370
Return on Average Common Equity 8.2% 8.8% 13.6%
Common Shareholder Equity-
% of Capitalization (Year-End) 45.8% 44.5% 42.8%
Total Assets 1,257,029 1,206,130 1,234,049
Cash Construction Expenditures 62,730 77,923 50,519
COMMON SHARE DATA
Consolidated Earnings per Share<F1> $ 1.50 $ 1.61 $ 2.41
Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515
Annual Dividend Rate $ 1.66 $ 1.60 $ 1.54
Total Common Shares Outstanding 20,435,997 20,436,764 19,936,980
Average Common Shares Traded Daily 91,843 58,573 35,359
Book Value per Share (Year-End) $ 18.19 $ 18.36 $ 18.33
Market Price - High 24 1/4 25 27 3/8
- Low 14 3/4 21 1/2 21 3/8
- Year-End 17 3/8 23 5/8 22
OPERATING DATA
Total Primary Sales (mWh) 4,491,000 4,441,000 4,410,000
System Requirements (mwh) 4,699,000 4,668,000 4,643,000
System Peak Demand (mw) 854 931 921
System Reserve Margin (At Peak) 34.4% 24.2% 22.4%
System Load Factor 62.6% 57.2% 57.5%
Customers (Year-End) 299,471 297,331 293,707
Employees (Year-End) - Core Electric<F2> 468 541 720
- Energy Related 213 253 240
- Corporate<F2> 564 536 437
<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.
</FN>
</TABLE>
The Competitive Revolution
The Age of Utility Competition Is Here
New England, home of the Industrial Revolution two centuries ago, is leading
the nation in the Competitive Revolution sweeping through the electric utility
industry today. Massachusetts and Rhode Island - home of Eastern Utilities
Associates' (EUA) electric distribution subsidiaries - are at the forefront of
states restructuring the way electric utilities conduct business. The age of
competition for electric utility customers is here.
EUA restructuring teams worked throughout the year with regulators, legislators
and various stakeholders in both states to produce a blueprint for a
restructured electric utility industry. Our teams provided comments to the
Federal Energy Regulatory Commission (FERC) during that agency's consideration
of rules to open the nation's bulk transmission system to wholesale
competition. The ground rules have been set in Massachusetts and Rhode Island
and a broad outline drawn at the federal level. Regulators and legislators
recognize the importance of an economically sound electric utility industry to
maintain reliability of service and safety.
The rules to implement competition in both Massachusetts and Rhode Island treat
all stakeholders fairly. They afford a framework for us to provide immediate
customer cost savings and provide for the recovery of the historic investments
incurred to build power plants that provide safe, reliable electric service,
that may not be able to compete on an economic basis - often referred to as
"stranded costs." By doing so, these rules maximize the benefits of
competition for both our shareholders and our customers. How? They remove
much of the uncertainty about stranded cost recovery ensuring the continued
financial health of our utility operations while providing for the opportunity
of additional cost reductions and service benefits for our customers as the
competitive electricity market matures.
At the same time, the advent of competition provides the vehicle to continue to
pursue power marketing opportunities in the six New England States with
Duke/Louis Dreyfus Energy Services (New England), our partnership with Duke
Energy Marketing and Louis Dreyfus Electric Power. The provisions of our
settlement agreements in Massachusetts and Rhode Island are consistent with
those aims.
Federal Energy Regulatory Commission Spurs Competition
On the national level, FERC's order opening bulk power transmission lines to
all users on a non-discriminatory basis provides the framework for an equitable
competitive wholesale power market.
Montaup Electric Company (Montaup), EUA's electric generation subsidiary, filed
its open-access rates with FERC to ensure that all potential power suppliers
will have the appropriate access to EUA System transmission lines. Application
of these rate s for competitive generation sources will begin when
Massachusetts and Rhode Island formally open to competition.
Also, the New England Power Pool (NEPOOL) has filed an amendment with FERC
which provides for an independent system operator of New England's bulk power
system, market-based pricing and easier entry into NEPOOL membership by power
marketers, brokers and load aggregators.
Rhode Island Legislation Leads the Way
While the general principles are effectively the same in Massachusetts and
Rhode Island, the states approached restructuring from different directions.
In Rhode Island, competition was brought into being with history-making
legislation. The state's Utility Restructuring Act of 1996 (URA) made Rhode
Island the first state to legislate competition among electric utilities.
We worked with the governor and the leadership of Rhode Island's legislative
bodies to reach consensus among the many interested parties while the
legislation was under debate. Critical issues were addressed in a responsible
manner, enabling Rhode Island to enact legislation that may well serve as a
model for other states in their approach to restructuring the electric utility
industry.
The Rhode Island legislation provides for unbundling of electric service into
generation, transmission, and distribution functions, recovery of stranded
costs, performance incentives for distribution services, and phases competition
into effect. The state's largest users may choose their supplier starting July
1, 1997; competition will be open to all customers no later than July 1, 1998.
While the legislation opens the state to competition, it also allows customers
to elect to continue to take full service from their local distribution
company. The distribution company will arrange for generation, or supply, at a
non-discriminatory " standard offer" price for those customers.
The law also provides for adjustments to the distribution companies' base rates
using the prior year's Consumer Price Index and other performance factors.
In February 1997, Blackstone Valley Electric Company (Blackstone), Newport
Electric Corporation (Newport) and Montaup reached a settlement with the Rhode
Island Division of Public Utilities and Carriers and the state's Attorney
General. In addition to complying with the URA, the settlement, to be formally
submitted to the Rhode Island Public Utilities Commission (RIPUC) in March 1997,
provides for an immediate 10% rate deduction and the filing of a plan to divest
all of Montaup's generating assets.
Massachusetts: Negotiation and Regulation
Rather than the legislative approach taken in Rhode Island, Massachusetts moved
into the competitive era through the regulatory arena and through the vehicle
of negotiated settlements between utilities, the state's Division of Energy
Resources (DOER) and Attorney General, whose "Consumers First" initiative
envisions that all customers will have their choice of electricity supplier
effective January 1, 1998.
Regulators, the DOER and the Attorney General took the view that a restructured
utility industry must lead to lower costs, over time, for all consumers of
electricity. In December 1996, Eastern Edison Company (Eastern Edison), our
Massachusetts electric distribution subsidiary, and Montaup reached a
settlement in principle with the Attorney General and the DOER. Our settlement
agreement provides for, among other things, a 10% reduction in the total cost
of electric service to our Eastern Edison customers when competition starts,
while at the same time providing for full recovery of our stranded costs
through a non-bypassable transition charge. The settlement also recognizes our
need to fully recover our stranded costs in order to remain financially viable
and provides for the filing of a plan to divest all of Montaup's generating
assets.
At the end of the year, the Massachusetts Department of Public Utilities (MDPU)
announced its model rules and legislative proposal for a restructured utility
industry. The MDPU describes the package as a "framework to ensure full and
fair competition in the generation of electric power and model rules to
implement that framework." Legislation, introduced in 1997, is needed to
provide regulators with the authority to fully implement their model rules.
Our settlement with the Attorney General and the DOER is expected to be filed
with the MDPU in March 1997.
Stranded Cost Recovery
The Rhode Island legislation and our Massachusetts and Rhode Island settlements
provide for full recovery of above market net investments in generating
facilities, with a return, over 12 years via a non-bypassable transition charge
passed through to all retail customers in both states. Proceeds realized from
the sale of any or all generating assets (market value) will be used to
mitigate the transition charge.
Commitments to nuclear power are treated somewhat differently. New England's
commitment to nuclear power was made at a time when nuclear power was
considered the best available option to reduce dependence on oil and protect
the environment. Many of those nuclear power plants may not be able to compete
cost effectively with newer generation sources. Regulators and legislators
recognize the need to ensure that funds are available to safely decommission
nuclear plants at the end of their useful lives. Costs of decommissioning
nuclear power plants will be recovered as incurred via the non-bypassable
transition charge over the remaining life of each unit. EUA does not operate
any of New England's nuclear generators, though we are joint owners of some
and are obligated under power purchase contracts to others.
Also, a utility's commitments under power purchase contracts will be compared
to prevailing market costs of electricity. Any contract costs above or below
market rates will be charged or credited to customers through the transition
charge for the duration of the individual contracts. EUA believes its
transition charge is the second lowest among Massachusetts utilities.
How Competition Will Work
In a competitive marketplace, traditional utility services - generation,
transmission, and distribution - will be unbundled into separate and distinct
services. Customers will be permitted to choose their own electric supplier at
an open market price. Distribution and transmission services will remain
regulated. Just as the local telephone company continues to deliver the long
distance service chosen by the customer, the local electric distribution
company - Eastern Edison, Blackstone, and Newport, in our case - retains the
responsibility of providing electric distribution services to all customers no
matter who supplies the electricity.
The distribution companies also arrange for the power supply for customers who
"choose not to choose," at a "standard offer" price.
We plan to put the standard offer energy requirement out to bid, with Montaup
or a successor serving as the backstop generation source. As a result, Montaup
plans to file an application with FERC to replace its all-requirements power
contracts with our three electric distribution companies with a contract
termination charge to recover stranded costs. The distribution companies will
collect these costs from ultimate electricity consumers through the non-
bypassable transition charge discussed above.
As previously mentioned, the rates customers pay for electric distribution and
transmission services will continue to be regulated. But they won't be
regulated in the same way as in the past. Historically, regulators allowed
utilities to recover their costs of doing business, plus a specified "fair
return" on the investment of the utility's shareholders. Under this type of
regulation - known as cost of service regulation - utilities periodically
applied to regulators for changes in rates to c over known or anticipated
changes in costs.
In the restructured environment of the competitive marketplace, rates charged
by distribution companies will incorporate performance standards, commonly
referred to as performance-based regulation. Under this technique, rates are
set for a specified period - five years, for example - during which the
utility is encouraged to manage its costs prudently to earn a premium return
while being penalized for not achieving specific agreed-upon regulated
performance objectives. Utility returns, or earnings, will be subject to a
guaranteed floor and a ceiling. Utilities which manage well can keep some of
their savings; those that manage poorly are penalized by lower earnings and/or
pre-determined penalty charges.
This is another area where our efforts have already proven effective. Since
1990 we have reduced the workforce of our Corporate and Core Electric
businesses by 23% through a combination of normal attrition and voluntary
retirement. In that same time period, our employees held the line on
operation and maintenance costs. We consolidated management of our utilities
into a single structure in 1995, further reducing costs. We will continue to
find creative solutions to the new challenges raised by competition, responding
with ever more creative approaches, including continued cross-functional staff
assignments, and more efficient use of existing equipment.
Energy-Related Business Continues To Be Important
While a great proportion of our attention was devoted to ensuring that we
remain a financially strong utility in the age of competition, our Energy
Related Businesses are also important. This business unit includes our non-
utility investments design ed to enhance shareholder value over the long-term,
and it remains a key factor in our strategy for growth.
EUA Ocean State, with its 29.9% ownership interest in Ocean State Power's twin
250-megawatt, gas-fired generating units, will continue to provide significant
earnings contributions for the foreseeable future.
EUA Cogenex Corporation (EUA Cogenex), the largest of our energy-related
subsidiaries, provides energy efficiency products and energy-management
services throughout North America. Despite a financially difficult year, EUA
Cogenex remains a national leader in the energy services field. In the third
quarter of 1996, EUA Cogenex refocused its sales efforts. Also, EUA Cogenex
reduced its year-end 1995 employee level by 22% through a combination of
attrition and a year-end workforce reduction in 1 996. A return to
profitability for EUA Cogenex is expected in the second half of 1997.
TransCapacity, our limited partnership which provides advanced information
systems to the natural gas industry, performed below our expectations in 1996.
We continue to expand the capability of its product T/Nominatr TM, which
provides clients with a single interface for making electronic data interchange
(EDI) notifications to move gas throughout multiple pipelines. T/Nominatr TM
is in full compliance with standards recently mandated by FERC for transporting
natural gas. Unfortunately, FERC delayed required compliance with these
standards until the second quarter of 1997.
Because of delays by pipelines in effecting EDI services, TransCapacity did not
make a positive contribution to 1996 earnings. We expect that TransCapacity
will start making positive contributions by year-end 1997.
Our BIOTEN partnership is in the final stages of testing its prototype biomass
generation unit. These units can solve disposal problems for producers of
large amounts of environmentally hazardous sawdust while producing electricity.
Its biomass-fired combustion turbine technology has received significant
interest from both potential buyers and fabricators.
And, our newest investment, a 20% ownership interest in Separation
Technologies, Inc., is expected to make a positive earnings contribution
during 1997. Potential customers throughout the United States and in Europe
have shown strong interest in the company's proprietary system to separate
unburned carbon from coal ash, providing coal-burning power plants with a
marketable product - high quality fly-ash - at the same time it reduces a
potential environmental disposal problem. The system has be en proven in
commercial use at New England power plants. This company fits well with our
goal of finding niche-type energy-related investments for our EUA Energy
Investment subsidiary.
We're Ready for Competition
Competition in the electric utility industry is well underway - at a much
quicker pace than anyone might have thought possible a year ago. Certainly, not
every issue of the competitive generation market and the new regulatory
environment has been addressed. But, our success in building consensus in
Massachusetts and Rhode Island shows that the private and public sectors can,
indeed, work as a team to treat all stakeholders fairly in such a complex
situation.
Our team has built strong skills in meeting the challenge of being among the
first to enter the competitive arena. We are ready to enter that arena, and to
act quickly to seize the opportunities presented by competition.
To counter revenue reductions anticipated during 1998 from the 10% rate
reduction required in the Rhode Island and Massachusetts settlement agreements,
we will continue to find ways to reduce costs and improve our operating
efficiency.
<TABLE>
Selected Consolidated Financial Data
Years Ended December 31,
(In Thousands Except Common Share Data) 1996 1995 1994 1993 1992
<CAPTION>
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating Revenues $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964
Operating Income<F1> 55,841 71,728 73,795 75,649 64,347
Consolidated Net Earnings<F1> 30,614 32,626 47,370 44,931 34,111
BALANCE SHEET DATA:
Plant in Service 1,067,056 1,037,662 1,020,859 1,016,453 1,002,717
Construction Work in Progress 3,839 7,570 8,389 8,728 4,943
Gross Utility Plant 1,070,895 1,045,232 1,029,248 1,025,181 1,007,660
Accumulated Depreciation and
Amortization 350,816 324,146 304,034 296,995 274,725
Net Utility Plant 720,079 721,086 725,214 728,186 732,935
Total Assets 1,257,029 1,206,130 1,234,049 1,203,137 1,203,320
CAPITALIZATION:
Long-Term Debt - Net 406,337 434,871 455,412 496,816 462,958
Redeemable Preferred Stock - Net 27,035 26,255 25,390 25,053 28,496
Non-Redeemable Preferred Stock - Net 6,900 6,900 6,900 6,900 15,850
Common Equity 371,813 375,229 365,443 333,165 266,855
Total Capitalization 812,085 843,255 853,145 861,934 774,159
Short-Term Debt 51,848 39,540 31,678 37,168 109,936
COMMON SHARE DATA:
Consolidated Earnings per Average
Common Share<F1> $ 1.50 $ 1.61 $ 2.41 $ 2.44 $ 2.00
Average Number of Shares Outstanding 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224
Return on Average Common Equity 8.2% 8.8% 13.6% 15.0% 13.2%
Market Price - High 24 1/4 25 27 3/8 29 7/8 25 1/4
- Low 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8
- Year-End 17 3/8 23 5/8 22 28 24 3/4
Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515 $ 1.42 $ 1.36
<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 1996 were $30.6 million, or $1.50 per share, on
revenues of $527.1 million, compared with 1995 earnings of $32.6 million, or
$1.61 per share, on revenues of $563.4 million. The results for both years
include one-time, after-tax charges to earnings, discussed below, and listed
in the following table.
Net Earnings and Earnings Per Share by business unit for 1996 and 1995 were
as follows:
<TABLE>
1996 1995
Net Earnings (Loss) Earnings (Loss) Net Earnings (Loss) Earnings (Loss)
(000's) Per Share (000's) Per Share
<S> <C> <C> <C> <C>
Core Electric Business $ 37,595 $ 1.84 $ 42,062 $ 2.08
Energy Related Business (2,738) (0.13) 3,658 0.18
Corporate (571) (0.03) 151 0.01
From Operations $ 34,286 $ 1.68 $ 45,871 $ 2.27
One-Time Impacts:
Cogenex Charge (3,672) (0.18)
Voluntary Retirement Incentive (2,747) (0.14)
Cogeneration Discontinuance (10,498) (0.52)
Consolidated $ 30,614 $ 1.50 $ 32,626 $ 1.61
</TABLE>
Major impacts on earnings by business unit are described in the following
paragraphs.
Cogenex Charge to Earnings
Difficulties in turning project proposals into signed contracts, the virtual
elimination of utility-sponsored demand side management programs and the
termination of the AYP Capital and Westar joint ventures hampered EUA Cogenex
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 current
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 an effort to refocus its sales activity, EUA Cogenex replaced virtually all
of its sales staff with individuals possessing more experience and proven sales
capability in the energy efficiency market. Cogenex has also restructured its
NOVA Division because of changing market conditions. 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 improve its sales activity
and reduce its overhead burdens.
Voluntary Retirement Incentive (VRI) Offer
In March 1995, EUA announced a corporate reorganization which, among other
things, consolidated management of Eastern Edison, Blackstone and Newport. As
part of the reorganization, a VRI was offered to 66 professionals within the
EUA System. Forty-nine of those eligible for the program accepted the
incentive and retired effective June 1, 1995. This incentive program resulted
in a one-time $4.5 million pre-tax ($2.7 million after-tax, or 14 cents per
share) charge to second quarter 1995 earnings of the Core Electric Business.
Discontinuation of Cogeneration Operations
In September 1995, EUA announced that EUA Cogenex was discontinuing its
cogeneration operations because overall, the cogeneration portfolio had not
performed up to expectations. EUA Cogenex's total net investment in its
cogeneration portfolio was $2 9.2 million. The decision to discontinue
cogeneration operations resulted in a one-time, after-tax charge to third
quarter 1995 earnings of approximately $10.5 million, or 52 cents per share.
Operating Revenues
The following table sets forth estimates of the factors which contributed to
the change in Operating Revenues from 1994 through 1996:
Increase (Decrease)
From Prior Years
($ in millions) 1996 1995
Operating Revenue change attributable to:
Core Electric Business:
Purchased Power Recovery $ (7.0) $ (2.5)
Recovery of Fuel Costs 0.2 11.8
Recovery of C&LM Expenses (5.4) (3.9)
Effect of Rate Changes (4.9)
Unit Contracts and Sales to NEPOOL 0.6 (8.2)
Kilowatthour (kWh) Sales and Other (1.5) 1.8
Energy Related Business:
EUA Cogenex (23.2) 5.0
Total Operating Revenues $(36.3) $(0.9)
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.
The Effect of Rate Changes reflects a base rate decrease for Montaup
implemented on May 21, 1994.
Revenues attributable to Unit Contracts and sales to 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 and changes in other
operating revenues including off-system contract demand sales.
Energy Related Business: EUA Cogenex revenues, which account for virtually all
of the Energy Related Business Unit 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 aggregated $5.5
million in 1995 and decreased EUA Nova revenues of $7.9 million. These
decreases were offset somewhat by increased revenues of EUA Highland, EUA
Citizens and EUA Day aggregating $8.8 million . The 1995 change was due
primarily to the impact of EUA Cogenex's acquisitions of Highland Energy Group
(Highland) and Citizens Conservation Corporation (Citizens) in 1995.
Core Electric Business kWh Sales
Primary kWh sales of electricity by EUA's Core Electric Business Unit increased
by a modest 1.1% in 1996 compared to the prior year. This change was led by an
increase of 2.6% in the residential customer class, which is typically more
weather sensitive. The first and second quarter increases, largely due to
colder weather, were mitigated by the third and fourth quarter results, when we
saw a milder than normal weather pattern. Total energy sales increased by
2.0%, mainly due to increased sales to NEPOOL, slightly offset by decreased
short-term unit contract energy sales.
Primary kWh sales of electricity by EUA's Core Electric Business unit increased
by 0.7% in 1995 compared to 1994. Total energy sales decreased 11.1% in 1995,
due mainly to decreased energy sales to NEPOOL and decreased short-term unit
contract sales. Purchased power contracts of Montaup totaling 41 megawatts
(mw) which expired in October 1994 resulted in lower kWh available to Montaup
for interchange and short-term energy sales. These interchange and short-term
energy sales essentially recover fuel costs only and have little or no
earnings impact.
Percentage Changes in kWh Sales by Class of Customer for the past two years
were as follows:
Percent Increase (Decrease)
From Prior Year
1996 1995
Residential 2.6 1.1
Commercial (0.5) 0.2
Industrial 0.1 2.0
Other Electric Utilities 15.7 1.4
Other 2.6 (5.7)
Total Primary Sales 1.1 0.7
Losses and Company Use (8.6) (2.6)
Total System Requirements 0.7 0.5
Unit Contracts 16.2 (59.8)
Total Energy Sales 2.0 (11.1)
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 1996.
Fuel expense of the Core Electric Business increased by $1.3 million or 1.4% in
1996, due primarily to a 2.0% increase in total energy generated and purchased.
The $3.3 million increase in 1995 was caused by a 14.1% increase in the average
cost of fuel, offset by an 11.1% decrease in total energy generated and
purchased. Also, a classification adjustment increased fuel expense and
decreased purchased power expense by approximately $1.8 million in 1995.
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 includes a prior period
refund of approximately $2 .0 million, and decreased billings from the Ocean
State Power Project (OSP) and the Maine Yankee nuclear unit aggregating $2.5
million. Purchased Power demand expense for 1995 decreased $4.5 million due
primarily to decreases of $6.7 million related to 41 mw of purchased power
contracts which expired in October 1994 and the classification adjustments
discussed above. These decreases were partially offset by increased billings
from OSP and the Yankee nuclear units aggregating $5.2 million.
Other Operation and Maintenance (O&M): O&M expenses for 1996 decreased by $7.5
million or 4.0% compared to 1995. Total O&M expenses are comprised of three
components: Direct Controllable, Indirect and Energy Related.
O&M expenses by component for 1996, 1995 and 1994 were as follows:
($ in millions) 1996 1995 1994
Direct Controllable $ 87.5 $ 83.4 $ 87.7
Indirect 36.7 41.3 46.7
Energy Related 55.7 62.7 50.1
Total O&M $179.9 $187.4 $184.5
Direct Controllable expenses of our Core Electric and Corporate Business units
represent 48.6% of total 1996 O&M and include expense items such as: salaries,
fringe benefits, insurance and maintenance. In 1996 these 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,
costs related to the electric industry restructuring activities and increased
assessments by FERC. The 1995 decrease was due primarily to one-time computer
software development and hardware buy-out costs aggregating $1.9 million
expensed in 1994, decreased insurance expense of approximately $1.2 million and
strict attention to cost control.
Indirect expenses include items over which we have limited short-term control.
Indirects include such expense items as: O&M expenses related to Montaup's
joint ownership interests in generating facilities such as Seabrook I and
Millstone III (see Note H of Notes to Consolidated Financial Statements for
other jointly-owned units), power contracts where transmission rental fees are
fixed, C&LM expenses that are fully recovered in revenues, and expenses related
to accounting standards such as Statement of Financial Accounting Standard
No. 106, "Accounting for Post-Retirement Benefits Other Than Pensions" (FAS
106). 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 increased legal expenses and jointly owned unit
expenses, which include incremental outage costs of Millstone III. The 1995
change was due primarily to $4.2 million of decreased C&LM expense and lower
litigation expense.
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 93% of the total O&M expenses of this business unit in 1996. 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 EUA
Nova 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. These
decreases were offset somewhat by the June 1996 EUA Cogenex charge of $5.9
million and increased expenses of EUA Highland and EUA Citizens aggregating
$7.9 million. EUA Cogenex's O&M expenses for 1995 increased by $10.4 million
and are directly related to increased revenues, the acquisition of Citizens and
High land and costs related to new product development of the EUA Day division.
Also, operating and development expenses of EUA Energy Investment increased
$2.2 million in 1995.
Taxes Other Than Income: Taxes other than income increased $3.2 million in
1996 and decreased by $3.6 million in 1995. A 1995 reversal of previously over-
accrued property taxes was primarily responsible for the change in both years.
Income Taxes: EUA files a consolidated federal income tax return for the EUA
System. The composite federal and state effective income tax rate for 1996
increased to 35.1% from 30.1% for 1995 due mainly to a decrease in state income
tax benefits. EUA's 1994 effective tax rate was approximately 29%. In 1994
EUA Ocean State recognized $3.9 million of investment tax credits (ITC) which
lowered the effective rate.
Other Income (Deductions) - Net: 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 Cogenex's AYP Capital and Westar joint venture start-up costs,
included in the June 1996 $5.9 million charge. Other Income (Deductions) - Net
decreased by $4.3 million in 1 995 from 1994. The 1994 amount included: (i)
ITC recognized by EUA Ocean State of approximately $3.9 million as previously
discussed; (ii) a settlement of $900,000 received in 1994 from the Vermont
Electric Generation and Transmission Cooperative, Inc. related to Seabrook
Nuclear Project payments previously withheld; and (iii) the 1994 income
recognition of $900,000 of capitalized costs related to nuclear fuel buyouts
which were previously deferred. EUA Cogenex interest income and management fee
income increased by approximately $1.1 million in 1995.
Interest Charges: 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% Firs t Mortgage and Collateral Trust Bonds of Eastern Edison, offset
somewhat by a decrease in capitalized interest by EUA Cogenex and higher
interest expense related to increased short-term debt. The 1995 decrease of
$2.3 million was due primarily to decreased long-term debt interest resulting
from normal cash sinking fund payments, increases in capitalized interest of
EUA Cogenex and decreased Other Interest Expense. Other Interest Expense in
1994 included approximately $1.0 million related to Internal Revenue Service
audits of prior years' consolidated income tax returns.
1996 System Financing Activity
Core Electric Business: On September 1, 1996, Eastern Edison used available
cash to fund maturities of $7 million of 4 7/8% First Mortgage Bonds.
Energy Related Business: As a result of the June 1996 $5.9 million charge to
earnings and lower than anticipated sales, EUA Cogenex was not in compliance
with the interest coverage covenant contained in certain of its unsecured note
agreements and therefore EUA Cogenex was in default under said note
agreements. EUA Cogenex has reached agreement with lenders to modify the
interest coverage covenant contained in these note agreements through January
1, 1998, and to waive the default created by the June 1996 charge.
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. To the extent that EUA divests all or a
portion of its generation assets, these needs will diminish.
Core Electric Business: For 1996, 1995 and 1994, Core Electric Business cash
construction expenditures were $33.3 million, $31.5 million, and $33.0 million,
respectively.
Internally generated funds available after the payment of dividends supplied
approximately 118%, 210%, and 150% of these cash construction requirements in
1996, 1995 and 1994, 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 1997, 1998 and
1999 are estimated to be approximately $22.4 million, $16.3 million and $16.5
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 in 1997, 1998, 1999, 2000 and 2001 are $2.3 million, $62.2
million, $11.6 million, $2.3 million and $4.1 million, respectively.
Energy Related Business: Capital expenditures of our Energy Related Business
amounted to $28.1 million, $44.7 million, and $17.2 million in 1996, 1995 and
1994, respectively. Internally generated funds supplied 71.5%, 68.8%, and
111.9% of cash capital requirements in 1996, 1995 and 1994, respectively.
Estimated capital expenditures of the Energy Related Business are $49.9
million, $46.7 million and $54.1 million in 1997, 1998 and 1999, respectively.
Internally generated funds are expected to supply approximately 70% of 1997
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 $24.2 million in 1997, $9.2
million in 1998 and 1999, $59.2 million in 2000 and $9.2 million in 2001.
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 1996 are $1.1
million.
Short-Term Lines of Credit: At December 31, 1996, EUA System companies
maintained short-term lines of credit with various banks aggregating
approximately $140 million.
Year-End Short-Term Debt Outstanding by business unit:
($ in thousands) 1996 1995
Core Electric Business $ 3,670 $ 6,761
Energy Electric Business 24,341 14,421
Corporate 23,837 18,358
Total $51,848 $39,540
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 1996 and 1995 were as follows:
<TABLE>
1996 1995
Net Net
Earnings Earnings Earnings Earnings
(Loss) (Loss) (Loss) (Loss)
(000's) Per Share (000's) Per Share
<S> <C> <C> <C> <C>
EUA Cogenex $ (2,850)<F1> $ (0.14)<F1> $ 2,704<F2> $ 0.13<F2>
EUA Ocean State 4,152 0.20 4,617 0.23
EUA Energy Investment (3,990) (0.19) (3,663) (0.18)
EUA Energy Services (50) (0.00)
From Operations (2,738) (0.13) $ 3,658 $ 0.18
Cogenex Charge (3,672) (0.18)
Cogenex Discontinuance (10,498) (0.52)
Energy Related Business $ (6,410) $ (0.31) $ (6,840) $ 0.34
<FN>
<F1> Excludes June 1996 charge to earnings of $3.7 million or 18 cents per
share.
<F2> Excludes one-time charge of $10.5 million, or 52 cents per share,
related to discontinuance of cogeneration operations.
</FN>
</TABLE>
EUA Cogenex: EUA Cogenex's earnings from continuing operations decreased by
approximately $5.6 million in 1996 due primarily to lower earnings on project
sales and operating losses of its EUA Nova division. Also, 1996 saw a
significant reduction in demand side management activity as electric utilities
nationwide prepared themselves for the evolution to a competitive marketplace.
In 1996, EUA Cogenex refocused its national sales force toward the private
sector and reduced its employee level by 22% through attrition and a 1996 year-
end workforce reduction. EUA Cogenex will continue to develop its sales and
marketing organization, evaluate and enter into strategic alliances, and
emphasize cost control 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 Ocean State Power, 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 change in EUA Ocean State's earnings contribution was
due to a lower allowed return on equity and a lower investment base billed by
the project in 1996.
EUA Energy Investment: EUA Energy Investment was organized to seek out
investments in energy related businesses. The 1996 results reflect an increase
in operating and development expenses versus 1995, in particular, expenses
related to the operating expenses of EUA Transcapacity, and development costs
of BIOTEN's biomass-fired combustion turbine electric generation system.
EUA Energy Services: The loss generated by EUA Energy Services relates to
startup costs of the Duke/Louis Dreyfus Energy Services (New England)
partnership in 1996.
Electric Utility Industry Restructuring Initiatives
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 to be phased-in commencing July 1, 1997 for large
manufacturing customers, certain new commercial and industrial customers, and
State of Rhode Island accounts. By July 1, 1998, or sooner, all customers will
have retail access. Under the URA the local distribution company will retain
the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who choose not to choose, the local distribution company would arrange for
supply at a non-discriminatory, "standard offer" price. Distribution companies
will also be providers of last resort, required to arrange for supply
at prevailing market prices for customers who are unable to obtain their own
supply.
The URA provides for full recovery of prudently incurred embedded generation
costs that might not be recovered in a competitive electric generation market,
commonly referred to as "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 July 1, 1997,
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 July 1, 1997, 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 rate-making standards for electric distribution companies. These
performance based standards provide for a 6% minimum and an approximate 12%
maximum allowed return on equity for EUA's Rhode Island distribution companies,
Blackstone and Newport. In addition, the URA provides for adjustments to
electric distribution companies' base rates using the prior year's Consumer
Price Index and other performance factors. Under this provision of the law,
base rates were increased 1.88% for customers of Blackstone, and 2.18% for our
Newport customers effective January 1, 1997.
The implementation of the URA requires approvals from applicable regulatory
agencies, including the Federal Energy Regulatory Commission (FERC), the RIPUC,
and the Securities and Exchange Commission (SEC).
In February 1997, Blackstone, Newport and Montaup reached a settlement with the
Rhode Island Division of Public Utilities and Carriers and the state's Attorney
General. In addition to complying with the URA, the settlement, to be formally
submitted to the RIPUC in March 1997, provides for an immediate 10% rate
reduction and the filing of a plan to divest all of Montaup's generating
assets, and is similar in many respects to the settlement negotiated in
Massachusetts, described below.
On December 23, 1996, Eastern Edison and Montaup reached an agreement in
principle with the Attorney General of Massachusetts and the Massachusetts DOER
on 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." A formal plan is
expected to be filed with the MDPU in March 1997.
The agreement envisions that all of Eastern Edison's customers will have the
ability to choose an alternative supplier of electricity beginning 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% savings from today's electricity rates. Eastern Edison would be required
to arrange for "standard offer" service and would purchase power for "standard
offer" service from suppliers through a competitive bidding process. The
agreement is also designed to achieve full divestiture of Montaup's generating
assets via implementation of a plan, to be submitted to the MDPU by July 1,
1997, that would require (1) separation by Montaup of its generating and
transmission businesses and (2) full market valuation and sale of all
generating assets through an auction or equivalent process, to be conducted by
an independent third party.
Upon the commencement of retail choice in Massachusetts, Montaup's wholesale
contract with Eastern Edison would be terminated. In return, the cost of
Montaup's above market, embedded generation commitments to serve Eastern
Edison's customers would be recovered, with a return, through a non-bypassable
transition access charge to all Eastern Edison customers. The transition
access charge would 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.
Embedded costs associated with generating plants and regulatory assets would be
recovered, with a return, over a period of 12 years. Purchased power contracts
and nuclear decommissioning costs would be recovered as incurred over the life
of those obligations, a period expected to extend beyond 12 years. The
initial transition access charge would be set at 3.04 cents per kWh through
December 31, 2000, and is expected to decline thereafter.
The agreement also establishes performance-based regulation for Eastern Edison,
incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates would be frozen until December
31, 2000. Subsequent to the commencement of retail choice, Eastern Edison's
annual return on equity would be subject to a floor of 6% and a ceiling of
11.75%.
In addition to MDPU approval of the agreement, implementation is also subject
to the approval of FERC. Any disposition of generation assets resulting from
the agreements or the URA would also require the approval of the SEC under the
Public Utility Holding Company Act of 1935.
While removing much of the uncertainty which currently exists as to how EUA
will be impacted by electric utility restructuring, the agreements, if
approved, are expected to have an estimated negative impact on EUA System
earnings in 1998 of between 1 0% and 12%.
Historically, electric rates have been designed to recover a utility's full
costs 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. EUA believes that its Core Electric operations will continue
to meet the criteria established in these accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in EUA no longer meeting the criteria of
these accounting standards which could trigger the discontinuance of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (FAS71). Should it be required to discontinue the
application of FAS71, EUA would be required to take an immediate write-down of
the affected assets in accordance with FAS101, "Accounting for the
Discontinuation of Application of FAS71."
In addition, if legislative or regulatory changes and/or competition result in
electric rates which do not fully recover the 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" (FAS121).
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.
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 t he 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, 1996, the EUA System had incurred costs of approximately
$5.7 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 $2.8 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.
In addition to the previously discussed costs, Blackstone is currently
litigating responsibility for clean-up costs and related interest aggregating
$5.9 million 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 III, an 1154-mw nuclear
unit that is jointly owned by a number of New England utilities, including
subsidiaries of Northeast Utilities (Northeast), the operator of the plant. On
March 30, 1996, Northeast 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 has
established 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. Northeast management has
indicated it cannot currently estimate the effect these efforts will have on
the timing of restarts or what additional costs, if any, these developments may
cause.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $400,000 to $800,000 per month. Montaup
bills its replacement power costs through its fuel adjustment clause, a
wholesale tariff jurisdictional to FERC. However, there is no comparable
clause in Montaup's FERC-approved rates which at this time would permit Montaup
to recover its share of the incremental O&M costs incurred at Millstone III.
EUA cannot predict the ultimate outcome of the NRC inquiries or the impact
which they may have on Montaup and the EUA system. Montaup is also evaluating
its rights and obligations under the various agreements relating to the
ownership and operation of Millstone III.
Montaup holds a 4.0% ownership interest in the Maine Yankee Nuclear Unit. In
December 1996 the unit was shut down for inspections and repairs and in January
1997 the NRC announced that it had placed the unit on its watch list. The
operator of the u nit had been addressing issues of non-conformance to the
unit's licensing basis identified by the NRC in October 1996, prior to the
NRC's January 1997 announcement. The operator of the plant cannot estimate
when the unit will restart.
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 $ 4.8 million at December 31, 1996.
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. As a
result of the analysis, work at the plant had slowed pending a final board
decision. In December 1996, the Board of Directors 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. Connecticut Yankee has two years to submit its decommissioning plan
with the NRC. The preliminary estimate of the sum of future payments for the
permanent shutdown, decommissioning, and recovery of the remaining investment
in Connecticut Yankee, is approximately $758 million. Montaup's share of the
total estimated costs is $34.1 million and is included with Other Liabilities
on the Consolidated Balance Sheet at December 31, 1996. Due to anticipated
recoverability, a regulatory asset has been recorded for the same amount and
is included with Other Assets.
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 III and Seabrook I nuclear generating units. Montaup's
share of the currently allowed estimated total costs to decommission Millstone
III is approximately $18.6 million in 1996 dollars and Seabrook I is
approximately $13.1 million in 1996 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.
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 Statement of Income 26
Consolidated Statement of Cash Flows 27
Consolidated Balance Sheet 28
Consolidated Statement of Retained Earnings 29
Consolidated Statement of Equity Capital and Preferred Stock 29
Consolidated Statement of Indebtedness 30
Notes to Consolidated Financial Statements 31
Report of Independent Accountants 40
Report of Management 40
Quarterly Financial and Common Share Information 41
Consolidated Operating and Financial Statistics 42
Shareholder Information 44
Trustees and Officers Inside Back Cover
<TABLE>
Consolidated Statement of Income
Years Ended December 31,
(In Thousands Except Common Shares and per Share Amounts) 1996 1995 1994
<CAPTION>
<S> <C> <C> <C>
OPERATING REVENUES $ 527,068 $ 563,363 $ 564,278
OPERATING EXPENSES:
Fuel 92,166 90,888 87,573
Purchased Power-Demand 118,830 125,616 130,080
Other Operation 154,831 163,907 160,985
Voluntary Retirement Incentive 4,505
Maintenance 25,047 23,468 23,510
Depreciation and Amortization 45,478 45,492 46,455
Taxes - Other Than Income 23,933 20,744 24,337
Income Taxes 10,942 17,015 17,543
Total Operating Expenses 471,227 491,635 490,483
Operating Income 55,841 71,728 73,795
Equity in Earnings of Jointly Owned Companies 10,698 12,063 12,485
Allowance for Other Funds Used
During Construction 452 538 351
Loss on Disposal of Cogeneration Operations (18,086)
Income Tax Impact of Loss on Disposal of Cogeneration
Operations 7,588
Other Income (Deductions) - Net 5,054 2,574 6,847
Income Before Interest Charges 72,045 76,405 93,478
INTEREST CHARGES:
Interest on Long-Term Debt 34,035 38,216 38,987
Amortization of Debt Expense and Premium - Net 2,620 2,752 2,729
Other Interest Expense 4,199 3,167 3,849
Allowance for Borrowed Funds Used During
Construction (Credit) (1,735) (2,677) (1,788)
Net Interest Charges 39,119 41,458 43,777
Net Income 32,926 34,947 49,701
Preferred Dividends of Subsidiaries 2,312 2,321 2,331
Consolidated Net Earnings $ 30,614 $ 32,626 $ 47,370
Average Common Shares Outstanding 20,436,217 20,238,961 19,671,970
Consolidated Earnings per Share $ 1.50 $ 1.61 $ 2.41
Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515
</TABLE>
<TABLE>
Consolidated Statement of Cash Flows
Years Ended December 31, (In Thousands) 1996 1995 1994
<CAPTION>
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 32,926 $ 34,947 $ 49,701
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 50,690 52,413 54,091
Amortization of Nuclear Fuel 1,676 3,647 3,310
Deferred Taxes 11,610 (985) 8,017
Non-cash Expenses/(Gains) on Sales of Investments in
Energy Savings Projects 8,262 (1,264) 382
Loss on Disposal of Cogeneration Operations 18,086
Investment Tax Credit, Net (1,207) (1,212) (181)
Allowance for Other Funds Used During Construction (452) (538) (351)
Collections and Sales of
Project Notes and Leases Receivable 7,776 17,748 11,115
Other - Net 6,373 5,129 (10,360)
Changes in Operating Assets and Liabilities:
Accounts Receivable (5,777) 5,729 (4,509)
Materials and Supplies 2,385 (1,280) (2,035)
Accounts Payable (1,958) 1,543 (2,668)
Taxes Accrued (1,539) (1,921) (5,834)
Other - Net 4,930 (19,079) 9,641
Net Cash Provided from Operating Activities 115,695 112,963 110,319
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (62,730) (77,923) (50,519)
Collections on Notes and Lease Receivables of EUA Cogenex 3,665 3,125 1,635
Proceeds from Disposal of Cogeneration Assets 11,501
Increase in Other Investments (3,889) (2,300) (11,329)
Net Cash (Used in) Investing Activities (62,954) (65,597) (60,213)
CASH FLOW FROM FINANCING ACTIVITIES:
Issuances:
Common Shares 5,985 9,538
Long-Term Debt 7,925
Redemptions:
Long-Term Debt (20,617) (42,725) (13,233)
Preferred Stock (90) (100) (100)
Premium on Reacquisition and
Financing Expenses (15) (63) (689)
EUA Common Share Dividends Paid (33,618) (32,050) (29,795)
Subsidiary Preferred Dividends Paid (2,314) (2,324) (2,333)
Net Increase (Decrease) in Short-Term Debt 12,308 7,862 (5,490)
Net Cash (Used in) Financing Activities (44,346) (63,415) (34,177)
NET INCREASE (DECREASE) IN CASH AND
TEMPORARY CASH INVESTMENTS: 8,395 (16,049) 15,929
Cash and Temporary Cash Investments at Beginning of Year 4,060 20,109 4,180
Cash and Temporary Cash Investments at End of Year $ 12,455 $ 4,060 $ 20,109
Cash Paid during the year for:
Interest (Net of Amounts Capitalized) $ 40,658 $ 39,306 $ 39,650
Income Taxes $ 11,530 $ 9,412 $ 15,233
Conversion of Investments in Energy Savings Projects
to Notes and Leases Receivable $ 7,779 $ 19,324 $ 10,914
</TABLE>
<TABLE>
Consolidated Balance Sheet
December 31, (In Thousands) 1996 1995
<CAPTION>
<S> <C> <C>
ASSETS
Utility Plant and Other Investments:
Utility Plant in Service $ 1,067,056 $ 1,037,662
Less Accumulated Provisions for Depreciation and Amortization 350,816 324,146
Net Utility Plant in Service 716,240 713,516
Construction Work in Progress 3,839 7,570
Net Utility Plant 720,079 721,086
Non-utility Property - Net 72,653 82,347
Investments in Jointly Owned Companies 71,626 70,210
Other 68,031 67,157
Total Utility Plant and Other Investments 932,389 940,800
Current Assets:
Cash and Temporary Cash Investments 12,455 4,060
Accounts Receivable:
Customers, Net 66,089 61,096
Accrued Unbilled Revenues 10,282 11,311
Other 13,782 11,969
Notes Receivable 24,691 18,663
Materials and Supplies (at average cost):
Fuel 6,924 7,450
Plant Materials and Operating Supplies 7,207 9,066
Other Current Assets 7,668 11,804
Total Current Assets 149,098 135,419
Other Assets 175,542 129,911
Total Assets $ 1,257,029 $ 1,206,130
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 371,813 $ 375,229
Non-Redeemable Preferred Stock of Subsidiaries - Net 6,900 6,900
Redeemable Preferred Stock of Subsidiaries - Net 27,035 26,255
Long-Term Debt - Net 406,337 434,871
Total Capitalization 812,085 843,255
Current Liabilities:
Short-Term Debt 51,848 39,540
Long-Term Debt Due Within One Year 27,512 19,506
Accounts Payable 33,811 35,769
Redeemable Preferred Stock Sinking Fund Requirement 50
Taxes Accrued 3,004 4,544
Interest Accrued 9,612 10,861
Other Current Liabilities 26,772 19,931
Total Current Liabilities 152,559 130,201
Other Liabilities 123,209 91,934
Accumulated Deferred Taxes 169,176 140,740
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization $1,257,029 $ 1,206,130
</TABLE>
<TABLE>
Consolidated Statement of Retained Earnings
Years Ended December 31, (In Thousands) 1996 1995 1994
<CAPTION>
<S> <C> <C> <C>
Retained Earnings - Beginning of Year $ 56,228 $ 56,617 $ 39,642
Consolidated Net Earnings 30,614 32,626 47,370
Total 86,842 89,243 87,012
Dividends Paid - EUA Common Shares 33,618 32,050 29,795
Other 820 965 600
Retained Earnings - Accumulated since June 1991 Accounting
Reorganization $ 52,404 $ 56,228 $ 56,617
</TABLE>
<TABLE>
Consolidated Statement Of Equity Capital & Preferred Stock
December 31, (Dollar Amounts In Thousands) 1996 1995
<CAPTION>
<S> <C> <C>
EASTERN UTILITIES ASSOCIATES:
Common Shares:
$5 par value 36,000,000 shares authorized,
20,435,997 shares outstanding in 1996
and 20,436,764 shares in 1995 $ 102,180 $ 102,184
Other Paid-In Capital 221,160 220,730
Common Share Expense (3,931) (3,913)
Retained Earnings - Accumulated since June 1991
Accounting Reorganization 52,404 56,228
Total Common Equity 371,813 375,229
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 (2,630) (3,447)
Newport Electric Corporation:
9.75% $100 par value 900 shares 90
Expense (3)
Sinking Fund Requirement Due Within One Year (50)
Total Redeemable Preferred Stock 27,035 26,255
Total Preferred Stock of Subsidiaries $ 33,935 $ 33,155
<FN>
<F1> Authorized and Outstanding.
<F2> Authorized 400,000 shares. Outstanding 300,000 at December 31, 1996.
</FN>
</TABLE>
<TABLE>
Consolidated Statement of Indebtedness
December 31, (In Thousands) 1996 1995
<CAPTION>
<S> <C> <C>
EUA Service Corporation:
10.2% Secured Notes due 2008 $ 10,100 $ 12,300
EUA Cogenex Corporation:
7.22% Unsecured Notes due 1997 15,000 15,000
7.0% Unsecured Notes due 2000 50,000 50,000
9.6% Unsecured Notes due 2001 16,000 19,200
10.56% Unsecured Notes due 2005 31,500 35,000
EUA Ocean State Corporation:
9.59% Unsecured Notes due 2011 31,067 33,544
Blackstone Valley Electric Company:
First Mortgage Bonds:
9 1/2% due 2004 (Series B) 12,000 13,500
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds due 2014<F1> 6,500 6,500
Eastern Edison Company
First Mortgage and Collateral Trust Bonds:
4 7/8% due 1996 7,000
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 3,250 3,900
Small Business Administration Loan:
6.5% due 2005 719 809
Variable Rate Revenue Refunding Bonds due 2011<F1> 7,925 7,925
Unamortized (Discount) - Net (598) (687)
433,849 454,377
Less Portion Due Within One Year 27,512 19,506
Total Long-Term Debt - Net $ 406,337 $ 434,871
<FN>
<F1> Weighted average interest rate was 3.5% for 1996 and 3.9% for 1995.
</FN>
</TABLE>
Notes to Consolidated Financial Statements
December 31, 1996, 1995 and 1994
(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.
Reclassifications: Certain prior period amounts on the financial statements
have been reclassified to conform with current presentation.
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 2.50% to
4.50%. Montaup is entitled to electricity produced from these facilities based
on its ownership interests and is billed for its entitlement pursuant to
contractual agreements which are approved by the Federal Energy Regulatory
Commission (FERC).
One of the four facilities, Yankee Atomic, is being decommissioned, but Montaup
is required to pay, and has received FERC authorization to recover, its
proportionate share of any unrecovered costs and costs incurred after the
plant's retirement. Montaup's share of all unrecovered assets and the total
estimated costs to decommission the unit aggregated approximately $7.8 million
at December 31, 1996 and is included with Other Liabilities on the Consolidated
Balance Sheet. Also, due to recoverability, a regulatory asset has been
recorded for the same amount and is included with Other Assets.
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 has a 4.5% equity ownership in Connecticut Yankee. Montaup's
share of all unrecovered assets and the total estimated costs to decommission
the unit aggregated approximately $34.1 million at December 31, 1996 and is
included with Other Liabilities on the Consolidated Balance Sheet. Also, due
to anticipated recoverability, a regulatory asset has been recorded for the
same amount and is included with Other Assets.
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 3.7% in 1996, 3.6% in 1995, and 3.3% in 1994 based on the average
depreciable property balances at the beginning and end of each year. 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, 1996 and 1995 are
detailed as follows:
<TABLE>
<CAPTION>
(In Thousands) 1996 1995
<S> <C> <C>
Regulatory Assets:
Unamortized losses on reacquired debt $ 14,088 $ 15,894
Unrecovered plant and
decommissioning costs 41,914 10,100
Deferred FAS 109 costs (Note B) 58,712 48,196
Deferred FAS 106 costs 4,054 4,583
Mendon Road judgment (Note J) 6,154 5,857
Other regulatory assets 6,363 6,031
Total regulatory assets 131,285 90,661
Other deferred charges and assets:
Unamortized debt expenses 4,625 5,349
Goodwill 6,848 7,054
Other 32,784 26,847
Total Other Assets $ 175,542 $ 129,911
</TABLE>
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. EUA believes
that its Core Electric operations continue to meet the criteria established in
these accounting standards. Effects of legislation and/or regulatory
initiatives or EUA's own initiatives could ultimately cause the Core Electric
companies to no longer follow these accounting rules. In such an event, a non-
cash write-off of regulatory assets and liabilities could be required at that
time.
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 a s a result of higher depreciation expense.
The combined rate used in calculating AFUDC was 9.0% in 1996, 9.2% in 1995, and
9.7% in 1994. The caption "Allowance for Borrowed Funds Used During
Construction" also includes interest capitalized for non-regulated entities in
accordance with Financial Accounting Standards Board (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 base rate revenues at the end of each month to
match costs and revenues more closely. In addition they also record the
difference between fuel costs incur red and fuel costs billed. Montaup
recognizes revenues when billed. Montaup, Blackstone, and Newport also record
revenues related to rate adjustment mechanisms.
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 defer
recognition of annual investment tax credits (ITC) and amortize these credits
over the productive lives of the related assets.
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" (FAS 109),
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 1996 and 1995 are comprised as
follows:
Deferred Tax Deferred Tax
($ in thousands) Assets ($ in thousands) Liabilities
1996 1995 1996 1995
Plant Related Plant Related
Differences $18,442 $21,028 Differences $188,425 $170,562
Alternative Refinancing
Minimum Tax 852 9,302 Costs 1,623 1,919
NOL Carryforward 1,655 1,646 Pensions 1,313 1,496
Pensions 4,012 3,392
Acquisitions 3,965 4,281
Other 5,657 5,663 Other 12,042 11,684
Total $34,583 $45,312 Total $203,403 $185,661
As of December 31, 1996 and 1995, EUA has recorded on its Consolidated Balance
Sheet a regulatory liability to ratepayers of approximately $21.2 million and
$27.2 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, 1996 and 1995, a regulatory asset of approximately $58.7 million
and $48.2 million, respectively, h as been recorded, representing the
cumulative amount of federal income taxes on temporary depreciation differences
which were previously flowed through to ratepayers.
EUA has $0.9 million of alternative minimum tax credits which have no
expiration and can be utilized to reduce the consolidated regular tax
liability.
In 1994, EUA Ocean State utilized $3.9 million of ITC related to its investment
in OSP, which were charged against 1994 federal income tax expense and reduced
the consolidated regular tax liability. EUA has no remaining ITC carryforwards
available.
Components of income tax expense for the year 1996, 1995, and 1994 are as
follows:
($ in thousands) 1996 1995 1994
Federal:
Current $ (231) $ 10,335 $ 5,986
Deferred 9,838 6,456 9,199
Investment Tax Credit, Net (1,125) (1,130) (99)
8,482 15,661 15,086
State:
Current 2,823 2,579 1,154
Deferred (363) (1,225) 1,303
2,460 1,354 2,457
Charged to Operations 10,942 17,015 17,543
Charged to Other Income:
Current 4,798 4,353 9,243
Deferred 2,135 (6,217) (2,486)
Investment Tax Credit, Net (82) (82) (3,972)
6,851 (1,946) 2,785
Total $17,793 $ 15,069 $ 20,328
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:
<TABLE>
<CAPTION>
($ in thousands) 1996 1995 1994
<S> <C> <C> <C>
Federal Income Tax Computed at Statutory Rates $ 17,751 $ 17,506 $ 24,510
(Decrease) Increase in Tax From:
Equity Component of AFUDC (189) (187) (123)
Depreciation Differences 2 118 50
Amortization and Utilization of ITC (1,207) (1,212) (5,115)
State Taxes, Net of Federal Income Tax Benefit 1,952 (44) 2,285
Other (516) (1,112) (1,279)
Total Income Tax Expense $ 17,793 $ 15,069 $ 20,328
</TABLE>
(C) Capital Stock:
The changes in the number of common shares outstanding and related increases in
Other Paid-In Capital during the years ended December 31, 1996, 1995, and 1994
were as follows:
<TABLE>
<CAPTION>
Number of Common Shares Issued
<S> <C> <C> <C> <C> <C> <C>
Dividend Northeast Highland Common Other
Reinvestment Energy Energy Shares Paid-In
and Employee J.L. Day Co. Management Group At Par Capital
Savings Plans Acquisition Acquisition Acquisition (000) (000)
1996 (767) $ (4) $ 4
1995 323,526 176,258 2,499 7,683
1994 427,304 12,499 464,579 4,522 10,209
</TABLE>
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, 1996 and 1995, 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.
In October 1996, Newport redeemed the remaining 900 shares of its 9.75%
Preferred Stock, representing 500 shares under the mandatory sinking fund
provision and 400 shares under the optional provision of the sinking fund.
(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, 1998. 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,
1998, 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, Eastern Edison used available cash to redeem $7 million of 4 7/8%
First Mortgage Bonds 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 1996 are:
$27.5 million in 19 97, $72.5 million in 1998, $21.9 million in 1999, $62.5
million in 2000, and $14.3 million in 2001.
As a result of the June 1996 $5.9 million charge to earnings and lower than
anticipated sales, EUA Cogenex was not in compliance with the interest coverage
covenant contained in certain of its unsecured note agreements and therefore
EUA Cogenex was i n default under said note agreements. EUA Cogenex has
reached agreement with lenders to modify the interest coverage covenant
contained in these note agreements through January 1, 1998, and to waive the
default created by the June 1996 charge.
(F) Fair Value Of Financial Instruments:
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate:
Cash and Temporary Cash Investments: The carrying amount approximates fair
value because of the short-term maturity of these instruments.
Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair
value of these assets are based on market rates of similar securities.
Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the
System's redeemable preferred stock and long-term debt were based on quoted
market prices for such securities at December 31, 1996.
The estimated fair values of the System's financial instruments at December 31,
1996, are as follows:
Carrying Fair
($ in thousands) Amount Value
Cash and Temporary Cash Investments $ 12,455 $ 12,455
Long-Term Notes Receivable and
Net Investment in Sales-Type Leases 52,599 54,869
Redeemable Preferred Stock 30,000 30,300
Long-Term Debt 434,447 450,419
(G) Lines Of Credit:
EUA System companies maintain short-term lines of credit with various banks
aggregating approximately $140 million. At December 31, 1996, unused short-
term lines of credit were approximately $89 million. In accordance with
informal agreements with the various banks, commitment fees are required to
maintain certain lines of credit. During 1996, the weighted average interest
rate for short-term borrowings was 5.5%.
(H) Jointly Owned Facilities:
At December 31, 1996, in addition to the stock ownership interests discussed in
Note A, Nature of Operations and Summary of Significant Accounting Policies -
Jointly Owned Companies, Montaup and Newport had direct ownership interests in
the following electric generating facilities:
Accumulated
Provision For Net Construc-
Utility Depreciation Utility tion
Percent Plant in and Plant in Work in
($ in thousands) Owned Service Amortization Service Progress
Montaup:
Canal Unit 2 50.00% $ 83,194 $41,843 $ 41,351 $446
Wyman Unit 4 1.96% 4,051 2,130 1,921
Seabrook Unit 1 2.90% 194,928 29,983 164,945 251
Millstone Unit 3 4.01% 178,854 49,560 129,294 170
Newport:
Wyman Unit 4 0.67% 1,285 726 559
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, 1996,
Montaup's total net investment in nuclear fuel of the Seabrook and Millstone
Units amounted to $2.8 million and $1.8 million, respectively.
Montaup's and Newport's shares of related operating and maintenance expenses
with respect to units reflected in the table above are included in the
corresponding operating expenses.
(I) Financial Information By Business Segments:
The Core Electric Business includes results of the electric utility operations
of Blackstone, Eastern Edison, Newport and Montaup.
Energy Related Business includes results of our diversified energy related
subsidiaries, EUA Cogenex, EUA Ocean State and EUA Energy Investment
Corporation (EUA Energy) and EUA Energy Services.
Corporate results include the operations of EUA Service and EUA Parent.
<TABLE>
<CAPTION>
Pre-Tax Depreciation Cash Equity in
Operating Operating Income and Construction Subsidiary
($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings
<S> <C> <C> <C> <C> <C> <C>
Year Ended
December 31, 1996
Core Electric $ 470,719 $ 80,042 $ 19,902 $ 35,178 $ 33,337 $ 1,587
Energy Related 56,349 (11,536) (9,231) 10,290 28,121 9,111
Corporate (1,723) 271 10 1,272
Total $ 527,068 $ 66,783 $ 10,942 $ 45,478 $ 62,730 $10,698
Year Ended
December 31, 1995
Core Electric $ 483,864 $ 86,505 $ 20,312 $ 34,218 $ 31,466 $ 1,646
Energy Related 79,499 3,377 (3,318) 11,265 44,684 10,417
Corporate (1,139) 21 9 1,773
Total $ 563,363 $ 88,743 $ 17,015 $ 45,492 $ 77,923 $12,063
Year Ended
December 31, 1994
Core Electric $ 489,798 $ 83,966 $ 18,879 $ 33,409 $ 32,978 $ 1,700
Energy Related 74,480 9,905 (1,149) 12,491 17,231 10,785
Corporate (2,533) (187) 555 310
Total $ 564,278 $ 91,338 $ 17,543 $ 46,455 $ 50,519 $12,485
</TABLE>
<TABLE>
<CAPTION>
December 31,
($ in thousands) 1996 1995
<S> <C> <C>
Total Plant and Other Investments
Core Electric $ 715,796 $ 716,828
Energy Related 196,236 203,670
Corporate 20,357 20,302
Total Plant and Other Investments 932,389 940,800
Other Assets
Core Electric 232,443 191,152
Energy Related 66,212 57,083
Corporate 25,985 17,095
Total Other Assets 324,640 265,330
Total Assets $1,257,029 $1,206,130
</TABLE>
(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. Montaup owns a 4.01%
interest in Millstone III and a 2.9% interest in Seabrook I. Northeast
Utilities, the operator of the units, indicates that Millstone III 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 o r 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 III and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone III is $18.6 million
in 1996 dollars, and Seabrook I is $13.1 million in 1996 dollars. These
figures are based on studies performed for the lead owners of the units.
Montaup also pays into decommissioning reserves pursuant to contractual
arrangements with other nuclear generating facilities in which it has an equity
ownership interest or life of the unit entitlement. Such expenses are
currently recoverable through rates.
Pensions: EUA maintains a non-contributory defined benefit pension plan
covering substantially all employees of the EUA System (Retirement Plan).
Retirement Plan benefits are based on years of service and average compensation
over the four years prior to retirement. It is the EUA System's policy to fund
the Retirement Plan on a current basis in amounts determined to meet the
funding standards established by the Employee Retirement Income Security Act of
1974.
Total pension expense for the Retirement Plan, including amounts related to the
1995 voluntary retirement incentive offer, for 1996, 1995 and 1994 included the
following components:
($ in thousands) 1996 1995 1994
Service cost-benefits earned
during the period $ 3,126 $ 2,776 $ 3,281
Interest cost on projected
benefit obligations 9,765 9,391 8,848
Actual loss (return) on assets (16,451) (36,220) 1,523
Net amortization and deferrals 4,060 24,392 (12,494)
Net periodic pension expense 500 339 1,158
Voluntary Retirement Incentive 1,653
Total periodic pension expense $ 500 $ 1,992 $ 1,158
Assumptions used to determine pension costs:
Discount Rate 7.25% 8.25% 7.25%
Compensation Increase Rate 4.25% 4.75% 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, 1996, 1995 and 1994:
<TABLE>
<CAPTION>
($ in thousands) 1996 1995 1994
<S> <C> <C> <C>
Accumulated benefit obligations
Vested $ (118,739) $ (117,060) $ (96,045)
Non-vested (254) (271) (315)
Total $ (118,993) $ (117,331) $ (96,360)
Projected benefit obligations $ (136,286) $ (135,415) $ (112,483)
Plan assets at fair value,
primarily stocks and bonds 161,300 152,308 122,816
Unrecognized net (gain) (29,963) (21,769) (13,643)
Unamortized net
assets at January 1 4,513 4,939 5,365
Net pension (liability) assets $ (436) $ 63 $ 2,055
</TABLE>
The discount rate and compensation increase rate used to determine pension
obligations, effective January 1, 1997 are 7.5% and 4.25% respectively, and
were used to calculate the plan's funded status at December 31, 1996.
The one-time voluntary retirement incentive also resulted in $1.6 million of
non-qualified pension benefits which were expensed in 1995. At December 31,
1996, approximately $1.4 million was 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 certain participants of the
Supplemental Plans to fund in whole, or in part, its future liabilities under
the Supplemental Plans. As of December 31, 1996, approximately $4.4 million
was included in accrued expenses and other liabilities f or these plans. For
the years ended December 31, 1996, 1995 and 1994 expenses related to the
Supplemental Plans were $1.5 million, $1.5 million, and $516,000, respectively.
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 $1.3 million in 1996, $1.4 million in 1995 and $1.3
million in 1994.
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," (FAS 106) as of
January 1, 1993. This standard establishes accounting and reporting standards
for such post-retirement benefits as health care and life insurance. Under FAS
106 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 period s prior to adopting FAS 106, EUA elected to
recognize accrued costs (the Transition Obligation) over a period of 20 years,
as permitted by FAS 106. The resultant annual expense, including amortization
of the Transition Obligation and net of capitalized and deferred amounts, was
approximately $6.1 million in 1996, $6.3 million in 1995 and $5.8 million in
1994.
The total cost of post-retirement benefits other than pensions, including
amounts related to the 1995 voluntary retirement incentive offer, for 1996,
1995 and 1994 includes the following components:
($ in thousands) 1996 1995 1994
Service cost $ 1,123 $ 996 $ 1,537
Interest cost 4,449 4,822 5,381
Actual return on plan assets (253) (671) (126)
Amortization of transition obligation 3,313 3,312 3,429
Other amortizations & deferrals - net (1,211) (970) (85)
Net periodic post-retirement
benefit cost 7,421 7,489 10,136
Voluntary Retirement Incentive 832
Total periodic post-retirement
benefit costs $ 7,421 $ 8,321 $10,136
Assumptions used to determine post-retirement benefit costs
Discount rate 7.25% 8.25% 7.25%
Health care cost trend rate
- near-term 9.00% 11.00% 13.00%
- long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.75% 4.75%
Long-term return on assets
- union 8.50% 8.50% 8.50%
- non-union 7.50% 5.50% 5.50%
Reconciliation of funded status:
($ in thousands) 1996 1995 1994
Accumulated post-retirement benefit
obligation (APBO):
Retirees $(36,518) $(40,817) $(35,386)
Active employees fully eligible
for benefits (5,952) (9,760) (9,778)
Other active employees (19,652) (20,115) $(23,306)
Total $(62,122) $(70,692) $(68,470)
Plan assets at fair value, primarily
notes and bonds 17,743 12,614 7,722
Unrecognized transition obligation 53,001 56,314 61,718
Unrecognized net loss (gain) (17,551) (7,575) (9,098)
(Accrued)/prepaid post-retirement
benefit cost $ (8,929) $ (9,339) $(8,128)
The discount rate and compensation increase rate used to determine post-
retirement benefit obligations effective January 1, 1997 are 7.5% and 4.25%,
respectively, and were used to calculate the funded status of post-retirement
benefits at December 31 , 1996.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1996 by $800,000 and
increase the total accumulated post-retirement benefit obligation by $7.5
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 $7.8 million in 1996, $7.1 million during 1995, and $6.7 million
in 1994.
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, 1996, the aggregate annual minimum commitments for such
contracts are approximately $122 million in 1997, $116 million in 1998, $114
million in 1999, $111 million in 2000, $111 million in 2001 and will aggregate
$1.0 billion for the ensuing year s. 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 Consolidate d 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 carrier 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 at December 31, 1996 and 1995.
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 hazardous.
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, 1996, the EUA System had incurred costs of approximately
$5.7 million (excluding the $5.9 million Mendon Road judgment) in connection
with 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 $2.8 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 November of 1996, the EPA proposed to toughen the nation's ozone standards
as well as the particulate matters standards. The effect that such rules will
have on the EUA System cannot be determined by management at this time.
On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney
General and Division of Energy Resources reached a settlement in principle
regarding electric utility industry restructuring in the state of
Massachusetts. The proposed 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 is expected to be submitted to
the MDPU in March 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. 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 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 69kv 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 $31.5 million,
10.56% unsecured long-term notes due 2005 and EUA Ocean State's $31.1 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 7.22% and 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 $4.8 million of the
outstanding debt of these two companies. In addition, Montaup and Newport have
minimum rental commitments which total approximately $12.7 million and $1.6
million, respectively under a noncancelable transmission facilities support
agreement for years subsequent to 1996. 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."
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 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
is $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, and EUA is consulting with those insurers to
determine the availability and extent of coverage. EUA cannot predict the
ultimate outcome of this matter at this time.
Report of Independent Accountants
To the Trustees and Shareholders of Eastern Utilities Associates
We have audited the accompanying consolidated balance sheet and consolidated
statements of equity capital and preferred stock and indebtedness of Eastern
Utilities Associates and subsidiaries (the Company) as of December 31, 1996 and
1995, and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1996.
These financial statements are the responsibility of the Company's management.
Our responsibility is to 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, 1996 and 1995, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996 in conformity with generally accepted accounting principles.
Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 5, 1997
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.
Quarterly Financial and Common Share Information (unaudited)
(Thousands of Dollars, Except Per Share and Share Price Amounts)
<TABLE>
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
FOR THE QUARTERS
ENDED 1996:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
FOR THE QUARTERS
ENDED 1995:
December 31 $ 135,327 $ 17,274 $ 10,989 $ 10,411 $ 0.51 $ 0.40 25 22 1/2
September 30 143,333 20,626 3,666 3,084 0.15 0.40 24 1/8 21 1/2
June 30 146,736 15,017 8,405 7,825 0.38 0.40 24 7/8 21 5/8
March 31 137,967 18,811 11,887 11,306 0.57 0.385 24 1/8 21 3/4
</TABLE>
<TABLE>
<CAPTION>
Consolidated Operating and Financial Statistics
Years Ended December 31, 1996 1995 1994 1993 1992 1991 1986
<S> <C> <C> <C> <C> <C> <C> <C>
ENERGY GENERATED
AND PURCHASED (millions of kWh):
Generated
- by Somerset Station 719 679 658 319 936 957 887
- by Nuclear Units 977 752 1,008 1,033 1,050 1,109 543
- by Jointly-Owned Units 848 1,410 1,615 1,809 2,105 2,053 2,101
- by Life of the Unit Contracts 526 236 648 602 793 863 667
- by Newport 1 1 1
Interchange with NEPOOL 381 573 295 360 157 191 157
Purchased Power - Unit Power 1,765 1,463 1,526 1,396 1,489 1,006 309
Total Generated and Purchased 5,216 5,113 5,750 5,520 6,531 6,180 4,664
OPERATING REVENUES
($ in thousands):
Residential $ 192,569 $ 193,233 $ 190,662 $ 189,470 $ 176,538 $ 178,812 $ 115,744
Commercial 164,096 169,841 169,241 179,145 170,034 171,732 105,777
Industrial 80,417 83,061 81,500 81,445 76,946 78,273 67,973
Other Electric Utilities 5,411 5,447 4,900 5,098 5,103 4,828 16,189
Other 14,281 17,482 17,282 21,790 21,314 17,984 15,019
Total Primary Sales Revenues 456,774 469,064 463,585 476,948 449,935 451,629 320,702
Unit Contracts 13,945 14,800 26,213 22,617 47,875 41,225 22,622
Non-Electric 56,349 79,499 74,480 66,912 44,154 29,729
Total Operating Revenues $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964 $ 522,583 $ 343,324
ENERGY SALES (millions of kWh):
Residential 1,740 1,697 1,678 1,624 1,575 1,579 1,262
Commercial 1,665 1,674 1,671 1,704 1,704 1,689 1,243
Industrial 868 867 850 816 785 777 855
Other Electric Utilities 86 75 74 61 68 66 372
Other 132 128 137 147 147 154 28
Total Primary Sales 4,491 4,441 4,410 4,352 4,279 4,265 3,760
Losses and Company Use 208 227 233 247 241 280 211
Total System Requirements 4,699 4,668 4,643 4,599 4,520 4,545 3,971
Unit Contracts 517 445 1,107 921 2,011 1,635 693
Total Energy Sales 5,216 5,113 5,750 5,520 6,531 6,180 4,664
NUMBER OF CUSTOMERS:
Residential 270,319 268,203 263,054 259,654 257,026 255,620 217,899
Commercial 27,331 27,401 29,004 30,805 32,851 32,745 24,356
Industrial 1,779 1,685 1,603 1,294 1,197 1,172 1,250
Other Electric Utilities 8 8 12 12 15 15 15
Other 34 34 34 34 34 34 30
Total Customers 299,471 297,331 293,707 291,799 291,123 289,586 243,550
Average Annual Revenue
per Residential Customer ($) 712 720 725 730 687 699 531
Average Annual Use per Residential
Customer (kWh) 6,437 6,327 6,379 6,254 6,128 6,177 5,792
AVERAGE REVENUE
PER KWH (cents):
Residential 11.06 11.39 11.36 11.67 11.21 11.32 9.17
Commercial 9.86 10.15 10.13 10.51 9.98 10.17 8.51
Industrial 9.26 9.58 9.59 9.98 9.80 10.07 7.95
</TABLE>
<TABLE>
<CAPTION>
Consolidated Operating and Financial Statistics
Years Ended December 31, 1996 1995 1994 1993 1992 1991 1986
<S> <C> <C> <C> <C> <C> <C> <C>
CAPITALIZATION ($ in thousands):
Bonds - Net $277,313 $ 279,374 $ 288,449 $ 300,389 $ 306,898 $ 346,146 $ 246,500
Other Long-Term Debt - Net 129,024 155,497 166,963 196,427 156,060 142,306 177,289
Total Long-Term Debt - Net 406,337 434,871 455,412 496,816 462,958 488,452 423,789
Preferred Stock - Net 33,935 33,155 32,290 31,953 44,346 45,830 44,931
Common Equity 371,813 375,229 365,443 333,165 266,855 248,598 225,156
Total Capitalization $812,085 $ 843,255 $ 853,145 $ 861,934 $ 774,159 $ 782,880 $ 693,876
CAPITALIZATION RATIOS (%)
Long-Term Debt 50 52 53 57 60 62 61
Preferred Stock 4 4 4 4 6 6 7
Common Equity 46 44 43 39 34 32 32
COMMON SHARE DATA:
Earnings (Loss) per Average
Common Share ($) 1.50 1.61 2.41 2.44 2.00 1.58 2.82
Dividends per Share ($) 1.645 1.585 1.515 1.42 1.36 1.45 2.15
Payout (%) 109.7 98.4 62.9 58.2 68.0 91.8 76.2
Average Common
Shares Outstanding 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224 16,608,090 11,537,677
Total Common Shares
Outstanding 20,435,997 20,436,764 19,936,980 19,032,598 17,237,788 16,831,062 11,676,229
Book Value per Share ($) 18.19 18.36 18.33 17.50 15.48 14.77 19.28
Percent Earned On Average
Common Equity 8.2 8.8 13.6 15.0 13.2 10.8 15.0
Market Price ($):
High 24 1/4 25 27 3/8 29 7/8 25 1/4 25 39 1/2
Low 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8 15 3/4 25 3/4
Year End 17 3/8 23 5/8 22 28 24 3/4 20 5/8 38 1/2
Miscellaneous ($ in thousands):
Total Construction Expenditures ($) 63,182 78,461 50,870 76,770 71,914 60,174 64,371
Cash Construction Expenditures ($) 62,730 77,923 50,519 76,391 71,365 57,570 47,137
Internally Generated Funds ($) 77,545 90,883 79,274 79,691 48,933 63,681 44,832
Internally Generated Funds as
a % of Cash Construction (%) 123.6 116.6 156.9 104.3 68.6 110.6 95.1
Installed Capability - mw 1,208 1,191 1,212 1,256<F1> 1,325 1,349 971
Less: Unit Contract Sales - mw 60 35 85 85 85 216 108
System Capability - mw 1,148 1,156 1,127 1,171 1,240 1,133 863
System Peak Demand - mw 854 931 921 854 849 879 691
Reserve Margin (%) 34.4 24.2 22.4 37.1 46.1 28.9 24.9
System Load Factor (%) 62.6 57.2 57.5 61.5 57.5 59.0 65.6
Sources of Energy (%):
Nuclear 29.0 28.2 33.8 34.0 34.1 31.3 19.0
Coal 14.7 14.7 11.7 5.4 18.6 21.0 22.0
Oil 19.8 25.5 20.0 28.3 12.7 26.9 59.0
Gas 30.8 26.5 28.4 26.0 29.3 17.2
Other 5.7 5.1 6.1 6.3 5.3 3.6
Cost of Fuel (Mills per kWh):
Nuclear 5.0 6.3 6.1 7.5 7.7 8.7 8.6
Coal 19.6 20.3 20.9 24.1 21.2 21.4 23.7
Oil 37.7 30.2 27.1 25.5 26.0 18.9 23.6
Gas 14.4 14.3 14.1 15.1 13.0 16.2
All Fuels Combined 16.7 16.7 14.5 15.5 14.8 15.7 20.8
<FN>
<F1> 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, 1997, there
were 11,978 common shareholders of record.
Form 10-K
A copy of EUA's 1996 Annual Report on Form 10-K filed with the Securities and
Exchange Commission is available to shareholders without charge by writing to
us.
Annual Meeting
The 1997 Annual Meeting of Shareholders will be held on
Monday, May 19, 1997, 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 replacement certificate.
Dividends
Schedule of anticipated record and payment dates for 1997 dividends on EUA
Common Shares:
Record Payment
January 31 February 15
May 1 May 15
August 1 August 15
October 31 November 15
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.,
Treasurer/Secretary 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
Trustees
Russell A. Boss (A,P)
President and Chief Executive Officer, A. T. Cross Company
Lincoln, Rhode Island
Paul J. Choquette, Jr. (C,P)
President, 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 (A,F)
Corporate Director and Trustee
Providence, Rhode Island
Larry A. Liebenow (A,F)
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 (C,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
EUA System Officers
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
Richard M. Burns
Comptroller
Clifford J. Hebert, Jr.
Treasurer and Secretary
Donald T. Sena
Assistant Treasurer
Left to Right: Richard M. Burns, Donald T. Sena, John D. Carney, Robert G.
Powderly, Donald G. Pardus, John R. Stevens, Clifford J. Hebert, Jr.
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). 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
Cogenex Corporation (EUA Cogenex), EUA Energy Investment Corporation (EUA
Energy), EUA Ocean State Corporation (EUA Ocean State), EUA Service Corporation
(EUA Service) and EUA Energy Services, Inc. (EUA Energy Services). 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
related services in New England. The holding company system of EUA, the three
retail subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy, EUA Energy
Services and EUA Ocean State is referred to as the EUA System.
Form 10-K
A copy of EUA's, Eastern Edison's and Blackstone's Co-Registrant 1996
Annual Report on Form 10-K, which is filed with the Securities and Exchange
Commission, is available to shareholders 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
1996 Per Share 1995 Per Share
First Quarter $5.91 First Quarter $5.35
Second Quarter 6.34 Second Quarter 5.69
Third Quarter 6.34 Third Quarter 5.74
Fourth Quarter 6.34 Fourth Quarter 5.74
No dividends 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.
<TABLE>
SELECTED FINANCIAL DATA
<CAPTION>
For the Years Ended December 31,
(In Thousands) 1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C>
______________________________________________________________________________
Operating Revenues $136,911 $140,861 $140,611 $143,666 $138,604
Net Earnings 3,776 4,009 3,438 4,069 2,583
Total Assets 132,313 129,835 121,413 114,552 115,698
Capitalization:
Long-Term Debt 35,000 36,500 38,000 39,500 39,500
Non-Redeemable
Preferred Stock 6,130 6,130 6,130 6,130 6,130
Common Equity 36,232 37,045 37,180 35,378 34,551
Total Capitalization $ 77,362 $ 79,675 $ 81,310 $ 81,008 $ 80,181
</TABLE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND REVIEW OF OPERATIONS
Overview
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 a
voluntary retirement incentive (VRI) offer recorded in June 1995.
Kilowatthour sales (kWh) 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.
Blackstone's net earnings for 1995 increased approximately $600,000 to
$4.0 million compared to 1994 net earnings despite a one-time charge of
approximately $550,000, on an after-tax basis, related to the VRI. kWh
sales of electricity increased by 1.1% for 1995. Sales to residential
customers increased by 2.6% and sales to industrial customers were up 1.0% for
1995 largely due to colder weather in the fourth quarter as compared to 1994.
Comparison of Financial Results
Operating Revenues
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 conservation and load management (C&LM) expenses,
as discussed below, and decreased kilowatthour sales.
Operating Revenues for 1995 increased by approximately $300,000 as
compared to those in 1994 primarily due to an increase in base revenues,
attributable to a 1.1% increase in kWh sales. Purchased power recoveries
increased by approximately $800,000 (see Operating Expenses below) offset by
a $700,000 decrease in transmission rental revenue.
Voluntary Retirement Incentive Offer
On March 15, 1995, EUA announced a corporate reorganization which, among
other things, consolidated management of Eastern Edison, Blackstone and
Newport. As part of the reorganization, a VRI was offered to sixty-six
professionals of the EUA System, including nine employees of Blackstone.
Forty-nine of those eligible for the program, including five Blackstone
employees, accepted the incentive and retired effective June 1, 1995.
The cost of this incentive program amounted to a one-time $900,000 pre-tax
($550,000 after-tax) charge to Blackstone's second quarter 1995 earnings.
Expenses
Purchased Power expense, which is recovered through Blackstone's purchased
power adjustment clause and represented 70% of total 1996 operating expense,
decreased approximately $4.7 million or 4.9% as compared to 1995. Impacting
purchased power expense 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. Purchased Power expense in 1995 increased approximately $800,000
or less than 1.0% as compared to 1994. The average cost of fuel increased 14.1%
in 1995 compared to 1994. This increase was partially offset by a wholesale
rate decrease by the company's supplier, Montaup effective May 21, 1994.
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 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. Other Operation and Maintenance
expenses for 1995 decreased by approximately $2.0 million or 9.3% when compared
to 1994. This decrease is primarily due to the Company's continued strict
attention to cost control including on-going savings related to the VRI, lower
rent expense related to the March 1995 purchase of the Company's general office
and operations buildings which were previously leased and decreased FAS106
expenses.
Taxes Other than Income for 1996 decreased by $300,000 or 3.6% in 1996 and
$400,000 or 4.0% in 1995. These decreases were due primarily to 1% decreases
in the Rhode Island Gross Receipts Tax billed to industrial customers in both
1996 and 1995.
Net interest charges for 1996 decreased by approximately $300,000 or 6.3%.
This decrease was primarily due to lower interest on long-term debt due to
reductions in long-term debt balances resulting from required sinking fund
payments and decreased customer deposits interest. Net interest charges
for 1995 decreased by approximately $400,000 or 8.7%. This decrease was
primarily due to decreased customer deposits interest and reduced interest
related to Internal Revenue Service (IRS) audits of prior years' consolidated
income tax returns, which together aggregated over $300,000.
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 1996, 1995 and 1994, the
Company's cash construction expenditures were $4.2 million, $5.1 million, $5.7
million, respectively. In 1996, internally generated funds provided over 100%
of cash construction requirements.
Cash Construction expenditures are expected to be $4.2 million in 1997,
$4.4 million in 1998 and $4.5 million in 1999 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.
EUA System companies, including Blackstone, maintain short-term lines of
credit with various banks aggregating approximately $140 million. At December
31, 1996, unused short-term lines of credit amounted to approximately $89
million. These credit lines are available to other EUA System companies under
joint credit line arrangements. Blackstone had $700,000 of short-term
borrowings outstanding at year end 1996, and $1.3 million at year-end 1995.
Blackstone's requirements for sinking fund payments and redemption of
securities for each of the five years following 1996 is $1.5 million in 1997,
1998, 1999 and 2000, and $3.3 million in 2001.
Electric Utility Industry Restructuring Initiatives
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 to be phased-in commencing July 1, 1997 for large
manufacturing customers, certain new commercial and industrial customers, and
State of Rhode Island accounts. By July 1, 1998 or sooner, all customers will
have retail access. Under the URA the local distribution company will retain
the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who choose not to choose, the local distribution company would be allowed to
arrange for supply at a non-discriminatory, "standard offer" price.
Distribution companies will also be providers of last resort, required to
arrange for supply, at prevailing market prices, for customers who are unable
to do so.
Blackstone is currently an all requirements customer of Montaup for
generation services. This legislation provides for recovery of prudently
incurred embedded generation costs that may not be to recovered in a
competitive electric generation market, commonly referred to as "stranded
costs," through a non-bypassable transition charge initially set at 2.8 cents
per kWh. The transition charge recovers, among other things, costs of
depreciated generation net of its market value, regulatory assets, nuclear
decommissioning 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 July 1,
1997 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 July 1, 1997
through the life of the respective unit or contract. The URA also provides for
commitments to demand side management initiatives and renewables, low income
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 rate making standards for electric distribution companies. These
performance based standards provide for a 6% minimum and an approximate 12.2%
maximum allowed return on equity for Blackstone and Newport. In addition, the
URA provides for adjustments to electric distribution companies' base rates
using the prior year's Consumer Price Index and other performance factors.
Under this provision of the law, base rates were increased 1.88% for customers
of Blackstone, and 2.18% for our Newport customers effective January 1, 1997.
The implementation of the URA will require approvals from applicable
regulatory agencies, including the Federal Energy Regulatory Commission (FERC),
the Rhode Island Public Utilities Commission (RIPUC), and the Securities and
Exchange Commission (SEC).
In February 1997, Blackstone, Newport and Montaup reached settlement with
the Rhode Island Division of Public Utilities and Carriers and the Rhode Island
Attorney General with regard to implementation of a restructuring plan for
Blackstone, Newport and Montaup. In addition to complying with the URA, the
settlement provides for an immediate 10% rate reduction and a commitment by
Montaup to file a plan by July 1, 1997 to divest all of its generating assets.
Any disposition of generation assets resulting from the URA would also require
the approval of the SEC under the Public Utility Holding Company Act of 1935.
Historically, electric rates have been designed to recover a utility's
full costs 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.
The Company believes that its operations will continue to meet the criteria
established in these accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in the Company no longer meeting the
criteria of certain accounting standards which could trigger the discontinuance
of Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (FAS71). Should it be required to
discontinue the application of FAS71, the Company would be required to take an
immediate write down of the affected assets in accordance with FAS101,
"Accounting for the Discontinuation of Application of FAS71."
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, an environmental audit program designed to
ensure compliance with environmental laws and regulations and to identify and
reduce liability was instituted by EUA.
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, 1996, Blackstone had incurred costs of approximately
$4.9 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 their financial position and thus, no
loss provision is required at this time.
Blackstone estimates that additional costs of up to $2.7 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 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. 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." Management cannot
predict the ultimate outcome of the EMF issue.
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
"Financial Statements" and "Notes to Financial Statements" in arriving at a
more complete understanding of such matters.
[This page left blank intentionally]
Financial Table of Contents
Statements of Income. . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Statement of Retained Earnings . . . . . . . . . . . . . . . . . . . . . 10
Statement of Cash Flow . . . . . . . . . . . . . . . . . . . . . . . . . 11
Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Statement of Capitalization . . . . . . . . . . . . . . . . . . . . . . . 13
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . 15
Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . 27
<TABLE>
Blackstone Valley Electric Company
Statement of Income
Years Ended December 31,
(In Thousands)
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Operating Revenues $ 136,911 $ 140,861 $ 140,611
Operating Expenses:
Purchased Power (principally from an affiliate) 91,016 95,725 94,970
Other Operation and Maintenance 11,781 10,938 13,405
Affiliated Company Transactions 10,092 8,280 7,787
Voluntary Retirement Incentive 0 912
Depreciation 5,594 5,501 5,303
Taxes - Other than Income 8,506 8,821 9,202
Income and Deferred Taxes 2,156 2,347 1,885
Total Operating Expenses 129,145 132,524 132,552
Operating Income 7,766 8,337 8,059
Allowance for Other Funds Used During
Construction 50 33 39
Other Income (Deductions) - Net 30 (38) 78
Income Before Interest Charges 7,846 8,332 8,176
Interest Charges:
Interest on Long-Term Debt 3,313 3,481 3,476
Other Interest Expense 524 612 1,009
Allowance for Borrowed Funds Used
During Construction (Credit) (56) (59) (36)
Net Interest Charges 3,781 4,034 4,449
Net Income 4,065 4,298 3,727
Preferred Dividend Requirements 289 289 289
Net Earnings Applicable to Common Stock $ 3,776 $ 4,009 $ 3,438
</TABLE>
Statement of Retained Earnings
Years Ended December 31,
(In Thousands)
1996 1995 1994
Restated
Retained Earnings - Beginning of Year $ 9,934 $ 10,069 $ 10,204
Net Income 4,065 4,298 3,727
Total 13,999 14,367 13,931
Dividends Paid:
Preferred 289 289 289
Common 4,589 4,144 3,573
Retained Earnings - End of Year $ 9,121 $ 9,934 $ 10,069
The accompanying notes are an integral part of the financial statements.
<TABLE>
Blackstone Valley Electric Company
Statement of Cash Flows
Years Ended December 31,
(In Thousands)
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 4,065 $ 4,298 $ 3,727
Adjustments to Reconcile Net Income
to Net Cash Provided from Operating Activities:
Depreciation and Amortization 5,976 5,953 6,157
Deferred Taxes (561) 1,200 176
Investment Tax Credit, Net (182) (183) 253
Allowance for Funds Used During Construction (50) (34) (39)
Other - Net (555) 643 (6,072)
Net Changes in Operating Assets and Liabilities:
Accounts Receivable 2,389 (2,324) (603)
Materials and Supplies 66 (172) (27)
Accounts Payable (383) 7,540 1,484
Accrued Taxes (362) 337 (1,280)
Other - Net 740 (7,239) 5,454
Net Cash Provided from Operating Activities 11,143 10,019 9,230
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (4,196) (5,064) (5,653)
Net Cash (Used in) Investing Activities (4,196) (5,064) (5,653)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (1,500) (1,500)
Premium on Reacquisition
and Financing Expenses
Common Share Dividends Paid (4,589) (4,144) (3,573)
Preferred Dividends Paid (289) (289) (289)
Net (Decrease) Increase in Short-Term Debt (524) 1,259
Net Cash (Used in) Financing Activities (6,902) (4,674) (3,862)
Net Increase (Decrease) in Cash 45 281 (285)
Cash and Temporary Cash Investments at
Beginning of Year 753 472 757
Cash and Temporary Cash Investments at
End of Year $ 798 $ 753 $ 472
Cash paid during the year for:
Interest (Net of Amounts Capitalized) $ 3,390 $ 3,565 $ 3,506
Income Taxes $ 3,301 $ 690 $ 1,836
</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
Blackstone Valley Electric Company
Balance Sheet
December 31,
(In Thousands)
<CAPTION>
ASSETS
1996 1995
<S> <C> <C>
Utility Plant and Other Investments:
Utility Plant $ 139,366 $ 136,503
Less Accumulated Provision for Depreciation 51,952 48,023
Net Utility Plant 87,414 88,480
Non-Utility Property - Net 46 47
Total Utility Plant and Other Investments 87,460 88,527
Current Assets:
Cash and Temporary Cash Investments 798 753
Accounts Receivable:
Customers, Net 11,141 11,254
Accrued Unbilled Revenue 1,196 1,339
Others 2,541 4,726
Associated Companies 482 429
Plant Materials and Operating Supplies (at average cost) 873 939
Other Current Assets 417 393
Total Current Assets 17,448 19,833
Other Assets (Note A) 27,405 21,475
Total Assets $ 132,313 $ 129,835
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 36,232 $ 37,045
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt 35,000 36,500
Total Capitalization 77,362 79,675
Current Liabilities:
Long-Term Debt Due Within One Year 1,500 1,500
Notes Payable 735 1,259
Accounts Payable:
Public 509 282
Associated Companies 16,759 17,371
Customer Deposits 1,113 992
Taxes Accrued 1,415 1,777
Dividends Accrued 72 72
Interest Accrued 899 981
Other Current Liabilities 1,157 431
Total Current Liabilities 24,159 24,665
Deferred Credits:
Unamortized Investment Credit 2,561 2,743
Other Deferred Credits 14,002 13,836
Total Deferred Credits 16,563 16,579
Accumulated Deferred Taxes 14,229 8,916
Commitments and Contingencies (Note H)
Total Liabilities and Capitalization $ 132,313 $ 129,835
</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
Blackstone Valley Electric Company
Statement of Capitalization
December 31,
(In Thousands)
<CAPTION>
1996 1995
<S> <C> <C>
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 9,121 9,934
Total Common Equity 36,232 37,045
Non-Redeemable Cumulative Preferred Stock:
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 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) 12,000 13,500
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds Due 2014 <F2> 6,500 6,500
36,500 38,000
Less Portion Due Within One Year 1,500 1,500
Total Long-Term Debt 35,000 36,500
Total Capitalization $ 77,362 $ 79,675
<FN>
<F1> Authorized and Outstanding.
<F2> Weighted average interest rate was 3.5% for 1996 and 3.9% for 1995.
</FN>
</TABLE>
The accompanying notes are an integral part of the financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
(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 FERC and 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.
Reclassifications: Certain prior period amounts on the financial
statements have been reclassified to conform with current presentation.
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 four other
non-utility companies.
Transactions between Blackstone and other affiliated companies include the
following: purchased power costs billed by Montaup of approximately
$90,970,000 in 1996, $95,683,000 in 1995 and $94,944,000 in 1994; accounting,
engineering and other services rendered by EUA Service of approximately
$11,923,000 in 1996, $10,448,000 in 1995 and $9,524,000 in 1994; and operating
revenue from the rental of transmission facilities to Montaup of approximately
$2,501,000 in 1996, $3,047,000 in 1995 and $2,665,000 in 1994. 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 1996,
1995 and 1994, 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, 1996 and
1995 are detailed as follows:
(In Thousands)
1996 1995
Regulatory Assets:
Unamortized losses on reacquired debt $ 425 $ 455
Deferred SFAS 109 costs (Note B) 7,487 1,996
Deferred SFAS 106 costs 872 1,017
Mendon Road Judgment (Note H) 6,154 5,857
Other regulatory assets 1,234 959
Total regulatory assets 16,172 10,284
Other deferred charges and assets:
Unamortized debt expenses 639 710
Other 10,594 10,481
Total Other Assets $27,405 $21,475
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. Effects of legislation and/or regulatory initiatives
or EUA's own initiatives could ultimately cause Blackstone to no longer follow
these accounting rules. In such an event, a non-cash write-off of regulatory
assets and liabilities could be required at that time.
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 9.4% in 1996, 8.6% in 1995 and 10.0% in 1994.
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. In addition, the Company also accrues
the difference between fuel and purchased power costs incurred and fuel and
purchased power costs billed to its customers.
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 currently 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 1996, 1995,
and 1994 are as follows:
_______________________________________________________________________
(In Thousands) 1996 1995 1994
Federal:
Current $2,901 $1,329 $1,436
Deferred (531) 1,133 176
Investment Tax Credit, Net (182) (184) 253
$2,188 $2,278 1,865
State:
Current 2 1 20
Deferred (34) 68
(32) 69 20
Charged to Operations 2,156 2,347 1,885
Charged to Other Income:
Current 40 3 46
Total $2,196 $2,350 $1,931
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) 1996 1995 1994
Federal Income Tax Computed
at Statutory Rates $2,191 $2,327 $1,980
(Decreases) Increases in Tax from:
Equity Component of AFUDC (17) (12) (14)
Consolidated Tax Savings (32) (15) (125)
Depreciation Differences 283 262 260
Amortization and Utilization of ITC (182) (184) (194)
State Taxes, Net of Federal
Income Tax Benefit (21) 45 13
Cost of Removal (67) (110)
Other (26) (6) 121
Total Income Tax Expense $2,196 $2,350 $1,931
(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 1996 and 1995 are comprised as follows:
Deferred Tax Deferred Tax
Assets Liabilities
($000) ($000)
1996 1995 1996 1995
Plant Related Plant Related
Differences $1,581 $1,730 Differences $ 14,593 $ 8,540
Pensions 425 501 Refinancing
Other 773 609 Costs 144 155
Total $2,779 $2,840 Pensions 436 556
Other 1,832 2,496
Total $17,005 $11,747
Blackstone has recorded on its Balance Sheets as of December 31, 1996 and
1995 a regulatory liability to ratepayers of approximately $3.0 million and
$3.4 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, 1996 and 1995, a regulatory asset of approximately $7.5 million
and $2.0 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, 1996, 1995, and 1994.
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.
(C) Capital Stock (continued)
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, 1996 and 1995, 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 $4,124,784 were unrestricted as to the payment of
cash dividends on its common stock at December 31, 1996.
(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, 1998. 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 1996 is
$1.5 million in 1997, 1998, 1999, and 2000, and $3.3 million in 2001.
(F) Lines of Credit:
The EUA System Companies, including Blackstone maintain short-term lines
of credit with various banks aggregating approximately $140 million. At
December 31, 1996, unused short-term lines of credit amounted to approximately
$89 million. These credit lines are available to other EUA System companies
under joint credit line arrangements. In accordance with informal agreements
with various banks, commitment fees are required to maintain certain lines of
credit. Blackstone had $700,000 of short-term borrowings outstanding at year
end. During 1996, Blackstone's weighted average interest rate for short-term
borrowings was 5.6%.
(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.
(G) Fair Value of Financial Instruments (continued)
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, 1996 are as follows (In Thousands):
Carrying Fair
Amount Value
Cash and Temporary Cash Investments $ 798 $ 798
Long-Term Debt $36,500 $37,596
(H) Commitments and Contingencies:
Pensions: Blackstone participates with other EUA System companies in a
non-contributory, defined benefit pension plan covering substantially all of
their employees (Retirement Plan). Retirement Plan benefits are based on years
of service and average compensation over the four years prior to retirement.
It is the EUA System's policy to fund the Retirement Plan on a current basis in
amounts determined to meet the funding standards established by the Employee
Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including amounts
related to the 1995 Voluntary Retirement Incentive offer, for 1996, 1995 and
1994 includes the following components ($ In Thousands):
1996 1995 1994
Service cost - benefits earned
during the period $ 664 $ 606 $ 696
Interest cost on projected
benefit obligation 2,373 2,346 2,186
Actual (return) loss on assets (4,216) (9,560) 397
Net amortization and deferrals 1,063 6,470 (3,241)
Net periodic pension (income) expense $ (116) $ (138) $ 38
Voluntary retirement incentive 410
Total periodic pension (income) expense $(116) $ 272 $ 38
Assumptions used to determine pension cost:
Discount Rate 7.25% 8.25% 7.25%
Compensation Increase Rate 4.25% 4.75% 4.75%
Long-Term Return on Assets 9.50% 9.50% 9.50%
(H) Commitments and Contingencies (continued)
The discount rate used to determine pension obligations was changed
effective January 1, 1997 to 7.5%. 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 one-time voluntary retirement incentive also resulted in approximately
$310,000 of non-qualified pension benefits which were expensed in 1995. At
December 31, 1996, approximately $177,000 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, 1996, 1995 and 1994, Blackstone's portion of
expenses related to the Supplemental Plans were approximately $284,000,
$306,000 and $147,000, 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 $111,000 in
1996, approximately $148,000 in 1995 and approximately $181,000 in 1994.
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 $1.5 million in
1996, $1.3 million in 1995 and $1.5 million in 1994.
(H) Commitments and Contingencies (continued)
The total cost of Post-Retirement Benefits other than Pensions, including
amounts related to the 1995 Voluntary Retirement Incentive offer, for 1996,
1995 and 1994 includes the following components ($ In Thousands):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Service cost $ 216 $ 191 $ 299
Interest cost 1,060 1,170 1,323
Actual return on plan assets (6) (111) (20)
Amortization of transition obligation 835 829 866
Net other amortization & deferrals (274) (239) (10)
Net periodic post-retirement benefit costs 1,831 1,840 2,458
Voluntary retirement incentive 90
Total periodic post-retirement benefit costs $ 1,831 $ 1,930 $2,458
Assumptions:
Discount rate 7.25% 8.25% 7.25%
Health care cost trend rate-near-term 9.00% 11.00% 13.00%
Health care cost trend rate-long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.75% 4.75%
Rate of return on plan assets 7.50% 5.50% 5.50%
Reconciliation of funded status:
($ In Thousands) 1996 1995 1994
Accumulated post-retirement benefit obligation (APBO):
Retirees $(7,045) $(8,235) $ (7,498)
Active employees fully eligible for benefits (1,543) (2,825) (2,589)
Other active employees (2,413) (3,052) (4,093)
Total $(11,001) $(14,112) $ (14,180)
Fair Value of assets (primarily notes and bonds) 1,573 924 364
Unrecognized transition obligation 11,372 12,083 13,328
Unrecognized net (gain) loss (5,551) (2,217) (2,358)
(Accrued) prepaid post-retirement benefit cost $ (3,607) $ (3,322) $ (2,846)
</TABLE>
The discount rate and compensation increase rate used to determine post-
retirement benefit obligations, effective January 1, 1997, are 7.5% and 4.25%,
respectively and were used to calculate the funded status of Post-Retirement
benefits at December 31, 1996.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1996 by approximately
$108,000 and increase the total accumulated post-retirement benefit obligation
by $1.2 million.
Blackstone has also established an irrevocable external Voluntary
Employee's Beneficiary Association (VEBA) Trust Fund as required by the
aforementioned regulatory decisions. Contributions to the VEBA fund commenced
in March 1993 and totaled approximately $1.2 million during 1996, $1.1 million
during 1995, and $800,000 during 1994.
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 at December 31, 1996 and 1995.
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. If the EPA determines that FFC is
not 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. 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 to be followed
by the Commonwealth's written reply.
(H) Commitments and Contingencies (continued)
The EPA will determine whether FFC is a hazardous substance. Further court
proceedings are likely.
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 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 which were filed by Stone & Webster and Valley. This proceeding was
stayed in December 1995 pending final EPA determination as to whether FFC is
hazardous.
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, 1996, Blackstone had incurred costs of approximately
$4.9 million (excluding the $5.9 million Mendon Road judgment) in connection
with 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 (excluding the Mendon Road judgment) may be incurred at these
sites through 1998 of up to approximately $2.7 million 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. 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. Rhode Island 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. Management cannot predict the impact, if
any, which legislation or other developments concerning EMF may have on
Blackstone.
In April 1992, NESCAUM, an environmental advisory group for eight
northeast states, including Massachusetts and Rhode Island, issued
recommendations for nitrogen oxide 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 EPA's 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 or more tons per
year of oxides of nitrogen. Rhode Island has also issued similar regulations.
Montaup has initiated compliance through, among other things, selective,
noncatalytic reduction processes.
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
is $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, and EUA is consulting with those insurers to determine the
availability and extent of coverage. 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 sheet and statement of capitalization
of Blackstone Valley Electric Company (the Company) as of December 31, 1996 and
1995, and the related statements of income, retained earnings and cash flows
for each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Company as of December 31,
1996 and 1995, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
/s/Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 5, 1997
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Company Profile
Eastern Edison Company (Eastern Edison or the Company) is a retail
electric utility company. Eastern Edison supplies retail electric service to
approximately 182,000 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). 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 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
Service Corporation (EUA Service). 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. The holding company system
of EUA, the three retail subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA
Energy, EUA Energy Services and EUA Ocean State is referred to as the EUA
System.
Form 10-K
A copy of EUA's, Eastern Edison's and Blackstone's Co-Registrant 1996
Annual Report on Form 10-K, which is filed with the Securities and Exchange
Commission, is available to shareholders 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
1996 Per Share 1995 Per Share
First Quarter $2.87 First Quarter $2.53
Second Quarter 3.00 Second Quarter 0.43
Third Quarter 3.00 Third Quarter 0.46
Fourth Quarter 3.00 Fourth Quarter 0.45
No dividends 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) 1996 1995 1994 1993 1992
_________________________________________________________________________
Operating Revenues $404,808 $420,069 $418,424 $417,021 $420,188
Net Earnings 30,983 31,455 31,395 28,145 29,231
Total Assets 775,082 739,198 756,045 742,273 776,510
Capitalization:
Long-Term Debt 222,402 222,313 229,224 264,134 269,995
Redeemable Preferred
Stock-Net 27,035 26,218 25,257 24,824 28,171
Non-Redeemable
Preferred Stock 8,949
Common Equity 240,213 244,368 225,064 223,005 220,257
Total Capitalization $489,650 $492,899 $479,545 $511,963 $527,372
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND REVIEW OF OPERATIONS
Overview
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
voluntary retirement incentive offer (VRI). The 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.
Consolidated Net Earnings for 1995 of approximately $31.5 million were
slightly higher than 1994 net earnings of $31.4 million due primarily to lower
litigation expenses resulting from favorable court decisions rendered in 1995,
lower interest expense and successful cost control efforts. Offsetting these
impacts somewhat were the VRI charge and Montaup's approximately $13.9 million
annual wholesale rate reduction effective May 21, 1994.
Comparison of Financial Results
Operating Revenues
Operating Revenues for 1996 decreased by approximately $15.3 million, as
compared to 1995. The change was primarily due to decreased purchased power
recoveries of $6.9 million, decreased conservation and load management (C&LM)
expense recoveries of $7.1 million, and decreased contract demand sales of $1.6
million.
Operating Revenues for 1995 increased by approximately $1.6 million as
compared to 1994. This change was primarily due to increased purchased power
and fuel expense recoveries aggregating $5.8 million and additional revenues
related to the full year impact of Newport becoming an all-requirements
customer of Montaup on May 21, 1994. Offsetting these increases somewhat were
decreased C&LM expense recoveries of $3.9 million and the full year impact of
Montaup's wholesale rate reduction implemented on May 21, 1994 which lowered
1995 revenues by approximately $4.9 million.
Voluntary Retirement Incentive Offer
On March 15, 1995, EUA announced a corporate reorganization which, among
other things, consolidated management of Eastern Edison, Blackstone and
Newport. As part of the reorganization, a VRI was offered to 66 professionals
of the EUA System including 22 employees of Eastern Edison and Montaup.
Forty-nine of those eligible for the program, including 16 employees of Eastern
Edison and Montaup, accepted the incentive and retired effective June 1, 1995.
The cost to Eastern Edison of this incentive program amounted to a one-time
$2.4 million pre-tax ($1.5 million after-tax) charge to second quarter 1995
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 1996.
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.
Fuel expense increased by $3.4 million or 3.8% in 1995 as compared to 1994.
This change was caused by an increase of 14.1% in the average cost of fuel
offset by decreases in total energy generated and purchased of 11.1%.
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 includes a prior period refund
of approximately $2.0 million, and decreased billings from the Ocean State
Power Project and the Maine Yankee nuclear unit aggregating $2.5 million.
Purchased Power demand expense for 1995 increased $2.6 million to $125.6
million. This increase was due primarily to the impact of Newport's purchased
power contracts assumed by Montaup effective May 21, 1994, coincident with
Newport becoming an all-requirements customer of Montaup, aggregating
approximately $4.8 million, and increased billings from the Ocean State Power
project and the Yankee nuclear units aggregating $5.2 million. These increases
were offset somewhat by decreases of approximately $6.7 million resulting from
purchase power contracts totaling 41 mw which expired in October 1994, and a
net $700,000 reduction in purchases from other power suppliers.
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
and include such expense items as Montaup's joint ownership interests in
generating facilities such as Seabrook I and Millstone III, 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-Retirement Benefits
Other Than Pensions" (FAS106).
Other Operation and Maintenance 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. Other Operation and Maintenance expenses for 1995 decreased by
approximately $5.7 million or 5.6% from 1994 levels. This decrease was due
primarily to lower C&LM expense totaling $4.3 million, decreased legal costs of
approximately $2.1 million and successful cost control efforts. Offsetting
these year-to date decreases somewhat were increases in Montaup power contract
expenses and FAS106 expenses aggregating $1.4 million.
Net interest charges decreased by approximately $2.7 million, due
primarily 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 and the September 1996 maturity of $7 million of 4 % First Mortgage
Collateral Trust Bonds of Eastern Edison. Net interest charges decreased by
$1.4 million in 1995 versus 1994. Other Interest expense provisions recorded
in June 1994 aggregating $1.0 million related to Internal Revenue Service
audits of prior years' consolidated income tax returns were primarily
responsible for this change.
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 1996, 1995 and 1994, Eastern Edison's and
Montaup's combined cash construction expenditures were $26.0 million, $23.4
million, and $23.6 million, respectively. Internally generated funds provided
approximately 118% of Eastern Edison's and Montaup's combined cash construction
requirements in 1996.
Cash construction expenditures are expected to be approximately $16.2
million in 1997, and $9.9 million in 1998 and 1999, 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. EUA System companies, including
Eastern Edison and Montaup, maintain short-term lines of credit with various
banks aggregating approximately $140 million. These credit lines are available
to other affiliated companies under joint credit line arrangements. At
December 31, 1996, unused short-term lines of credit amounted to approximately
$89 million. At December 31, 1996, Eastern Edison had $2.0 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 2001 are $60 million in 1998. The
Company has no sinking fund requirements until the year 2003.
Electric Utility Industry Restructuring Initiatives
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 to be phased-in commencing July 1, 1997 for large
manufacturing customers, certain new commercial and industrial customers, and
State of Rhode Island accounts. By July 1, 1998 or sooner, all customers will
have retail access. Under the URA the local distribution company will retain
the responsibility of providing distribution services to the ultimate
electricity consumer within its franchised service territory. For customers
who choose not to choose, the local distribution company would be allowed to
arrange for supply at a non-discriminatory, "standard offer" price.
Distribution companies will also be providers of last resort, required to
arrange for supply, at prevailing market prices, for customers who are unable
to do so.
Both Blackstone and Newport are currently all requirements customers of
Montaup for generation services. This legislation provides for recovery of
prudently incurred embedded generation costs that may not be to recovered in a
competitive electric generation market, commonly referred to as "stranded
costs", through a non-bypassable transition charge initially set at 2.8 cents
per kWh. The transition charge recovers, among other things, costs of
depreciated generation net of its market value, regulatory assets, nuclear
decommissioning 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 July 1,
1997 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 July 1, 1997
through the life of the respective unit or contract. The URA also provides for
commitments to demand side management initiatives and renewables, low income
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 rate making standards for electric distribution companies. Performance
based regulation provides for a minimum and maximum allowed return on equity.
In addition, the URA provides for adjustments to electric distribution
companies' base rates using the prior year's Consumer Price Index and other
performance factors. Under this provision of the law, base rates were
increased 1.88% for customers of Blackstone, and 2.18% for our Newport
customers effective January 1, 1997.
The implementation of the URA will require approvals from applicable
regulatory agencies, including the Federal Energy Regulatory Commission (FERC),
the Rhode Island Public Utilities Commission (RIPUC), and the Securities and
Exchange Commission (SEC).
In February 1997, Blackstone, Newport and Montaup reached settlement with
the Rhode Island Division of Public Utilities and Carriers (RIDPUC) and the
Rhode Island Attorney General with regards to implementation of a restructuring
plan for Blackstone, Newport and Montaup. In addition to complying with the
URA, the settlement provides for an immediate 10% rate reduction and a
commitment by Montaup to file a plan by July 1, 1997 to divest all of its
generating assets, and is similar in many respects to the settlement negotiated
in Massachusetts, described below.
On December 23, 1996, Eastern Edison and Montaup reached an agreement in
principle with the Attorney General of Massachusetts and the Massachusetts
Division of Energy Resources on 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."
A formal plan is expected to be filed with the Massachusetts Department of
Public Utilities (MDPU) in March of 1997.
The agreement envisions that all of Eastern Edison's customers will have
the ability to choose an alternative supplier of electricity beginning on
January 1, 1998. Until a customer chooses an alternative supplier, that
customer would receive "standard offer" service which would be priced to
guarantee that customer at least a ten percent savings from today's electricity
prices. Eastern Edison would be required to arrange for "standard offer"
service and would purchase power for "standard offer" service from suppliers
through a competitive bidding process. The agreement is also designed to
achieve full divestiture of Montaup's generating assets via implementation of a
plan, to be submitted to the MDPU by July 1, 1997, that would require (1)
separation by Montaup of its generating and transmission businesses and (2)
full market valuation and sale of all generating assets through an auction or
equivalent process, to be conducted by an independent third party.
Upon the commencement of retail choice in Massachusetts, Montaup's
wholesale contract with Eastern Edison would be terminated. In return, the
cost of Montaup's above market, embedded generation commitments to serve
Eastern Edison's customers would be recovered, with a return, through a non-
bypassable transition access charge to all Eastern Edison customers. The
transition access charge would 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.
Embedded costs associated with generating plants and regulatory assets
would be recovered, with a return, over a period of 12 years. Purchased power
contracts and nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond 12 years.
The initial transition access charge would be set at 3.04 cents per kWh through
December 31, 2000, and is expected to decline thereafter.
The agreement also establishes performance-based regulation for Eastern
Edison incorporating a floor and cap on allowed return on equity. Under the
agreement, Eastern Edison's distribution rates would be frozen at 1996 levels
until December 31, 2000. Subsequent to the commencement of retail choice,
Eastern Edison's annual return on equity would be subject to a floor of 6
percent and a ceiling of 11.75 percent.
In addition to MDPU approval of the agreement, implementation is also
subject to the approval of the FERC. Any disposition of generation assets
resulting from the agreement or the URA would also require the approval of the
SEC under the Public Utility Holding Company Act of 1935.
Historically, electric rates have been designed to recover a utility's
full costs 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.
The Company believes that its operations will continue to meet the criteria
established in these accounting standards.
However, the potential exists that the final outcome of state and federal
agency determinations could result in the Company no longer meeting the
criteria of certain accounting standards which could trigger the discontinuance
of Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (FAS71). Should it be required to
discontinue the application of FAS71, the Company would be required to take an
immediate write down of the affected assets in accordance with FAS101,
"Accounting for the Discontinuation of Application of FAS71."
In addition, if legislative or regulatory changes and/or competition
result in electric rates which do not fully recover the 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" (FAS121) issued in March 1995.
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 United States 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, an environmental audit program designed
to ensure compliance with environmental laws and regulations and to identify
and reduce liability was instituted by EUA.
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 generally 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. Eastern Edison and Montaup 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, Eastern Edison and Montaup
are 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, 1996, Eastern Edison and Montaup had incurred costs of
approximately $800,000, in connection with these sites. These amounts have
been financed primarily by internally generated cash. Montaup is currently
recovering certain of its incurred environmental costs in rates.
Eastern Edison and Montaup estimate that additional costs of up to
$130,000 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.
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, Eastern Edison and Montaup do
not believe that the ultimate impact of environmental costs will be material to
their 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. 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." Management cannot
predict the ultimate outcome of the EMF issue.
Nuclear Power Issues
Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw
nuclear unit that is jointly owned by a number of New England utilities,
including subsidiaries of Northeast Utilities (Northeast), the operator of
the plant. On March 30, 1996, Northeast 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 has established 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. Northeast management
has indicated it cannot currently estimate the effect these efforts will have
on the timing of restarts or what additional costs, if any, these developments
may cause.
While Millstone III is out of service, Montaup will incur incremental
replacement power costs estimated at $400,000 to $800,000 per month. Montaup
bills its replacement power costs through its fuel adjustment clause, a
wholesale tariff jurisdictional to FERC. However, there is no comparable
clause in Montaup's FERC-approved rates which at this time would permit Montaup
to recover its share of the incremental O&M costs incurred at Millstone III.
The Company cannot predict the ultimate outcome of the NRC inquiries or
the impact which they may have on Montaup. Montaup is also evaluating its
rights and obligations under the various agreements relating to the ownership
and operation of Millstone III.
Montaup holds a 4.0% ownership interest in the Maine Yankee nuclear unit.
In December, 1996 the unit was shut down for inspections and repairs and in
January 1997 the NRC announced that it had placed the unit on its watch list.
The operator of the unit had been addressing issues of non-conformance to the
unit's licensing basis identified by the NRC in October 1996, prior to the
NRC's January 1997 announcement. The operator of the plant cannot estimate
when the unit will restart.
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 $4.8 million at December 31, 1996.
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. As a
result of the analysis, work at the plant had slowed pending a final board
decision. In December 1996, the Board of Directors 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. Connecticut Yankee has two years to submit its decommissioning
plan to the NRC. The preliminary estimate of the sum of future payments for
the permanent shutdown, decommissioning, and recovery of the remaining
investment in Connecticut Yankee, is approximately $758 million. Montaup's
share of the total estimated costs is $34.1 million at December 31, 1996 and
is included in Other Liabilities on the Consolidated Balance Sheet at December
31, 1996. Also, due to anticipated recoverability, a regulatory asset has been
recorded for the same amount and is included with Other Assets.
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 III and Seabrook I nuclear generating units. Montaup's
share of the currently allowed estimated total costs to decommission Millstone
III is approximately $18.6 million in 1996 dollars and Seabrook I is
approximately $13.1 million in 1996 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.
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 Statement of Income. . . . . . . . . . . . . . . 12
Consolidated Statement of Retained Earnings . . . . . . . . . . . . . . 12
Consolidated Statement of Cash Flow . . . . . . . . . . . . . . . . . . 13
Consolidated Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . 14
Consolidated Statement of Capitalization . . . . . . . . . . . . . . . . 15
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . 16
Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . 31
<TABLE>
Eastern Edison Company and Subsidiary
Consolidated Statement of Income
Years Ended December 31,
(In Thousands)
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Operating Revenues:
From Affiliated Companies $ 127,981 $ 133,388 $ 126,481
Other 276,827 286,681 291,943
Total Operating Revenues 404,808 420,069 418,424
Operating Expenses:
Fuel 92,159 90,881 87,522
Purchased Power - Demand 118,843 125,594 122,995
Other Operation and Maintenance 66,311 73,638 80,300
Affiliated Company Transactions 25,908 23,386 22,446
Voluntary Retirement Incentive 0 2,413
Depreciation and Amortization 26,810 26,039 25,546
Taxes - Other than Income 10,705 10,233 10,543
- Income 16,058 15,653 15,830
Total Operating Expenses 356,794 367,837 365,182
Operating Income 48,014 52,232 53,242
Equity in Earnings of Jointly Owned Companies 1,587 1,646 1,700
Allowance for Other Funds Used During
Construction 365 473 263
Other Income (Deductions) - Net 1,583 407 897
Income Before Interest Charges 51,549 54,758 56,102
Interest Charges:
Interest on Long-Term Debt 15,233 18,277 18,488
Other Interest Expense 3,653 3,541 4,525
Allowance for Borrowed Funds Used During
Construction (Credit) (308) (503) (294)
Net Interest Charges 18,578 21,315 22,719
Net Income 32,971 33,443 33,383
Preferred Dividend Requirements 1,988 1,988 1,988
Consolidated Net Earnings Applicable to
Common Stock $ 30,983 $ 31,455 $ 31,395
</TABLE>
<TABLE>
Consolidated Statement of Retained Earnings
Years Ended December 31,
(In Thousands)
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Retained Earnings - Beginning of Year $ 124,878 $ 105,574 $ 103,515
Net Income 32,971 33,443 33,383
Amortization of Preferred Stock Redemption Premium (817) (961) (596)
Total 157,032 138,056 136,302
Dividends Paid:
Preferred 1,988 1,988 1,988
Common 34,320 11,190 28,740
Retained Earnings - End of Year $ 120,724 $ 124,878 $ 105,574
</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
Eastern Edison Company and Subsidiary
Consolidated Statement of Cash Flows
Years Ended December 31,
(In Thousands)
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 32,971 $ 33,443 $ 33,383
Adjustments to Reconcile Net Income
to Net Cash Provided by Operating Activities:
Depreciation and Amortization 28,607 29,852 28,981
Amortization of Nuclear Fuel 1,676 3,647 3,310
Deferred Taxes 5,217 2,694 5,500
Investment Tax Credit, Net (939) (942) (348)
Allowance for Funds Used During Construction (365) (473) (263)
Other - Net (2,333) 1,219 (3,285)
Changes to Operating Assets and Liabilities:
Accounts Receivable (1,862) (7,055) (7,667)
Fuel, Materials and Supplies 673 (1,678) 194
Accounts Payable 186 827 3,495
Accrued Taxes (241) 1,807 (2,814)
Other - Net 9,266 (6,630) 4,485
Net Cash Provided from Operating Activities 72,856 56,711 64,971
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (26,006) (23,423) (23,613)
Decrease in Other Investments 148
Net Cash (Used in) Investing Activities (25,858) (23,423) (23,613)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (7,000) (35,000)
Premium on Reacquisition and Financing Expenses (62)
Common Stock Dividends Paid (34,320) (11,190) (28,740)
Preferred Dividends Paid (1,988) (1,988) (1,988)
Net (Decrease) Increase in Short Term De (2,118) 4,158
Net Cash (Used in) Financing Activities (45,426) (44,020) (30,790)
Net Increase (Decrease) in Cash
and Temporary Cash Investments 1,572 (10,732) 10,568
Cash and Temporary Cash Investments at
Beginning of Year 533 11,265 697
Cash and Temporary Cash Investments at
End of Year $ 2,105 $ 533 $ 11,265
Cash paid during the year for:
Interest (Net of Amounts Capitalized) $ 15,241 $ 18,343 $ 18,406
Income Taxes $ 13,267 $ 9,044 $ 15,877
</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
Eastern Edison Company and Subsidiary
Consolidated Balance Sheet
December 31,
(In Thousands)
<CAPTION>
ASSETS
1996 1995
<S> <C> <C>
Utility Plant and Other Investments:
Utility Plant $ 817,992 $ 798,706
Less Accumulated Provision for Depreciation 261,464 241,673
Net Utility Plant 556,528 557,033
Non-Utility Property - Net 2,705 2,705
Investment in Jointly Owned Companies 13,210 13,223
Other Investments (at cost) 95 50
Total Utility Plant and Other Investments 572,538 573,011
Current Assets:
Cash and Temporary Cash Investments 2,105 533
Accounts Receivable:
Customers 27,633 25,730
Others 3,464 2,348
Accrued Unbilled Revenue 8,376 9,158
Associated Companies 25,486 25,861
Fuel (at average cost) 6,844 7,385
Plant Materials and Operating Supplies (at average cost) 3,805 3,937
Prepayments and Other Current Assets 3,598 4,170
Total Current Assets 81,311 79,122
Other Assets (Note A) 121,233 87,065
Total Assets $ 775,082 $ 739,198
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity $ 240,213 $ 244,368
Redeemable Preferred Stock - Net 29,665 29,665
Preferred Stock Redempton Cost (2,630) (3,447)
Long-term Debt - Net 222,402 222,313
Total Capitalization 489,650 492,899
Current Liabilities:
Long-term Debt Due Within One Year 0 7,000
Notes Payable 2,040 4,158
Accounts Payable:
Public 27,391 27,242
Associated Companies 3,950 3,913
Customer Deposits 1,153 1,103
Taxes Accrued 2,977 3,219
Interest Accrued 4,895 4,999
Other Current Liabilities 16,081 7,332
Total Current Liabilities 58,487 58,966
Other Liabilities 41,914 10,100
Deferred Credits:
Unamortized Investment Credit 16,903 17,842
Other Deferred Credits 25,689 30,625
Total Deferred Credits 42,592 48,467
Accumulated Deferred Taxes 142,439 128,766
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization $ 775,082 $ 739,198
</TABLE>
The accompanying notes are an integral part of the financial statements.
<TABLE>
Eastern Edison Company and Subsidiary
Consolidated Statement of Capitalization
December 31,
(In Thousands)
<CAPTION>
1996 1995
<S> <C> <C>
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) (43)
Retained Earnings 120,724 124,878
Total Common Equity 240,213 244,368
Redeemable Preferred Stock:
6 5/8%, $100 par value, 300,000 shares <F1> 30,000 30,000
Expense, Net of Premium (335) (335)
Preferred Stock Redemption Cost (2,630) (3,447)
Total Redeemable Preferred Stock 27,035 26,218
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
4.875% due 1996 0 7,000
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 (598) (687)
222,402 229,313
Less Portion Due Within One Year 0 7,000
Total Long-Term Debt 222,402 222,313
Total Capitalization $ 489,650 $ 492,899
<FN>
<F1> Authorized and Outstanding.
</FN>
</TABLE>
The accompanying notes are an integral part of the financial statements.
EASTERN EDISON COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995, and 1994
(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 FERC and the MDPU 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.
Reclassifications: Certain prior period amounts on the financial statements
have been reclassified to conform with current presentation.
Jointly Owned Companies: 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 2.50 to 4.50 percent. Montaup is entitled to
electricity produced from these facilities based on its ownership interests and
is billed for its entitlement pursuant to contractual agreements which are
approved by FERC.
One of the four nuclear generating facilities, Yankee Atomic, is being
decommissioned. Montaup is required to pay, and has received FERC
authorization to recover, its proportionate share of any unrecovered costs and
costs incurred after the plant's retirement. Montaup's share of all
unrecovered assets and the total estimated costs to decommission the unit
aggregated approximately $7.8 million at December 31, 1996 and is included with
Other Liabilities on the Consolidated Balance Sheet. Also, due to
recoverability, a regulatory asset has been recorded for the same amount and is
included with Other Assets.
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 has a 4.5% equity ownership in Connecticut Yankee. Montaup's
share of all unrecovered assets and the total estimated costs to decommission
the unit aggregated approximately $34.1 million at December 31, 1996 and is
included with Other Liabilities on the Consolidated Balance Sheet. Also, due
to anticipated recoverability, a regulatory asset has been recorded for the
same amount and is included with Other Assets.
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 four 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 $127,536,000 in 1996, $133,841,000 in 1995 and $126,237,000 in
1994; accounting, engineering and other services rendered by EUA Service
Corporation to Eastern Edison and Montaup of approximately $30,886,000,
$29,264,000, and $27,365,000, in 1996, 1995 and 1994, respectively; and
operating expense from the rental of transmission and generation facilities by
Blackstone and Newport to Montaup aggregating approximately $3,960,000 in
1996, $4,351,000 in 1995 and $3,627,000 in 1994. Montaup rental of
transmission facilities to Newport was zero in 1996 and 1995, and $149,000 for
1994, respectively. 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 1996, 1995 and 1994 based on the average depreciable
property balances at the beginning and end of each year.
Electric Plant Held for Future Use: In January 1994 Montaup determined that
it would not be economically feasible to bring its 42-year old, coal-fired
Somerset Station Unit 5 generating unit into compliance with Clean Air Act
Amendments of 1990 (Clean Air Act). The unit was placed in cold storage and
its net investment, $5.4 million, was transferred to electric plant held for
future use pending final determination by Montaup of its usefulness. Under
terms of the settlement agreement filed with FERC, entered into by Montaup and
the intervenors in Montaup's 1994 rate decrease application, Montaup continues
to earn a return on the net investment of the unit.
Other Assets: The components of Other Assets at December 31, 1996 and 1995
are detailed as follows:
(In Thousands) 1996 1995
Regulatory Assets:
Unamortized losses on
reacquired debt $13,277 $14,981
Unrecovered plant and
decommissioning cost 41,914 10,100
Deferred SFAS 109 costs (Note B) 47,326 44,387
Deferred SFAS 106 costs (Note J) 2,153 2,365
Other regulatory assets 4,886 4,790
Total regulatory assets 109,556 76,623
Other deferred charges and assets:
Unamortized debt expenses 2,456 2,847
Other 9,221 7,595
Total Other Assets $121,233 $87,065
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. Eastern
Edison and Montaup believe that their operations continue to meet the criteria
established in these accounting standards. Effects of legislation and/or
regulatory initiatives or EUA's own initiatives could ultimately cause Eastern
Edison and Montaup to no longer follow these accounting rules. In such
an event, a non-cash write-off of regulatory assets and liabilities could be
required at that time.
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 8.9% in 1996, 9.4% in 1995 and 9.6%
in 1994.
Operating Revenues: Revenues are based on billing rates authorized by
applicable federal and state regulatory commissions. Eastern Edison 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. Montaup recognizes revenues when billed. In addition, Eastern
Edison and Montaup also record the difference between fuel costs incurred and
fuel costs billed. Montaup also records the difference between purchased power
costs incurred and billed.
(A) Nature of Operations and Summary of Significant Accounting Policies:
(continued)
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.
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 1996, 1995,
and 1994 are as follows:
___________________________________________________________________
(In Thousands) 1996 1995 1994
Federal:
Current $9,111 $11,387 $ 9,143
Deferred 5,152 3,679 4,697
Investment Tax Credit, Net (939) (942) (348)
$13,324 $14,124 $13,492
State:
Current 2,612 2,447 1,468
Deferred 122 (918) 870
2,734 1,529 2,338
Charged to Operations 16,058 15,653 15,830
Charged to Other Income:
Current 1,233 522 617
Deferred (67) (67) (67)
Total $17,224 $16,108 $16,380
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) 1996 1995 1994
Federal Income Tax Computed
at Statutory Rates $17,568 $17,343 $17,417
(Decreases) Increases in Tax from:
Equity Component of AFUDC (128) (165) (92)
Consolidated Tax Savings (156) (108) (651)
Depreciation Differences (452) (264) (321)
Amortization and Utilization
of ITC (939) (942) (945)
State Taxes, Net of Federal
Income Tax Benefit 1,897 (2,625) 1,614
Cost of Removal 58 (226)
Other (566) 2,811 (416)
Total Income Tax Expense $17,224 $16,108 $16,380
(B) Income Taxes (continued)
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, 1996 and 1995
are comprised as follows:
Deferred Tax Deferred Tax
Assets Liabilities
($000) ($000)
1996 1995 1996 1995
Plant Related Plant Related
Differences $13,490 $16,181 Differences $153,471 $146,632
Alternative Refinancing
Minimum Tax 412 4,470 Costs 1,471 1,691
Pensions 1,299 1,070 Pensions 877 940
Other 1,040 1,060 Other 2,507 1,901
Total 16,241 $22,781 Total $158,326 $151,164
As of December 31, 1996 and 1995, the Company had recorded on its
Consolidated Balance Sheet a regulatory liability to ratepayers of
approximately $18.0 million and $23.6 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, 1996 and 1995, a
regulatory asset of approximately $47.3 million and $44.4 million,
respectively, has been recorded, representing the cumulative amount of federal
income taxes on temporary depreciation differences which were previously flowed
through to ratepayers.
Montaup has approximately $0.4 million, respectively, of alternative
minimum tax credits which can be utilized to reduce the EUA System's
consolidated regular tax liability and have no expiration.
(C) Capital Stock:
There were no changes in the number of shares of common or preferred stock
during the years ended December 31, 1996, 1995 and 1994.
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, 1996, 1995 and 1994, 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
$117,385,954 as of December 31, 1996 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.
In September, Eastern Edison used available cash to redeem $7 million of
4.875% First Mortgage Bonds at maturity.
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 1996 are:
none in 1997, $60 million in 1998, and none in 1999, 2000 and 2001.
(G) Lines of Credit:
EUA System companies including Eastern Edison maintain short-term lines of
credit with various banks aggregating approximately $140 million. At December
31, 1996, unused short-term lines of credit were approximately $89 million.
These credit lines are available to other EUA System companies under joint
credit line arrangements. In accordance with informal agreements with the
various banks, commitment fees are required to maintain certain lines of
credit. During 1996, the weighted average interest rate for short-term
borrowings by the Company was 5.6%.
(H) Jointly Owned Facilities:
At December 31, 1996, in addition to the stock ownership interests
discussed in Note A, Summary of Significant Accounting Policies - Jointly
Owned Companies, Montaup had direct ownership interests in the following
electric generating facilities (In Thousands):
Accumulated
Provision For Net Construc-
Utility Depreciation Utility tion
Percent Plant in and Plant in Work in
($ In Thousands) Owned Service Amortization Service Progress
Montaup:
Canal 2 50.00% $ 83,194 $41,843 $ 41,351 $446
Wyman 4 1.96% 4,051 2,130 1,921
Seabrook I 2.90% 194,928 29,983 164,945 251
Millstone III 4.01% 178,854 49,560 129,294 170
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, 1996,
Montaup's total net investment in nuclear fuel of the Seabrook and Millstone
units amounted to $2.8 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, 1996 are as follows (In Thousands):
Carrying Fair
Amount Value
Cash and Temporary Cash Investments $ 2,105 $ 2,105
Redeemable Preferred Stock 30,000 30,300
Long-Term Debt $223,000 $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. Montaup owns a 4.01%
interest in Millstone III and a 2.9% interest in Seabrook I. Northeast
Utilities, the operator of the units, indicates that Millstone III 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 III and Seabrook I. Montaup's share of
the current estimate of total costs to decommission Millstone III is $18.6
million in 1996 dollars, and Seabrook I is $13.1 million in 1996 dollars.
These figures are based on studies performed for the lead owner of the units.
Montaup also pays into decommissioning reserves pursuant to contractual
arrangements with other nuclear generating facilities in which it has an
equity ownership interest or life of the unit entitlement. Such expenses are
currently recoverable through rates.
Pensions: Eastern Edison and Montaup participate with the other EUA System
companies in a non-contributory defined benefit pension plan covering
substantially all of their employees (Retirement Plan). Retirement Plan
benefits are based on years of service and average compensation over the four
years prior to retirement. It is the EUA System's policy to fund the
Retirement Plan on a current basis in amounts determined to meet the funding
standards established by the Employee Retirement Income Security Act of 1974.
Total pension (income) expense for the Retirement Plan, including amounts
related to the 1995 Voluntary Retirement Incentive Offer, for 1996, 1995 and
1994 includes the following components ($ In Thousands):
1996 1995 1994
Service cost - benefits earned during
the period $ 1,713 $ 1,504 $ 1,783
Interest cost on projected benefit
obligation 5,767 5,575 5,217
Actual (return) loss on assets (10,036) (22,158) 927
Net amortization and deferrals 2,407 14,855 (7,677)
Net periodic pension (income) expense $ (149) $ (224) $ 250
Voluntary retirement incentive 857
Total periodic pension (income) expense $ (149) $ 633 $ 250
Assumptions used to determine pension cost:
1996 1995 1994
Discount Rate 7.25% 8.25% 7.25%
Compensation Increase Rate 4.25% 4.75% 4.75%
Long-Term Return on Assets 9.50% 9.50% 9.50%
The discount rate used to determine pension obligations was changed
effective January 1, 1997 to 7.5%. 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 one-time voluntary retirement incentive also resulted in approximately
$800,000 of non-qualified pension benefits which were expensed in 1995. At
December 31, 1996, approximately $424,000 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, 1996, 1995 and 1994 Eastern Edison's and
Montaup's expenses related to the Supplemental Plan were approximately
$717,000, $825,000 and $266,000, 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 $306,000 in
1996, approximately $369,000 in 1995 and approximately $ 431,000 in 1994.
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 $3.6 million in 1996, $4.0 million in 1995, and
$3.4 million in 1994.
The total cost of Post-Retirement Benefits other than Pensions,
including amounts related to the 1995 Voluntary Retirement Incentive Offer,
for 1996, 1995 and 1994 includes the following components (In Thousands):
1996 1995 1994
Service cost $ 637 $ 565 $ 880
Interest cost 2,688 2,926 3,252
Actual return on plan assets (115) (388) (75)
Amortization of transition obligation 1,955 1,965 2,026
Net other amortization & deferrals (721) (632) (50)
Net periodic post-retirement benefit costs 4,444 4,436 6,033
Voluntary retirement incentive 470
Total post-retirement benefit costs $4,444 $ 4,906 $ 6,033
Assumptions:
Discount rate 7.25% 8.25% 7.25%
Health care cost trend rate-near-term 9.00% 11.00% 13.00%
-long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.75% 4.75%
Rate of return on plan assets-union 8.50% 8.50% 8.50%
- non-union 7.50% 5.50% 5.50%
<TABLE>
Reconciliation of funded status:
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
(In Thousands)
Accumulated post-retirement benefit obligation (APBO):
Retirees ($19,864) $(23,223) $(20,227)
Active employee fully eligible for benefits (1,728) (3,649) (4,116)
Other active employees (6,031) (7,711) (9,255)
Total (27,623) (34,583) (33,598)
Fair Value of assets (primarily notes and bonds) 5,161 3,830 2,169
Unrecognized transition obligation 26,095 27,726 30,007
Unrecognized net (gain) loss (9,297) (2,142) (3,158)
(Accrued) prepaid post-retirement benefit cost $5,664 $ (5,169) $ (4,580)
</TABLE>
The discount rate and compensation increase rates used to determine post-
retirement benefit obligations effective January 1, 1997, are 7.5% and 4.25%,
and were used to calculate the funded status of Post-Retirement Benefits at
December 31, 1996.
Increasing the assumed health care cost trend rate by 1% each year would
increase the total post-retirement benefit cost for 1996 by approximately
$311,000 and increase the total accumulated post-retirement benefit obligation
by approximately $3.0 million.
Eastern Edison and Montaup have also established an irrevocable external
Voluntary Employees' Beneficiary Association (VEBA) Trust Fund as required by
the aforementioned regulatory decisions. Contributions to the VEBA fund
commenced in March 1993 and contributions were made totaling approximately $2.9
million in 1996, $3.2 million in 1995, and $2.9 million during 1994,
respectively.
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, 1996, the aggregate annual minimum commitments for such contracts
are approximately $122 million in 1997, $116 million in 1998, $114 million in
1999, $111 million in 2000, $111 million in 2001, 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. Eastern
Edison and Montaup 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 Eastern Edison and Montaup 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 carrier
in these matters.
As of December 31, 1996, Eastern Edison and Montaup have incurred costs of
approximately $800,000 in connection with the foregoing environmental matters
and estimate that additional expenditures may be incurred through 1997 up to
$130,000.
As a general matter Eastern Edison and Montaup will seek to recover costs
relating to environmental proceedings in their rates. Montaup is currently
recovering certain of the incurred costs in its 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, Eastern Edison and Montaup do not believe that the ultimate impact of
the environmental costs will be material to their financial position and thus,
no loss provision is required at this time.
The Clean Air Act Amendments of 1990 (Clean Air Act) created new
regulatory programs and generally updated and strengthened air pollution
control laws. These amendments will expand the regulatory role of the EPA
regarding emissions from electric generating facilities and a host of
other sources. Montaup generating facilities were first affected in 1995,
when EPA regulations took effect for facilities owned by Montaup. Montaup's
coal-fired Somerset Unit No. 6 is utilizing lower sulfur content coal to meet
the 1995 air standards. Eastern Edison does not anticipate the impact from the
Amendments to be material to its financial position.
In November of 1996, the EPA proposed to toughen the nation's ozone
standards as well as the particulate matters standards. The effect that such
rules will have on the EUA System cannot be determined by management at this
time.
On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney
General and Division of Energy Resources reached a settlement in principle
regarding electric utility industry restructuring in the State of
Massachusetts. The proposed 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
sulfur dioxide (SO2) and nitrogen oxide (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
proposed settlement is expected to be filed with MDPU in March 1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight Northeast states including
Massachusett 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 Amendments. The NESCAUM recommendations are more
restrictive than 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 per year or more of NOx. Rhode Island has also
issued similar regulations requiring that RACT be implemented at all
stationary sources potentially emitting 50 tons or more per year of NOx.
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 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. 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 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 $4.8 million of the outstanding debt of these two companies. In
addition, Montaup has a minimum rental commitment which totals approximately
$12.7 million under a noncancellable transmission facilities support agreement
for years subsequent to 1996.
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 is $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, and EUA is consulting with those
insurers to determine the availability and extent of coverage. EUA cannot
predict the ultimate outcome of this matter at this time.
Report of Independent Accountants
To the Directors and Shareholder of
Eastern Edison Company and Subsidiary:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Eastern Edison Company and its subsidiary (the
Company) as of December 31, 1996 and 1995, and the related consolidated
statement of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1996. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of the Company as of December 31,
1996 and 1995, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
/s/Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 5, 1997
Exhibit 23-1.03
Consent of Independent Accountants
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 5, 1997, on our audits of the
consolidated financial statements and financial statement schedule of Eastern
Utilities Associates and subsidiaries as of December 31, 1996 and 1995, and for
the years ended December 31, 1996, 1995 and 1994, which reports are
incorporated by reference or included in this Annual Report on Form 10-K.
/s/Coopers & Lybrand L.L.P.
Boston, Massachusetts
March 17, 1997
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