Dear Shareholder,
In light of our imminent merger with New England Electric System (NEES), this
is Eastern Utilities Associates' (EUA) final Annual Report to Shareholders,
management's report to you outlining our stewardship of your investment.
Our plans for the future of EUA are simple and were announced on February 1,
1999. We are merging into New England Electric System (NEES), a much larger
entity, as soon as all regulatory approvals are received. As of this writing,
we anticipate receiving final approval and completing the merger very close to
the time you will be receiving this report. Since November 17, 1999, the
amount you will receive for your EUA shares has increased by $0.003 per share
per day. As of March 31, 2000, the price you would receive was $31.405. A
detailed discussion of what has transpired in the past year is included in the
Annual Report on Form 10K to the Securities and Exchange Commission that is
included with this letter.
In summary . . .
Since the merger was announced, activity has been nearly non-stop to ensure a
smooth transition of EUA and its electric utilities into NEES and its
utilities. A number of steps have been taken to merge the operational aspects
of the two Systems. Staffing decisions are underway, and several EUA
employees are included in the mix of executives and managers who will play a
critical role in the new company.
Savings are expected to come from elimination of redundant positions when the
merger is completed. A special voluntary early retirement program was accepted
by 175 EUA employees and 37 at NEES; another 127 EUA employees took advantage
of a voluntary severance package. This enabled Richard P. Sergel, NEES Chief
Executive Officer, to announce in early February 2000 that all NEES and EUA
employees who have chosen to go forward with the merged entity will have
positions offered to them.
Customers of the EUA and NEES retail electric utilities in Massachusetts and
Rhode Island will save from the merger. The consolidated rates planned when
our Blackstone Valley and Newport Electric utilities merge into NEES's
Narragansett Electric will save Rhode Island customers approximately $100
million through 2004. A negotiated settlement awaits approval by the Rhode
Island Public Utilities Commission. In Massachusetts, customers of our
Eastern Edison and NEES's Massachusetts Electric subsidiaries should save more
than $170 million in the next 10 years based on a settlement filed with the
Massachusetts Department of Telecommunications and Energy and now awaiting
that agency's approval.
In addition to the merger activity, we are pleased to note that EUA continued
to deliver electric service at the high levels of reliability, safety and
customer satisfaction for which we have been known. Our year-long customer
survey showed a customer satisfaction level of 84% -- higher than our
neighboring utilities.
During the year, we also reduced our non electric utility business
activities. EUA Cogenex, our energy management subsidiary, divested itself of
its EUA Day division. EUA Energy Investment ended its BIOTEN, EUA
TransCapacity and Renova involvement. Along with these actions, our Montaup
generation and transmission subsidiary, divested itself of its entire
generation portfolio, except for a small portion of the Millstone 3 generating
unit in Connecticut, as required under electric utility deregulation
legislation in Massachusetts and Rhode Island.
The value of EUA is in its people. We have maximized that value for you, our
shareholders, by creating one of the most efficient and lowest cost
electricity providers in the region. With the completion of the merger, this
dedicated team will be going in different directions -- many to New England
Electric System, some to new careers, and some to retirement. No matter what
direction these people go, they will know that they are going at the top of
their game.
It truly has been our privilege to serve you.
/s/ Donald G. Pardus /s/ John R. Stevens
Donald G. Pardus John R. Stevens
Chairman and Chief Executive Officer President and Chief Operating Officer
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, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-5366
Eastern Utilities Associates
(Exact name of registrant as specified in its charter)
Massachusetts 04-1271872
(State or other jurisdication (I.R.S Employer
Incorporation or organization) Identification No.)
750 W. Center Street
West Bridgewater, Massachusetts 02379
(Address of principal executive offices) (Zip Code)
Registrant's telephone number: (508) 559-1000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class: Name of each Exchange on
Common Shares, par value $5 per share which registered:
New York Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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 20, 2000:
Common Shares, $5 par value - $639,902,156
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Common Shares Outstanding at March 20, 2000: 20,435,997
Documents Incorporated by Reference: None
EASTERN UTILITIES ASSOCIATES
1999 Annual Report on Form 10-K
Table of Contents
Table of Contents. . . . . . . . . . . . . . . . . . . . . . . .I
GLOSSARY OF DEFINED TERMS. . . . . . . . . . . . . . . . . . . IV
PART I
Item 1. BUSINESS. . . . . . . . . . . . . . . . . . . . .1
Merger Update . . . . . . . . . . . . . . . . . . . . . . .1
System Overview . . . . . . . . . . . . . . . . . . . . . .2
General - Core Electric Business. . . . . . . . . . . . . .2
Electric Utility Industry Restructuring . . . . . . . . . .5
Generation Divestiture . . . . . . . . . . . . . . . . .6
General - EUA Cogenex . . . . . . . . . . . . . . . . . . 7
General - EUA Energy Investment . . . . . . . . . . . . . 10
Capital Requirements . . . . . . . . . . . . . . . . . . 10
Fuel for Generation . . . . . . . . . . . . . . . . . . . 11
Nuclear Power Issues . . . . . . . . . . . . . . . . . . 13
General . . . . . . . . . . . . . . . . . . . . . . . . 13
Decommissioning . . . . . . . . . . . . . . . . . . . . 14
Millstone 3 . . . . . . . . . . . . . . . . . . . . . . 14
Connecticut Yankee. . . . . . . . . . . . . . . . . . . 15
Maine Yankee . . . . . . . . . . . . . . . . . . . . 16
NRC Oversight . . . . . . . . . . . . . . . . . . . . . 17
Public Utility Regulation . . . . . . . . . . . . . . . . 17
Rates . . . . . . . . . . . . . . . . . . . . . . . . . 18
FERC Proceedings - Transmission . . . . . . . . . . . . 19
FERC Proceedings - Supply . . . . . . . . . . . . . . . 19
Rhode Island Proceedings . . . . . . . . . . . . . . . 20
Massachusetts Proceedings . . . . . . . . . . . . . . . 23
Environmental Regulation . . . . . . . . . . . . . . . . 25
General . . . . . . . . . . . . . . . . . . . . . . . . 25
Preconstruction Reviews . . . . . . . . . . . . . . . . 25
Solid and Hazardous Waste Regulation. . . . . . . . . . 25
Superfund Requirements. . . . . . . . . . . . . . . . . 26
Chemical Regulation . . . . . . . . . . . . . . . . . . 26
Potential Regulation of Electric and Magnetic Fields. . 26
Water Regulation. . . . . . . . . . . . . . . . . . . . 26
Permit Transfers . . . . . . . . . . . . . . . . . . . 27
Other Requirements. . . . . . . . . . . . . . . . . . . 27
Environmental Regulation of Nuclear Power . . . . . . . . 27
The Year 2000 Issue . . . . . . . . . . . . . . . . . . . 28
EUA's State of Readiness . . . . . . . . . . . . . . . 28
Costs to Address EUA's Year 2000 Issues . . . . . . . . 29
Risks of EUA's Year 2000 Issues . . . . . . . . . . . . 30
Year 2000 Contingency Plans . . . . . . . . . . . . . . 30
Summary of the Year 2000 Issue. . . . . . . . . . . . . 31
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Item 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . 31
Power Supply . . . . . . . . . . . . . . . . . . . . . . 31
Other Property. . . . . . . . . . . . . . . . . . . . . . 33
Item 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . 33
Rate Proceeding . . . . . . . . . . . . . . . . . . . . . 33
Environmental Proceedings . . . . . . . . . . . . . . . . 33
Other Proceedings . . . . . . . . . . . . . . . . . . . . 37
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.. 38
PART II
Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS . . . . . . . . . . . . . . . . . . . . . . . . 39
Item 6. SELECTED FINANCIAL DATA. . . . . . . . . . . . . . 40
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS . . . . . . . . . . . . . 41
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . 57
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURES. . . . . . . . 86
Table of Contents (Cont'd)
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS 86
Item 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . 89
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT ........................... . . . . . . 96
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . 97
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K. . . . . . . . . . . . . . . . . . . . . . 97
(a)(1) Financial Statements . . . . . . . . . . . . . . . 97
(a)(2) Financial Statement Schedules . . . . . . . . . . 97
(a)(3) Exhibits (*denotes filed herewith).. . . . . . . . 98
(b) Reports on Form 8-K. . . . . . . . . . . . . . . . .109
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . .110
Report of Independent Accountants. . . . . . . . . . . . . . .114
Consent of Independent Accountants . . . . . . . . . . . . . .115
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 BIOTEN EUA BIOTEN Inc.
EUA Cogenex EUA Cogenex Corporation
EUA Day EUA Day Company, a division of EUA Cogenex
EUA Ocean State EUA Ocean State Corporation
EUA Service EUA Service Corporation
EUA Energy EUA Energy Investment Corporation
EUA Energy Services EUA Energy Services Corporation
EUA Telecommunications EUA Telecommunications Corporation
EUA TransCapacity EUA TransCapacity, Inc.
Montaup Montaup Electric Company
Newport Newport Electric Corporation
Renova Renova LLC (formerly EUA Nova)
Retail Subsidiaries Blackstone, Eastern Edison and Newport
Non-Affiliated Companies
Connecticut Yankee Connecticut Yankee Atomic Power Company
Maine Yankee Maine Yankee Atomic Power Company
MECO Massachusetts Electric Company, a subsidiary of
New England Electric System
NEES New England Electric System
Narragansett Narragansett Electric Company, a subsidiary of
New England Electric System
OSP Ocean State Power Project Units 1 and 2
Vermont Yankee Vermont Yankee Power Corporation
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
CERCLIS Comprehensive Environmental Response,
Compensation and Liability Information System
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
DOE Department of Energy
DTE Massachusetts Department of Telecommunications
and Energy (formerly Massachusetts Department
of Public Utilities)
Energy Policy Act Energy Policy Act of 1992
EPA Federal Environmental Protection Agency
FERC Federal Energy Regulatory Commission
IRS Internal Revenue Service
MADEP Massachusetts Department of Environmental
Protection
MADOER Massachusetts Department of Energy Resources
NRC Nuclear Regulatory Commission
NWPA Nuclear Waste Policy Act
Price-Anderson Act The Price-Anderson Act, as amended by the
Price-Anderson Amendments of 1988
PURPA Public Utility Regulatory Policies Act
of 1978
RIDEM Rhode Island Department of Environmental
Management
RIDIV Rhode Island Division of Public Utilities
and Carriers
RIPUC Rhode Island Public Utilities Commission
SEC Securities and Exchange Commission
TSCA Toxic Substances Control Act
Other
CTC Contract Termination Charge
DSM Demand Side Management
EMF Electric and Magnetic Fields
EWG Exempt Wholesale Generator
IDIQ Indefinite Delivery and Indefinite
Quantity Contract
IPP Independent Power Producer
kv Kilovolt
kWh Kilowatthour
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
Merger Update
On February 1, 1999, Eastern Utilities Associates (EUA) and New England
Electric System (NEES) announced a merger agreement under which NEES will
acquire all outstanding shares of EUA for $31 per share in cash. The merger
agreement, which is subject to the approval of various regulatory agencies,
valued EUA's equity at approximately $634 million, which represents a 23%
premium above the price of EUA shares on December 4, 1998, the last trading day
before other regional merger announcements affected EUA's share price. EUA
shareholders will continue to receive dividends at the current level, as
declared by the Board of Trustees, until the closing of the merger.
The closing of the merger is expected to occur by April 2000, after SEC
approval is received. The merger agreement contains an upward price adjustment
if the merger does not close within six months from May 17, 1999, the date EUA
shareholders approved the merger plan. Therefore, since November 17, 1999,
NEES will pay an additional $0.003 per day per share for EUA's outstanding
common stock until the merger closes, up to a maximum price of $31.495 per
share. If the merger were to close by March 31, 2000, the price paid for EUA
shares would be $31.405 per share.
On May 5, 1999, EUA and NEES filed a joint application with FERC seeking
FERC approval and related waivers or authorizations to merge EUA and NEES and
to subsequently merge and consolidate the complimentary operating companies of
EUA and NEES. With its approval on September 29, 1999, FERC concluded that the
proposed merger will not adversely affect competition, rates or regulation, and
that the merger is in the public's best interest.
On May 20, 1999, EUA and NEES jointly filed a rate consolidation plan with
the Rhode Island Public Utilities Commission reflecting consolidated rates for
each company's Rhode Island subsidiaries, indicating savings to Rhode Island
customers of an estimated $100 million through 2004. A settlement agreement
was reached on January 26, 2000. A similar filing was made for EUA's and
NEES's Massachusetts subsidiaries on April 30, 1999 with the Massachusetts
Department of Telecommunications and Energy (DTE) indicating savings of over
$170 million over the next ten years. A settlement agreement was reached on
the Massachusetts filing on November 29, 1999. Hearings on both settlements
were completed in February 2000. An order approving the settlement agreement
in Massachusetts was received from the DTE on March 15, 2000. An order
approving the Rhode Island settlement agreement is expected to be issued close
to the time of the issuance of this report.
On July 19, 1999, a Voluntary Early Retirement Program (VERP) was offered
to certain of EUA's and NEES's employees who have completed at least ten years
of service and will be at least fifty-five years of age by December 31, 2000.
The VERP allows an eligible employee to retire and receive enhanced pension
benefits. The VERP offer was accepted by 82% of eligible employees.
An eligible employee may only retire after the merger closes under the VERP.
On October 12, 1999, details of a Severance Plan were distributed. The
Severance Plan will provide benefits and provisions for eligible non-union
employees who are involuntarily terminated due to the merger. At the same
time, the Company also offered a Limited Hardship Early Decision Severance Plan
(LHEDO) to designated non-union employees who choose to terminate their
employment with EUA rather than be considered for a position in the merged
company. Under the LHEDO, employees will receive an additional eight weeks of
severance pay for accepting the offer. Forty-three percent of the eligible
employees have accepted the LHEDO. Because the VERP and LHEDO are contingent
on the completion of the merger, which is subject to regulatory approvals, a
liability for expenses related to the VERP and LHEDO has not yet been recorded.
On February 25, 2000 the Nuclear Regulatory Commission (NRC) approved the
merger. This approval was necessary because of Montaup's ownership interest in
the Millstone 3 and Vermont Yankee nuclear generating units. Montaup also has
ownership interests in the Connecticut Yankee, Maine Yankee, and Yankee Atomic
units which are permanently retired.
System Overview
EUA 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. EUA owns directly all of the shares of
common stock of three retail companies: Blackstone, Eastern Edison, and
Newport. Blackstone operates in northern Rhode Island, Eastern Edison operates
in southeastern Massachusetts, and Newport operates in south coastal Rhode
Island. These subsidiaries are collectively referred to as the Retail
Subsidiaries. EUA also owns directly all of the shares of common stock of EUA
Cogenex, EUA Energy, EUA Ocean State, EUA Service and Montaup. Montaup is a
generation and transmission company. (See Item 2. PROPERTIES -Power Supply.)
See Financial Condition and Liquidity in Item 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND REVIEW OF OPERATIONS for a discussion of
Eastern Edison's transfer of its wholly-owned Montaup securities to EUA in
February 2000, making Montaup a direct subsidiary of EUA. 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. The holding company
system of EUA, the Retail Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA
Energy and EUA Ocean State is referred to as the EUA System. The EUA System is
organized into a business unit structure. The Core Electric Business consists
of the Retail Subsidiaries and Montaup. (See Electric Utility Industry
Restructuring for a discussion of changes taking place in the utility industry
in the territories served by EUA's Core Electric Business.) The Energy Related
Business includes EUA Cogenex, EUA Energy and EUA Ocean State. EUA
Telecommunications and EUA Energy Services, which were included in the Energy
Related Business, were dissolved in 1999. The Corporate Business consists of
EUA and EUA Service. See Note I of Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA for financial information by business segment.
General - Core Electric Business
As of December 31, 1999, core electric and corporate business units had 839
regular employees. Labor bargaining unit contracts covering approximately 64
employees of Eastern Edison in the Fall River area, and 49 employees of Newport
expire in May 2001 and March 2002, respectively. A newly formed labor unit
covers approximately 107 employees of Eastern Edison in the Brockton area. A
contract is currently being negotiated. 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 597 square miles and has an
estimated population of approximately 737,000. At December 31, 1999, Core
Electric Business served approximately 309,000 retail customers.
The Core Electric Business accounted for approximately 90% of total operating
revenues of the EUA System in 1999, and 89% in 1998 and 1997. The remaining
balance of operating revenues during these periods were primarily attributable
to EUA Cogenex.
In 1999, through divestiture and competitive bidding, Montaup assigned 100%
of its standard offer service obligations to alternate suppliers. (See
Electric Utility Restructuring below.) A majority of the standard offer
assignments became effective on January 1, 1999, and the remainder became
effective on September 1, 1999. In addition, Montaup served Eastern Edison's
default service requirements and Blackstone's and Newport's last resort service
requirements.
Through September 1, 1999, Montaup provided its share of the standard offer
requirements using its entitlement in the Seabrook Station and from its long-
term power contracts in the Canal Unit 1, Northeast Energy Associates, McNeil
and the Hydro Quebec Project. On September 1, 1999, Montaup's remaining share
of standard offer and its long-term power contracts in the above referenced
facilities were assigned to Constellation Power Sources Inc., see Generation
Divestiture below.
On December 1, 1999, Eastern Edison's default service requirements were
assigned to an alternate supplier through its competitive bidding process.
Montaup continues to serve Blackstone's and Newport's last resort service
requirements using short-term purchases from NEPOOL and the bilateral markets.
Consistent with Electric Utility Industry Restructuring legislation passed
in Rhode Island and Massachusetts and settlement agreements approved by
regulators in those states and at FERC, Montaup agreed to sell its generating
assets and substantially completed the divestiture process in 1999. (See
"Divestiture" under Electric Utility Industry Restructuring for further
discussion of the divestiture process.)
The Retail Subsidiaries and Montaup hold valid franchises, permits and
other rights which are necessary to allow these companies to conduct electric
business within the territories which they serve. Such franchises, permits and
other rights contain no unduly burdensome restrictions or limitations upon
duration. Section 312 of the Massachusetts Electric Industry Restructuring Act
signed into law on November 25, 1997 directs the DTE in conjunction with the
Massachusetts Department of Energy Resources (MADOER) to commence, no sooner
than January 1, 2000, an investigation and review of the manner in which
metering, billing and information services (MBIS) are provided and the
exclusivity of electric distribution service territories. In the event that
the DTE determines that such services should be subject to competition or that
territorial exclusivity shall be terminated or altered in any manner, the DTE
shall, by no later than January 1, 2001, file its recommendations, along with
drafts of legislation necessary to implement said recommendations, with the
Clerk of the Massachusetts House of Representatives. Any unbundling and
creation of competition of such services shall not commence unless statutorily
authorized.
The EUA System's electric sales are seasonal to some extent due to
electricity usage for heating and lighting in the winter and air conditioning
in the summer. The EUA System is not dependent on a single customer or a few
customers for its electric sales.
There is no competition from other electric distribution utilities within
the retail territories served by the Retail Subsidiaries at this time.
The electric generation, or supply, function is now a competitive industry
in Rhode Island and Massachusetts, and initiatives nationwide are considering
adopting similar principles. Recently announced sales of generating portfolios
by regional utility companies, including Montaup, should generate a more robust
energy market in the regions served by EUA's Core Electric Business as new
supply entrants vie for customers. Montaup faces competition from these new
suppliers as well as existing suppliers and marketers in selling the output of
its remaining generating capacity.
Competition in the generation sector has been developing for over two
decades, enabled and encouraged by federal and state initiatives. PURPA was
intended, among other things, to promote national energy independence and
diversification of energy supply and to improve the overall efficiency of
energy usage. PURPA created a class of non-utility power generation facilities
called qualifying facilities or QFs. PURPA currently allows QFs to sell power
generated by the QFs to local utilities at specified rates based on each
utility's avoided cost. In order to further promote competition in energy
supply, the Energy Policy Act established another class of non-utility
generators, referred to as EWGs, which are exempt from the 1935 Act. EWGs and
another class of non-utility wholesale generators, generally known as
independent power producers or IPPs, are subject to FERC regulations under the
Federal Power Act as well as various other federal, state, and local
regulations. The Energy Policy Act also increased FERC's power to order
transmission access, resulting in FERC's open access transmission order and
Regional Transmission Group Policy. As a complement to the federal
initiatives, the DTE and the RIPUC implemented regulations in the
1980's and early 1990's which require utilities to integrate least-cost
planning with competitive proposals to meet requirements for new generation.
Both states also approved in 1993 a Memorandum of Understanding among Montaup
and the Retail Subsidiaries that establishes a framework which makes possible a
coordinated, regional review of the resource planning and procurement process
of the EUA System Companies. (See Electric Utility Industry Restructuring
and Public Utility Regulation below).
NEPOOL is a voluntary organization open to any person engaged in the
electric business such as investor-owned utilities, generators, municipals,
cooperative utilities, power marketers, brokers and load aggregators.
On April 6, 1999, the FERC issued an order approving NEPOOL restructured
market rules. On May 1, 1999, the markets for Operable Capability, Energy,
Automatic Generation Control, and Operating Reserves were implemented in
addition to the Installed Capability Market, which was previously implemented
in April 1998.
On December 30, 1999, the NEPOOL Participants Committee submitted an
informational filing to the FERC identifying the status of its efforts to
develop a Congestion Managements System (CMS) and a Multi-Settlement System
(MSS), including an informational "Compromise" CMS/MSS Proposal. The
submission also included amendments to the Restated NEPOOL Agreement and
NEPOOL Tariff which address how the markets and congestion matters are proposed
to be treated during the interim period between now and implementation of an
acceptable CMS/MSS proposal. Those amendments extend through February 29,
2000, the current treatment for socializing congestion costs within NEPOOL and
eliminate the Operable Capability market as of March 1, 2000. The intent is
for NEPOOL to file further amendments to the NEPOOL arrangements in early
2000 which would be consistent with the understandings in the Compromise
Proposal regarding how congestion costs will be allocated after March 1, 2000.
The Compromise Proposal will form the basis for continued negotiations on
details of CMS/MSS, with the goal of NEPOOL submitting a comprehensive CMS/MSS
filing on or before March 31, 2000. The Compromise Proposal would also change
the settlement system for the NEPOOL revised markets from the current single
settlement system to a system that settles once in a day ahead forward market,
which would be financially binding on the market participants and again in a
real time market to address any differences between actual dispatch
requirements and the forecasted requirement in the ahead markets. A new market
for Four Hour Reserves would be established, the Operable Capability market
would be eliminated as of March 1, 2000, and the Installed Capability market
would be eliminated as of January 1, 2002.
Electric Utility Industry Restructuring
Legislation enacted in Rhode Island in 1996 and Massachusetts in 1997
along with approved electric utility industry restructuring settlement
agreements in both states and at the federal level granted EUA's Rhode Island
and Massachusetts electric customers with choice of electricity supplier
and rate reductions commencing January 1, 1998 and March 1, 1998, respectively.
Until a customer chooses an alternative supplier, that customer will receive
standard offer service from the retail distribution company. Blackstone and
Newport are required to arrange for standard offer service through December 31,
2009 and Eastern Edison must arrange for this service through February 28,
2005. Under the approved settlement agreements, Montaup had guaranteed
standard offer supply at a fixed price schedule for the duration of the
standard offer periods and Blackstone, Newport and Eastern Edison agreed to
subject their standard offer requirements to a competitive bidding process
in which competitive suppliers would bid against the guaranteed price. Through
Montaup's successful divestiture process, and competitive bidding process
conducted in late 1998, 100% of the retail companies' standard offer
obligations are being served by third party suppliers. A majority of this
standard offer assignment became effective January 1, 1999; the remainder
became effective on September 1, 1999 with the closing of the transfer of power
purchase agreements to Constellation Power Source Inc. (Constellation), see
Generation Divestiture below. The guaranteed standard offer price will
increase over time to encourage customers to leave standard offer service and
enter the competitive power supply market.
Provisions of the approved settlement agreements also allowed Montaup to
replace its all-requirements wholesale contracts with its affiliated retail
distribution companies with a contract termination charge (CTC) which permits
Montaup to recover, among other things, its above market investments and
commitments in generation assets along with an 80% ratepayer/20% shareholder
sharing mechanism for ongoing nuclear generation operations. Montaup began
billing the CTC coincident with retail access and the distribution companies
are recovering the CTC through a non-bypassable transition charge to all of
their distribution customers.
As part of the approved settlement agreements, Montaup agreed to divest
its entire generation portfolio. The net proceeds of the sales, as defined in
the settlement agreements, will be used to mitigate Montaup's CTC to its retail
affiliates via a Residual Value Credit (RVC). The RVC reduces the fixed
component of the CTC by an amount equal to the net proceeds, with a return,
over the period commencing on the date the RVC is implemented through December
31, 2009. Effective April 1, 1999, subject to dispute resolution procedures
pursuant to restructuring settlement agreements, Montaup reduced its CTC to its
retail subsidiaries to reflect the RVC and other adjustments. Montaup lowered
its CTC from 3.04 cents per kWh to 2.10 cents per kWh for Eastern Edison and
from 3.0 cents per kWh to 2.04 cents per kWh and 2.06 cents per kWh in the case
of Blackstone and Newport, respectively. Retail transition charge decreases to
reflect these changes were authorized by respective state regulatory bodies
effective April 1, 1999 for Eastern Edison and May 1, 1999 for Blackstone and
Newport.
Effective January 1, 2000 the standard offer service rate for Blackstone
and Newport customers was increased from a flat 3.5 cents per kilowatthour to a
flat 3.8 cents per kilowatthour. The standard offer service rate for Eastern
Edison customers was increased to a flat rate of 3.8 cents per kilowatthour
effective January 1, 2000.
Generation Divestiture: By the end of 1999, pursuant to settlement agreements
approved by federal and state regulators, Montaup had completed the transfer of
all of its non-nuclear power generation assets and power purchase agreements to
various non-affiliated parties in connection with electric utility
restructuring undertaken in Massachusetts and Rhode Island. At the end of
1998, Newport sold several diesel-powered generating units (totaling
approximately 16 mw) to Illinois-based Wabash Power Equipment Company for
approximately $1.4 million and Montaup sold its 50% share (approximately 280
mw) of Unit 2 of the Canal generating station in Sandwich, Massachusetts to
Southern Energy Canal, LLC, an indirect subsidiary of The Southern Company,
for approximately $75 million. On April 7, 1998, Montaup entered into an
agreement to transfer power purchase contracts for approximately 170 mw of
output from Ocean State Power I and Ocean State Power II to TransCanada Power
Marketing Ltd., an indirect subsidiary of TransCanada Pipelines Limited; the
transfer was effective June 1, 1999. On December 21, 1998, Montaup entered
into an agreement to transfer purchase power contracts totaling approximately
177 mw to Constellation Power Source, Inc., a wholly-owned affiliate of the
Baltimore Gas and Electric Company; the transfer became effective on September
1, 1999. On April 26, 1999, Montaup completed the sale of its 170 mw Somerset
Generating Station, located in Somerset, Massachusetts, to Somerset Power, LLC,
a direct subsidiary of NRG, Inc., for approximately $55 million. In June
of 1999, Montaup completed the sale of its and Newport's combined 2.6%
(approximately 16 mw) share of the W.F. Wyman Unit 4 in Yarmouth, Maine to FPL
Energy Wyman IV LLC, an indirect subsidiary of the Florida-based FPL Group, Inc
for $2.4 million. Also in June of 1999, Blackstone sold its hydroelectric
facility in Pawtucket, Rhode Island (approximately 1 mw) to Pawtucket
Hydropower LLC. In November of 1999, Montaup completed the transfer of its
ownership interest in the Seabrook Station nuclear power plant to Little Bay
Power Corporation, a subsidiary of BayCorp Holding, Ltd.
In July 1999, in connection with Entergy Nuclear Generation Company's
(Entergy) acquisition of Pilgrim Station from Boston Edison, Montaup agreed to
a buy-out of its power purchase agreement (approximately 73 mw) with Boston
Edison. As a condition of the buy-out, Montaup entered into a reduced-term
power purchase contract for Pilgrim Station power with Entergy. Accordingly,
in the third quarter of 1999, Montaup recorded on EUA's Consolidated Balance
Sheet a regulatory asset of approximately $111.7 million, a corresponding
current liability of $105.6 million, and a long-term regulatory liability of
$6.1 million related to this buyout.
In November 1999, Vermont Yankee agreed to the sell the 540-mw nuclear
unit to AmerGen Energy Company for approximately $10 million based on a
December 1, 2000 closing. Montaup has a 2.5% (12 mw) equity ownership interest
in the unit. As part of the agreement, Vermont Yankee will make a one-time
payment to the unit's decommissioning fund, and AmerGen will assume
responsibility for all future operating costs and costs to decommission the
plant at the end of its operating license in 2012. Montaup also elected to
buy-out of its obligation to purchase 2.5% of the unit's output.
EUA's only remaining generating capacity is approximately 58 mw from its
ownership share of the Millstone 3 nuclear facility. Montaup has entered into a
settlement agreement with Northeast Utilities, settling a number of outstanding
issues with respect to Millstone and providing that Montaup's share of
Millstone 3 will be included in Northeast's planned auction of the facility.
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 process reflected efficiency improvements,
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's revenues under these agreements are
dependent upon the actual achievement of energy savings. In addition, EUA
Cogenex participates in demand side management (DSM) programs sponsored by
electric utilities as a means to decrease both base load and peak demand on the
utilities' systems. In utility DSM programs, EUA Cogenex contracts with the
utility and its commercial and industrial customers in order to decrease the
overall demand on the utility system or to reduce peak demand, curtailing the
need for costly capacity additions. EUA Cogenex contracts for utility DSM
programs through a bidding process or participates in the utility's "Fixed Rate
Program." EUA Cogenex also may, from time to time, acquire existing DSM
contracts or energy services agreements, or the benefits from those contracts
from other energy services companies.
EUA Cogenex's principal markets include institutional, industrial,
government entities and, through its EUA Citizens Conservation Services, Inc.
(Citizens) subsidiary, public and private multi-family housing.
On October 23, 1998, an arbitrators' panel rendered their decision in a
matter involving the 1995 sale of a portfolio of cogeneration units by EUA
Cogenex to Ridgewood/Mass Power Partners, et al (Ridgewood). Ridgewood claimed
that financial and other warranties in the purchase and sale agreement had been
breached. Cogenex entered counterclaims seeking recovery of costs of certain
services performed for Ridgewood. The arbitration panel found for the buyer on
some of the warranty claims, and awarded damages of approximately $2.6 million
plus interest of approximately $900,000 (an amount substantially less than
claimed). Cogenex was awarded approximately $400,000 plus interest of
approximately $130,000 on its counterclaim. Cogenex paid the arbitration
panel's net award less interest and recorded this charge to earnings in the
fourth quarter of 1998. In addition, Ridgewood claimed attorney fees and
additional interest. In 1999, the arbitration panel again found for Ridgewood,
and Cogenex paid legal fees and interest totalling $1.5 million in 1999,
which resulted in an after-tax charge, after liability offset, to 1999 earnings
of approximately $700,000. Management believes that this payment of interest
and legal fees constitutes full settlement of this matter.
On February 15, 2000, the United States Attorney for the District of
Massachusetts informed the Company that his office is investigating possible
criminal conduct, including mail fraud by EUA Cogenex and/or its employees.
The conduct in question involves alleged intentional overbilling by
EUA Cogenex of certain cogeneration customers during 1994 and 1995, when EUA
Cogenex owned cogeneration projects, and filing false information with FERC in
order to maintain the facilities' status as qualifying facilities under the
Public Utility Regulatory Policies Act of 1978. EUA Cogenex is fully
cooperating with the United States Attorney's investigation. Although the
Company cannot predict the ultimate outcome of this investigation, the Company
does not believe that it will have a material effect on the financial position
of the Company.
EUA Cogenex also operated a controls division, EUA Day, and a data
acquisition division, DayMetrix. In order for EUA Cogenex to concentrate on its
core business, Cogenex management decided in June of 1999 to sell the assets of
the Day division and discontinue the operations of the DayMetrix division. The
Day division was sold to its existing management on December 30, 1999 for $1.5
million in cash plus the assumption of certain liabilities. Cogenex recorded
after-tax charges of $3.3 million in 1999 related to this sale and
discontinuance. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - Energy Related Asset Adjustments.
Also in June of 1999, Cogenex management decided to explore the sale of
its Citizens subsidiary. The Company has decided that Cogenex's core business
needed to concentrate its resources on its primary markets. Although Citizens
performs essentially the same services as Cogenex, its market is primarily
public and private multi-family housing. EUA Cogenex has received letters of
intent from interested parties.
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.
At December 31, 1999, EUA Cogenex employed 95 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
financial institutions who provide capital to finance energy efficiency
projects.
In addition, EUA Cogenex has recently concentrated on obtaining contract
awards under the Department of Energy's (DOE) Energy Saving Performance
Contracting Programs. In 1998, EUA Cogenex was awarded the DOE's Midwest
region's Indefinite Delivery and Indefinite Quantity (IDIQ) contract to provide
energy conservation services to reduce energy and water consumption and
associated utility costs. Early in 1999, EUA Cogenex was awarded its second
IDIQ contract from the DOE to provide energy-saving services in the Mid-
Atlantic region. Under the Mid-Atlantic IDIQ contract, EUA Cogenex will
provide energy conservation services in federally-owned facilities in the six-
state area of Delaware, Maryland, New Jersey, Pennsylvania, Virginia, and West
Virginia, in addition to Washington, D.C. The DOE has authorized $750 million
in capital expenditures under this contract. Although Cogenex has not realized
a positive earnings impact from these awards through 1999, the Company believes
that it will benefit from these in the future.
Over the past two years, EUA Cogenex has been involved in energy saving
projects at numerous federal facilities such as the U.S. Department of Energy
Headquarters in Washington, D.C, the U.S. Army Base at Fort Lewis, Washington,
the National Cancer Institute and U.S. Army Garrison at Fort Detrick, Maryland
and the Department of Veterans Affairs Medical Center in West Haven,
Connecticut.
As of December 31, 1999, 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,
1999 1998 1997
(In Thousands)
Operating Revenues $49,399 $54,776 $61,321
Pre-tax Income (Loss) $(8,135)(1) $(2,090)(2) $769
Net Earnings (Loss) $(6,353)(1) $(1,299)(2) $202
Total Assets $128,936 $157,188 $188,351
(1) Includes after-tax charge of approximately $700,000 ($1.1 million pre-tax)
for charges related to the 1995 cogeneration write off and $3.8 million
($5.1 million pre-tax) related to the discontinued operations of Day and
Day Matrix divisions.
(2) Includes after-tax charge of $2.1 million related to the 1995 sale of
cogeneration projects.
General - EUA Energy Investment
EUA Energy is a wholly owned subsidiary of EUA. EUA Energy invests in
energy related projects, and its only current active investment is Separation
Technologies, Inc., in which EUA Energy has a 20% equity interest. Separation
Technologies markets and installs patented technology that separates unburned
carbon from coal fly-ash, which enables its customers to sell the fly-ash to
secondary markets and to reburn the separated carbon. During 1999, EUA Energy
completed the sale of several project investments. On September 30, 1999, it
sold certain assets of Renova LLC's to its management. On August 30, 1999, EUA
TransCapacity, a wholly-owned subsidiary of EUA Energy, sold all of its assets
in TransCapacity L.P. and at the same time dissolved the TransCapacity L.P.
EUA BIOTEN was an investment in a general partnership formed to develop a
generating unit that would burn biomass-agricultural waste and create renewable
energy. EUA BIOTEN had previously executed an agreement with the management of
BIOTEN Partnership to, among other things, extend the right of its management
to purchase BIOTEN Partnership assets. As a result of BIOTEN Partnership
management's inability to attain financing and thereby exercise and complete
the purchase option, BIOTEN Partnership was dissolved and its assets were
distributed to EUA BIOTEN. EUA BIOTEN has commenced liquidation of all assets
of its investment in BIOTEN Partnership and is negotiating with a third party
for the sale of such assets. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Energy Related Asset
Adjustments.
See Note I - Financial Information by Business Segment of Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Notes to Consolidated Financial
Statements contained herein for the year ended December 31, 1999.
Capital Requirements
The EUA System's cash construction expenditures for the year ended
December 31, 1999 were approximately $57.0 million.
Planned core electric cash construction expenditures and energy related
capital requirements for 2000, 2001 and 2002 as set forth below, are estimated
to total $189.9 million, and are expected to be financed with internally
generated funds.
EUA SYSTEM CONSTRUCTION PROGRAM
(In Thousands)
2000 2001 2002 3-yr-Total
Transmission $9,499 $12,462 $6,702 $28,663
Distribution 26,367 21,634 20,229 68,230
General 315 323 331 969
Total Utility Construction
Requirements 36,181 34,419 27,262 97,862
EUA Cogenex Capital
Requirements 28,439 28,880 34,716 92,035
Total $64,620 $63,299 $61,978 $189,897
Fuel for Generation
In 1999, the Retail Subsidiaries partly relied on power purchased from
Montaup and alternate suppliers to meet the electric energy requirements of
their standard offer and default service customers. (See Electric Utility
Industry Restructuring above.) The Retail Subsidiaries recover their
costs associated with the purchase of power to meet their standard offer,
default service, and last resort services through the operation of revenue
adjustment clauses that provide full recovery of such costs.
In 1999, the sources of energy, by fuel type, used to serve Montaup's
obligations were as follows: 32% nuclear, 30% gas, 26% oil, 6% coal and 6%
other. During 1999, prior to the closing of the sale of the Somerset Station
to Somerset Power LLC in April 1999, Montaup had an average fuel inventory of
78,088 tons of coal for its steam generating unit at the Somerset Station - the
equivalent of 86 days' supply (based on average daily output at 80% capacity
factor). The cost of coal averaged about $48.71 per ton for that period, which
is equivalent to fuel oil at $10.97 per barrel. Montaup coal was under
contract, and coal prices have historically been very stable. Montaup also
maintained an average inventory of Nos. 2 and 6 oil of 2,257 barrels and
128,698 barrels, respectively, during that period. These fuels were used for
start-up and flame stabilization for Montaup's steam generating unit. The cost
of Nos. 2 and 6 oil averaged $16.44 per barrel and $12.85 per barrel,
respectively. Montaup also maintained an average inventory of jet oil of 1,666
barrels at an average cost per barrel of $18.45 during that period for its two
peaking units at the Somerset Station.
Montaup's costs of fossil and nuclear fuels for the years 1997 through
1999, together with the weighted average cost of all fuels, are set forth
below:
Mills per kWh (1)
1999 1998 1997
Nuclear (2) 4.4 5.0 5.7
Gas 15.4 15.6 16.4
Coal 19.6 18.9 18.6
Oil 21.4 22.3 31.0
All fuels 17.1 15.7 19.2
(1) One Mill is 1/10 of one cent
(2) Does not include the cost of fuel for Pilgrim in 1999. The new
contract with Entergy does not contain separate billing for fuel.
The owners (or lead participants) of the nuclear units in which Montaup
has an interest have made, or expect to make, various arrangements for the
acquisition of uranium concentrate, the conversion, enrichment, fabrication and
utilization of nuclear fuel and the disposition of that fuel after use. The
owners (or lead participants) of United States nuclear units have entered into
contracts with the DOE for disposal of spent nuclear fuel in accordance with
the NWPA. The NWPA requires (subject to various contingencies) that the
federal government design, license, construct and operate a permanent
repository for high level radioactive wastes and spent nuclear fuel and
establish a prescribed fee for the disposal of such wastes and nuclear fuel.
The NWPA specifies that the DOE provide for the disposal of such waste and
spent nuclear fuel starting in 1998. Objections on environmental and other
grounds have been asserted against proposals for storage as well as disposal
of spent nuclear fuel. The DOE now estimates that a permanent disposal site
for spent fuel will not be ready to accept fuel for storage or disposal until
at least the year 2010. Montaup currently owns a 4.01% interest in Millstone
3. Northeast Utilities, the operator of the unit, indicates that Millstone
3 has sufficient on-site storage facilities which, with rack additions, can
accommodate its spent fuel for the projected life of the unit.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power
plants in which Montaup has an interest. These assessments are calculated
based on the utilities' prior use of the government facilities and have been
levied by the DOE, starting in September 1993, and will continue over 15 years.
This cost is passed on to the joint owners or power buyers as an additional
fuel charge on a monthly basis and is currently being recovered by Montaup
through the CTC.
In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee,
individually, as well as a number of other utilities, filed suit in federal
appeals court seeking a court order to require the DOE to immediately establish
a program for the disposal of spent nuclear fuel. Under the Nuclear Waste
Policy Act of 1992, the DOE was to provide for the disposal of radioactive
wastes and spent nuclear fuel starting in 1998 and has collected funds from
owners of nuclear facilities to do so. On February 19, 1998, Maine Yankee also
filed a petition in the U.S. Court of Appeals seeking to compel the Department
of Energy to remove and dispose of the spent fuel at the Maine Yankee site.
Under their Standard Contract, the DOE had a deadline for beginning the removal
process at all nuclear plants on January 31, 1998, which was not met. On May
5, 1998, the Court of Appeals denied several motions brought in the proceeding,
including several motions for injunctive relief brought by the utility
petitioners. In particular, the Court denied the requests to require the DOE
to immediately establish a program for the disposal of spent nuclear fuel.
Also, Yankee Atomic, Connecticut Yankee, and Maine Yankee filed lawsuits
against the DOE in the U.S. Court of Federal Claims seeking damages of $70
million, $90 million and $128 million, respectively, as a result of the DOE's
refusal to accept the spent nuclear fuel.
In late October and early November 1998, the U.S. Court of Federal Claims
issued rulings with respect to Yankee Atomic, Maine Yankee, and Connecticut
Yankee finding that the DOE was financially responsible for failing to accept
spent nuclear fuel. These rulings clear the way for Yankee Atomic, Connecticut
Yankee and Maine Yankee to pursue at trial their individual damage claims.
The DOE filed a motion to stay the case pending resolution of its appeal
request granted by the Appeals Court. In October 1999, the Court issued a stay
order on the damage claims. Management cannot predict at this time the
ultimate outcome of these actions.
Nuclear Power Issues
General: Nuclear generating facilities, including those in service in which
Montaup participates, as shown in the table under Item 2. PROPERTIES - Power
Supply, are subject to extensive regulation by the NRC. The NRC is empowered
to authorize the siting, construction and operation of nuclear reactors after
consideration of public health, safety, environmental and anti-trust matters.
The NRC has promulgated numerous requirements affecting safety systems,
fire protection, emergency response planning and notification systems, and
other aspects of nuclear plant construction, equipment and operation. These
requirements have caused modifications to be made at some of the nuclear units
in which Montaup has an interest. Montaup has been affected, to the extent of
its proportionate share, by the costs of such modifications.
Nuclear units in the United States have been subject to widespread
criticism and opposition. Some nuclear projects have been canceled following
substantial construction delays and cost overruns as the result of licensing
problems, unanticipated construction problems and other difficulties. Various
groups have by litigation, legislation and participation in administrative
proceedings sought to prohibit the completion and operation of nuclear units
and the disposal of nuclear waste. In the event of cancellation or shutdown of
any unit, the unit must be decontaminated of any residual radioactivity so as
to satisfy NRC regulations which generally require that the property be
releasable for unrestricted use. The cost of such decommissioning, depending
on the circumstances, could substantially exceed the owners' investment at the
time of cancellation.
Joint owners of nuclear projects are subject to the risk that one of their
number may be unable or unwilling to finance its share of the project's costs,
thus jeopardizing continuation of the project. Also, the continuing public
controversy concerning nuclear power could affect the operating units in which
Montaup has an interest. While management cannot predict the ultimate effect
of such controversy, it is possible that it could result in the premature
shutdown of one or more of the units.
The Price-Anderson Act provides, among other things, that the limit of
liability for a nuclear incident would not exceed an amount which at present is
approximately $9.9 billion. Under the Price-Anderson Act, prior to operation
of a nuclear reactor, the facility 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 liability for
an incident exceed $200 million, the difference between such liability and the
overall maximum liability, currently about $9.7 billion, will be made up by the
retrospective rating program. Under such a program, each operating nuclear
facility may be assessed a retrospective premium of up to a limit of $88.1
million (which shall be adjusted for inflation at least every five years) for
each reactor owned in the event of any one nuclear incident occurring at any
reactor in the United States, with provision for payment of such assessment
to be made over time as necessary to limit the payment in any one year to no
more than $10 million per reactor owned. With respect to operating nuclear
facilities of which it is a part owner or from which it contracts (on terms
reflecting such liability) to purchase power, Montaup would be obligated to pay
its proportionate share of any such assessment.
Decommissioning: Vermont Yankee, an operating nuclear generating company in
which Montaup has an equity ownership interest (see Item 2. PROPERTIES - Power
Supply) has developed its estimate of the cost of decommissioning its unit and
has received the approval of FERC to include charges for the estimated costs of
decommissioning its unit in the cost of energy which it sells. From time to
time, Vermont Yankee re-estimates the cost of decommissioning and applies to
FERC for increased rates in response to increased decommissioning costs. See
Generation Divestiture for a discussion of the proposed sale of Vermont Yankee
and a proposed one-time payment of decommissioning liability. Maine Yankee has
filed a decommissioning financing plan under a Maine statute which requires the
establishment of a decommissioning trust fund. That statute also provides that
if the trust has insufficient funds to decommission the plant, the licensee
(Maine Yankee) is responsible for the deficiency and, if the licensee is unable
to provide the entire amount, the "owners" of the licensee are jointly and
severally responsible for the remainder. The definition of "owner" under the
statute includes Montaup and may include companies affiliated with Montaup.
The applicability and effect of this statute cannot be determined at this time.
Montaup would seek to recover through its rates any payments that might be
required. (See Connecticut Yankee and Maine Yankee below.)
Montaup is recovering through rates its share of estimated decommissioning
costs for Millstone 3. Montaup's share of the current estimate of total cost
to decommission Millstone 3 is $24.8 million in 1999 dollars. This figure is
based on studies performed for Northeast Utilities, the lead owner of the
plant. Montaup also pays into decommissioning reserves pursuant to contractual
arrangements with other nuclear generating facilities in which Montaup has an
equity ownership interest.
Millstone 3: Montaup has a 4.01% ownership interest in Millstone 3, an 1,154
mw nuclear unit that is jointly owned by a number of New England utilities,
including subsidiaries of Northeast Utilities (Northeast). Subsidiaries of
Northeast are the lead participants in Millstone 3. On March 30, 1996,
it was necessary to shut down the unit following an engineering evaluation
which determined that four safety-related valves would not be able to perform
their design function during certain postulated events.
In October 1996, the NRC, which had raised numerous issues with respect to
Millstone 3 and certain of the other nuclear units in which Northeast and its
subsidiaries, either individually or collectively, have the largest ownership
shares, informed Northeast that it was establishing a Special Projects Office
to oversee inspection and licensing activities at Millstone. In July 1998,
after the NRC performed an inspection and verified that several final technical
and programmatic issues were resolved, Millstone 3 was restarted, and returned
to full power operation on July 14, 1998. The NRC will continue to closely
monitor Millstone 3's performance.
In August 1997, nine non-operating owners, including Montaup, who together
own approximately 19.5% of Millstone 3, filed a demand for arbitration against
Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company
(WMECO) as well as lawsuits against Northeast and its Trustees. CL&P and
WMECO, owners of approximately 65% of Millstone 3, are Northeast subsidiaries
that agreed to be responsible for the proper operation of the unit.
The non-operating owners of Millstone 3 claim that Northeast and its
subsidiaries failed to comply with NRC regulations, failed to operate the
facility in accordance with good utility operating practice and attempted to
conceal their activities from the non-operating owners and the NRC. The
arbitration and lawsuits seek to recover costs associated with replacement
power and operation and maintenance (O&M) costs resulting from the shutdown of
Millstone 3. The non-operating owners conservatively estimate that their
losses exceed $200 million. In December 1997, Northeast filed a motion to
dismiss the non-operating owners' claims, or alternatively to stay the pending
lawsuit until after the resolution of the arbitration case. These requests
were denied in July 1998. In May 1999, Northeast filed a request for summary
judgement in the arbitration case. This request was denied in July 1999. In
May 1999, all parties entered into a Alternative Dispute Resolution Agreement
and began mediation sessions in an effort to reach a settlement of all issues.
In November 1999, Montaup entered into an agreement with Northeast Utilities
and its subsidiaries, Connecticut Light Power Company and Western Massachusetts
Electric Company, to settle the arbitration and lawsuit claims it had asserted.
The Company does not expect the outcome of this settlement to have a
material effect on its operating results or financial position.
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.
In October 1996, Montaup, as one of the joint owners, participated in an
economic evaluation of Connecticut Yankee which recommended permanently closing
the unit and replacing its output with less expensive energy sources. In
December 1996, the Board of Directors of Connecticut Yankee voted to retire the
generating station. Connecticut Yankee certified to the NRC that it had
permanently closed power generation operations and removed fuel from the
reactor. Montaup's share of the total estimated costs for the permanent
shutdown, decommissioning, and recovery of the investment in Connecticut Yankee
is approximately $19.3 million and is included with Other Liabilities on the
Consolidated Balance Sheet as of December 31, 1999. The recovery of this
estimated amount, elements of which have been disputed by certain intervening
parties, is subject to approval of FERC. Also, due to anticipated
recoverability, a regulatory asset has been recorded for the same amount and is
included with Other Assets.
On August 31, 1998, a FERC law judge rejected Connecticut Yankee's plan to
decommission the plant. The judge claimed that estimates of clean-up costs
were flawed and certain restoration costs were not supported. The judge also
said Connecticut Yankee could not pass on spent fuel storage costs to rate-
payers. The judge recommended that Connecticut Yankee withdraw its
decommissioning plan and submit a new plan which addresses the issues cited by
him. FERC will review the judge's recommendations and issue a decision on this
case in the coming months. If FERC concurs with the judge's recommendation,
this may result in a write down of certain of Connecticut Yankee plant
investments. Montaup cannot predict the ultimate outcome of FERC's review.
See Fuel for Generation for a discussion of a Connecticut Yankee action
against the DOE.
Maine Yankee: On August 6, 1997, as the result of an economic evaluation, the
Maine Yankee Board of Directors voted to permanently close that nuclear plant.
Montaup has a 4.0% equity ownership in the permanently closed Maine Yankee
nuclear plant. Montaup's share of the total estimated costs for the permanent
shutdown, decommissioning, and recovery of the remaining investment in Maine
Yankee is approximately $25.5 million and is included with Other Liabilities
on the Consolidated Balance Sheet as of December 31, 1999. Also, due to
recoverability, a regulatory asset has been recorded for the same amount and is
included with Other Assets.
On November 6, 1997, Maine Yankee submitted an estimate of its costs,
including recovery of unamortized plant investment (including fuel) along with
a return on equity, to FERC reflecting the fact that the plant was no longer
operating and had entered the decommissioning phase. On January 14, 1998, the
FERC accepted the new rates, subject to refund, and amounts of Maine Yankee's
collections for decommissioning. On January 19, 1999, Maine Yankee and the
active intervening parties, including the Secondary Purchasers, filed an Offer
of Settlement with FERC which was supported by FERC trial staff on February 8,
1999. The FERC approved the Settlement effective June 1, 1999. This
agreement constitutes full settlement of the issues raised in this proceeding.
Also, as a result of the shutdown, Montaup and the other equity owners
were notified by the Secondary Purchasers that they would no longer make
payments for purchased power to Maine Yankee. The Secondary Purchase
Contracts are between the equity owners as a group and 30 municipalities
throughout New England. Presently, the equity owners are making payments to
Maine Yankee to cover the payments that would be made by the municipals.
On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation
of Arbitration to the equity owners of Maine Yankee, which was denied by a
Maine judge on April 7, 1998. The judge indicated that the jurisdictional
question should be first decided by FERC. On December 15, 1997, the equity
owners as a group filed at FERC a Complaint and Petition for Investigation,
Contract Modification, and Declaratory Order. A separately negotiated
Settlement Agreement filed with FERC on February 5, 1999, was approved by FERC
and made effective on June 1, 1999. This settlement resolved issues raised by
the Secondary Purchasers by limiting the amount they will pay for
decommissioning and settling other points of contention.
The outcome of these recent settlements will not have a material effect on
EUA's future operating results or financial position.
On August 4, 1998, the Maine Yankee Board of Directors selected Stone &
Webster Engineering Corporation to execute a $250 million contract for the
decommissioning and decontamination of Maine Yankee. The decommissioning plan
includes an option for Stone & Webster to repower the Maine Yankee site with a
gas-fired plant.
See Fuel for Generation for a discussion of a Maine Yankee action against
the DOE.
NRC Oversight: Recent actions by the NRC, some of which are cited above,
indicate that the NRC has become more critical and active in its oversight of
nuclear power plants. EUA is unable to predict at this time what, if any,
ramifications these NRC actions will have on any of the other nuclear power
plants in which Montaup has an ownership interest or power contract.
Public Utility Regulation
Eastern Edison and Montaup are subject to regulation by the DTE with
respect to the issuance of securities, the form of accounts, and in the case of
Eastern Edison, rates to be charged, services to be provided, and other
matters. Blackstone and Newport are subject to regulation in numerous respects
by the RIPUC and the RIDPUC, including matters pertaining to financing, sales
and transfers of utility properties, accounting, rates and service. In
addition, by reason of its ownership of fractional interests in certain
facilities located in other states, Montaup is subject to limited regulation in
those states.
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. On February 17, 2000, EUA Ocean State filed a petition
to RIPUC to obtain an exemption from the 1935 Act by gaining "exempt wholesale
generator" status from FERC. In order to establish units as "exempt wholesale
generators," certain findings are needed from the RIPUC.
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.
See Rates with respect to regulation of rates charged to customers. See
Environmental Regulation. See Fuel for Generation with respect to the disposal
of spent nuclear fuel. See Environmental Regulation of Nuclear Power and see
Nuclear Power Issues with respect to regulation of nuclear facilities by the
NRC. See also Electric Utility Industry Restructuring.
Rates
Rates charged by Montaup (which sells power only for resale) are subject
to the jurisdiction of FERC. The rates for services rendered by the Retail
Subsidiaries for the most part are subject to approval by and are on file with
the DTE in the case of Eastern Edison and with the RIPUC in the case of
Blackstone and Newport. For the twelve months ended December 31, 1999, 47% of
EUA's consolidated revenues were subject to the jurisdiction of FERC, 24% to
that of the DTE and 19% to that of the RIPUC. The remaining 10% of
consolidated revenues were generated from EUA Cogenex and EUA Energy Investment
and are not subject to jurisdiction of utility commissions. 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 for Montaup and the Retail Subsidiaries are
as follows (In Thousands):
Applied For Effective (1)
Annual Annual
Revenue Date Revenue Date
Federal
- Montaup See Electric Utility Industry Restructuring
Massachusetts
DTE - 99-106 (150) 8/25/99 (150) 9/1/99
Rhode Island
- Blackstone
RIPUC - 2498 3,094 11/15/96(2) 2,821 1/1/97
RIPUC - 2498 2,265 11/15/97(3) 2,265 1/1/98
- Newport
RIPUC - 2499 1,437 11/15/96(2) 1,425 1/1/97
RIPUC - 2499 1,031 11/15/97(3) 1,055 1/1/98
Notes:
(1) Per final order or settlement agreement.
(2) The revenue requirement represents the compliance with
R.I.G.L. 39-1-27.4 to file performance based rates reflecting the
change in the Consumer Price Index for the most recent 12 months ended
September 30, 1996.
(3) The revenue requirement represents the compliance with R.I.G.L. 39-1-
27.4 to file rates reflecting the change in the Consumer Price Index
for the most recent 12 months ended September 30, 1997.
FERC Proceedings - Transmission: On May 14, 1999, Montaup filed amendments to
the Open Access Transmission Tariff (OATT) that modifies the charges for
Ancillary Services. The tariff amendments provide for the charges for
Ancillary Services to reflect a pass-through of the costs that the Company
would incur in obtaining the services from third parties if the NEPOOL OATT no
longer provides for such services.
On June 30, 1999, Montaup filed a modification to the OATT that reduces
the rate of return on common equity from 11.1% to 10.65%. This rate reduction
is made with the consent of Montaup's wholesale customers and is consistent
with the settlement agreement in Docket Nos. ER97-4691-000 and ER98-861-000
with those customers.
On September 24, 1999, Montaup filed an amendment to its existing OATT to
comply with the terms and conditions of the NEPOOL Settlement Agreement, filed
on April 7, 1999, by adding the Phase I and Phase II Uplift charges to its
retail transmission rate in order to ensure recovery of those expenses. Phase
I and Phase II Uplift charges are to resolve all claims of alleged double
charges or overpayments resulting from the treatment of Excepted Transactions
under the NEPOOL OATT. Excepted Transactions are transmission agreements that
individual transmission owners have with third parties in effect on November 1,
1996 as specified in Section 25 of the NEPOOL OATT which will continue to be in
effect for the term of their agreements.
FERC Proceedings - Supply: On October 29, 1997 Montaup filed settlement
agreements in Dockets ER97-2800 and ER97-3121 among Montaup, Blackstone,
Newport, RIDIV, RIPUC and the R.I. Attorney General; a settlement agreement
among Montaup, the Division of Energy Resources of the Office of the Attorney
General of Massachusetts and Eastern Edison; separate settlements between
Montaup and the Middleborough Gas and Electric Department; Montaup and
the Pascoag Fire District; and a settlement between Montaup and Taunton
Municipal Lighting Plant. These settlements shorten the notice of termination
from three years to 90 days. These agreements were approved by FERC in orders
issued in 1997 and 1998. (See Electric Utility Industry Restructuring for
further discussion of the termination of Montaup's all-requirements contracts
with its affiliated customers and other electric utility industry restructuring
issues.)
On August 7, 1998, Montaup petitioned FERC to approve the sale of its 50%
interest in the Canal 2 generating facility to Southern Energy New England, LLC
for $75 million. Approval was granted in an order issued by FERC on November
12, 1998.
On October 2, 1998, Montaup filed with FERC an agreement for the transfer
of its OSP I and OSP II purchased power obligations to TransCanada Power
Marketing LTD (TransCanada) in exchange for fixed monthly contributions from
Montaup beginning in 1999 and ending December 31, 2007. TransCanada will
assume all future OSP I and OSP II contractual obligations of Montaup
less the fixed monthly contributions for the balance of the contracts periods.
FERC accepted the agreement on October 29, 1998.
On November 30, 1998, Montaup petitioned FERC to approve the sales of its
160 mw Somerset Station to Somerset Power, LLC for approximately $55 million
and its 2.63% interest in Wyman Station electric generating plant to FPL Energy
Wyman IV LLC for approximately $2.4 million. FERC approved these transactions
in an order issued on March 15, 1999.
On January 7, 1999, Montaup petitioned FERC to approve the sale of its
2.9% interest in the Seabrook nuclear generating facility to Great Bay Power
Corporation for approximately $3.2 million. The agreement also provides that
Montaup prefund its 2.9% share of the unit's decommissioning liability up to an
agreed upon amount at the time of sale. Great Bay will assume all future
operating and decommissioning obligations of the unit. Approval was granted in
an order issued by FERC on April 12, 1999.
On February 1, 1999, Montaup filed with FERC an agreement for the transfer
of approximately 177 mw of its purchased power obligations to Constellation
Power Source Inc. (Constellation) in exchange for fixed monthly contributions
from Montaup beginning in 1999 and ending December 31, 2009. Constellation
will assume all future Canal I, McNeil, Northeast Energy Associates,
Blackstone Hydro Electric and Hydro Quebec Firm Energy contractual obligations
of Montaup less the fixed monthly contribution for the balance of the contracts
periods. FERC accepted the agreement on June 18, 1999.
On February 5, 1999, Montaup petitioned FERC for a declaratory order
approving Montaup's recovery of a proposed buyout of Montaup's obligations
under the Pilgrim Nuclear Station Purchased Power Agreement with Boston Edison
(BEC) and above market costs of a purchase power agreement with the station's
prospective owner. The buyout agreement is in conjunction with BEC's
plans to sell the unit to Entergy Nuclear Generating Co. (Entergy). Along with
the buyout payment of $111.7 million, Montaup has agreed to a short-term, fixed
price purchased power contract with Entergy for declining shares of Pilgrim's
output beginning with 11% in 1999 and ending with 5.5% in 2004. Entergy will
assume all future operating and decommissioning obligations of the unit.
FERC approved the transaction in an order issued on April 30, 1999.
On February 12, 1999, Montaup petitioned FERC to implement a Residual
Value Credit (RVC) effective April 1, 1999. The RVC would lower Montaup's CTC
to the Retail Subsidiaries as a result of Montaup's generation assets
divestiture and other adjustments. Montaup requested to lower the CTC it bills
from 3.04 cents per kWh to 2.10 per cents kWh for Eastern Edison and from
3.0 cents per kWh to 2.04 cents per kWh and 2.06 cents per kWh in the case of
Blackstone and Newport, respectively. This filing was accepted and made
effective on April 1, 1999. See Electric Utility Industry Restructuring.
Rhode Island Proceedings: On November 13, 1997, Blackstone and Newport filed a
report on their annual return on equity for the twelve months ended September
30, 1997 as prescribed in the URA. These filings resulted in the refund of
approximately $307,000 and $136,000 to customers of Blackstone and Newport,
respectively. The annual return on equity reports for the twelve months
ended December 31, 1998 were filed on February 16, 1999 resulting in
approximately $300,000 and $438,000 being refunded to Blackstone and Newport
customers, respectively.
On April 1, 1998, Blackstone and Newport filed their Annual Performance
Standards Report in Compliance with RIPUC Order 15383. This report presented
Blackstone's and Newport's performance against each of the Performance
Standards based on actual data for the twelve months ending December 31, 1997
resulting in revenue increases of $127,288 for Blackstone and $69,088
for Newport. These increases were being collected through a per-kilowatthour
factor effective July 1, 1998 through June 30, 1999. Blackstone and Newport
made their Annual Performance Standard Report filing for the twelve months
ending December 31, 1998 in April 1999. As presented in the filing,
Blackstone's 1998 performance entitles it to a net reward of $172,620 and
Newport's performance entitles it to a reward of $90,095. The revenues were to
be collected by the Performance Based Revenue factor from July 1, 1999 through
June 30, 2000.
On April 26, 1999, Blackstone and Newport filed their recommendations to
RIPUC Docket No. 2888, and filed consolidated factors to resolve all other
issues from Docket Nos. 2514 and 2891. RIPUC Docket No. 2514 addressed
Blackstone and Newport's Annual Performance Standards and Performance Based
Ratemaking revenue reward collection factors, excess revenue refunds in
compliance with the return on equity filing, the 1996 PCAC refund and the
estimated CTC over recovery. RIPUC Docket No. 2891 included Blackstone's and
Newport's Standard Offer Cost Adjustment provisions, which proposed a factor
that would true up final balances related to the companies' fuel adjustment
clause accounts, a reconciliation of interim generation services and a
reconciliation of Standard Offer Service from June to December 1998. RIPUC
Docket No. 2888, Implementation of Residual Value Credit, proposed a Transition
Cost Adjustment Clause, a Transition Cost Adjustment Factor that would flow
through Montaup's Contract Termination Charge, and a refund of Blackstone's
portion of the overcollection of Montaup's 1996 Purchase Capacity Adjustment
Clause from 1997. Blackstone and Newport implemented the consolidated
factors for May through December 1999.
On October 29, 1999, Blackstone and Newport made a Standard Offer Service
Tariff Advice filing with the RIPUC, Docket No. 3022. The purpose of this
filing was to update the Companies' tariffs to reflect the change in Montaup's
Standard Offer Rate effective January 1, 2000 and also to update the Companies'
Last Resort Service rates. These rates were approved by the RIPUC on December
17, 1999. Effective January 1, 2000, Blackstone and Newport began billing the
new Standard Offer Rate at a flat rate of 3.8 cents per kilowatthour.
On March 1, 1999, Blackstone and Newport filed with the RIPUC to reduce
their transition charge from 2.8 cents per kilowatthour to 2.04 cents and 2.06
cents per kilowatthour, respectively, to reflect the RVC representing the net
proceeds from the divestiture of Montaup's generation assets which lowers the
contract termination charge that Montaup charges Blackstone and Newport. This
new rate became effective on May 1, 1999.
On December 2, 1999, Blackstone and Newport filed with the RIPUC to
increase their transition charges from 2.04 cents per kilowatthour and 2.06
cents per kilowatt-hour to 2.14 cents per kilowatt-hour and 2.16 cents per
kilowatthour, respectively. The transition charges increase was proposed to be
effective on January 1, 2000, coincident with the expected change in Montaup's
contract termination charge. The RIPUC, at an open meeting on December 16,
1999, voted to suspend the proposed transition charge increase and authorized
Blackstone and Newport to continue billing the last approved transition
charges. The foundation for the RIPUC's action on this matter was knowledge
that settlement negotiations were in progress on Montaup's residual value
credit filing which could favorably impact the level of Montaup's contract
termination charge to the Companies.
On February 24, 1999, Blackstone petitioned the RIPUC to make certain
findings that would enable Blackstone's hydroelectric facilities to be
designated eligible facilities under the Public Utility Holding Company Act, a
condition to closing the sale of the facilities. The RIPUC issued an order
making the necessary findings on March 31, 1999.
On April 27, 1999 the Division of Public Utilities and Carriers and the
Attorney General filed a petition seeking an investigation and reduction in the
rates and charges of Blackstone and Newport. In their petition, the Division
and Attorney General requested that the RIPUC:
- Determine the amount of refund to be made by Blackstone and Newport for
excess earning from January 1, 1999 until the conclusion of the
proceeding;
- Determine the appropriate present and prospective cost of common equity
for Blackstone and Newport; and
- Determine the prospective rate reductions necessary to resolve
Blackstone's and Newport's overearnings, to eliminate excess revenue,
and to conform the returns earned by Blackstone and Newport to their
actual cost of common equity.
The Commission accepted the petition, and opened Docket No. 2911 to begin
an investigation into the matters raised in the petition. On February 9, 2000,
an amended stipulation and settlement agreement was filed with the RIPUC in
Docket No. 2930, which resolves all of the issues raised in this proceeding.
On May 20, 1999, Blackstone, Newport and Narragansett, NEES's Rhode
Island subsidiary, collectively submitted a Rate Plan in support of the Merger
(the Rhode Island Rate Plan) with the RIPUC, docketed as RIPUC 2930, seeking
approval for the Rhode Island Rate Plan and merger of Blackstone and Newport,
EUA's Rhode Island distribution subsidiaries, into Narragansett. A
supplemental filing was submitted collectively in September 1999 and on
February 9, 2000, a settlement agreement was submitted to RIPUC. The
settlement provides for, among other things:
- immediate rate reductions totaling $13.1 million for the combined
customers of the three companies;
- a rate freeze at the post-reduction level through December 31, 2004
subject only to limited exogenous events;
- rate equalization for customer classes of the three individual companies
subsequent to the merger;
- a sharing of merger related savings between the Company and customers
subject to demonstration proofs made by the Company;
- company commitment to service quality including increased penalties for
service quality deterioration, and;
- a long term incentive rate plan designed to require the Company to
maintain rates at a level below an agreed upon rate path in order to
retain a share of the merger savings.
- a resolution of Blackstone's and Newport's overearnings; RIPUC Docket
No. 2911.
Hearings on the uncontested settlement agreement concluded on February 29,
2000. A decision by the RIPUC is expected close to the time of the issuance of
this report.
On August 24, 1999, Blackstone, Newport and Narragansett filed a petition
for approval of Merger with the Division of Public Utilities and Carriers,
seeking approval to have Blackstone and Newport merged with and into the
Narragansett. The Division established Docket No. D-99-12 to address this
matter. On December 3, 1999, the Attorney General filed a motion to intervene.
On December 23, 1999, a notice of public hearing was issued establishing a
public hearing dated for January 6, 2000. On December 30, 1999, the Attorney
General and the Division filed testimony. On February 10, 2000, the Division
held a hearing to introduce the testimony and exhibits of the Companies and
intervenors into the record, including the Stipulation and Settlement Agreement
filed in Docket No. 2930. On February 9, 2000, an Amended Stipulation and
Settlement was filed with the RIPUC in Docket No. 2930 which if approved, will
resolve all of the issues raised by the Attorney General and the Division.
Massachusetts Proceedings: On December 31, 1997, Eastern Edison made a
partial compliance filing of unbundled rates and Terms and Conditions to
facilitate its Settlement Agreement and received an order approving them on
January 8, 1998. On February 9, 1998, Eastern Edison made a second compliance
filing of retail delivery rates, standard offer service, and default service.
On February 25, 1998, Eastern submitted revisions to its February 9, 1998
compliance filing and on February 27, 1998, the DTE approved the filing. Rates
were effective March 1, 1998 coincident with retail choice of electricity
supplier. On that date, Eastern Edison began billing a transition charge
of 3.04 cents per kilowatthour and a Standard Offer rate of 2.8 cents per
kilowatthour.
On March 12, 1999, Eastern Edison made a filing with the DTE to reduce its
transition charge from 3.04 cents per kilowatthour to 2.10 cents per
kilowatthour to reflect the residual value credit calculated from the
divestiture of Montaup's generation assets which lowers the contract
termination charge that Montaup charges Eastern Edison. The filing also
requested an increase in Eastern Edison's Standard Offer Rate from 3.1 cents
per kilowatthour, which became effective January 1, 1999, to 3.5 cents per
kilowatthour. These changes were approved and became effective on April 1,
1999.
On August 25, 1999 Eastern Edison filed rates and charges designed to
comply with the DTE's August 19, 1999 directive on meeting the 15 percent rate
reduction required under the Restructuring Act, DTE Docket No. 99-106. The
compliance filing reflected reduced transition charges and temporary statutory
compliance credit tariff provisions. The reduced transition charges would
produce a deferral of approximately $900,000 which would be recovered under the
terms of Eastern Edison's Transition Charge Tariff provision. The temporary
statutory compliance credits would result in a revenue reduction of
approximately $150,000. The DTE approved the proposed rates and charges
effective September 1, 1999.
On July 1, 1997, the EUA Companies filed their Plan for Implementing
Divestiture and Corporate Restructuring with the DTE, Docket DTE 97-105. The
plan was updated in a supplemental filing on November 21, 1997. A third filing
in this docket, seeking approval of the sales of Montaup's 160 mw Somerset
Station to Somerset Power, LLC and its 1.96% interest in Wyman Station electric
generating plant to FPL Energy Wyman IV LLC, was made on December 4, 1998. The
DTE approved the sales process and the transactions on April 23, 1999.
On August 7, 1998, Montaup petitioned the DTE to approve the sale of its
50% interest in the Canal 2 generating facility to Southern Energy New England,
LLC. This filing was docketed DTE 98-83 and consolidated with Docket DTE 98-
78, the ComEnergy companies' petition for sale of its generating assets.
Approval of the sale was granted in an order issued by the DTE on October
30, 1998.
On January 9, 1999, Montaup petitioned the DTE to approve the sale of its
2.9% interest in the Seabrook nuclear generating facility to Great Bay Power
Corporation. This was docketed DTE 99-9 by the DTE and was approved in an
order issued on November 4, 1999.
On February 16, 1999, Eastern Edison petitioned the DTE to approve its
guaranty of the obligations of Montaup pursuant to Montaup's purchase and sale
agreement with Constellation Power Source. This was docketed DTE 99-21 by the
DTE and was approved on July 28, 1999.
On April 30, 1999, Eastern Edison and Massachusetts Electric Company
(MECO) collectively submitted a Rate Plan in Support of Merger (Massachusetts
Rate Plan) with the DTE seeking approval of the rate plan and the merger of
Eastern Edison, EUA's Massachusetts electric into MECO a New England Electric
System (NEES) electric distribution subsidiary. On November 29, 1999, a
settlement agreement entered into by all of the intervening parties was
submitted. The uncontested settlement provides for, among other things:
- immediate rate reductions totaling $10 million for all customers of the
combined MECO and Eastern Edison entity and customers of Nantucket
Electric Company, another Massachusetts electric distribution subsidiary
of NEES;
- a rate freeze at the post reduction rate levels through February 28,
2005 (Rate Cap Period) subject only to limited exogenous events;
- a rate path for the period from March 1, 2005 through December 31, 2009
(Rate Index Period) during which MECO's distribution rates are to be
indexed to an average of regional distribution rates of similarly
unbundled investor owned utilities. The index is to be based on
MECO's rates at the inception of the Rate Index Period relative to the
regional average but in no case in excess of 90% of such average;
- an opportunity for MECO to include earned savings in its cost of service
for rate making purposes for the period commencing January 2010 and
ending 20 years from the effective date of the settlement;
- a comprehensive service quality plan which provides incentives and
penalties so that service quality in the combined service territory will
be maintained and enhanced throughout the 20-year rate plan period.
Hearings on the settlement concluded in early February. An order
approving the settlement agreement in Massachusetts was received from the DTE
on March 15, 2000.
On November 29, 1999 Eastern Edison filed to increase the price of
Standard Offer Service to be effective January 1, 2000. On December 10, 1999
Eastern Edison refiled with the Department a proposal to increase the price of
Standard Offer Services from 3.4 cents per kilowatthour to 3.8 cents per
kilowatthour and to adjust its transition charge to meet the Department
requirements to maintain a 15 percent overall rate reduction. On December 17,
1999, the Department issued additional guidelines related to maintaining the 15
percent overall rate reductions. On December 22, 1999 Eastern Edison presented
a revised filing in conformance with the Department's directives. On December
30, 1999, the Department ordered that the operation of the rates and charges,
as revised by Eastern Edison, be suspended and the use thereof deferred until
January 14, 2000, unless otherwise ordered by the Department. On January 4,
2000, Eastern Edison submitted a second revised filing designed to further meet
the Department's 15 percent rate reduction requirements. The Department
approved the rates and charges proposed by Eastern Edison effective January 1,
2000. Approval of this proposal eliminated the temporary distribution rate
credit implemented on September 1, 1999.
Environmental Regulation
General: The Retail Subsidiaries and Montaup and other companies owning
generating units from which power is obtained are subject, like other electric
utilities, to environmental and land use regulations at the federal, state and
local levels. The EPA, and certain state and local authorities, have
jurisdiction over releases of pollutants, contaminants and hazardous substances
into the environment and have broad authority in connection therewith,
including the ability to require installation of pollution control devices and
remedial actions. In 1994, EUA instituted an environmental audit program for
Montaup and the Retail Subsidiaries, designed to ensure compliance with
environmental laws and regulations and to identify and reduce liability with
respect to those requirements.
Preconstruction Reviews: Federal, Massachusetts and Rhode Island legislation
and regulations require the preparation of reports evaluating the environmental
impact of large projects and of ways for limiting their adverse impact as a
prerequisite to the granting of various government permits and licenses.
Federal, Massachusetts and Rhode Island air quality regulations also require
that plans for construction or modification of fossil fuel generating
facilities (including procedures for operation and maintenance) receive prior
approval from the MADEP or RIDEM. In addition, in Massachusetts, certain
electric generation and transmission facilities will be permitted to be built
only if they are consistent with a long-range forecast of energy demand filed
by the utility concerned and approved by the Massachusetts Energy Facilities
Siting Council. In Rhode Island, siting, construction and modification of
major electric generating and transmission facilities must be approved by the
Rhode Island Energy Facility Siting Board.
Generating facilities owned or operated by Montaup and Newport as well as
those in which they have an interest, and are required to pay a share of the
costs, are also subject, like other electric utilities, to regulation with
regard to zoning, land use, and similar controls by various state and local
authorities.
Solid and Hazardous Waste Regulation: Federal, Massachusetts and Rhode Island
legislation and regulations impose requirements on the generation,
transportation, storage and disposal of hazardous and solid wastes. In
Massachusetts, the state and some of the federal requirements are implemented
and enforced by the MADEP, whereas in Rhode Island, RIDEM carries out these
activities.
Superfund Requirements: Remediation of contaminated sites is subject to
federal and state legislation and regulation. At the federal level, the
governing statute is the Comprehensive Environmental Responsibility,
Compensation, and Liability Act of 1980 (CERCLA), as amended by the Superfund
Amendments and Reauthorization Act of 1986. In Massachusetts, the superfund
statute is known as Chapter 21E, while in Rhode Island it is called the
"Industrial Property Site Remediation and Reuse Act." In addition, certain
sections of the Massachusetts and Rhode Island hazardous waste requirements are
relevant to the reporting, study, and cleanup of site contamination. Such
authorities impose liability for site contamination and spills and authorize
response by government agencies. Under these provisions, joint and several
liability may be imposed for cleanup costs upon, among others, the owners or
operators of a facility where hazardous substances were disposed, the party who
generated the substances, or any party who arranged for the disposition or
transport of the substances. Due to the nature of the business of EUA's
utility subsidiaries, certain materials are generated that may be classified as
hazardous under CERCLA, Chapter 21E and Rhode Island law. As a rule, the
subsidiaries employ licensed contractors to dispose of such materials. (See
Item 3. LEGAL PROCEEDINGS - Environmental Proceedings, for a discussion of
specific sites where such authorities have been invoked.)
Chemical Regulation: The EPA, pursuant to the Toxic Substances Control Act
(TSCA), regulates the use, storage, and disposal of polychlorinated biphenyls
(PCBs) and other dielectric fluids. Because the EUA System had owned and used
some electrical transformers containing PCBs, it is subject to EPA regulation
under TSCA. These PCB transformers have been either declassified or
disposed of in accordance with TSCA requirements. EUA currently uses
electrical equipment containing mineral oil in which there may be traces of
PCBs. Such equipment may therefore be subject to regulations pursuant to TSCA.
Potential Regulation of Electric and Magnetic Fields: A number of scientific
studies in the past several years have examined the possibility of health
effects from Electric and Magnetic Fields (EMF) that are found wherever there
is electricity. While some of the studies have indicated some association
between exposure to EMF and health effects, many others have indicated no
direct association. On October 31, 1996, the National Academy of Sciences
issued a literature review of all research to date, "Possible Health Effects of
Exposure to Residential Electric and Magnetic Fields." Its most widely
reported conclusion stated, "No clear, convincing evidence exists to show
that residential exposures to EMF are a threat to human health." Additional
studies, which are intended to provide a better understanding of EMF, are
continuing.
Some states have enacted regulations to limit the strength of EMF at the
edge of transmission line rights-of-way. The Rhode Island legislation has
enacted a statute which authorizes and directs the Rhode Island Energy Facility
Siting Board to establish rules and/or regulations governing construction of
high voltage transmission lines of 69 kv or more. In addition, in Rhode Island
an energy facility siting application, must include, when applicable, any
current independent, scientific research pertaining to EMF exposure for review
by the Board. Management cannot predict the impact if any, which
legislation(s) or other developments concerning EMF may have on the EUA System.
Water Regulation: The objective of the Federal Water Pollution Control Act
(FWPCA) is to restore and maintain the chemical, physical, and biological
integrity of the nation's surface waters, and it prohibits the discharge of
pollutants (including heat) into navigable waters without a permit. Similar
laws have been adopted in Massachusetts and Rhode Island. All wastewater
discharge permits for plants in Massachusetts are issued jointly by the EPA and
MADEP. These same agencies also regulate certain industrial stormwater
discharges. The EPA has promulgated requirements under the authority of the
FWPCA regarding the preparation of oil spill prevention, countermeasure
and control (SPCC) plans for certain oil storage facilities that are located
near a waterway. Similar requirements are imposed under the authority of the
Oil Pollution Act of 1990 and mandate the preparation of contingency plans to
prevent releases of oil into waters of the United States and to ensure that
sufficient resources are in place and ready to respond to any release of oil.
Standards have been established to control the dredging and filling or
alteration of wetlands under the FWPCA, the Massachusetts Wetlands Protection
Act, and the Rhode Island Wetlands Act, and of land alterations in close
proximity to a river under the Massachusetts Rivers Protection Act. The EPA,
the Army Corps of Engineers, RIDEM, the Rhode Island Coastal Resources
Management Council and the MADEP are pursuing a non-degradation (no loss)
policy for wetlands. In addition, the MADEP is responsible for promulgating
regulations relating to water usage and conservation, under the Massachusetts
Water Management Act, and for licensing structures (Chapter 91 licenses)
in Massachusetts waterways.
Permit Transfers: Because Montaup's Somerset Station was sold to NRG Energy
(NRG), the environmental permits covering operation of those assets were
transferred to NRG. The transfer was completed in April 1999 and no
interruption in operation or other adverse impact is expected to
occur as a result of the transfer. See Electric Industry Restructuring -
Divestiture for a discussion of Montaup's divestiture of its generating assets.
Other Requirements: The EPA and state and local authorities may, after
appropriate proceedings, require modification of generating facilities for
which construction permits or operating licenses have already been issued, or
impose new conditions on such permits or licenses, and may require that
the operation of a generating unit cease or that its level of operation be
temporarily or permanently reduced. Such action may result in increases in
capital costs and operating costs which may be substantial, in delays or
cancellation of construction of planned facilities, or in modification or
termination of operations of existing facilities.
Other activities of the EUA System from time to time are subject to the
jurisdiction of various other local, state and federal regulatory agencies. It
is not possible to predict with certainty what effects the above described
statutes and regulations or activities will have on the EUA System.
Environmental Regulation of Nuclear Power
The NRC has promulgated a variety of standards to protect the public from
radiological pollution caused by the normal operation of nuclear generating
facilities. For example, the NRC requires licensed facilities to develop plans
to respond to unexpected developments.
Under the Nuclear Waste Policy Act (NWPA), the federal government is
charged with providing facilities for the disposal or permanent storage of
civilian nuclear waste. (See Fuel for Generation above.) The NRC has
promulgated regulations for the protection of the public from radiological
dangers in connection with the disposal of nuclear waste materials.
In certain instances the NRC and the EPA have overlapping jurisdiction.
Thus, NRC regulations are supplemented by requirements imposed by the EPA under
a variety of federal environmental statutes. Those include requirements for
permits covering the discharge of pollutants (including heat) into the nation's
waters and compliance with EPA standards for so-called mixed waste (i.e.
hazardous waste which contains radioactive materials) and for certain toxic air
pollutants which include radionuclides. The EPA has also promulgated
environmental radiation protection standards for nuclear power plants to
regulate the doses of radiation received by the general public.
Environmental regulation of nuclear facilities in which the EUA System has
an interest or from which they purchase power may result in significant
increases in capital and operating costs. They could also result in delays or
cancellation of construction of planned improvements, or in modification or
termination of existing facilities.
The Year 2000 Issue
On June 30, 1999, EUA reported to the North American Electric Reliability
Council (NERC) that all of its mission critical systems were Year 2000 ready,
consistent with the recommended industry schedule published by NERC. During the
transition to the year 2000, EUA did not experience any significant problems.
There were no disruptions to operations and none of EUA's customers were
impacted as a result of Year 2000 problems. In addition, there were no
significant problems with any business systems during the transition period or
since.
EUA's Year 2000 Program successfully negated the potential impact on EUA's
computer systems and embedded systems and components that could have resulted
from a common software program code convention that utilized two digits instead
of four to represent a year. This disclosure constitutes a Year 2000 Statement
and Readiness Disclosure. It is subject to the protections afforded it as such
by the Year 2000 Information and Readiness Disclosure Act of 1998.
EUA's State of Readiness: To address potential Year 2000 issues, EUA divided
the focus of its Year 2000 Program into three major categories of business
activity: the generation and delivery of electricity to customers, the
acquisition of goods and services (including purchased power), and ongoing
general and administrative activities related to the corporate infrastructure
and support functions, which included among other things, billings and
collections.
The following types and quantities of date sensitive IT systems were identified
and remediated:
- Central Applications: 54 date sensitive items consisting of
centralized computing software that addressed major business and
operational needs were identified; 67% required repair or
replacement.
- Server Based Networks: 22 date sensitive items consisting of
networked applications, as well as supporting computing and
communications equipment were identified; 55% required repair or
replacement.
- Desktops: 48 categories of items typically consisting of personal
computer hardware and software were identified; 52% of such
categories required repair or replacement.
- Infrastructure: 44 items consisting of components of central IT
operations (e.g., the mainframe computer, its operating system and
centralized database) were identified; 57% required repair or
replacement.
- Embedded Systems and Components: 3,977 items were identified; 96%
were Year 2000 ready or inert. 4% were tested - none failed.
EUA utilized a four phased approach to address information technology (IT)
issues. The four phases were: Analysis, Remediation, Unit Testing and
Integration Testing. The Analysis phase consisted of two stages. The first
stage consisted of conducting an inventory of all products, applications and
systems, department by department. The second stage consisted of an assessment
of the risk (potential impact and likelihood of failure) of each item
identified in the inventory. Items identified as not being Year 2000 ready were
repaired or replaced during the Remediation phase. The Unit Testing phase
involved testing at the module, program and application level to assure that
each such item functioned properly after repair or replacement. Finally, in the
Integration Testing phase, dates were moved ahead, data were aged, and all date
conditions pertinent to each application or product were tested "end-to-end" to
assure that each item was tested in its final complete environment. As of June
30, 1999, each phase described above was 100% completed and all mission
critical systems were Year 2000 ready. All mission critical non-information
systems (i.e., embedded systems and components) were also 100% Year 2000 ready
as of June 30, 1999 as well.
EUA developed a process to identify and assess the Year 2000 readiness of
third parties with which it had a material relationship. First, a list of all
vendors utilized over the prior two years was developed from the accounts
payable system. Sub-lists were then developed and distributed to departments
based on the departmental allocation of charges for goods and services.
Departmental managements worked with the purchasing department to rank vendors
identified as being critical or important.
All vendors, regardless of rank, were contacted in writing requesting
information regarding their Year 2000 status. Vendors ranked as critical or
important were selected for additional inquiry, in the form of additional
written inquiry and telephone inquiries. If available, vendor literature,
regulatory filings and web sites were also reviewed. Critical vendors included
providers of a variety of goods and services, such as telecommunications,
banking and other financial services, computer products and services,
equipment, fuel and mail delivery.
As a result of this process, the purchasing department and/or the
department(s) utilizing the goods or services in question were able to confirm
to their satisfaction that all mission critical vendors and a significant
majority of the important vendors had provided adequate evidence of their
Year 2000 readiness. All remaining vendors were monitored as the process of
gathering their Year 2000 readiness information continued. This process was
essentially complete on June 30, 1999. Contingency plans were developed for
services provided by all mission critical vendors. Those plans identified
workarounds for any mission critical vendor for which there was not an
alternative source. EUA did not experience any Year 2000 vendor-related
problems during the transition period or since then.
Costs to Address EUA's Year 2000 Issues: Through December 31, 1999, EUA
incurred costs of approximately $7.5 million to address Year 2000 issues,
including approximately $4.7 million of non-incremental labor, $1.2 million of
capital expenditures and $1.6 million of consulting and other costs. The
company estimates it will incur additional costs of approximately $500,000
from January 1, 2000 through March 31, 2000, to complete its Year 2000 Program
including approximately $400,000 of non-incremental labor and $100,000 of
consulting and other costs.
Risks of EUA's Year 2000 Issues: EUA's first priority was to minimize any
potential disruptions to electric service as a result of the Year 2000. Since
the provision of electric service depends in large part on the viability of the
New England power grid, EUA actively participated on ISO/NEPOOL's Year 2000
operating and oversight committees. EUA's assessment of its own transmission
and distribution equipment and facilities indicated that the risk of failure of
this equipment did not appear to be significant.
In addition to electric service received from the New England power grid,
dependable voice and data telecommunications are also critical to EUA's ongoing
operations. EUA's internal telecommunication systems were Year 2000 ready as
of June 30, 1999. Since EUA also relies heavily on external telecommunication
systems, i.e., the local and regional telephone systems, and had identified
these providers as critical vendors, EUA had gathered extensive documentation
regarding their Year 2000 efforts and status. This included face-to-face
meetings with representatives of these companies and attendance at public
conferences sponsored by them at which they described their Year 2000 process
and progress. Each of these companies anticipated being Year 2000 ready
and devoid of major system failures. Nevertheless, EUA had provided for
several methods for maintaining adequate communications. For example, if the
regional, land-line telephone systems were not in service, EUA could rely on
mobile or cellular telephones. If those failed, EUA maintains mobile radios.
Further, all of EUA's operating locations, including EUA Service Corporation,
are linked through a captive microwave telecommunications system.
No other significant reasonably likely failure scenarios stemming solely
from problems relating to Year 2000 had been identified. EUA's most reasonably
likely Year 2000 related worst case scenario would have been the occurrence of
isolated year 2000 failures such as described above in conjunction with a
severe winter storm. However, EUA believed that such year 2000 failures
would not likely have affected whether the storm event would have a material
impact on EUA's business or financial condition. In this context, and based on
its communications with key vendors and customers and its long experience with
storm events, EUA did not anticipate significant adverse effects on its
relationships with its customers or vendors, or any resulting material adverse
effects on its business or operations.
None of the potential transition period Year 2000 risks described above
materialized. The New England power grid was stable and there were no Year
2000 related disruptions to electric service. In addition, the
telecommunication systems, both internal and external, remained viable and
functioning throughout the transition period and since. Finally, there was no
storm activity in EUA's service territories during the Year 2000 transition
period.
Year 2000 Contingency Plans: Contingency planning teams consisting of managers
and employees experienced in system reliability, disaster recovery and risk
were established and made responsible for developing contingency plans. The
overall strategy was to identify Year 2000 risks, both internal and external to
EUA, that could have a material impact on EUA's operations or financial well
being. For such risks, formal, written contingency plans were created.
Preliminary plans were developed in March 1999 and final contingency plans were
in place and ready to implement as of June 30, 1999. Although EUA had an
expanded Year 2000 team in place throughout the transition period, it was not
necessary to implement the contingency plans.
In addition to the contingency plans described above which were designed
to ensure a rapid recovery from any Year 2000 related failures, EUA had also
developed a formal, written Implementation Plan. The purpose of this plan was
to ensure that the activities necessary to maintain a clean systems environment
from July 1, 1999 through the transition weekend and into the year 2000 were
properly planned for, appropriately communicated throughout the company, and
understood by those responsible for performing the various tasks. This plan
included provisions for additional staffing during the transition weekend to
monitor mission critical systems and to resolve any Year 2000 issues, which
might arise. The Implementation Plan, which was in place as of June 30, 1999,
has been completed successfully.
Summary: The amount of effort and resources necessary to address Year 2000
issues and make EUA Year 2000 ready was significant. There were dedicated teams
in place, guided by a formal implementation plan, to ensure EUA remained Year
2000 ready throughout the transition to the year 2000. The effort expended to
prepare EUA for a successful transition to the year 2000 was an overwhelming
success. There were no significant Year 2000 disruptions to electric service
or other company operations. It is management's belief, which has been
validated by outside technical consultants and other experts, that EUA's
preparation and execution of its Year 2000 Program was successful, and
appropriate in size, scope and cost.
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. This report contains information about the Company's future
business prospects. These statements are considered "forward-looking" within
the meaning of the Private Securities Litigation Reform Act. These statements
are based on the Company's current plans and expectations and involve risks and
uncertainties that could cause actual future activities and results of
operations to be materially different from those set forth in the forward-
looking statements. The Company expressly undertakes no duty to update any
forward-looking statement.
Item 2. PROPERTIES
Power Supply
During 1999, EUA divested Somerset Station, Pawtucket Hydro facility, the
Eldred and Jepson diesel units, and its joint ownership interests in Wyman Unit
#4 and the Seabrook Nuclear Station. In addition, Montaup transferred all of
its entitlements under purchased power contracts, except for Vermont Yankee and
Pilgrim, under long term contracts (See Item 1. BUSINESS - Electric Utility
Restructuring, Generation Divestiture). The following table summarizes
Montaup's remaining generation investments and purchase power arrangements as
of December 31, 1999.
The EUA System (including retail load served by alternate suppliers)
experienced a new all-time peak demand of approximately 1,005 mw on July 19,
1999.
EUA System Capability
Generating Units in Service as of December 31, 1999
Gross Winter Max Gross Net
In System Claimed System Unit System
Service Fuel Owner Share Capability Share Sales Share
Date Unit Name Type Operator % MW MW MW MW
JOINT OWNERSHIP:
1986 Millstone 3 Nuclear Northeast
Utilities (1) 4.01% 1,140.00 45.70 45.70 0.00
SUBTOTAL: 45.70 45.70 0.00
EQUITY OWNERSHIP:
1972 Vermont Nuclear Vt. Yankee
Yankee Nuclear Power (1) 2.25% 529.08 11.90 11.90 0.00
SUBTOTAL: 11.90 11.90 0.00
PURCHASED POWER:
1968 Canal 1 No. 6 Oil Canal Electric 25.00% 566.00 141.50 141.50 0.00
Company (2)
1972 Pilgrim 1 Nuclear Entergy Nuclear 11.00% 667.48 73.42 73.42 0.00
Generation Co. (1)
1984 McNeil Wood Burlington Electric
Department (2) 15.24% 53.00 8.08 8.08 0.00
1990 OSP 1 Gas Ocean State
Power (2) 28.00% 310.00 86.80 86.80 0.00
1991 OSP 2 Gas Ocean State
Power (2) 28.00% 307.00 85.96 85.96 0.00
1991 NEA Gas Northeast Energy
Assoc. (2) 8.62% 333.43 28.74 28.74 0.00
SUBTOTAL: 424.50 424.50 0.00
HYDRO QUEBEC ENTITLEMENT:
1991 Hydro Quebec
I & II Hydro HQ/ISO-NE 4.06% 630.00 25.57 25.57 0.00
SUBTOTAL: 25.57 25.57 0.00
TOTAL GROSS SYSTEM CAPABILITY (MW) 507.68
LESS: UNIT CONTRACT SALES (MW) 507.68
TOTAL NET SYSTEM CAPABILITY 0.00
Note: See Item 1. BUSINESS Electric Utility Industry Restructuring and
Generation Divestiture for a discussion of EUA's exit from the
electric generation business.
(1) As of December 31, 1999, Montaup had entered into agreements to sell
to non-affiliated parties the output from these units through
December 31, 2000.
(2) As of December 31, 1999, Montaup transferred there purchased power
agreements to various non-affiliated parties pursuant to electric
utility restructuring settlements.
Montaup's participation in generating units of which it is not the sole
owner takes various forms including stock (equity) ownership, joint ownership
and purchase contracts. In most cases (other than short-term purchased power
contracts) the purchaser is required to pay its share (i.e., the same
percentage as the percentage of its entitlement to the output) of all of the
costs of the generating unit (whether or not the unit is operating) including
fixed costs, operating costs, costs of additional construction or modification,
costs associated with condemnation, shutdown, retirement, or decommissioning of
the unit, and certain transmission charges. Under its contracts with Maine
Yankee, Connecticut Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic and, under its agreements relating to Phase II of
the interconnection with Hydro-Quebec, Montaup may be called upon to provide
additional capital and/or other types of direct or indirect financial support.
(See Item 1. BUSINESS - Nuclear Power Issues.) (See also Item 1. BUSINESS -
Electric Utility Industry Restructuring regarding Montaup's disposition of its
generating assets.)
Other Property
The EUA System owns approximately 7,900 miles of transmission and
distribution lines and approximately 84 substations located in the cities and
towns served.
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 Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA, Notes to Consolidated Financial Statements contained herein
for the year ended December 31, 1999, regarding encumbrances.
Item 3. LEGAL PROCEEDINGS
Rate Proceedings
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 (PRP) under Massachusetts law with respect to a condition of
soil and ground water contamination at a site 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
other facilities from the early 1960s and until 1984. Among the contaminants
apparently released at the site were PCBs. The PRPs, including Blackstone,
performed site studies and proposed a remedial action plan which was approved
by the DEQE several years ago. The remediation option selected was
solidification of onsite material. However, as a result of a risk assessment
required under MADEP's current regulations, the PRPs may instead choose to cap
the site with the cost of remediation ranging from $250,000 for capping to
$600,000 for solidification. Blackstone is alleged to be the fifth ranked
generator, and its estimated 2% share allocation is considerably less than the
shares of the four largest contributors at the site. In 1997, the PRPs
resolved outstanding issues with the MADEP relative to the status of the site
under the current Massachusetts Contingency Plan (MCP). A Phase II site study
has been completed and site remediation should be underway in the near future;
Blackstone's share of these costs is expected to be minimal.
2. On July 14, 1987, the Commonwealth of Massachusetts (the
Commonwealth), on behalf of the MADEP, filed a cost recovery action pursuant
to CERCLA and Massachusetts General Law Chapter 21E against Blackstone in the
United States District Court for the District of Massachusetts (District
Court). The Complaint seeks $2.2 million in costs incurred by the MADEP in the
cleanup of an alleged coal gasification disposal waste site at Mendon Road in
Attleboro, Massachusetts. Blackstone has contested the MADEP's cost recovery
action, arguing, inter alia, that the ferric ferrocyanide (FFC) waste removed
from the Mendon Road site was not "hazardous" within the meaning of CERCLA or
Massachusetts General Laws Chapter 21E, and that the MADEP's cleanup actions
were inconsistent with the National Contingency Plan (NCP). On November 25,
1991, the District Court held that the waste was "hazardous" within the meaning
of both statutes and on December 20, 1992, the District Court held Blackstone
and a co-defendant, the Courtois Sand & Gravel Co. (Courtois) liable for an
undetermined amount of cleanup costs. The District Court remanded the case to
the MADEP to supplement the administrative record with Blackstone's oral and
written comments concerning the cleanup. On March 19, 1993, Blackstone made an
oral presentation to the MADEP and on April 19, 1993, Blackstone submitted
written comments. On December 13, 1994, the District Court issued a judgment
against Blackstone, finding Blackstone liable to the Commonwealth for the full
amount of response costs incurred by the Commonwealth in the cleanup of the
Mendon Road site. The judgment also found Blackstone liable for interest and
litigation expenses calculated to the date of judgment. The total liability at
December 31, 1994 was approximately $5.9 million, including approximately $3.6
million in interest which had 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 appealed the District Court's judgment and on October 6, 1995,
the First Circuit Court of Appeals vacated the District Court's $5.9 million
judgment. Rather than remand the case to the District Court for a trial on the
issue of whether 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. On January 9, 1997, Blackstone met
with representatives of EPA and the Commonwealth to discuss the procedure EPA
would follow in resolving the FFC issue. In January 1997, Blackstone submitted
written comments which were followed by the Commonwealth's written reply in
March 1997. Both parties submitted additional memoranda to the EPA during the
remainder of the year but the EPA has not yet made a determination as to
whether FFC is a hazardous substance. Given the present posture of the case,
Blackstone may not be liable for the Commonwealth's Mendon Road cleanup costs,
but further court proceedings are likely.
In October 1987, without admitting liability, Blackstone entered into an
Administrative Consent Order with the MADEP regarding the Mendon Road site and
another alleged coal gasification site discovered by the MADEP approximately
1/4 mile away in Attleboro known as the Lawn Street site. Under the Order,
Blackstone agreed to perform preliminary assessments at both sites in order to
determine what remediation, if any, is necessary at the sites. On August 15,
1996, Blackstone entered into an Amended Administrative Consent Order to
complete investigation and cleanup of these sites pursuant to the revised
Massachusetts Contingency Plan, and in 1998 Blackstone purchased properties at
both sites to facilitate site closure. Investigation of the Mendon Road site
was completed in 1998, and it was concluded that no future remedial action will
be required at the site. Investigation and cleanup of the Lawn Street site was
substantially completed in 1999. Final reports, required by the Massachusetts
Contingency Plan to close the site, will be completed in the first quarter of
2000.
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 and several of its affiliated companies
(Stone & Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley)
for any damages incurred by Blackstone regarding the Mendon Road site. The
District Court has denied motions to dismiss the complaint filed by Stone &
Webster and Valley in 1994. This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is a hazardous substance.
On March 22, 1996, Blackstone and Valley filed a Complaint in the Rhode
Island District Court seeking contribution from Stone & Webster for the cleanup
of the Tidewater site mentioned below. On June 27, 1997, that case was stayed
for the same reasons that the Massachusetts case was stayed.
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 CERCLIS list in 1987. The site includes
the Tidewater Plant owned by Valley Gas Company (approximately 8 acres), the
No. 1 Station owned by Blackstone (approximately 12 acres), and land formerly
owned by Blackstone that was sold in 1968 to the City of Pawtucket
(approximately 8 acres). RIDEM told Blackstone that the site contained
hazardous materials and petroleum-contaminated soils due to tanks formerly
located at the site. In December, 1990, after obtaining approval from RIDEM,
Blackstone removed approximately 1,000 tons of soil from the site. On
September 3, 1991, RIDEM initiated a site investigation which constitutes the
second step in a site screening and assessment process established by the EPA
to determine whether the site should be listed on the National Priorities List
(NPL) as a Superfund site. On February 3, 1993, RIDEM notified Blackstone that
it required further assessment and evaluation of site conditions to determine
if the site qualifies for review pursuant to the Hazard Ranking System. On
September 12, 1995, RIDEM notified Blackstone and Valley of their
responsibility regarding the release of hazardous substances at the Tidewater
Plant site. RIDEM ordered Blackstone and Valley to conduct an environmental
study of the Tidewater Plant site and adjoining lots. On the adjacent lots are
the Francis J. Varieur Elementary School and the Max Read Field athletic
facility and ball fields. Blackstone and Valley have entered into an
agreement to share the expenses of conducting the study and/or retaining an
environmental consulting firm to conduct a remedial investigation. A work plan
was submitted to RIDEM in April 1996 and it was approved on June 14, 1996.
Preliminary field work was completed in September 1996 and additional sampling
required by RIDEM was completed in 1997. In 1998 RIDEM completed its review of
the draft Remedial Investigation Report and followup documents and requested
additional information. The site investigation report was completed in 1999
and identified elevated levels of contaminants over an extended area of both
the surface and subsurface. A risk assessment and feasibility study will be
conducted in 2000.
4. On September 12, 1995, RIDEM demanded payment of $296,000 which
represents the amount of money plus interest RIDEM expended to clean up oxide
box waste at the Cumberland, Rhode Island site. Following extended discussions
and negotiations with legal counsel on behalf of RIDEM, Blackstone reached an
agreement with RIDEM to escrow approximately $296,000 in an interest-bearing
account pending the outcome of EPA's remand proceedings to determine whether
FFC is a hazardous substance. This money has been placed in an interest-
bearing escrow account by Blackstone pending the outcome of EPA's proceedings
for the Mendon Road site described above. If EPA finds that FFC is not a
hazardous substance, Blackstone will be able to recover the escrowed funds on
the ground that RIDEM's cleanup of the site in 1986 was not required by law.
In 1998, representatives of Blackstone and RIDEM discussed implementation of
certain actions under Rhode Island regulations to close the site. In
accordance with these discussions, Blackstone may initiate an investigation in
2000 to determine whether RIDEM's 1986 removal action meets current RIDEM
regulations for sight closure.
5. On February 11, 1997, RIDEM ordered Blackstone and Valley to conduct a
site assessment of Valley's Woonsocket property (the Hamlet Avenue, Woonsocket
site), which is the site of a former manufactured gas plant owned by
Blackstone's and Valley's predecessor, Blackstone Valley Gas & Electric
Company, and the predecessor of that company, which was Woonsocket Gas Company.
The site also includes an active electric substation, and a former electric
generating facility previously owned by Blackstone Valley Gas & Electric
Company and a predecessor, Woonsocket Electric Machine and Power Company. The
entire site consists of several adjoining properties encompassing approximately
nine acres. Blackstone and Valley submitted a Work Plan on June 16, 1997.
RIDEM approved the Work Plan in 1998. Phase I studies were undertaken in 1998;
further field work was required by RIDEM under Phase I, and that work was
completed in 1999. Blackstone expects to begin work on the risk assessment and
feasibility study in 2000. Costs associated with these activities are
estimated to be approximately $200,000.
6. In accordance with the regulations implementing Chapter 21E, Montaup
notified MADEP on October 2, 1998 of contamination at the South Somerset
property resulting from prior permitted deposits of ash. On November 17, 1998,
MADEP issued a Notice of Responsibility to Montaup with respect to
investigation and remediation of the contamination at the South Somerset site.
Montaup expects to complete the remediation work during 2000. The estimated
cost of cleanup work is $800,000.
7. In May 1989, the U.S. Environmental Protection Agency issued an
Administrative Consent Order to Bay State Gas Company to conduct contaminant
removal activities under CERCLA at a site know as Lot 55 in Brockton,
Massachusetts. These removal actions, which were completed in 1990, impacted
an adjacent, downgradient parcel (Lot 94-1) owned by Eastern Edison.
The removal work included the installation of an engineered cap over fill
material and the erection of a security fence on part of Lot 94-1 without the
prior knowledge or consent of Eastern Edison.
Subsequent to these actions, in 1998, MADEP required Bay State Gas to
conduct further investigations in accordance with regulations implementing MGL
Chapter 21E. In October 1998, Bay State Gas informed Eastern Edison for the
first time of the prior work conducted on Lot 94-1. It also requested access
to the parcel in order to conduct these further investigations. The
investigation now being undertaken by Bay State Gas Company includes the
installation of groundwater monitoring wells and the collection of soil,
surface water, and groundwater samples. Until these further investigations
have been completed, it is not possible to determine the need for, or extent
of, response actions at Lot 94-1. However, it should be noted that the
regulations implementing Chapter 21E provide relief for landowners located
downgradient from the source of groundwater contamination.
Blackstone has notified certain liability insurers and has filed claims
with respect to the Mendon Road site. In addition, Blackstone submitted claims
to various carriers with respect to the Mendon Road, Tidewater, Lawn Street,
Cumberland, and Hamlet Avenue sites.
Blackstone, Montaup and Eastern Edison are not able 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 EUA System Companies in
such cases to provide notice to liability insurers and to make claims.
However, it is not possible at this time to predict whether the insurance
carriers will honor such claims, or whether such claims can be enforced against
them. With respect to any liability under CERCLA, and state counter parts to
that statute, 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, 1999, the EUA System has incurred costs of
approximately $9.5 million (excluding the Mendon Road judgment) in connection
with the foregoing environmental matters. These amounts have been financed
primarily by internally generated cash. EUA estimates that additional
expenditures (excluding the Mendon Road judgment) may be incurred through 2000
of up to $2.2 million, $1.4 million of which relates to Blackstone, and
$800,000 which relates to Montaup.
As a general matter, the EUA System will seek to recover costs relating to
environmental proceedings in their rates. Blackstone is currently amortizing
all of its incurred costs over a five-year period consistent with prior
regulatory recovery periods and is recovering certain of those costs in rates.
Estimated amounts after 2000 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.
Other Proceedings
On December 15, 1995, Eastern Edison exercised its right to terminate a
Power Purchase Agreement (PPA) entered into with the Meridian Middleboro
Limited Partnership (MMLP) and a related entity on September 20, 1993. In
February and May of 1996, MMLP made demands for over $25 million under the
termination provision of the PPA. On June 17, 1996, Eastern Edison responded
to MMLP's demand stating that if Eastern Edison were to be liable for payments,
only approximately $170,000 would be due under the termination provision. On
July 18, 1996, Eastern Edison filed a declaratory judgement action in Suffolk
Superior Court in Boston, Massachusetts against MMLP seeking a declaration of
the rights of the parties under the PPA. MMLP's response to the complaint,
filed on August 8, 1996, included counterclaims in excess of $20 million and a
request for treble damages. Eastern Edison paid MMLP, under a reservation of
rights, approximately $192,000 as the amount Eastern Edison might owe to MMLP.
On July 20, 1998, the judge granted limited summary judgement in favor of
Eastern Edison Company, finding that MMLP had not done an audit by an
independent auditor as required under the subject agreement. While being
challenged, an "audit" has been done. The trial commenced February 23, 2000.
Eastern Edison will continue to defend itself from the counterclaims, and
cannot determine the outcome of this proceeding at this time.
Since early 1997, fourteen plaintiffs brought suits against numerous
defendants, including EUA, for injuries and illness allegedly caused by
exposure to asbestos over approximately a thirty-year period, at various
premises, including some owned by EUA companies. The total damages claimed in
all of these complaints is $34 million in compensatory and punitive damages,
plus exemplary damages and interest and costs. Each complaint names between
fifteen and twenty-eight defendants, including EUA. These complaints have been
referred to the applicable insurance companies. Counsel has been retained by
the insurers and is actively defending all cases. Six cases have been
dismissed as against EUA companies. EUA cannot predict the ultimate outcome of
this matter at this time.
A pending class action, filed on March 2, 1998, in the Massachusetts
Supreme Judicial Court naming all Massachusetts electric distribution
companies, including Eastern Edison, and certain Massachusetts state agencies
as defendants, seeks to invalidate certain sections of the Electric Utility
Restructuring Act of 1997. The Act directs the Massachusetts Department of
Telecommunications and Energy to impose mandatory charges on all electricity
sold to customers, except those served by a municipal lighting plant, to fund
energy efficiency activities and to promote renewable energy projects. In
addition to declaratory judgment, plaintiffs seek remittance of monies paid by
customers to each distribution company by customers for renewable projects
together with any interest earned. The outcome of this class action is unknown
at this time however, Eastern Edison is vigorously defending the lawsuit.
See Item 1. BUSINESS - Fuel for Generation for a discussion of legal
actions filed against the DOE. Also, see Item 1. BUSINESS - General-EUA
Cogenex for a discussion of a legal matter related to cogeneration units
formerly owned by EUA Cogenex.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
PART II
Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Quarterly Common Share Information (unaudited)
Dividends
Declared per
Common Market Price
Share High Low
FOR THE QUARTERS
ENDED 1999:
December 31 $0.415 30 11/16 29 7/8
September 30 0.415 30 1/16 29 1/4
June 30 0.415 29 9/16 28 1/4
March 31 0.415 31 26 7/8
FOR THE QUARTERS
ENDED 1998:
December 31 $0.415 28 1/4 24 5/8
September 30 0.415 26 15/16 24 5/16
June 30 0.415 27 3/8 24 7/16
March 31 0.415 27 11/16 23 11/16
EUA's stock is traded on the New York and Pacific Stock Exchanges. As of
February 1, 2000 there were 9,332 EUA common shareholders of record. The
closing price of EUA's Common Shares as reported by the Wall Street Journal on
March 20, 2000 was $31.3125 per share.
Item 6. SELECTED CONSOLIDATED FINANCIAL DATA
(Unaudited)
Years Ended December 31,
(In thousands except Common Share Data)
INCOME STATEMENT DATA: 1999 1998 1997 1996 1995
Operating Revenues $553,767 $538,801 $568,513 $527,068 $563,363
Operating Income (1) 55,267 60,123 58,807 55,841 71,728
Consolidated Net Earnings (1) 16,918 34,710 37,960 30,614 32,626
BALANCE SHEET DATA:
Plant in Service 735,944 1,000,243 1,079,361 1,067,056 1,037,662
Construction Work in Progress 9,033 5,151 5,538 3,839 7,570
Gross Utility Plant 744,977 1,005,394 1,084,899 1,070,895 1,045,232
Accumulated Depreciation and
Amortization 290,962 353,780 376,722 350,816 324,146
Net Utility Plant 454,015 651,614 708,177 720,079 721,086
Total Assets 1,467,853 1,302,638 1,270,752 1,257,029 1,206,130
CAPITALIZATION:
Long-Term Debt - Net 104,235 310,346 332,802 406,337 434,871
Redeemable Preferred Stock - Net 28,360 27,995 27,612 27,035 26,255
Non-Redeemable Preferred Stock - Net 6,900 6,900 6,900 6,900 6,900
Common Equity 358,039 373,674 373,467 371,813 375,229
Total Capitalization 497,534 718,915 740,781 812,085 843,255
Short-Term Debt 143,955 63,574 61,484 51,848 39,540
COMMON SHARE DATA:
Consolidated Basic and Diluted Earnings
per Average Common Share (1) $0.83 $1.70 $1.86 $1.50 $1.61
Average Number of Shares
Outstanding 20,435,997 20,435,997 20,435,997 20,436,217 20,238,961
Return on Average Common Equity 4.6% 9.3% 10.2% 8.2% 8.8%
Market Price - High 31 28 1/4 26 5/8 24 1/4 25
- Low 26 7/8 23 11/16 16 3/8 14 3/4 21 1/2
- Year-End 30 5/16 28 1/4 26 1/4 17 3/8 23 5/8
Dividends Paid per Share $1.66 $1.66 $1.66 $1.645 $1.585
(1) See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS for details of one-time impacts to
earnings.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Merger Update
On February 1, 1999, Eastern Utilities Associates (EUA) and New England
Electric System (NEES) announced a merger agreement under which NEES will
acquire all outstanding shares of EUA for $31 per share in cash. The merger
agreement, which is subject to the approval of various regulatory agencies,
valued EUA's equity at approximately $634 million, which represents a 23%
premium above the price of EUA shares on December 4, 1998, the last trading day
before other regional merger announcements affected EUA's share price. EUA
shareholders will continue to receive dividends at the current level, as
declared by the Board of Trustees, until the closing of the merger.
The closing of the merger is expected to occur by April 2000, after SEC
approval is received. The merger agreement contains an upward price adjustment
if the merger does not close within six months from May 17, 1999, the date EUA
shareholders approved the merger plan. Therefore, since November 17, 1999,
NEES will pay an additional $0.003 per day per share for EUA's outstanding
common stock until the merger closes, up to a maximum price of $31.495 per
share. If the merger were to close by March 31, 2000, the price paid for EUA
shares would be $31.405 per share.
On May 5, 1999, EUA and NEES filed a joint application with FERC seeking
FERC approval and related waivers or authorizations to merge EUA and NEES and
to subsequently merge and consolidate the complimentary operating companies of
EUA and NEES. With its approval on September 29, 1999, FERC concluded that the
proposed merger will not adversely affect competition, rates or regulation, and
that the merger is in the public's best interest.
On May 20, 1999, EUA and NEES jointly filed a rate consolidation plan with
the Rhode Island Public Utilities Commission reflecting consolidated rates for
each company's Rhode Island subsidiaries, indicating savings to Rhode Island
customers of an estimated $100 million through 2004. A settlement agreement
was reached on January 26, 2000. A similar filing was made for EUA's and
NEES's Massachusetts subsidiaries on April 30, 1999 with the Massachusetts
Department of Telecommunications and Energy (DTE) indicating savings of over
$170 million over the next ten years. A settlement agreement was reached on
the Massachusetts filing on November 29, 1999. Hearings on both settlements
were completed in February 2000. An order approving the settlement agreement
in Massachusetts was received from the DTE on March 15, 2000. An order
approving the Rhode Island settlement agreement is expected to be issued close
to the time of the issuance of this report.
On July 19, 1999, a Voluntary Early Retirement Program (VERP) was offered
to certain of EUA's and NEES's employees who have completed at least ten years
of service and will be at least fifty-five years of age by December 31, 2000.
The VERP allows an eligible employee to retire and receive enhanced pension
benefits. The VERP offer was accepted by 82% of eligible employees.
An eligible employee may only retire after the merger closes under the VERP.
On October 12, 1999, details of a Severance Plan were distributed. The
Severance Plan will provide benefits and provisions for eligible non-union
employees who are involuntarily terminated due to the merger. At the same
time, the Company also offered a Limited Hardship Early Decision Severance Plan
(LHEDO) to designated non-union employees who choose to terminate their
employment with EUA rather than be considered for a position in the merged
company. Under the LHEDO, employees will receive an additional eight weeks of
severance pay for accepting the offer. Forty-three percent of the
eligible employees have accepted the LHEDO. Because the VERP and LHEDO are
contingent on the completion of the merger, which is subject to regulatory
approvals, a liability for expenses related to the VERP and LHEDO has not yet
been recorded.
On February 25, 2000 the Nuclear Regulatory Commission (NRC) approved the
merger. This approval was necessary because of Montaup's ownership interest in
the Millstone 3 and Vermont Yankee nuclear generating units. Montaup also has
ownership interests in the Connecticut Yankee, Maine Yankee, and Yankee Atomic
units which are permanently retired.
On February 1, 1999, Eastern Utilities Associates (EUA) and New England
Electric System (NEES) announced a merger agreement under which NEES will
acquire all outstanding shares of EUA for $31 per share in cash. The merger
agreement, which is subject to the approval of various regulatory agencies,
valued EUA's equity at approximately $634 million, which represents a 23%
premium above the price of EUA shares on December 4, 1998, the last trading day
before other regional merger announcements affected EUA's share price. EUA
shareholders will continue to receive dividends at the current level, as
declared by the Board of Trustees, until the closing of the merger.
The closing of the merger is expected to occur by April 2000. The merger
agreement contains an upward price adjustment if the merger does not close
within six months from May 17, 1999, the date EUA shareholders approved the
merger plan. Therefore, since November 17, 1999, NEES will pay an additional
$0.003 per day per share for EUA's outstanding common stock until
the merger closes, up to a maximum price of $31.495 per share. If, as
expected, the merger closes by March 31, 2000, the price paid for EUA shares
would be $31.405 per share.
On May 5, 1999, EUA and NEES filed a joint application with FERC seeking
FERC approval and related waivers or authorizations to merge EUA and NEES and
to subsequently merge and consolidate the complimentary operating companies of
EUA and NEES. With its approval on September 29, 1999, FERC concluded that the
proposed merger will not adversely affect competition, rates or regulation, and
that the merger is in the public's best interest.
On May 20, 1999, EUA and NEES jointly filed a rate consolidation plan with
the Rhode Island Public Utilities Commission reflecting consolidated rates for
each company's Rhode Island subsidiaries, indicating savings to Rhode Island
customers of an estimated $100 million through 2004. A settlement agreement
was reached on January 26, 2000. A similar filing was made for EUA's and
NEES's Massachusetts subsidiaries on April 30, 1999 with the Massachusetts
Department of Telecommunications and Energy (DTE) indicating savings of over
$170 million over the next ten years. A settlement agreement was reached on
the Massachusetts filing on November 29, 1999. Hearings on both settlements
were completed in February 2000. Orders approving the settlement agreements
are expected to be issued close to the time of the issuance of this report.
On July 19, 1999, a Voluntary Early Retirement Program (VERP) was offered
to certain of EUA's and NEES's employees who have completed at least ten years
of service and will be at least fifty-five years of age by December 31, 2000.
The VERP allows an eligible employee to retire and receive enhanced pension
benefits. The VERP offer was accepted by 82% of eligible employees.
An eligible employee may only retire after the merger closes under the VERP.
On October 12, 1999, details of a Severance Plan were distributed. The
Severance Plan will provide benefits and provisions for eligible non-union
employees who are involuntarily terminated due to the merger. At the same
time, the Company also offered a Limited Hardship Early Decision Severance Plan
(LHEDO) to designated non-union employees who choose to terminate their
employment with EUA rather than be considered for a position in the merged
company. Under the LHEDO, employees will receive an additional eight weeks of
severance pay for accepting the offer. Forty-three percent of the
eligible employees have accepted the LHEDO. Because the VERP and LHEDO are
contingent on the completion of the merger, which is subject to regulatory
approvals, a liability for expenses related to the VERP and LHEDO has not yet
been recorded.
On February 25, 2000 the Nuclear Regulatory Commission (NRC) approved the
merger. This approval was necessary because of Montaup's ownership interest in
the Millstone 3 and Vermont Yankee nuclear generating units. Montaup also has
ownership interests in the Connecticut Yankee, Maine Yankee, and Yankee Atomic
units which are permanently retired.
1999 Operations Overview
Consolidated net earnings for 1999 were $16.9 million, or 83 cents per
share, on revenues of $553.8 million, a 51.3% decrease from 1998 earnings of
$34.7 million on revenues of $538.8 million. Results for 1999 include non-
recurring after-tax charges made in the second and fourth quarters of 1999
related to the discontinuance of certain of EUA's energy related activities and
the benefit related to the reversal of previously established estimated tax
liabilities for the 1991 through 1995 income tax audits. 1998 results include
the impacts of the EUA Cogenex Settlement and tax audit adjustments. These
items are discussed below and listed in the following table.
Net Earnings and Earnings Per Share by business unit for 1999 and 1998 were as
follows:
1999 1998
Net Earnings Earnings Net Earnings Earnings
(Loss) (Loss) (Loss) (Loss)
(000's) Per Share (000's) Per Share
Core Electric Business $35,534 $1.74 $35,160 $1.72
Energy Related Business (2,980) (0.14) (792) (0.04)
Corporate (606) (0.03) 541 0.03
From Operations 31,948 1.57 34,909 1.71
Energy Related After-tax
Charges (16,658) (0.82)
Cogenex Settlement (2,062) (0.10)
Tax Audit Adjustments 1,628 0.08 1,863 0.09
Consolidated $16,918 $0.83 $34,710 $1.70
Major impacts on earnings by business unit are described in the following
paragraphs.
Energy Related Asset Adjustments: 1999 results include non-recurring after-
tax charges made in the second and fourth quarters of 1999 totalling $16.7
million, or 82 cents per common share, related to the discontinuance of certain
of EUA's energy related activities. These charges were consistent with EUA's
efforts in evaluating its investments in energy related projects, and were a
result of several pending sales offers and completed sales for its interest in
certain of these investments. These non-recurring charges have settled future
uncertainty associated with these investments and are as follows:
EUA BIOTEN had previously executed an agreement with the management
of BIOTEN Partnership to, among other things, extend the right of its
management to purchase the assets of BIOTEN Partnership. As a result
of BIOTEN Partnership management's inability to close on this
purchase option, BIOTEN Partnership was dissolved, and its assets
were distributed to EUA BIOTEN. EUA Energy in turn recorded an
after-tax charge to its earnings of approximately $9.4 million in the
second quarter of 1999. EUA BIOTEN is currently reviewing its options
for disposing of the assets of BIOTEN Partnership.
On September 30, 1999 EUA Energy sold certain of Renova LLC's assets
to its management. As a result, an after-tax charge of
approximately $3.5 million was recorded for this anticipated sale in
the second quarter of 1999 based on a tentative agreement. This
transaction did not have an impact on third quarter 1999 earnings.
On August 30, 1999, EUA TransCapacity, sold all of its assets in
TransCapacity L.P. and dissolved TransCapacity L.P. EUA Energy will
not have any further obligations or commitments to TransCapacity
L.P., its employees, or its successor. The after-tax loss of
$900,000 in the third quarter of 1999 on this transaction was offset
by previously-established estimated liabilities at EUA's parent
company.
As of June 28, 1999, the management of EUA Cogenex decided to divest
certain of its businesses and activities including Citizens, and the
EUA Day and DayMetrix divisions. EUA Cogenex recorded an after-tax
charge of $2.9 million in the second quarter of 1999 as a result of
this anticipated sale and cessation of continued development of the
DayMetrix division. In addition, the completion of the sale of the
assets of the EUA Day division of EUA Cogenex resulted in an after-
tax charge of approximately $1.0 million in the fourth quarter of
1999. EUA Cogenex has hired an investment banker to assist in the
possible sale of Citizens. There can be no assurance that EUA
Cogenex will consummate a sale of Citizens.
Cogenex Settlement: EUA Cogenex recorded an after-tax charge of $2.1 million
to earnings related to an arbitration panel's decision in a matter involving
the 1995 sale of a portfolio of cogeneration units by EUA Cogenex to
Ridgewood/Mass Power Partners, et al (Ridgewood). Ridgewood claimed that
financial and other warranties in the purchase and sale agreement had been
breached. EUA Cogenex entered counterclaims seeking recovery of costs of
certain services performed for Ridgewood. The arbitration panel found for the
buyer on some of the warranty claims, and awarded damages of approximately $2.6
million plus interest. EUA Cogenex was awarded approximately $400,000 plus
interest on its counterclaim. EUA Cogenex paid the arbitration panel's net
award less interest and recorded this charge to earnings during the fourth
quarter of 1998. In addition, Ridgewood claimed attorney fees and additional
interest. In the second quarter of 1999, EUA Cogenex settled with Ridgewood on
the interest and legal fees, and accordingly recorded an after-tax charge to
earnings of approximately $700,000.
Tax Audit Adjustments: In January 1997, the Internal Revenue Service (IRS)
issued a report in connection with its examination of the consolidated federal
income tax returns of EUA for 1992 and 1993. This report included 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 in 1992 relating to EUA Power's Common and Preferred Stock that was
redeemed in 1993. EUA filed an administrative appeal contesting the IRS
position. In January 1999, EUA reached an understanding with the IRS Appeals
Office concerning settlement of this matter. Adjustments to EUA's estimated
tax liabilities related to this and other items resulted in a net $1.9 million
addition to fourth quarter 1998 earnings.
During 1999, the IRS completed the 1991 through 1995 federal income tax
audit and issued final reports. The completion of final audits through 1995
settled all outstanding issues related to prior tax years. Accordingly, in the
fourth quarter of 1999, EUA adjusted previously established estimated tax
liabilities resulting in a net $1.6 million addition to earnings.
Operating Revenues
Total Operating Revenues by business unit for 1999, 1998 and 1997 were as
follows:
($ in millions) 1999 1998 1997
Core Electric $499.7 $480.1 $506.7
Energy Related 54.1 58.7 61.8
Corporate - - -
Total $553.8 $538.8 $568.5
Core Electric Revenues increased approximately $19.6 million in 1999.
Generation related revenues increased approximately $16.4 million as a result
of the assignment of entitlements from certain power contracts to third parties
and associated repurchases and sale of energy to satisfy standard offer
requirements. Offsetting this increase were the impacts of rate reductions to
Massachusetts retail customers, pursuant to electric industry restructuring
legislation and settlement agreements effective March 1, 1998 and a reduction
in wholesale rates as prescribed in these settlement agreements. Distribution
related revenues increased $3.2 million. The impacts of increased primary
kilowatthour (kWh) sales in 1999, and a distribution rate increase in Rhode
Island effective in the second quarter of 1999 were partially offset by
decreased conservation and load management (C&LM) recoveries of approximately
$500,000 and a reduction in other operating revenue. Core Electric Revenues
decreased by $26.6 million in 1998 due to the following: Generation related
revenues decreased by $24.6 million as a result of rate reductions to all of
EUA's retail customers, pursuant to electric industry restructuring legislation
and settlement agreements effective January 1, 1998, and March 1, 1998, in
Rhode Island and Massachusetts, respectively. Of this decrease, $21.5 million
relates to decreased fuel and purchased power expenses in 1998. The remaining
change in generation related revenues was due to the net impacts of rate
reductions and accrued revenues as prescribed in the previously mentioned
settlement agreements. Distribution revenues decreased by $4.2 million in 1998
due to the net impacts of restructured rates, a 1.7% increase in primary kWh
sales and a $2.2 million increase in C&LM recoveries.
Energy Related Revenues decreased by $4.6 million in 1999 primarily due to
decreased EUA Cogenex project sales of $6.7 million and decreased installation
and fabrication revenues of $2.8 million, offset by increased paid-from-savings
revenues of $4.0 million. Energy Related Revenues decreased by $3.1 million in
1998 due primarily to decreased EUA Cogenex project sales of $8.1 million
offset by increased paid-from-savings revenues and installation and fabrication
revenues totalling $5.6 million.
Core Electric Business kWh Sales
Primary kWh sales of electricity by EUA's Core Electric Business unit
increased approximately 4.5% in 1999 compared to 1998. This change was led by
increases of 6.4% and 4.7% in the residential and commercial classes,
respectively. These increases are the result of the continued strength of the
regional economy and warmer weather, particularly in the summer months of 1999.
Primary kWh sales increased approximately 1.7% in 1998 compared to 1997.
Total energy sales increased 9.5% in 1998, due mainly to increased sales to the
New England Power Pool (NEPOOL) and increased short-term unit contract energy
sales.
Percentage changes in kWh Sales by class of customer for the past two years
were as follows:
Percent
Increase (Decrease)
from Prior Year
1999 1998
Residential 6.4 0.3
Commercial 4.7 2.2
Industrial 1.5 2.9
Other (2.8) 4.9
Total Primary Sales 4.5 1.7
Other Electric Utilities* - (100.0)
Losses and Company Use 13.9 13.0
Total System Requirements 5.0 0.5
Unit Contracts* (43.6) 71.5
Total Energy Sales (4.7) 9.5
* Effective January 1998, Middleboro and Pascoag are no longer contract demand
customers of Montaup. Energy sales to these customers are now included with
unit contracts.
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 50% of total operating expenses in 1999.
Fuel and Purchased Power expenses increased approximately $39.0 million or
18.7% in 1999 compared to 1998. This increase was primarily due to
aforementioned assignments of entitlements from certain power contracts which
resulted in repurchases of energy to satisfy standard offer requirements and,
subsequent to the sale of Montaup's owned generating units, purchases from
third parties replaced energy requirements previously supplied by those owned
units. This increase was compounded by a 4.5% increase in kWh sales.
Fuel and Purchased Power expense of the Core Electric Business decreased
by approximately $21.5 million or 9.3% in 1998. Increased nuclear generation
and a 17.1% decrease in the cost of fossil fuels resulted in an 18.7% decrease
in the average cost of fuel compared to 1997, offset by a 9.5% increase in
total energy generated and purchased in 1998 compared to 1997. This decrease
was also due to decreased billings from the Maine Yankee, Connecticut Yankee
and Pilgrim Nuclear units aggregating approximately $8.5 million, and from
Ocean State Power (OSP) of approximately $1.9 million.
Other Operation and Maintenance (O&M): O&M expenses for 1999 decreased by
approximately $10.1 million or 5.7% compared to 1998. Total O&M expenses are
comprised of three components: Direct Controllable, Indirect and Energy
Related.
O&M expenses by component for 1999, 1998 and 1997 were as follows ($ in
millions):
1999 1998 1997
Direct Controllable $81.9 $87.7 $89.1
Indirect 36.2 40.5 51.1
Energy Related 47.9 47.9 52.7
Total O&M $166.0 $176.1 $192.9
Direct Controllable expenses of our Core Electric and Corporate Business
units represent 49.4% of total 1999 O&M expenses and include expense items such
as salaries, fringe benefits, insurance and maintenance. In 1999, direct
expenses decreased approximately $5.8 million compared to 1998. Decreased
expenses since the sale of Montaup's Somerset plant in April 1999 were
partially offset by impacts of adjustments to incentive plan accruals in the
first quarter of 1999 and non-recurring expense credits related to billings to
Maine utilities for EUA's storm restoration support in February 1998. In 1998,
direct expenses decreased approximately $1.4 million compared to 1997. This
change is primarily the result of increased expenses in 1997 related to an
April 1997 storm which struck Eastern Edison's service territory.
Indirect expenses include items over which we have limited short-term
control. Indirects include such expense items as O&M expenses related to
Montaup Electric Company's (Montaup) joint ownership interests in generating
facilities such as Millstone 3 (see Note H of Notes to Consolidated Financial
Statements for other jointly-owned units), power contracts where transmission
rental fees are fixed and C&LM expenses that are fully recovered in revenues.
Indirect expenses decreased by approximately $4.3 million in 1999 compared to
1998. Jointly owned units expenses decreased approximately $6.1 million,
largely due to decreased expenses of Canal 2 after the sale of the unit in
December 1998. In addition, C&LM expenses decreased approximately $600,000 in
1999. Offsetting these decreases were increased pension expenses of
approximately $1.1 million as a result of a re-estimate of the pension
liability of Key Executive Incentive Plans and increased transmission rental
expenses of approximately $1.3 million resulting from increased expenses
allocated to Montaup from NEPOOL/ISO. Indirect expenses decreased by
approximately $10.6 million in 1998. Jointly owned units expenses decreased
approximately $9.4 million in 1998, due largely to the return to service of
Millstone 3 in July of 1998 and decreased expenses of Canal Unit 2 and Seabrook
I. In addition, charges from other utilities decreased approximately $1.9
million and Other Post-Retirement Benefits and Pension expenses decreased
approximately $1.4 million collectively in 1998. These decreases were offset
by increased C&LM expense of approximately $2.2 million.
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 29% of the total O&M expenses of this business unit in 1999. Expenses
of the Energy Related Business Unit were relatively unchanged in 1999 compared
to 1998. Expenses at EUA Cogenex increased approximately $1.1 million in 1999.
Expenses at EUA Citizens, Cogenex West and Cogenex Canada increased by
approximately $8.5 million, primarily due to increased operating activity in
1999. These increases were offset by decreased expenses at the Cogenex
Division and the Cogenex partnerships of aggregating $7.5 million. These
increases were essentially offset by decreased expenses of EUA Energy
Investment since the recording of the discontinued activity of Renova and EUA
BIOTEN in the second quarter of 1999 and EUA TransCapacity in third quarter of
1999.
Expenses of EUA Cogenex decreased approximately $10.3 million in 1998, due
primarily to decreased expenses of Cogenex West, Cogenex Canada, Citizens and
the Cogenex Partnerships of $9.9 million in aggregate, largely the result of
decreased operating activity in 1998. In addition, EUA Cogenex expenses
reflect the impact of the sale of Renova operations to EUA Energy Investment in
May 1998 and ongoing cost control efforts at the Cogenex division which were
offset by increased operating expenses at EUA Day in connection with its
development of Day Matrix, a division which provided energy metering and
control systems. EUA Energy Investment expenses increased by $4.9 million in
1998 due primarily to the impact of the Renova sale.
Depreciation and Amortization: Depreciation and Amortization expense
decreased approximately $6.6 million or 12.9% in 1999 as compared to 1998.
This decrease was due largely to decreased depreciable property, particularly
after the sale of Montaup's 50% ownership of the Canal Unit 2 generating
station in December of 1998 and the sale of the Somerset Generating Station in
April of 1999, and was further impacted by decreased depreciation at EUA
Cogenex.
Depreciation and Amortization expense increased by approximately $4.1
million or 8.8% in 1998 as compared to 1997. This increase is due largely to
increased depreciation at EUA Cogenex directly related to an increase in number
of projects placed in service, and amortization of certain regulatory assets at
the Core Electric Business pursuant to restructuring settlement agreements.
Income Taxes: EUA files a consolidated federal income tax return for the EUA
System. The composite federal and state effective income tax rate for 1999 was
21.7% versus 34.5% in 1998. This change was due to the recognition of
remaining unamortized investment tax credits pursuant to IRS regulations on the
sales of EUA's generating assets in 1999 and the impacts of the reversal
of the previously discussed tax audit adjustments.
Other Income (Deductions) - Net: Other Income Deductions (Net) increased
approximately $1.7 million or 26.8% in 1999 compared to 1998. This change was
primarily due to the reversal of previously established estimated tax
liabilities of approximately $1.6 million in the fourth quarter of 1999 related
to the completion of the IRS's examination of EUA's consolidated federal income
tax returns through 1995. Other Income and (Deductions) - Net decreased by
approximately $4.5 million, or 41.2% in 1998 as compared to 1997. This
decrease is due largely to the absence of the impacts of the 1997 power
marketing joint venture termination and the 1997 favorable resolution
of a Massachusetts corporate income tax dispute. The tax issue in question
related to a 1989 Massachusetts State income tax audit which assessed tax
liability for certain intercompany transactions. In order to contest the tax
assessment, EUA paid the disputed tax liability in 1989. Final resolution of
this matter was reached in 1997 in favor of EUA. The disputed tax amount,
along with related interest, was returned to EUA in 1997. The one-time benefit
to 1997 earnings relates to the interest portion of the refund. Also
contributing to the 1998 decrease were non-operating expenses of $2.5 million
related to Montaup's divestiture efforts and approximately $800,000 of
expenses related to opposition of a 1998 Massachusetts referendum to repeal
deregulation legislation.
Net Interest Charges: Net interest charges decreased slightly in 1999 as
compared to 1998. Interest on long term debt decreased by $6.7 million,
primarily the result of Eastern Edison's redemption of all of its First
Mortgage Bonds in July 1999, its $35 million 7.78% Secured Medium Term Notes in
August 1999, and the maturities of $60 million of First Mortgage Bonds in 1998.
In addition, Newport redeemed $1.4 million of 9% and $8 million of 9.8% First
Mortgage Bonds at their maturity in September of 1999. The decrease in
interest charges was also, to a lesser extent, the result normal cash sinking
fund payments. This decrease was offset by increased other interest expense
related to revenue reconciliation accounts pursuant to restructuring settlement
agreements and interest expense related to the 1991 through 1995 federal income
tax audits completed in 1999.
Net Interest charges decreased by approximately $2.0 million or 5.0% in
1998 compared to 1997. Interest on long term debt decreased as a result of
normal cash sinking fund payments and the maturities of Eastern Edison's $20
million, 5 7/8% First Mortgage Bonds in May 1998 and $40 million, 5 3/4% First
Mortgage Bonds in July 1998. This decrease was partially offset by interest
expense on increased short term borrowings, which were used to finance Eastern
Edison's long-term debt maturities.
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.
Core Electric Business: For 1999, 1998 and 1997, Core Electric Business cash
construction expenditures were $23.9 million, $22.9 million and $21.9 million,
respectively.
Internally generated funds available after the payment of dividends were
approximately 220%, 250% and 133% of cash construction requirements in 1999,
1998 and 1997, 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 2000,
2001, and 2002 are estimated to be approximately $35.9 million, $34.1 million
and $26.9 million, respectively, and are expected to be financed with
internally generated funds.
In addition to construction expenditures, projected requirements for
scheduled cash sinking fund payments and mandatory redemption of securities of
the Core Electric Business for 2000 through 2004 are $2.2 million for 2000,
$4.0 million for 2001, $3.3 million for 2002, 2003, and 2004, none of which
relates to Blackstone's or Newport's variable rate bonds.
In December 1998, Montaup used the proceeds from the sale of its 50%
ownership interest in the Canal 2 Generating Station to Southern Energy for
approximately $75 million to redeem $55 million of Montaup debenture bonds,
wholly-owned by Eastern Edison, and paid a special dividend to Eastern Edison.
Eastern Edison used these proceeds to repay its outstanding short-term debt and
make short-term investments of $25.6 million. In January 1999, Eastern Edison
used those investments to retire 551,956 shares of its outstanding, $25 par
value, common stock at a price of $41.67 per share.
In April 1999, Montaup completed the sale of its Somerset Station to NRG
Energy Inc. for approximately $55 million. In July 1999, Montaup used the
proceeds from this sale to redeem $54.8 million of its outstanding securities
wholly-owned by Eastern Edison. Eastern Edison used these proceeds along with
a capital contribution from EUA to redeem $40 million of 8%, $40 million of
6 7/8%, and $8 million of 6.35% First Mortgage and Collateral Trust Bonds.
In July 1999, EUA filed an application under the Public Utility Holding
Company Act with the Securities and Exchange Commission (SEC) requesting
authorization for Eastern Edison to transfer all of its investment in Montaup,
including Montaup's preferred stock, common stock and debenture bonds, to EUA.
Montaup would then become a wholly-owned subsidiary of EUA. Also related to
this transfer, Eastern Edison filed a Petition for Approval of the transfer or
Request for Alternative Findings of No Jurisdiction with the DTE. A public
hearing was held at the DTE on October 18, 1999 at which time no one from the
public intervened. Eastern Edison received an order from the DTE on January 4,
2000, approving the transfer. SEC approval was received on February 4, 2000
and the transfer of Montaup from Eastern Edison to EUA was consummated with a
filing at the DTE on February 17, 2000.
In August 1999, Eastern Edison used short term borrowings to redeem its
$35 million 7.78% Secured Medium Term notes.
In September 1999, Newport used short-term borrowings to redeem $1.4
million of 9% and $8 million of 9.8% First Mortgage Bonds at their maturity.
In November 1999, Newport used available cash to redeem the remaining balance
of approximately $440,000 of its 6.5% Small Business Administration Loan.
On February 25, 2000, Blackstone issued Notices of Redemption for the
35,000 outstanding shares of its 4.25% Cumulative Preferred Stock and the
25,000 outstanding shares of its 5.6% Cumulative Preferred Stock. These shares
will be redeemed on March 27, 2000. The redemption price for the 4.25% shares
will be $100 per share plus a premium of $4.40 per share plus accrued
dividends through March 27, 2000, amounting to a redemption price of $105.43
per share. The redemption price for the 5.60% shares will be $100 per share
plus a premium of $3.82 per share plus accrued dividends through March 27,
2000, amounting to a redemption price of $105.17 per share.
On February 25, 2000, Newport issued a Notice of Redemption for the 7,689
outstanding shares of its 3 3/4% Cumulative Preferred Stock. These shares will
be redeemed on March 27, 2000. The redemption price will be $100 per share
plus a premium of $3.50 per share plus accrued dividends through March 27,
2000, amounting to a redemption price of $104.41 per share.
Energy Related Business: Capital expenditures of our Energy Related Business
amounted to $33.0 million, $26.8 million and $51.9 million, in 1999, 1998 and
1997, respectively. Internally generated funds supplied 105%, 143% and 88%, of
cash capital requirements in 1999, 1998 and 1997, respectively. Estimated
capital expenditures of the Energy Related Business are $28.4 million, $28.9
million, and $34.7 million in 2000, 2001 and 2002, respectively. Internally
generated funds are expected to supply approximately 100% of 2000 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 $59.2 million in
2000, $9.2 million in 2001, $6.0 million in 2002, 2003 and 2004.
Corporate: Construction activity of the Corporate Business unit is minimal.
Projected requirements for scheduled cash sinking fund payments for the
corporate operations are $1.1 million in 2000 to 2003, and $700,000 in 2004.
Short-Term Lines of Credit: In July 1997, several EUA System companies entered
into a three-year revolving credit agreement allowing for borrowings in
aggregate of up to $225 million, as amended in November 1999, from all sources
of short-term credit. On November 23, 1999, Eastern Edison and Montaup entered
into a $60 million credit agreement to facilitate the buy out of the
Pilgrim Station purchase power agreement between Montaup and Boston Edison and
for other general corporate purposes. As of December 31, 1999, various
financial institutions have committed up to $75 and $60 million under each of
the respective credit facilities. In addition to the $135 million available
under these credit facilities, EUA System companies maintain short-term lines
of credit with various banks totaling $90 million for an aggregate amount
available of $225 million.
Year-End Short-Term Debt Outstanding by Business Unit:
($ in thousands) 1999 1998
Core Electric Business $49,790 $2,220
Energy Related Business 3,335 19,354
Corporate 90,830 42,000
Total $143,955 $63,574
Interest Rate Risk: EUA is exposed to interest rate risk primarily related to
Blackstone's and Newport's variable rate bonds. Refer to the Consolidated
Statements of Indebtedness for a listing of EUA's long-term fixed and variable
rate debt.
Energy Related Businesses
EUA Cogenex: EUA Cogenex provides energy efficiency products and energy
management services throughout North America. EUA Cogenex posted a loss of
$2.5 million in 1999, compared to earnings of approximately $800,000 in 1998.
These results were exclusive of $1.0 million in charges recorded in the fourth
quarter of 1999 and $2.9 million in charges recorded in the second quarter of
1999 related to the sale of the assets of EUA Day. The change in EUA
Cogenex's earnings were largely the result of decreased project sales.
EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which
developed and operate Units I and II of OSP, twin 250-megawatt (mw) 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. EUA Ocean State's earnings in 1999 were approximately $3.9
million compared to $4.1 million in 1998. The slight change in earnings is due
to lower availability bonuses based on the units' operational levels in 1999.
In February 2000, EUA entered into a letter of intent with TransCanada Energy
Ltd. to sell all of the outstanding capital stock of EUA Ocean State to
TransCanada. As a condition of the sale, EUA Ocean State must obtain an
exemption from the 1935 Act from FERC. On February 17, 2000, EUA Ocean State
filed a petition to RIPUC for "exempt wholesale generator" status. In order to
gain the exemption from FERC, certain findings are needed from RIPUC.
EUA Energy Investment: EUA Energy invests in energy related businesses. EUA
Energy generated a loss of approximately $4.4 million in 1999 due to losses at
Renova and EUA TransCapacity. This loss was approximately $900,000 less than
the loss generated in 1998. This decreased loss reflects the discontinued
activity of Renova resulting from its sale, and EUA BIOTEN in the second
quarter of 1999. In addition, in the third quarter of 1999, EUA sold all of
the assets of TransCapacity L.P. and dissolved the TransCapacity L.P. The
after-tax loss of $900,000 on the TransCapacity sale was offset by previously
established estimated liabilities at EUA's parent company. Therefore,
consolidated operating results were not impacted by this transaction. Due to
the discontinued activity of these entities, EUA Energy anticipates minimal
losses in the future.
Electric Utility Industry Restructuring
See Item 1. BUSINESS Electric Utility Industry Restructuring for a
discussion of changes in the utility industry.
Environmental Matters
EUA's Core Electric Business subsidiaries and other companies owning
generating units from which power is obtained are subject, like other electric
utilities, to environmental and land use regulations at the federal, state and
local levels. The federal Environmental Protection Agency (EPA), and certain
state and local authorities, have jurisdiction over releases of pollutants,
contaminants and hazardous substances into the environment and have broad
authority to set rules and regulations in connection therewith, such as the
Clean Air Act Amendments of 1990, which could require installation of pollution
control devices and remedial actions. In 1994, EUA instituted an environmental
audit program to ensure compliance with environmental laws and regulations and
to identify and reduce liability with respect to those requirements.
Because of the nature of the EUA System's business, various by-products
and substances are produced or handled which are classified as hazardous under
the rules and regulations promulgated by such authorities. The EUA System
typically provides for the disposal of such substances through licensed
contractors, but statutory provisions generally impose potential joint and
several responsibility on the generators of the wastes for clean-up costs.
Subsidiaries of EUA have been notified with respect to a number of sites where
they may be responsible for such costs, including sites where they may have
joint and several liability with other responsible parties.
It is the policy of the EUA System companies to notify liability insurers
and to initiate claims. However, EUA is unable to predict whether liability,
if any, will be assumed by, or can be enforced against, insurance carriers in
these matters. As of December 31, 1999, the EUA System had incurred costs of
approximately $9.5 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 $2.2 million may be incurred
at these sites through 2000 by its subsidiaries.
During the second quarter of 1999, EUA identified four new sites related
to the production of manufactured gas at which certain environmental conditions
may exist. Three sites are associated with Blackstone and one site is
associated with Eastern Edison. EUA has conducted a preliminary assessment of
the potential cost of remediation at these sites. An engineering model was
recently obtained by the Company to provide the estimated potential costs.
Since site specific studies have not yet been performed, EUA has recorded a
minimum liability for each of these sites based on this engineering model to
recognize risk assessment, monitoring, and legal and administrative costs.
In addition, EUA has recorded estimated environmental remediation
liabilities for two previously-identified manufactured gas plant sites
associated with Blackstone. The sites are the Tidewater site, the location of
a former electric generating station and manufactured gas plant in Pawtucket,
Rhode Island, and the Hamlet Avenue Site, a former manufactured gas plant site
located in Woonsocket, Rhode Island. Estimates were not previously recorded
for these locations since site-specific studies had not been completed and a
reliable engineering model deemed essential to develop a reasonable estimate
was not previously available.
With respect to the Tidewater site, EUA completed its site investigation
study during the third quarter of 1999 to determine the nature and extent of
contamination. The study identified elevated levels of hazardous substances
over an extended area of both the surface and subsurface. The Hamlet Street
site assessment has not yet been finalized. However, the assessment conducted
to date has determined that varying degrees of hazardous substances are present
at that site.
Therefore, in the third quarter of 1999, a total estimated remediation
liability of $21.2 million was recorded as a long-term liability with a
corresponding charge to a regulatory asset on the Consolidated Balance Sheet.
Blackstone and Eastern Edison are currently recovering certain environmental
cleanup costs in rates. In addition, the Company will seek recovery of certain
costs from its insurance carriers and other possible responsible parties. The
Company expects, based on prior regulatory approvals, to recover such costs in
future rates. As a result, the Company does not believe that the ultimate
impact of the cleanup costs associated with these sites will be material to
the results of its operations or its financial position.
Also see Item 1. BUSINESS, Environmental Regulation "Potential Regulation
of Electric and Magnetic Fields" for a discussion of electric and magnetic
fields. In addition to the previously discussed costs, Blackstone is
currently litigating responsibility for clean-up costs and related interest
aggregating $5.9 million. The clean-up costs were incurred by the Commonwealth
of Massachusetts at a site in which Blackstone has been named as a responsible
party. See Item 3. LEGAL PROCEEDINGS, Environmental Proceedings for further
discussion of environmental matters involving EUA.
Nuclear Power Issues
See Item 1. BUSINESS - Nuclear Power Issues for a discussion of issues
related to several of the nuclear plants in which Montaup has an ownership
interest.
The Year 2000 Issue
See Item 1. BUSINESS - The Year 2000 Issue for a discussion of this issue.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
133, Accounting for Derivative Instruments and Hedging Activities, which is
effective for fiscal years beginning after June 15, 1999. In June 1999, the
FASB issued SFAS 137, Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date, which amends SFAS 133 to be
effective for all fiscal quarters of all fiscal years beginning after June 15,
2000 (that is, January 1, 2001 for companies with calendar-year fiscal years).
SFAS 133 requires the recognition of all derivative instruments as either
assets or liabilities in the statement of financial position and the
measurement of those instruments at fair value. The Company does not expect
SFAS 133 to have a material impact on its financial position or results of
operations.
Other
See Item 3. LEGAL PROCEEDINGS - Other Proceedings for a discussion of
legal proceedings involving EUA or its subsidiaries.
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. This report contains information about the Company's future
business prospects. These statements are considered "forward-looking" within
the meaning of the Private Securities Litigation Reform Act. These statements
are based on the Company's current plans and expectations and involve risks and
uncertainties that could cause actual future activities and results of
operations to be materially different from those set forth in the forward-
looking statements. The Company expressly undertakes no duty to update any
forward-looking statement.
Item 7. 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 Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA to arrive at a more complete understanding of such matters.
[This page intentionally left blank]
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Table of Contents
Consolidated Statements of Income. . . . . . . . . . . 58
Consolidated Statements of Retained Earnings . . . . . 58
Consolidated Statements of Cash Flows . . . . . . . . 59
Consolidated Balance Sheets . . . . . . . . . . . . . . 60
Consolidated Statements of Equity Capital & Preferred Stock 61
Consolidated Statements of Indebtedness . . . . . . . . . . 62
Notes to Consolidated Financial Statements . . . . . . . . 63
Quarterly Financial Information . . . . . . . . . . . . . . 113
Report of Independent Accountants . . . . . . . . . . . . . 114
Consent of Independent Accountants . . . . . . . . . . . . 115
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31,
(In Thousands)
1999 1998 1997
Operating Revenues $ 553,766 538,801 568,513
Operating Expenses:
Fuel and Purchased Power 247,667 208,717 230,209
Other Operations 146,761 155,943 162,464
Maintenance 19,192 20,143 30,432
Voluntary Retirement Incentive 0 0 1,416
Depreciation and Amortization 44,510 51,079 46,941
Taxes - Other than Income 21,473 23,323 24,021
- Income 18,896 19,473 14,223
Total Operating Expenses 498,499 478,678 509,706
Operating Income 55,267 60,123 58,807
Equity in Earnings of Jointly Owned Companies 9,233 9,524 9,466
Allowance for Other Funds Used During
Construction 276 173 162
Energy Related Asset Adjustments (24,868) (3,172)
Income Tax Impact of Energy Related
Asset Adjustments 8,210 1,110
Other Income - Net 8,183 6,456 10,986
Income Before Interest Charges 56,301 74,214 79,421
Interest Charges:
Interest on Long-Term Debt 21,551 28,288 32,198
Amortization of Debt Expense and Premium - Net 1,309 1,813 2,548
Other Interest Expense 14,710 7,745 5,245
Allowance for Borrowed Funds Used During
Construction (Credit) (492) (647) (835)
Net Interest Charges 37,078 37,199 39,156
Net Income 19,223 37,015 40,265
Preferred Dividend Requirements 2,305 2,305 2,305
Consolidated Net Earnings $ 16,918 34,710 37,960
Average Common Shares Outstanding 20,435,997 20,435,997 20,435,997
Consolidated Basic and Diluted Earnings
per Share $0.83 $1.70 $1.86
Dividends Paid per Share $1.66 $1.66 $1.66
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years Ended December 31,
(In Thousands)
1999 1998 1997
Retained Earnings - Beginning of Year $ 56,466 56,062 52,404
Consolidated Net Earnings 16,918 34,710 37,960
Total 73,384 90,772 90,364
Dividends Paid - EUA Common Shares 33,924 33,924 33,924
Other 365 382 378
Retained Earnings - Accumulated since June 1991
Accounting Reorganization $ 39,095 56,466 56,062
The accompanying notes are an integral part of the financial statements.
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31,
(In Thousands)
1999 1998 1997
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 19,223 37,015 40,265
Adjustments to Reconcile Net Income
to Net Cash Provided by Operating Activities:
Depreciation and Amortization 51,332 56,308 51,615
Amortization of Nuclear Fuel 3,667 1,265 1,067
Deferred Taxes 8,617 (17,854) (6,317)
Non-cash Expenses/(Gains) on Sales of
Investments in Energy Saving Projects 14,718 10,002 15,993
Energy Related Assets Adjustments 22,765
Investment Tax Credit, Net (6,179) (3,081) (1,201)
Allowance for Funds Used During Construction (276) (173) (162)
Collections and Sales of Project Notes
and Lease Receivable 7,933 17,261 19,148
Other - Net (27,112) (15,546) (5,726)
Changes to Operating Assets and Liabilities:
Accounts Receivable (5,944) 11,411 (2,494)
Materials and Supplies 8,738 (2,232) 2,929
Accounts Payable 6,927 (6,018) 1,225
Taxes Accrued (11,640) 11,145 59
Regulatory Asset - Purchased Power Contract
Buyout - Net (51,801)
Other - Net 12,464 (2,563) (664)
Net Cash Provided from Operating Activities 53,432 96,940 115,737
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (57,039) (51,201) (76,118)
Proceeds from Divestiture of Generation Assets 62,346 76,873
Collections on Notes and Lease Receivables
of EUA Cogenex 14,733 11,558 10,076
Proceeds from Sale of Day Division 2,894
Other Investments 216 (2,071) 312
Net Cash Provided From (Used in) Investing
Activities 23,150 35,159 (65,730)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions of Long-Term Debt (145,344) (73,122) (28,617)
EUA Common Share Dividends Paid (33,924) (33,924) (33,924)
Subsidiary Preferred Dividends Paid (2,305) (2,305) (2,305)
Net Increase in Short Term Debt 80,381 2,090 9,636
Net Cash (Used in) Financing Activities (101,192) (107,261) (55,210)
Net (Decrease) Increase in Cash
and Temporary Cash Investments (24,610) 24,838 (5,203)
Cash and Temporary Cash Investments at
Beginning of Year 32,090 7,252 12,455
Cash and Temporary Cash Investments at
End of Year $ 7,480 32,090 7,252
Cash paid during the year for:
Interest (Net of Amounts Capitalized) $ 28,608 37,087 40,172
Income Taxes $ 17,421 25,976 28,921
Conversion of Investments in Energy
Savings Projects to Notes and
Leases Receivable $ 1,922 4,529 5,404
The accompanying notes are an integral part of the financial statements.
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED BALANCE SHEETS
December 31,
(In Thousands)
ASSETS
1999 1998
Utility Plant and Other Investments:
Utility Plant in Service 735,944 1,000,243
Less Accumulated Provision for
Depreciation and Amortization 290,962 353,780
Net Utility Plant 444,982 646,463
Construction Work in Progress 9,033 5,151
Non-Utility Property - Net 42,644 55,274
Investment in Jointly Owned Companies 64,022 69,485
Other 44,352 55,320
Total Utility Plant and Other Investments 605,033 831,693
Current Assets:
Cash and Temporary Cash Investments 7,480 32,090
Accounts Receivable:
Customers, Net 53,862 55,286
Unbilled Revenues 6,385 10,655
Other 24,714 15,294
Notes Receivable 22,000 27,078
Materials and Supplies (at average cost):
Fuel 0 6,024
Plant Materials and Operating Supplies 3,997 7,410
Other Current Assets 5,256 8,448
Total Current Assets 123,694 162,285
Other Assets 739,126 308,660
Total Assets 1,467,853 1,302,638
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Equity 358,039 373,674
Non-Redeemable Preferred Stock of Subsidiaries - Net 6,900 6,900
Redeemable Preferred Stock of Subsidiaries - Net 28,360 27,995
Long-term Debt - Net 104,235 310,346
Total Capitalization 497,534 718,915
Current Liabilities:
Short Term Debt 143,955 63,574
Long-term Debt Due Within One Year 83,127 21,911
Accounts Payable 35,146 29,018
Taxes Accrued 2,565 14,208
Interest Accrued 4,529 6,997
Purchased Power Contract Buyout Payable 75,698
Other Current Liabilities 60,736 34,908
Total Current Liabilities 405,756 170,616
Other Liabilities 418,253 271,078
Accumulated Deferred Taxes 146,310 142,029
Commitments and Contingencies (Note J)
Total Liabilities and Capitalization 1,467,853 1,302,638
The accompanying notes are an integral part of the financial statements.
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED STATEMENTS OF EQUITY CAPITAL & PREFERRED STOCK
December 31,
(In Thousands)
1999 1998
Common Shares:
$5 par value, 36,000,000 authorized, 20,435,997
shares outstanding in 1999 and 1998 102,180 102,180
Other Paid-In Capital 220,695 218,959
Common Share Expense (3,931) (3,931)
Retained Earnings - Accumulated since June 1991
Accounting Reorganization 39,095 56,466
Total Common Equity 358,039 373,674
Cumulative Preferred Stock of Subsidiaries:
Non-Redeemable Preferred Stock:
Blackstone Valley Electric Company:
4.25% $100 par value 35,000 shares 3,500 3,500
5.60% $100 par value 25,000 shares 2,500 2,500
Premium 129 129
Newport Electric Corporation:
3.75% $100 par value 7,689 shares 769 769
Premium 2 2
Total Non-Redeemable Preferred Stock 6,900 6,900
Redeemable Preferred Stock:
Eastern Edison Company
6 5/8% $100 par value 300,000 shares 30,000 30,000
Expense, Net of Premium (335) (335)
Preferred Stock Redemption Costs (1,305) (1,670)
Total Redeemable Preferred Stock 28,360 27,995
Total Preferred Stock of Subsidiaries 35,260 34,895
EASTERN UTILITIES ASSOCIATES
CONSOLIDATED STATEMENTS OF INDEBTEDNESS
December 31,
(In Thousands)
1999 1998
EUA Service Corporation:
10.2% Secured Notes due 2008 5,100 6,200
EUA Cogenex Corporation:
7.0% Unsecured Notes due 2000 50,000 50,000
9.6% Unsecured Notes due 2001 6,400 9,600
10.56% Unsecured Notes due 2005 21,000 24,500
EUA Ocean State Corporation:
9.59% Unsecured Notes due 2011 23,637 26,114
Blackstone Valley Electric Company:
First Mortgage Bonds:
9 1/2 % due 2004 (Series B) 7,500 9,000
10.35% due 2010 (Series C) 18,000 18,000
Variable Rate Demand Bonds due 2014 (1) 6,500 6,500
Eastern Edison Company:
First Mortgage and Collateral Trust Bonds:
6 7/8% due 2003 0 40,000
8% due 2023 0 40,000
6.35% due 2003 0 8,000
7.78% Secured Medium-Term Notes due 2002 0 35,000
Pollution Control Revenue Bond:
5 7/8% due 2008 40,000 40,000
Newport Electric Corporation:
First Mortgage Bonds:
9.0% due 1999 0 1,386
9.8% due 1999 0 8,000
8.95% due 2001 1,300 1,950
Small Business Administration Loan:
6.5% due 2005 0 533
Variable Rate Revenue Refunding Bonds due 2011 (1) 7,925 7,925
Unamortized (Discount) - Net 0 (451)
187,362 332,257
Less Portion Due Within One Year 83,127 21,911
Total Long-Term Debt - Net 104,235 310,346
(1) Weighted average interest rate was 3.3% for 1999 and 3.6% 1998.
The accompanying notes are an integral part of the financial statements.
Notes To Consolidated Financial Statements
December 31, 1999, 1998 and 1997
(A) Nature of Operations and Summary of Significant Accounting Policies:
General: Eastern Utilities Associates (EUA) is a public utility holding
company headquartered in West Bridgewater, Massachusetts. 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. See "Generation Divestiture"
below for a discussion of EUA's divestiture its of generating capacity. On
February 1, 1999, EUA and New England Electric System (NEES) announced a merger
agreement under which NEES will acquire all outstanding shares of EUA. The
merger agreement is subject to the approval of various regulatory agencies.
The closing of the merger is expected to occur by April 2000.
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 2.5% to
4.5%. Three of the four facilities, Yankee Atomic, Connecticut Yankee and
Maine Yankee, have been permanently shut down and are in the process of
decommissioning. Montaup's share of total estimated costs for the permanent
shutdown, decommissioning and recovery of the investment in Yankee Atomic,
Connecticut Yankee and Maine Yankee is $1.1 million, $19.3 million and $25.5
million, respectively. These amounts are included with Other Liabilities on
the Consolidated Balance Sheet as of December 31, 1999. Also, due to
anticipated recoverability, a regulatory asset has been recorded for the same
amount and is included with Other Assets. Montaup is currently entitled to
electricity produced from the remaining facility, Vermont Yankee, based on
its ownership interest and is billed for its entitlement pursuant to a
contractual agreement which is approved by the Federal Energy Regulatory
Commission (FERC). Vermont Yankee is under agreement to be sold to AmerGen
Energy Company. (See Generation Divestiture in Item 1. BUSINESS.)
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 20% stock ownership in
Separation Technologies, Inc. This ownership interest 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 1999, 3.5% in 1998, and 3.6% in 1997
based on the average depreciable property balances at the beginning and end of
each year. Beginning in 1998, coincident with billing a contract termination
charge (CTC) to its retail affiliates, Montaup commenced recovery of its net
investment in generation related assets through the CTC over a twelve-year
period. The difference between the annual recovery and annual depreciation
expense pursuant to generally accepted accounting principles is being deferred.
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.
Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest:
AFUDC represents the estimated cost of borrowed and equity funds used to
finance the EUA System's construction program. In accordance with regulatory
accounting, AFUDC is capitalized as a cost of utility plant in the same manner
as certain general and administrative costs. AFUDC is not an item of current
cash income but is recovered over the service life of utility plant in the form
of increased revenues collected as a result of higher depreciation expense.
The combined rate used in calculating AFUDC was 8.5% in 1999 and 8.0% in 1998
and 1997. The caption "Allowance for Borrowed Funds Used During Construction"
also includes interest capitalized for non-regulated entities in accordance
with FASB Statement No. 34.
Operating Revenues: Utility revenues are based on billing rates authorized by
applicable federal and state regulatory commissions. Eastern Edison Company
(Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport
Electric Corporation (Newport) (collectively, the Retail Subsidiaries) accrue
the estimated amount of unbilled revenues at the end of each month to match
costs and revenues more closely. Montaup recognizes revenues when billed. In
1998, Montaup and the Retail Subsidiaries also began recording revenues in an
amount management believes to be recoverable pursuant to provisions of approved
settlement agreements and enabling state legislation. Provisions of the
approved restructuring settlement agreements in conjunction with accounting
provisions of SFAS 71 allow Montaup and the retail subsidiaries to accrue
and/or defer revenue related to the future recovery of certain items. Montaup
has accrued revenues and recorded associated regulatory assets and liabilities
for certain items during 1998 and 1999 commencing with the implementation of
the aforementioned settlement agreements and billing of the Contract
Termination Charge (CTC), January 1, 1998 in Rhode Island and March 1, 1998 in
Massachusetts. Also, Montaup is normalizing the difference between GAAP
depreciation expense on generation plant assets prior to divestiture and the
recovery level included in the settlement agreements. Montaup normalizes for
the difference in actual versus estimated CTC variable components costs
and revenues. Montaup was authorized to accrue an amount of lost revenue equal
to the difference in revenues Montaup would have collected under its previously
approved rates and revenues collected pursuant to the settlement agreements.
As directed by the settlement agreements, Montaup ceased accruing lost
revenues, with the completion of the divestiture of its fossil generating
assets, which occurred with the sale of the Somerset generating plant on April
26, 1999. The settlements also provide Montaup with a nuclear PBR provision
under which Montaup normalizes expenses and revenues for 80% of going forward
operations of Montaup's nuclear interests. Montaup was also allowed to accrue
a return enhancement related to stranded investments charged to its Rhode
Island retail affiliates during the generation divestiture period as an
incentive to divest. Beginning in 1999, Montaup began accruing a similar
revenue enhancement related to standard investments charged to its
Massachusetts retail affiliate, Eastern Edison. Montaup has also accrued
revenue related to the two-month delay in implementing the Massachusetts
settlement agreement from January 1, 1998 to March 1, 1998. The retail
companies normalize the difference between revenue and expenses from
energy conservation programs. The retail companies normalize the difference
between amounts billed to customers and the costs for standard offer/default
service. The retail companies also normalize the difference between CTC
revenue and expenses. Montaup refunds to the retail companies previous over or
under recoveries related to the CTC rate mechanism. Montaup also accrues
interest on reconciliation account balances owed to the retail companies.
Settlement provisions and SFAS 71 also provide for Eastern Edison to
accrue revenue equal to the approved deferral of standard offer costs which
will be collected in the future.
The following table reflects the nature and amount of accrued and/or
deferred revenue and the associated balance sheet placement (000's).
1999 1998 Balance Sheet Placement
Depr. Normalization
(12 year Straight line
vs. CTC) $ - $10,933 Other Assets/Accrued CTC Assets
Depr. Normalization
(GAAP vs. 12 year
Straight line) (6,635) (14,294) Other Liabilities/Regulatory Liabilities
CTC Normalization (28,992) (23,793) Other Liabilities/Regulatory Liabilities
Lost revenue 24,599 18,527 Other Assets/Accrued CTC Assets
Nuclear PBR 5,730 3,933 Other Assets/Other Regulatory Assets
R.I. Return True-up 3,652 1,970 Other Assets/Accrued CTC Assets
Assets
Mass. Mitigation Incentive 1,445 - Other Assets/Accrued CTC Assets
Mass. Delay Credit 768 768 Other Assets/Accrued CTC Assets
CCA Normalization (5,019) (1,906) Other Liabilities/Regulatory Liabilities
Standard Offer/Default
Service Deferral 13,917 12,411 Other Assets/Regulatory Assets
Retail CTC Differential 4,322 - Other Assets/Regulatory Assets
Reconciliation Account Refund 7,141 - Other Assets/Other Regulatory Assets
Interest on Reconciliation
Account (3,060) - Other Liabilities/Regulatory Liabilities
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 contracts are
first accounted for as recovery of costs to the extent incurred.
Federal Income Taxes: EUA and its subsidiaries generally reflect in income
the estimated amount of taxes currently payable, and provide for deferred taxes
on certain items subject to temporary timing differences to the extent
permitted by the various regulatory agencies. EUA's rate-regulated
subsidiaries amortize previously deferred investment tax credits (ITC) over the
productive lives of the related assets. Beginning in 1998, Montaup is
amortizing previously deferred ITC related to generation investments
recoverable through the CTC over a twelve-year period. Unamortized ITC
related to the sales of generating units are reversed to Other Income on the
Consolidated Income Statement at the time of sale pursuant to IRS regulations.
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.
Accounts Receivable: Accounts Receivable - Customers, Net includes an
allowance for doubtful accounts of approximately $1.1 million in 1999 and $1.3
million in 1998.
Other Assets: The components of Other Assets at December 31, 1999 and 1998
are detailed as follows:
($ in thousands) 1999 1998
Regulatory Assets:
Unamortized losses on reacquired debt $11,852 $10,979
Unrecovered plant and
decommissioning costs 48,659 66,934
Deferred FAS 109 costs (Note B) 40,922 50,167
Deferred FAS 106 costs 6,685 7,354
Mendon Road judgment (Note J) 6,154 6,154
Manufactured Gas Production
Environmental Liability 21,158
Unrecovered CTC plant assets 209,667 33,161
Accrued CTC assets 262,607 32,198
Other regulatory assets 44,667 32,499
Total regulatory assets 652,371 239,446
Other deferred charges and assets:
Split dollar life insurance premiums 33,721 24,803
Unamortized debt expenses 1,916 3,381
Goodwill 6,230 6,436
Other 44,888 34,594
Total Other Assets $739,126 $308,660
Regulatory assets represent deferred costs for which future revenues are
expected in accordance with regulatory practices. These costs are expensed
when the corresponding revenues are received in order to appropriately match
revenues and expenses. Unrecovered CTC plant assets increased in 1999 as a
result of the divestiture of generation assets in 1999. Accrued CTC assets
increased in 1999 as a result of the transfer of power contracts to various
non-affiliated parties in 1999.
Other Liabilities: The components of Other Liabilities at December 31, 1999
and 1998 are detailed as follows:
1999 1998
Unamortized investment tax credits $10,212 $16,391
FAS 109 liability 8,122 15,930
FAS 106 liability 16,339 16,442
Decommissioning liabilities of jointly
owned companies 45,955 58,503
Pension liability 33,925 23,483
Accrued CTC liabilities 41,391 47,160
Proceeds from divestiture of generation assets 109,525 70,167
Contract buyout payables 96,454
Manufactured gas production environmental
liability 21,158
Other 35,172 23,002
Total Other Liabilities $418,253 $271,078
Regulatory Accounting: Core Electric companies are subject to certain
accounting rules that are not applicable to other industries. These accounting
rules allow regulated companies, in appropriate circumstances, to establish
regulatory assets and liabilities which defer the current financial impact
of certain costs that are expected to be recovered in future rates. In light
of approved restructuring settlement agreements and restructuring legislation
in both Massachusetts and Rhode Island, EUA has determined that Montaup no
longer will apply the provisions of Financial Accounting Standards Board's
(FASB) Statement of Financial Accounting Standards No. 71 (FAS71), "Accounting
for the Effects of Certain Types of Regulation" for the generation portion of
its business. Montaup ceased applying SFAS 71 to its ongoing generation
portion of its business effective January 1, 1998. Approved restructuring
settlement agreements with parties in Massachusetts and Rhode Island, the
two states in which Montaup operates, allow Montaup full recovery of stranded
generation investments as of December 31, 1997 and as such Montaup incurred no
asset impairment. As disclosed below in Generation Divestiture, Montaup has
divested all of its generation assets and power purchase agreements with the
exception of its 4.0% (46mw) ownership interest in the Millstone 3 nuclear
station and its 12 mw entitlement from the Vermont Yankee nuclear unit.
Post-divestiture ongoing generation operations will include the two
aforementioned nuclear units in which Montaup will continue to have an
interest. The approved settlement agreements also provide Montaup with
recovery of 100% of embedded nuclear investments as of December 31, 1997
and recovery of 80% of its post 1997 on going nuclear generation operations.
Because only 20% of Montaup's remaining nuclear operations will no longer be
subject to the accounting treatment pursuant to SFAS 71 and would be subject to
market risk, management believes that the discontinuation of SFAS 71 for
Montaup's post-divestiture generation business will not have a material impact
on EUA's results of operations or financial position. EUA believes its
transmission and retail distribution businesses continue to meet the criteria
for continued application of FAS71.
Generation Divestiture: Terms of approved electric utility restructuring
settlement agreements provide that EUA exit the electric generation business.
Through separately negotiated agreements, EUA has completed the transfer of
all of its non-nuclear generation assets and power purchase contracts to
various non-affiliated parties, with the exception of its 4.0% (46 mw)
ownership interest in the Millstone 3 nuclear station. Vermont Yankee has
agreed to sell the 540-mw nuclear unit in which Montaup has a 2.5% equity (12
mw) interest.
The sales of EUA's generating assets totaling 509 mw amounted to $133.2
million in aggregate. The net proceeds from the sales, as defined in the
settlement agreements, have been recorded as a regulatory liability at the time
of sale and will be returned to customers via a Residual Value Credit (RVC)
through the year 2009.
EUA has also agreed to make contribution payments to two parties in
exchange for their assumption of all future obligations under six purchased
power contracts. These fixed monthly payments ranging from $850,000 to $2.6
million, will be made from the effective date through 2009. EUA recorded a
liability for these fixed contributions, and a regulatory asset for a like
amount due to recoverability. In addition, in July 1999, EUA agreed to a
buyout of its obligations under the Pilgrim Nuclear purchased power contract in
conjunction with the sale of the unit by Boston Edison Co. (BEC) to Entergy
Nuclear Generating Co. (Entergy). This agreement included a buyout
payment by EUA to BEC of $111.7 million, along with a short-term, fixed-price
purchased power agreement with Entergy for declining shares of the unit's
output beginning with 11% in 1999 and ending with 5.5% in 2004. Entergy will
assume all future operating and decommissioning obligations. Accordingly, in
the third quarter of 1999, Montaup recorded a regulatory asset of approximately
$111.7 million, a corresponding current liability of $105.6 million, and a
long-term liability of $6.1 million.
EUA will continue to attempt to sell and/or transfer its minority interest
in Millstone 3. Until such time as this and the Vermont Yankee units are
divested, EUA will share 80% of the operating costs and revenues associated
with the units with customers and 20% with shareholders.
(B) Income Taxes:
EUA adopted FASB Statement No. 109, "Accounting for Income Taxes"
(FAS109), which requires recognition of deferred income taxes for temporary
differences that are reported in different years for financial reporting and
tax purposes using the liability method. Under the liability method,
deferred tax liabilities or assets are computed using the tax rates that will
be in effect when temporary differences reverse. Generally, for regulated
companies, the change in tax rates may not be immediately recognized in
operating results because of ratemaking treatment and provisions in the Tax
Reform Act of 1986. Total deferred tax assets and liabilities for 1999 and
1998 include the following:
Deferred Tax Deferred Tax
Assets Liabilities
(In thousands) 1999 1998 1999 1998
Plant Related Plant Related
Differences $14,085 $22,776 Differences $117,444 $185,590
Deregulation 12,877 23,301 Refinancing
NOL Costs 1,247 1,325
Carryforward 2,554 1,973 Deregulation 62,681 12,993
Employee Benefit Employee
Accruals 5,686 5,294 Benefit Accruals 5,791 4,481
Acquisitions 3,018 3,334 Other 18,475 8,393
Other 21,108 14,075 Total $205,638 $212,782
Total $59,328 $70,753
As of December 31, 1999 and 1998, EUA has recorded on its Consolidated
Balance Sheet a regulatory liability to ratepayers of approximately $8.1
million and $15.5 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, 1999 and 1998, a regulatory asset of approximately $41.0
million and $50.2 million, respectively, has been recorded, representing the
cumulative amount of federal income taxes on temporary depreciation differences
which were previously flowed through to ratepayers. Components of income tax
expense for 1999, 1998, and 1997 are as follows:
(In thousands) 1999 1998 1997
Federal:
Current $607 $30,755 $17,249
Deferred 14,326 (14,054) (4,901)
Investment Tax Credit, Net (1,264) (1,483) (1,120)
13,669 15,218 11,228
State:
Current 2,059 5,217 3,623
Deferred 3,168 (961) (628)
5,227 4,256 2,995
Charged to Operations 18,896 19,474 14,223
Charged to Other Income:
Current 216 4,416 9,142
Deferred (8,878) (2,839) (789)
Investment Tax Credit, Net (4,915) (1,598) (81)
(13,577) (21) 8,272
Total Income Tax Expense $5,319 $19,453 $22,495
Total income tax expense was different from the amounts computed by applying
federal income tax statutory rates to book income subject to tax for the
following reasons:
(In thousands) 1999 1998 1997
Federal Income Tax Computed
at Statutory Rates $8,590 $19,764 $21,966
(Decrease) Increase in Tax from:
Equity Component of AFUDC (97) (60) (57)
Depreciation Differences 2,181 1,320 (12)
Amortization of ITC (6,179) (3,081) (1,201)
State Taxes, Net of Federal
Income Tax Benefit 3,041 2,803 2,092
Other (2,217) (1,293) (293)
Total Income Tax Expense $5,319 $19,453 $22,495
(C) Capital Stock:
The Agreement and Plan of Merger dated February 1, 1999 by and among New
England Electric System (NEES) and EUA, which was approved by EUA shareholders
and is subject to various regulatory agencies' approval, provides for NEES to
purchase all of the outstanding EUA shares for $31 per share in cash. The
transaction is expected to be completed by April 2000. The merger agreement
contains an upward price adjustment if the merger does not close within six
months from May 17, 1999, the date EUA shareholders approved the merger plan.
Therefore, since November 17, 1999, NEES will pay an additional $0.003 per day
per share for EUA's outstanding common stock until the merger closes, up to a
maximum price of $31.495 per share.
There was no change in the number of common shares outstanding during 1999
and 1998.
As permitted, the Company accounts for its stock-based compensation, as
discussed below, using the method prescribed in Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees" (APB25) and as
permitted under FASB Statement No. 123, "Accounting for Stock-Based
Compensation" (FAS123).
The Company established a Restricted Stock Plan in 1989. Under the
Restricted Stock Plan, executives and certain key employees may be granted
restricted common shares of the Company. In 1998, 1997 and 1995, approximately
74,000 shares, 95,000 shares, and 61,000 shares, respectively, of restricted
common shares, valued at approximately $1.8 million and $2.4 million,
and $1.4 million respectively, were granted. The issued shares are restricted
for a period ranging from two to five years and all shares are subject to
forfeiture if specified employment services are not met. There are no exercise
prices related to these share grants. During the applicable restriction
period, the recipient has all the voting, dividend, and other rights of a
record holder except that the shares are nontransferable. The annual
compensation expense related to these grant awards was approximately $1.6
million in 1999 and 1998 and was immaterial for 1997. There are no material
differences in the Company recording its annual compensation expense under
APB25 from the requirements under FAS123. All of the restricted shares will
become immediately vested upon the completion of EUA's merger with NEES.
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, 1999 and 1998, 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
In July 1999, EUA filed an application under the Public Utility Holding
Company Act with the Securities and Exchange Commission (SEC) requesting
authorization for Eastern Edison to transfer all its investment in Montaup,
including Montaup's preferred stock, common stock and debenture bonds, to EUA.
Montaup would then become a wholly-owned subsidiary of EUA. Also related to
this transfer, Eastern Edison filed a Petition for Approval of the transfer or
Request for Alternative Findings of No Jurisdiction with the DTE. A public
hearing was held at the DTE on October 18, 1999 at which no one from the public
intervened. Eastern Edison received an order from the DTE on January 4, 2000,
approving the transfer. SEC approval was received on February 4, 2000 and the
transfer of Montaup from Eastern Edison to EUA was consummated with a filing
at the DTE on February 17, 2000.
(D) Redeemable Preferred Stock:
Eastern Edison's 6 5/8% Preferred Stock issue is entitled to an annual
mandatory sinking fund sufficient to redeem 15,000 shares commencing September
1, 2003. The redemption price is $100 per share plus accrued dividends. All
outstanding shares of the 6 5/8% issue are subject to mandatory redemption on
September 1, 2008, at a price of $100 per share plus accrued dividends.
In the event of liquidation, the holders of Eastern Edison's 6 5/8% Preferred
Stock are entitled to $100 per share plus accrued dividends.
(E) Long-Term Debt:
The various mortgage bond issues of Blackstone, Eastern Edison, and
Newport are collateralized by substantially all of their utility plant.
In April 1999, Montaup completed the sale of its Somerset Station to NRG
Energy Inc. for approximately $55 million. In July 1999, Montaup used the
proceeds from this sale to redeem $54.8 million of its outstanding securities
wholly-owned by Eastern Edison. Eastern Edison used these proceeds along with
a capital contribution from EUA to redeem $40 million of 8%, $40 million of
6 7/8%, and $8 million of 6.35% First Mortgage and Collateral Trust Bonds.
These First Mortgage bonds were collateralized by securities of Montaup, which
were wholly-owned by Eastern Edison. The principal amount of Montaup
securities wholly-owned by Eastern Edison at December 31, 1999 was
approximately $134 million. See Note C - Capital Stock for a discussion of
Eastern Edison's transfer of its investment in Montaup to EUA in February 2000.
In August 1999, Eastern Edison used short term borrowings to redeem its
$35 million 7.78% Secured Medium Term notes.
In September 1999, Newport used short-term borrowings to redeem $1.4
million of 9% and $8 million of 9.8% First Mortgage Bonds at maturity. In
November 1999, Newport used available cash to redeem the remaining balance of
approximately $440,000 of its 6.5% Small Business Administration Loan.
Blackstone's Variable Rate Demand Bonds are collateralized by an
irrevocable Letter of Credit which expires on July 31, 2000. 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, 2000, 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.
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
1999 are: $62.5 million in 2000, $14.2 million in 2001, $10.4 million in 2002,
$11.9 million in 2003, and $11.5 million in 2004.
EUA Cogenex was not in compliance with the interest coverage covenant
contained in certain of its unsecured note agreements at December 31, 1999.
EUA Cogenex is seeking a waiver from note holders. Under the terms of these
note agreements, since EUA Cogenex was not in compliance with certain
covenants, the note holders may, with written notice to EUA Cogenex, declare
the notes immediately due and payable. Accordingly, $20.7 million of long-term
debt has been reclassified as current maturities of long-term debt on the
Consolidated Balance Sheet as of December 31, 1999. It is anticipated that EUA
Cogenex will be in compliance by the end of the second quarter of 2000.
EUA Cogenex is marketing the sale of a portfolio of certain of its project
cash flows. EUA Cogenex is currently negotiating the terms of a sale agreement
with interested lenders. In early 2000, EUA filed a request with the SEC to
allow for EUA's guarantee of EUA Cogenex's ongoing performance obligations
related to the projects to be sold. SEC approval of EUA's guarantee is
expected in late March or April of 2000 and the sale of the portfolio is
expected to be completed in the second quarter of 2000. EUA Cogenex intends to
redeem all of its long-term debt of approximately $77 million with the proceeds
from the sale.
(F) Fair Value Of Financial Instruments:
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate:
Cash and Temporary Cash Investments: The carrying amount approximates fair
value because of the short-term maturity of these instruments.
Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair
value of these assets are based on market rates of similar securities.
Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the
System redeemable preferred stock and long-term debt were based on quoted
market prices for such securities at December 31, 1999 and 1998.
The estimated fair values of the System's financial instruments at
December 31, 1999 and 1998, were as follows:
Carrying Amount Fair Value
($ in thousands) 1999 1998 1999 1998
Cash and Temporary
Cash Investments $7,480 $32,090 $7,480 $32,090
Long-Term Notes Receivable
and Net Investment
in Sales-Type Leases 35,499 40,934 35,603 42,052
Redeemable Preferred Stock 30,000 30,000 30,525 32,625
Long-Term Debt 187,362 332,708 192,249 350,392
(G) Lines Of Credit:
In July 1997, several EUA System companies entered into a three-year
revolving credit agreement allowing for borrowings in aggregate of up to $225
million, as amended in November 1999, from all sources of short-term credit. On
November 23, 1999, Eastern Edison and Montaup entered into a $60 million credit
agreement to facilitate the buy out of the Pilgrim Station purchase power
agreement between Montaup and Boston Edison and for other general corporate
purposes. As of December 31, 1999, various financial institutions have
committed up to $75 and $60 million under each of the respective credit
facilities. In addition to the $135 million available under these credit
facilities, EUA System companies maintain short-term lines of credit with
various banks totaling $90 million for an aggregate amount available of $225
million. At December 31, 1999, the EUA System had unused short-term lines of
credit of approximately $81.0 million. During 1999, the weighted average
interest rate for short-term borrowings was 5.5%.
(H) Jointly Owned Facilities:
At December 31, 1999, in addition to the stock ownership interests
discussed in Note A, Nature of Operations and Summary of Significant Accounting
Policies - Jointly Owned Companies, Montaup had direct ownership interests in
the following electric generating facility:
Accumulated Net
Utility Provision for Utility Construction
Percent Plant in Depreciation Plant in Work in
($ in thousands) Owned Service & Amortization Service Progress
Montaup:
Millstone Unit 34.01% $178,359 $64,785 $113,574 $485
The foregoing amounts represent Montaup's interest in Millstone Unit 3,
including nuclear fuel where appropriate, and are included on the like-
captioned lines on the Consolidated Balance Sheet. At December 31, 1999
Montaup's total net investment in nuclear fuel amounted to $2.2 million.
Montaup's share of related operating and maintenance expenses of Millstone Unit
3 reflected in the preceding table are included in the corresponding operating
expenses.
(I) Financial Information By Business Segments:
Statement of Financial Accounting Standards No. 131, Disclosures about
Segments of an Enterprise and Related Information (SFAS 131), requires
disclosure of certain financial and descriptive information by operating
segments. The Core Electric Business includes results of the electric utility
operations of Blackstone, Eastern Edison, Newport and Montaup.
Energy Related Business includes results of our diversified energy-related
subsidiaries, EUA Cogenex, EUA Ocean State and EUA Energy Investment
Corporation (EUA Energy). EUA Telecommunications and EUA Energy Services,
which were included in Energy Related Business, were dissolved in 1999.
Corporate results include the operations of EUA Service and EUA Parent.
EUA does not have any intersegment revenues. Financial data for the business
segments are as follows:
Year Ended December 31, 1999
($ in thousands)
Core Energy
Electric Related Corporate Total
Operating Revenues $499,717 $54,050 $ $553,767
Pre-Tax Operating Income 82,237 (5,922) (2,152) 74,163
Income Taxes 17,769 (9,920) (2,530) 5,319
Depreciation and
Amortization 33,740 10,764 6 44,510
Cash Construction Expenditures 23,877 33,015 147 57,039
Equity in Subsidiary Earnings 839 8,394 9,233
Net Interest Charges 21,353 9,932 5,793 37,078
Net Interest Income 1,774 5,879 17 7,670
Net Income 35,534 (19,638) 1,022 16,918
Year Ended December 31, 1998
($ in thousands)
Core Energy
Electric Related Corporate Total
Operating Revenues $480,080 $58,721$ $538,801
Pre-Tax Operating Income 84,586 (2,945) (2,045) 79,596
Income Taxes 22,685 (1,387) (1,845) 19,453
Depreciation and
Amortization 38,804 12,267 8 51,079
Cash Construction Expenditures 22,888 26,801 1,512 51,201
Equity in Subsidiary Earnings 1,390 8,134 9,524
Net Interest Charges 23,593 12,219 1,387 37,199
Net Interest Income 528 7,210 63 7,801
Net Income 35,160 (2,854) 2,404 34,710
Year Ended December 31, 1997
($ in thousands)
Core Energy
Electric Related Corporate Total
Operating Revenues $506,696 $61,817$ $568,513
Pre-Tax Operating Income 78,795 (3,785) (1,980) 73,030
Income Taxes 20,303 547 1,645 22,495
Depreciation and
Amortization 36,069 10,858 14 46,941
Cash Construction Expenditures 21,870 51,941 2,307 76,118
Equity in Subsidiary Earnings 1,599 7,867 9,466
Net Interest Charges 24,668 13,295 1,193 39,156
Net Interest Income 1,678 8,854 16 10,548
Net Income 35,188 1,529 1,243 37,960
Years ended December 31, ($ in thousands) 1999 1998
Total Plant and Other Investments
Core Electric $450,885 $648,281
Energy Related 136,395 164,439
Corporate 17,753 18,973
Total Plant and Other Investments 605,033 831,693
Other Assets
Core Electric 768,183 370,360
Energy Related 56,513 67,780
Corporate 38,124 32,805
Total Other Assets 862,820 470,945
Total Assets $1,467,853 $1,302,638
(J) Commitments And Contingencies:
Plan of Merger Agreement: On February 1, 1999, EUA and New England Electric
System (NEES) entered into an Agreement and Plan of Merger under which NEES
will acquire all outstanding shares of EUA for $31 per share in cash. Under
certain terms of the merger agreement, if the merger agreement is terminated by
EUA, EUA would pay NEES a termination fee of $20 million plus up to $5 million
for documented out-of-pocket expenses.
Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs: The owners (or
lead participants) of the nuclear units in which Montaup has an interest have
made, or expect to make, various arrangements for the acquisition of uranium
concentrate, the conversion, enrichment, fabrication and utilization of nuclear
fuel and the disposition of that fuel after use. The owners (or lead
participants) of United States nuclear units have entered into contracts with
the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance
with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject
to various contingencies) that the federal government design, license,
construct and operate a permanent repository for high level radioactive wastes
and spent nuclear fuel and establish a prescribed fee for the disposal of such
wastes and nuclear fuel. The NWPA specifies that the DOE provide for the
disposal of such waste and spent nuclear fuel starting in 1998. Objections on
environmental and other grounds have been asserted against proposals for
storage as well as disposal of spent nuclear fuel. The DOE now estimates that
a permanent disposal site for spent fuel will not be ready to accept fuel for
storage or disposal until as late as the year 2010. In early 1998, a number of
utilities filed suit in federal appeals court seeking, among other things, an
order requiring the DOE to immediately establish a program for the disposal of
spent nuclear fuel. On May 5, 1998, the Court of Appeals denied several motions
brought in the proceeding, including several motions for injunctive relief
brought by the utility petitioners. In particular, the Court denied the
requests to require the DOE to immediately establish a program for the disposal
of spent nuclear fuel. In late October and early November 1998, the U.S. Court
of Federal Claims issued rulings with respect to Yankee Atomic, Maine Yankee,
and Connecticut Yankee finding that the DOE was financially responsible for
failing to accept spent nuclear fuel. These rulings clear the way for Yankee
Atomic, Connecticut Yankee and Maine Yankee to pursue at trial their individual
damage claims. The DOE filed a motion to stay the case pending resolution
of its appeal request granted by the Appeals Court. In October 1999, the Court
issued a stay order on the damage claims. Montaup owns a 4.01% interest in
Millstone 3. Northeast Utilities, the operator of the units, indicates that
Millstone 3 has sufficient on-site storage facilities which, with rack
additions, can accommodate its spent fuel for the projected life of the unit.
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.
Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear
generating facility which is in the process of decommissioning. Montaup's
share of the total estimated costs for the permanent shutdown, decommissioning,
and recovery of the investment in Connecticut Yankee is approximately $19.3
million. On August 31, 1998, a FERC law judge rejected Connecticut Yankee's
filed plan to decommission the plant. The judge claimed that estimates of
clean-up costs were flawed and certain restoration costs were not supported.
The judge also said Connecticut Yankee could not pass on spent fuel storage
costs to rate-payers. The judge recommended that Connecticut Yankee withdraw
its decommissioning plan and submit a new plan which addresses the issues cited
by him. FERC will review the judge's recommendations and issue a decision on
this case in the coming months. If FERC concurs with the judge's
recommendation, this may result in a write down of certain of Connecticut
Yankee plant investments. Montaup cannot predict the ultimate outcome of
FERC's review.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3. Montaup's share of the current estimate
of total costs to decommission Millstone 3 is approximately $24.8 million in
1999 dollars. This figure is based on studies performed for Northeast
Utilities, the lead owner of the unit. Montaup also pays into decommissioning
reserves pursuant to contractual arrangements with other nuclear generating
facilities in which it has an equity ownership interest. Such expenses are
currently recoverable through rates.
Pensions: EUA maintains a noncontributory defined benefit pension plan
(Retirement Plan) covering most of the employees of the EUA System. 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 an amount
related to the 1997 voluntary retirement incentive offer, for 1999, 1998 and
1997 included the following components:
(In thousands) 1999 1998 1997
Service cost $3,051 $2,929 $2,816
Interest cost 10,776 10,390 10,116
Expected return on assets (16,797) (15,033) (13,761)
Net amortization:
Prior service cost 763 671 667
Net actuarial gain (556) (395) (183)
Transition asset (274) (274) (274)
Net periodic pension income $(3,037) (1,712) (619)
Subsidiary curtailment* (131)
Total periodic pension
income expense $(3,037) $(1,712) $(750)
* During 1999, Montaup recorded a regulatory asset of approximately $2.7
million related to the cost of offering an early retirement plan and a
$700,000 gain due the curtailment of the plan. This amount will be recovered
as part of Montaup's CTC billed to its retail affiliates.
Assumptions to determine pension costs:
1999 1998 1997
Discount rate 6.75% 7.25% 7.50%
Compensation increase rate 4.25% 4.25% 4.25%
Long-term return on assets 9.50% 9.50% 9.50%
The following tables set forth the actuarial present value of projected
benefit obligations, fair value of assets and funded status at December 31,
1999 and 1998:
Reconciliation of Projected Benefit Obligation
(In thousands)
1999 1998
Beginning of year benefit obligation $159,458 $144,915
Service cost 3,051 2,929
Interest cost 10,776 10,390
Actuarial (gain) loss (20,760) 9,256
Disbursements (10,959) (8,032)
Plan amendments 3,656
Special benefit termination
cost 2,676
Curtailment gain (1,038)
End of year benefit obligation $146,860 $159,458
Reconciliation of Fair Value of Assets
(In thousands)
1999 1998
Beginning of year fair value of assets $212,837 $182,795
Actual return on plan assets 46,796 38,074
Disbursements (10,959) (8,032)
End of year fair value of assets $248,674 $212,837
Reconciliation of Funded Status
(In thousands)
1999 1998
Projected benefit obligation (PBO) $(146,860) $(159,458)
Fair value of plan assets (FVA) 248,674 212,837
PBO less than FVA (funded status) 101,814 53,379
Unrecognized prior service cost 6,714 4,153
Unrecognized net transition
obligation (asset) (387) (662)
Unrecognized net actuarial (gain) (105,049) (54,845)
Net amount recognized $3,092 $2,025
The discount rate used to determine pension obligations, effective January
1, 2000 was changed from 6.75% to 7.75% and was used to calculate the plan's
funded status at December 31, 1999.
At December 31, 1999, approximately $2.5 million was included in other
liabilities for unfunded non-qualified pension benefits related to the 1997
voluntary retirement incentive.
EUA also maintains non-qualified supplemental retirement plans
(Supplemental Plans) for certain officers and trustees of the EUA System.
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, and policy cash values and death
benefits may be available to offset EUA's obligations under the Supplemental
Plans. As of December 31, 1999, approximately $8.2 million was included in
accrued expenses and other liabilities for these plans. Expenses related
to the Supplemental Plans were $2.2 million in 1999, $1.1 million in 1998 and
$1.9 million in 1997.
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 $1.7 million in 1999, $1.5 million in
1998 and 1997.
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 total cost of post-retirement benefits other than pensions, including
an amount related to the 1997 voluntary retirement incentive offer, for 1999,
1998 and 1997 includes the following components:
(In thousands) 1999 1998 1997
Service cost $1,091 $967 $949
Interest cost 4,822 4,526 4,434
Expected return on assets (2,352) (1,849) (1,254)
Net amortization:
Net actuarial (gain) (266) (780) (842)
Transition obligation 2,841 3,289 3,289
Net periodic postretirement
benefit cost 6,136 6,153 6,576
Subsidiary curtailment * (548)
Voluntary retirement incentive * 172
Total periodic postretirement
benefit cost $6,136 $6,153 $6,200
* Montaup recorded a regulatory asset of approximately $5.5 million due to a
loss resulting from the curtailment of the plan, and $200,000 related to the
cost of offering an early retirement plan.
This amount will be recovered as part of Montaup's CTC billed to its retail
affiliates.
Assumptions to determine post-retirement costs:
Discount rate 6.75% 7.25% 7.50%
Health care cost trend rate
- near-term 6.00% 6.00% 7.00%
- long-term 5.00% 5.00% 5.00%
Compensation increase rate 4.25% 4.25% 4.25%
Long-term return on assets
- union 8.50% 8.50% 8.75%
- non-union 7.50% 7.50% 7.75%
The following tables forth the actuarial present value of accumulated
postretirement benefit obligation, fair value of assets and funded status at
December 31, 1999 and 1998.
Reconciliation of Accumulated Post-retirement Benefit Obligation
(In thousands) 1999 1998
Beginning of year benefit
obligation (January 1) $69,628 $64,826
Service cost 1,091 967
Interest cost 4,821 4,526
Participant contributions 145 151
Actuarial (gain) loss (6,389) 2,644
Disbursements (3,707) (3,486)
Special benefit termination cost 205
Curtailment gain (746)
End of year benefit
obligation (December 31) $65,048 $69,628
Reconciliation of Fair Value Assets
(In thousands) 1999 1998
Beginning of year fair value of
assets (January 1) $30,195 $23,729
Actual return on plan assets 2,762 3,007
Company contributions 6,173 6,794
Participant contributions 144 151
Disbursements (3,707) (3,486)
End of year fair value of
assets (December 31) $35,567 $30,195
Reconciliation of Funded Status
(In thousands) 1999 1998
Accumulated post-retirement benefit
obligation (APBO) $(65,048) $(69,628)
Fair value of plan assets (FVA) 35,567 30,195
APBO (in excess of) FVA (Funded Status) (29,481) (39,433)
Unrecognized net transition
obligation 36,938 46,046
Unrecognized net actuarial gain (20,500) (13,967)
Net amount recognized $(13,043) $(7,354)
Effect of 1% Change in Assumed Health Care Cost Trend Rate
One Percent
(In thousands) Increase Decrease
Effect on 1999 service and interest cost
components of net-periodic costs $917 $(728)
Effect on 1999 accumulated post-retirement
benefit obligation $8,440 $(6,855)
The discount rate used to determine post-retirement benefit obligations
effective January 1, 2000 was changed from 6.75% to 7.75% and was used to
calculate the funded status of post-retirement benefits at December 31, 1999.
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 certain charges whether or not energy is received in addition to
other amounts that depend on the actual amount of energy delivered. In 1999,
these purchased power contracts, with the exception of the nuclear
entitlements, were transferred to third parties under terms that result in
fixed payments through 2009. In addition, Montaup's obligations to Boston
Edison under the Pilgrim contract have been essentially reduced to its share of
the property tax settlement with the town of Plymouth, and Montaup is obligated
to Entergy under the replacement contract only for energy actually delivered.
It is anticipated that in 2000, Montaup will make a payment to terminate its
purchase obligation from Vermont Yankee. Under terms in effect as of December
31, 1999, the aggregate commitments under the long-term purchased power
contracts are approximately $46 million in 2000, $37 million in 2001, $39
million in 2002, $23 million in 2003, $24 million in 2004 and $98 million for
the ensuing years. These amounts, which also include certain continuing
obligations (primarily for decommissioning) to Vermont Yankee and the retired
nuclear plants, are currently fully recoverable through rates.
Environmental Matters: There is an extensive body of federal and state
statutes governing environmental matters, which permit, among other things,
federal and state authorities to initiate legal action providing for liability,
compensation, cleanup, and emergency response to the release or threatened
release of hazardous substances into the environment and for the cleanup of
inactive hazardous waste disposal sites which constitute substantial hazards.
Because of the nature of the EUA System's business, various by-products and
substances are produced or handled which are classified as hazardous under the
rules and regulations promulgated by the United States Environmental Protection
Agency (EPA) as well as state and local authorities. The EUA System generally
provides for the disposal of such substances through licensed contractors, but
these statutory provisions generally impose potential joint and several
responsibility on the generators of the wastes for cleanup costs. Subsidiaries
of EUA have been notified with respect to a number of sites where they may be
responsible for such costs, including sites where they may have joint and
several liability with other responsible parties. It is the policy of the EUA
System companies to notify liability insurers and to initiate claims. EUA is
unable to predict whether liability, if any, will be assumed by, or can be
enforced against, the insurance carriers in these matters. On December 13,
1994, the United States District Court for the District of Massachusetts
(District Court) issued a judgment against Blackstone, finding Blackstone
liable to the Commonwealth of Massachusetts (Commonwealth) for the full amount
of response costs incurred by the Commonwealth in the cleanup of a by-product
of manufactured gas at a site at Mendon Road in Attleboro, Massachusetts. The
judgment also found Blackstone liable for interest and litigation expenses
calculated to the date of judgment. The total liability is approximately $5.9
million, including approximately $3.6 million in interest which had accumulated
since 1985. Due to the uncertainty of the ultimate outcome of this proceeding
and anticipated recoverability whether through rates, insurance providers or
other parties, Blackstone recorded an asset for the amount funded under the
escrow agreement (discussed below) consistent with provisions of SFAS 5,
specifically paragraphs 3, 10, and 13 and SFAS 71, specifically paragraphs 3
and 9. This amount is included with Other Assets on the Consolidated Balance
Sheets at December 31, 1999 and 1998. Should the EPA determine the substance
to be non-toxic, the company may be able to retain the entire escrowed amount
and would relieve both the asset and liability from its balance sheet at that
time. However should the EPA determine that the substance is hazardous, the
company would amortize its asset, net of amounts recovered through insurance
proceeds or from other parties, over a five year period in accordance with the
company's established rate recovery mechanisms of similar costs.
Blackstone filed a Notice of Appeal of the District Court Judgment and
filed its brief with the United States Court of Appeals for the First Circuit
(First Circuit) on February 24, 1995. On October 6, 1995, the First Circuit
vacated the District Court's judgment and ordered the District Court to refer
the matter to the EPA to determine whether the chemical substance, ferric
ferrocyanide (FFC), contained within the by-product is a hazardous substance.
On January 20, 1995, Blackstone entered into an escrow agreement with the
Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who
transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue
on the judgment amount.
On January 28, 1994, Blackstone filed a complaint in the District Court,
seeking, among other relief, contribution and reimbursement from Stone &
Webster Inc., of New York City and several of its affiliated companies (Stone &
Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any
damages incurred by Blackstone regarding the Mendon Road site. On November 7,
1994, the Court denied motions to dismiss the complaint which were filed by
Stone & Webster and Valley. This proceeding was stayed in December 1995
pending final EPA determination as to whether FFC is a hazardous substance.
In addition, Blackstone has notified certain liability insurers and has
filed claims with respect to the Mendon Road site, as well as other sites.
Blackstone reached settlement with one carrier for reimbursement of legal costs
related to the Mendon Road case. In January 1996, Blackstone received the
proceeds of the settlement.
As of December 31, 1999, the EUA System had incurred costs of
approximately $9.5 million (excluding the $5.9 million Mendon Road judgment) in
connection with the investigation and clean-up of these sites, substantially
all of which relate to Blackstone. These amounts have been financed primarily
by internally generated cash. Blackstone is currently amortizing all of its
incurred costs over a five-year period consistent with prior regulatory
recovery periods and is recovering certain of those costs in rates.
EUA estimates that additional costs of up to $2.2 million (excluding the
$5.9 million Mendon Road judgment) may be incurred at these sites through 2000,
$1.4 million of which of which relates to Blackstone and $800,000 which relates
to sites at which Blackstone is a potentially responsible party. Estimates
beyond 2000 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.
During the second quarter of 1999, EUA identified four new sites related
to the production of manufactured gas at which certain environmental conditions
may exist. Three sites are associated with Blackstone and one site is
associated with Eastern Edison. EUA has conducted a preliminary assessment of
the potential cost of remediation at these sites. An engineering model was
recently obtained by the Company to provide the estimated potential costs.
Since site specific studies have not yet been performed, EUA has recorded a
minimum liability for each of these sites based on this engineering model to
recognize risk assessment, monitoring, and legal and administrative costs.
In addition, EUA has recorded estimated environmental remediation
liabilities for two previously-identified manufactured gas plant sites
associated with Blackstone. The sites are the Tidewater site, the location of
a former electric generating station and manufactured gas plant in Pawtucket,
Rhode Island, and the Hamlet Avenue Site, a former manufactured gas plant site
located in Woonsocket, Rhode Island. Estimates were not previously recorded
for these locations since site-specific studies had not been completed and a
reliable engineering model deemed essential to develop a reasonable estimate
was not previously available.
With respect to the Tidewater site, EUA completed its site investigation
study during the third quarter of 1999 to determine the nature and extent of
contamination. The study identified elevated levels of hazardous substances
over an extended area of both the surface and subsurface. The Hamlet Street
site assessment has not yet been finalized. However, the assessment conducted
to date has determined that varying degrees of hazardous substances are present
at that site.
Therefore, in the third quarter of 1999, a total estimated remediation
liability of $21.2 million was recorded as a long-term liability with a
corresponding charge to a regulatory asset on the Consolidated Balance Sheet.
Blackstone and Eastern Edison are currently recovering certain environmental
cleanup costs in rates. In addition, the Company will seek recovery of certain
costs from its insurance carriers and other possible responsible parties. The
Company expects, based on prior regulatory approvals, to recover such costs in
future rates. As a result, the Company does not believe that the ultimate
impact of the cleanup costs associated with these sites will be material to
the results of its operations or its financial position.
See Note A, Nature of Operations and Summary of Significant Accounting
Policies - Generation Divestiture regarding EUA's divestiture of generation
assets.
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. Some states have enacted
regulations to limit the strength of EMF at the edge of transmission line
rights-of-way. The Rhode Island legislation has enacted a statute which
authorizes and directs the Rhode Island Energy Facility Siting Board to
establish rules and/or regulations governing construction of high voltage
transmission lines of 69 kv or more. 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 $24.5 million,
10.56% unsecured long-term notes due 2005 and EUA Ocean State's $26.1 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 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 $3.7 million of
the outstanding debt of these two companies. In addition, Montaup and Newport
have minimum rental commitments which total approximately $10.5 million
and $1.3 million, respectively, under a noncancelable transmission facilities
support agreement for years subsequent to 1999.
Other: Since early 1997, fourteen plaintiffs brought suits against numerous
defendants, including EUA, for injuries and illness allegedly caused by
exposure to asbestos over approximately a thirty-year period, at various
premises, including some owned by EUA companies. The total damages claimed in
all of these complaints is $34 million in compensatory and punitive damages,
plus exemplary damages and interest and costs. Each complaint names between
fifteen and twenty-eight defendants, including EUA. These complaints have been
referred to the applicable insurance companies. Counsel has been retained by
the insurers and is actively defending all cases. Six cases have been
dismissed as against EUA companies. EUA cannot predict the ultimate outcome of
this matter at this time.
A pending class action, filed on March 2, 1998, in the Massachusetts
Supreme Judicial Court naming all Massachusetts electric distribution
companies, including Eastern Edison, and certain Massachusetts state agencies
as defendants, seeks to invalidate certain sections of the Electric Utility
Restructuring Act of 1997. The Act directs the Massachusetts Department of
Telecommunications and Energy to impose mandatory charges on all electricity
sold to customers, except those served by a municipal lighting plant, to fund
energy efficiency activities and to promote renewable energy projects. In
addition to declaratory judgment, plaintiffs seek remittance of monies paid by
customers to each distribution company by customers for renewable projects
together with any interest earned. The outcome of this class action is unknown
at this time however, Eastern Edison is vigorously defending the lawsuit.
On February 15, 2000, the United States Attorney for the District of
Massachusetts informed the Company that his office is investigating possible
criminal conduct, including mail fraud by EUA Cogenex and/or its employees.
The conduct in question involves alleged intentional overbilling by
EUA Cogenex of certain cogeneration customers during 1994 and 1995, when EUA
Cogenex owned cogeneration projects, and filing false information with FERC in
order to maintain the facilities' status as qualifying facilities under the
Public Utility Regulatory Policies Act of 1978. EUA Cogenex is fully
cooperating with the United States Attorney's investigation. Although the
Company cannot predict the ultimate outcome of this investigation, the Company
does not believe that it will have a material effect on the financial position
of the Company.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages and positions of all of the Trustees of EUA as of March
20, 2000 are listed below. Trustees are elected annually at the Annual Meeting
of Shareholders and each was elected to their present term of office at the
Annual Meeting of Shareholders held on May 17, 1999. Each of the Trustees has
served in the capacity indicated in the list for more than five years, with the
exception of Jacek Makowski, who was Chairman and Chief Executive Officer of J.
Makowski Company prior to 1996. There is no family relationship between any of
the Trustees of EUA.
In addition to their principal occupations in the following table, the
individuals listed are trustees or directors of publicly held companies as
follows: Mr. Boss is a Director of A.T. Cross Company and Brown & Sharpe
Manufacturing Co.; Mr. Choquette is a Director of Fleet Financial
Group and Carlisle Companies, Inc.; Mr. Freeman is a Trustee or Director of
Providence Journal Company, Amica Mutual Insurance Company, Amica Life
Insurance Company and various registered mutual funds for which Scudder Kemper
Investments is investment advisor; Mr. Liebenow is a Director of Quaker Fabric
Corporation; Mr. Marple is a Trustee of various registered mutual funds for
which Scudder Kemper Investments is investment advisor; and Mr. Thorndike is
a Director of Courier Corporation, Data General Corporation and Bradley Real
Estate Inc. and a Trustee of the Putnam Funds and Cabot Industrial Trust. In
February 1994, Mr. Thorndike accepted appointment as a successor trustee of
private trusts in which he has no beneficial interest, and concurrently became,
serving until October 1994, Chairman of the Board of two privately owned
corporations controlled by such trusts that filed voluntary petitions for
relief under Chapter 11 of the United States Bankruptcy Code in August 1994.
Trustee
Name and age Principal Occupation Since
Russell A. Boss, 61 Chairman and Director,
A.T. Cross Company (writing
instruments manufacturer), Lincoln,
Rhode Island 1989
Paul J. Choquette, Jr., 61 Chairman and Chief Executive Officer of
Gilbane Building Company
(building construction),
Providence Rhode Island 1992
Peter S. Damon, 64 Vice Chairman, Financial Services,
Bank of Newport, Newport, Rhode
Island 1991
Peter B. Freeman, 67 Corporate Director and Trustee,
Providence, Rhode Island 1979
Larry A. Liebenow, 56 President and Chief Executive Officer
of Quaker Fabric Corporation
(upholstery manufacturer), Fall
River, Massachusetts 1994
Jacek Makowski, 69 Chairman, Poseidon Resources Corporation
(origination and development of major
capital projects), Stamford, Connecticut 1995
Wesley W. Marple, Jr., 67 Professor of Business Administration,
Northeastern University, Boston,
Massachusetts 1976
Donald G. Pardus, 59 Chairman of the Board of Trustees
and Chief Executive Officer of the
Association 1982
Margaret M. Stapleton, 63 Vice President, John Hancock Mutual
Life Insurance Company, Boston,
Massachusetts 1977
John R. Stevens, 59 President and Chief Operating Officer
of EUA 1990
W. Nicholas Thorndike, 66 Corporate Director and Trustee,
Brookline, Massachusetts 1991
The names, ages and positions of all of the executive officers of EUA as
of March 20, 2000, 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
2000 Annual Meeting of Shareholders is scheduled to be held on July 17, 2000.
This meeting will occur only if the EUA-NEES merger is not completed by that
date. There are no family relationships among these officers, nor any
arrangement or understanding between any officer and any other person pursuant
to which the officer was selected. The executive officers also serve
as officers/or directors of various subsidiary companies.
Name, Age and Position Business Experience During Past 5 Years
John D. Carney, 55 Executive Vice President since April 1995;
Executive Vice President President of Eastern Edison Company since
January 1990; President of Blackstone and
Newport since April 1995. Responsible for the
day-to-day activities of The EUA System's retail
electric operations.
Clifford J. Hebert, Jr., 52 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, 59 Chairman since July 1990; Chief Executive Officer
Chairman of the Board, since April 1989. Responsible for the overall
Chief Executive Officer management of the EUA System.
and Trustee
Robert G. Powderly, 52 Executive Vice President since April 1992.
Vice President Executive Responsible for purchasing, customer
information services, information systems, human
resources, marketing and r ate activities of the
EUA System.
John R. Stevens, 59 President since July 1990; Chief Operating
President, Chief Operating Officer since January 1990. Responsible for
Officer and Trustee 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.
Item 11. EXECUTIVE COMPENSATION
Compensation and Other Transactions
Summary Compensation Table: Information is set out below as to compensation
paid by EUA and its subsidiaries for the years 1997, 1998 and 1999, to each of
the five highest paid executive officers of EUA whose aggregate cash
compensation for 1999 exceeded $100,000.
Long Term
Annual Compensation Compensation
Other Restricted
Fiscal Incentive Annual Stock All Other
Name and Position Year Salary Bonus Compensation(1) Awards (2) Compensation(3)
Donald G. Pardus 1999 $461,265 - (4) $13,313 - $18,577
Chairman and Chief 1998 $443,525 $351,311 $14,100 $511,106 $14,865
Executive Officer 1997 $428,525 $167,112 $12,747 $232,617 $13,775
John R. Stevens 1999 $360,025 - (4) $12,743 - $14,305
President and Chief 1998 $346,025 $296,026 $16,696 $408,811 $11,462
Operating Officer 1997 $334,325 $133,665 $11,763 $232,617 $10,726
Robert G. Powderly 1999 $199,025 $64,492 $13,671 - $6,842
Executive Vice 1998 $191,025 $145,743 $10,726 $142,105 $5.907
President 1997 $184,025 $51,249 $10,240 $116,322 $5,560
John D. Carney 1999 $195,525 $64,492 $9,157 - $6,961
Executive Vice 1998 $187,525 $145,743 $11,302 $142,105 $6,085
President 1997 $179,525 $51,249 $10,502 $87,235 $5,624
Clifford J. Hebert, Jr. 1999 $162,625 $53,774 - - $5,039
Treasurer and Secretary 1998 $148,025 $138,140 - $90,056 $4,699
1997 $136,025 $28,417 - $116,322 $4,078
(1) Represents amount reimbursed for tax liability accruing as a result of
personal use of company-owned automobiles.
(2) Aggregate amount and value (including the value reflected in the table
under "Restricted Stock Awards") as of December 31, 1999 of shares
granted under EUA's Restricted Stock Plan to the officers listed above are
as follows: Mr. Pardus, 43,841 shares, $1,063,124; Mr. Stevens, 34,565
shares, $843,990; Mr. Powderly, 13,412 shares, $329,451; Mr. Carney,
12,363 shares, $302,089; and Mr. Hebert, 9,834 shares, $244,213.
Dividends are paid on these shares. Restrictions on awards made in 1998
expire after five years, and restrictions on awards made in 1997 expired
after two years. All restrictions expire upon the occurrence of a change-
of-control event, including the proposed merger (See Item 1. BUSINESS -
Merger Update.)
(3) Contributions made under EUA's Employees' Savings Plan and term life
insurance premiums.
(4) The EUA Board voted to award Messrs. Pardus and Stevens a Merger
Completion Bonus to be paid on the closing of the EUA-NEES merger. This
bonus is in lieu of an annual incentive payment for 1999. The bonus
payment to Messrs. Pardus and Stevens is $500,000 and $425,000,
respectively.
Pension Plan Table:
Years of Service
Average Annual Salary 15 20 25 30 35 40
$100,000 $24,000 $32,000 $40,000 $48,000 $56,000 $59,750
200,000 48,000 64,000 80,000 96,000 112,000 119,500
300,000 72,000 96,000 120,000 144,000 168,000 179,250
400,000 96,000 128,000 160,000 192,000 224,000 239,000
500,000 120,000 160,000 200,000 240,000 280,000 298,750
600,000 144,000 192,000 240,000 288,000 336,000 358,500
The Employee's Retirement Plan of Eastern Utilities Associates and its
Affiliated Companies (the "Pension Plan") is a tax-qualified defined benefit
plan available to employees who have completed one year of service and have
attained the age of twenty-one. All of the officers referred to in the
preceding Summary Compensation Table participate in the Pension Plan. Trustees
who are not also employees of EUA and its subsidiaries (the "EUA System") are
not covered by the Pension Plan. The benefits of participants become fully
vested after five years of service. Annual lifetime benefits are determined
under formulas applicable to all employees, regardless of position, and the
amounts depend on length of credited service and salaries prior to retirement.
Benefits are equal to one and six-tenths percent of salaries (averaged over the
four years preceding retirement) for each year of credited service up to
thirty-five, reduced for each year by one and two-tenths percent of the
participants' estimated age sixty-five Social Security benefit, plus seventy-
five hundredths percent of salaries for each year of credited service in excess
of thirty-five years up to the Pension Plan maximum of forty years.
Any contributions to provide benefits under the Pension Plan are made by
the EUA System in amounts determined by the Pension Plan's actuaries to meet
the funding standards established by the Employee Retirement Income Security
Act of 1974. Any contributions are actuarially determined and cannot
appropriately be allocated to individual participants. The annual benefits
shown in the table above are straight life annuity amounts, without reduction
for primary Social Security benefits as described above. Federal law limits the
annual benefits payable from qualified pension plans in the form of a life
annuity, after reduction for Social Security benefits, to $130,000 for 1999
plus adjustments for increases in the cost of living. The number of years of
service credited at present under the Pension Plan to Messrs. Pardus, Stevens,
Carney, Powderly and Hebert are thirty-seven, thirty-four, thirty-three, twenty
and twenty-three, respectively.
EUA also has a Key Executive Plan for certain officers of EUA and its
subsidiaries. This plan provides for the annual payment of supplemental
retirement benefits equal to 25% of the officer's base salary when he retires
or EUA terminates the executive's employment without cause, for a period of
fifteen (15) years following the date of retirement. In addition, in the event
of the death of the participant prior to retirement an amount equal to 200% of
the officer's base salary at that time will be paid to his beneficiary. In
1999, EUA amended the Key Executive Plan to provide five (5) additional years
(from fifteen (15) to twenty (20) years) of benefits continuation for Messrs.
Pardus and Stevens.
EUA maintains Retirement Restoration Plans for Members of the Employees'
Retirement Plan of Eastern Utilities Associates and its Subsidiary Companies
and EUA Employees' Savings Plan (the "Restoration Plans") and the Supplemental
Retirement Plan for Certain Officers of EUA and its Affiliated Companies
("SERP") as unfunded retirement plans to restore benefits under the qualified
plans' formulas which are not covered under the qualified plan trusts due to
federal limitations on either earnings, contributions or benefits. Payments or
contributions which exceed the applicable federal limitations are made outside
the qualified plans in the same manner and under the same conditions as are
applicable to benefits payable from, or contributions payable to, the qualified
plans. A grantor trust has been established by EUA to help ensure the
performance of its payment obligations under these plans. Any amounts not
covered by trust payments or otherwise will be paid from funds available to the
EUA System. In 1999, EUA amended and restated the Restoration Plans and SERP
to provide for an increase in the benefit payable to Messrs. Pardus, Stevens,
Powderly, Carney and Hebert by adding five (5) additional years of age and
service when determining their retirement benefits under such plans. The
additional years of service used in such calculation for Mr. Pardus was
limited to a maximum for forty (40) years.
Change-In-Control Arrangements: EUA entered into Executive Severance
Agreements in 1991 with each of its executive officers - Donald G. Pardus,
Chairman and Chief Executive Officer, John R. Stevens, President and Chief
Operating Officer, Robert G. Powderly, Executive Vice President, John D.
Carney, Executive Vice President, and Clifford J. Hebert, Jr., Treasurer and
Secretary, and extended the Executive Severance Agreements for these executive
officers with certain modifications in 1995. In 1999, EUA amended the
Executive Severance Agreements for Messrs. Pardus and Stevens (described
below). These agreements remain in effect for a three year protection
period.
Under these agreements, EUA is obligated to pay the executive officer
severance benefits if, during the protection period, either (1) EUA terminates
the executive officer's employment without cause (as defined in the Executive
Severance Agreement), or (2) the executive terminates his covered employment
for good reason (as defined in the agreement). NEES has not offered either
of Messrs. Pardus or Stevens continuation of employment in their current
positions, and since neither is expected to remain with the surviving company
following the merger, each will become entitled to severance benefits upon the
Effective Time of the Merger. Messrs. Hebert and Carney will terminate their
employment following consummation of the merger and will be entitled to receive
severance benefits in accordance with their respective Executive Severance
Agreements. NEES has indicated that following the merger it expects to seek to
retain the services of Mr. Powderly, but Mr. Powderly is not party to any new
agreement with NEES with respect to such continued employment.
Benefits that may be payable under the Executive Severance Agreements
consist of (i) a lump-sum cash amount generally equal to the present value of
the additional wages and retirement benefits that the executive would have
received in return for completing an additional three years of service, (ii)
continuation or vesting of certain fringe benefits and common share grants,
(iii) reimbursement of legal fees and expenses incurred as a result of the
termination or to enforce the provisions of the severance agreement and (iv)
reimbursement for a portion of the taxes on certain of the foregoing payments,
including any amount constituting a "parachute payment" under the Internal
Revenue Code.
In June 1999, the Board voted to award Messrs. Pardus and Stevens a Merger
Completion Bonus along the terms described above. After considering the
payment of the Merger Completion Bonus, the Board voted to award a lump sum
severance payment to Messrs. Pardus and Stevens of $4,984,780 and $4,052,980,
respectively, and voted to amend the Executive Severance Agreements for Messrs.
Pardus and Stevens to guarantee retirement health coverage not less favorable
than the coverage provided under existing EUA plans at no cost to Messrs.
Pardus and Stevens, as well as to their spouses for their lives. The Board
also increased the life insurance coverage for Pardus and Stevens equal to two
times their final base salary.
Compensation of Trustees: Each non-management Trustee of EUA receives, as a
standard arrangement, a retainer fee for all services as a Trustee in the
amount of $19,000 annually, with an additional $850 fee for each Trustees' or
Committee meeting attended. In addition, each committee chairperson receives
an annual retainer fee in the amount of $2,500. Each non-management Trustee
is entitled to participate in the EUA Trustees' Retirement Plan. The EUA
Trustees' Retirement Plan was amended in 1999 to provide for a retirement
benefit based on a minimum period of credited service equal to ten years and a
lump sum payment of all retirement benefits under the Trustees' Retirement Plan
to active Trustees as allowed under the Merger Agreement with NEES. In the
event of a change in control of EUA, a grantor trust has been established by
EUA to ensure the performance of its payment obligations under this retirement
plan.
None of the Trustees of EUA are expected to continue as such following the
Merger, although following the consummation of the Merger, NEES is expected to
cause all of the members of the EUA Board to be appointed to serve for a period
of two years on an advisory board to be formed pursuant to the National Grid
Merger Agreement. NEES has indicated to the Company that advisory board
members will be paid a $10,000 annual retainer fee and a $3,500 per meeting
fee. The function of the advisory board will to be to advise the NEES Board of
Directors with respect to general business as well as opportunities and
activities in the surviving entities' market area and to maintain and develop
customer relationships.
Report of the Compensation and Nominating Committee on Compensation of
Executive Officers
Historically, the compensation philosophy of the Board of Trustees'
Compensation and Nominating Committee (the "Committee") and the Association is
to be competitive with prevailing utility industry compensation norms when
satisfactory results are achieved and surpass market norms when exceptional
results are reached. In early 1999, the completion of the Agreement and Plan
of Merger with New England Electric System was a significant accomplishment
which was taken into account by the Committee in making its decisions on
Executive compensation. The Committee is composed entirely of independent,
non-employee trustees.
Compensation of executive officers, including the Chief Executive Officer
("CEO"), is a mix of three components, base salary, annual cash incentives and
long-term incentives ("Stock Grants"). In recent years, the Association has
moved toward placing a greater percentage of compensation at risk through the
use of annual cash incentives and Stock Grants. The incentives are designed to
retain the talent required to manage the Association's business through the
transition to competition and to enhance shareholder value. In 1997, the
Association added a special retention stock grant component to the compensation
mix in an effort to enhance the probability of retaining certain key management
professionals for the next two years.
Base Salary: The Committee, working with an independent compensation
consultant, annually reviews the base salary of the CEO and the four other
executive officers named in the Summary Compensation Table on page 89. Each
executive officer, including those named above, is assigned a salary range
which is established using compensation data for comparable officer positions
in other utilities. These other utilities: 1) generally have the same level
of annual revenue as the Association; 2) operate in generally the same
geographic areas as the Association; and 3) have other characteristics similar
to the Association. None of the comparative utilities are included in the
Standard & Poor's 26 Electric Utility Index ("S&P Electric Utility Index")
because their level of annual revenue is less than those utilities included in
that Index.
Each salary range has a minimum amount, a position value (reasonably
equivalent to market value) and an excess amount which is 10% above the
position value. Base salary is limited to no more than the excess amount.
Although no specific measure of corporate performance is used in determining
base salary, the Committee sets the base salaries for each of the officers
listed in the Summary Compensation Table after considering all of the following
factors: 1) the financial and operational performance of the Association; 2)
observed individual performance; 3) time in current position; 4) existing base
salary relative to position value and excess amount; and, 5) except for the
CEO, input of the CEO. Generally, the base salary of the CEO and the four
other officers approximates the averages for similar positions in the
comparable utilities described above. Base salary increases for 1999 were
based on the factors outlined above, as well as the signing of the Agreement
and Plan of Merger factor discussed above.
Annual Cash Incentives: The Association has had an Annual Cash Incentive Plan
since 1987. The 1999 version of the Plan applicable to officers, other than
the CEO and COO, contained three Performance Objectives which were approved by
the Committee in early 1999. One Performance Objective measures Core Electric
Business Operation and Maintenance Expense against budget. The second
Performance Objective measures the Cost of Service Per Customer against a peer
group of 20 New England utilities.
The 1999, Core Electric Business Operation and Maintenance Expense was
more than 5% under budget, resulting in a maximum payout for this component.
Performance under the Cost of Service Per Customer Objective was slightly under
the target.
With respect to the peer group of 20 New England utilities used for the
Cost of Service Per Customer Performance Objective, none are included in the
S&P Electric Utility Index. This peer group was selected because it includes
virtually all of the electric utilities located in the same geographic area as
the Association (New England).
The final Performance Objective was discretionary. The officer group had
as its primary goal complete involvement in all activities related to the
completion of the merger with New England Electric System and the combination
of New England Electric System and the EUA System.
The Committee's discretionary awards to Messrs. Powderly, Carney and
Hebert reflect their participation in the merger transition. These awards are
included in the amounts reflected in the Summary Compensation Table on page 89.
The Agreement and Plan of Merger expressly reserved to EUA's Board of
Trustees and the Committee the right to award the CEO and COO merger-completion
bonuses. Such bonuses were authorized in 1999, but with a payable date of the
merger-completion date. Such bonuses were in lieu of any Annual Cash Incentive
payment for these individuals.
Long-Term Incentives (Stock Grant Plan): The Association established a
restricted stock grant plan in 1989 which, as amended since then, is now the
Eastern Utilities Associates Restricted Stock Plan. The purpose of the plan is
to assist the Association in securing, retaining and motivating key executives
and to recognize their efforts on behalf of the Association through awards of
common shares of the Association. Such grants generally may be awarded every
third year and the currently outstanding awards vest on the fifth anniversary
of the date of the grant if the executive has continued in the employment of
the Association through that date. Restricted stock grant awards
were made in early 1998 to the Executives listed in the Summary Compensation
Table on page 89. In addition, Special Retention Stock Grants were awarded in
1997 (See below). No further grants were made in 1999.
Special Retention Stock Grants: In 1997, the Association recognized that it
was vulnerable to the loss of certain key management and professionals to new
competitors due to the rapid transition to a competitive utility environment in
New England. The Association was particularly concerned about losing those
individuals involved in implementing the Association's own restructuring plans
over the next two years.
As a result, in late 1997, the Committee authorized the awarding of
Special Retention Stock Grants as a means of retaining these key individuals
through 1999. These awards were made to 21 individuals, including the five
executives named in the Summary Compensation Table on Page 89. In order to
vest in the Special Retention Stock Grant, individuals were required to stay in
the employ of the Association for a period of two years.
COMPENSATION AND NOMINATING COMMITTEE
Russell A. Boss Paul J. Choquette, Jr.
Peter S. Damon Larry A. Liebenow
CORPORATE PERFORMANCE GRAPH
The following table compares total shareholder returns over the last five
fiscal years to the Standard & Poors 500 Stock Index ("S&P 500") and the S&P
Electric Utility Index. Total return values for the S&P 500, S&P Electric
Utility Index and Eastern Utilities Associates were calculated based on
cumulative total return values assuming reinvestment of dividends.
TOTAL RETURN SUMMARY
Based On Initial Investment Of $100
Comparison of Five Year Cumulative Total Return*
Among Eastern Utilities Associates, The S&P 500 Index
And The S&P Electric Utility Index
Line Graph showing plot points as follows:
12/94 12/95 12/96 12/97 12/98 12/99
Eastern Utilities Associates $100 $115 $92 $152 $175 $198
S&P 500 $100 $138 $169 $226 $290 $351
S&P Electric Companies $100 $131 $131 $165 $191 $154
* $100 invested on December 31, 1993 in stock or index, including
reinvestment of dividends. Fiscal Year ended December 31.
The foregoing report of the Committee and the Corporate Performance Graph
that appears immediately after such report shall not be deemed to be
soliciting material or to be filed with the Securities and Exchange Commission
under the Securities Act of 1933 or the Securities Exchange Act of 1934 or
incorporated by reference in any document so filed.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners.
The following table sets forth information regarding beneficial ownership
of Common Shares held by President and Fellows of Harvard College (together,
"Harvard") as of December 31, 1999 based on a Schedule 13-G filing made by
Harvard with the SEC dated February 14, 2000. Such filing stated that Harvard
had sole voting power with respect to 2,023,300 such shares beneficially
held.
Percent of
Name and Address Number of Common Outstanding Common
Shares Beneficially Held Shares
President and Fellows of Harvard 2,023,300 9.9%
College
c/o Harvard Management Company Inc.
600 Atlantic Avenue
Boston, MA 02210
(b) Security ownership of management of EUA.
The table below sets forth the information concerning beneficial ownership
by the Trustees of EUA, by each of the executive officers named in the Summary
Compensation Table on page 89 and by all Trustees and executive officers as a
group.
Common Shares of
EUA Beneficially Owned at
Name and age January 1, 2000 (a)
Russell A. Boss, Trustee 1,000(b)
John D. Carney, Executive Vice President 17,125(c)
Paul J. Choquette, Jr., Trustee 4,255(d)
Peter S. Damon, Trustee 809(e)
Peter B. Freeman, Trustee 2,500
Clifford J. Hebert, Jr., Treasurer and Secretary 14,673(c)
Larry A. Liebenow, Trustee 5,000(f)
Jacek Makowski, Trustee 200
Wesley W. Marple, Jr., Trustee 2,585(g)
Donald G. Pardus, Chairman of the Board of Trustees
and Chief Executive Officer 71,800(c)
Robert G. Powderly, Executive Vice President 21,411(c)
Margaret M. Stapleton, Trustee 1,781
John R. Stevens, President and Chief Operating
Officer 33,673(c)
W. Nicholas Thorndike, Trustee 2,146
Trustees and executive officers as a group 173,837(h)
(a) Unless otherwise indicated, beneficial ownership is based on sole
investment and voting power. Each nominee's ownership represents less
than four-tenths of one percent of the outstanding common shares of EUA.
(b) In addition, Mr. Boss owns 5 shares of Blackstone Valley Electric
Company's 4.25% Preferred Stock.
(c) Jointly owned with spouse except for 2,287, 2,906, 6,931, 2,863 and
3,006 shares held under EUA's Employee's Savings Plan for Messrs.
Carney, Hebert, Pardus, Powderly and Stevens, respectively, as to which
each has voting power, and 8,992, 5,339, 34,852, 8,917 and 25,576
shares held under the Eastern Utilities Associates Restricted Stock Plan
by Messrs. Carney, Hebert Pardus, Powderly and Stevens respectively, as
to which each has voting power. Also included are 5,846, 3,386, 8,989
9,320 and 4,952 shares individually owned by Messrs. Carney,
Hebert, Pardus, Powderly and Stevens.
(d) In addition, Mr. Choquette's spouse owns 150 common shares. Mr.
Choquette disclaims any beneficial interest in such shares.
(e) Jointly owned with spouse, except for 400 shares held individually.
(f) In addition, Mr. Liebenow's spouse owns 500 common shares. Mr. Liebenow
disclaims any beneficial interest in such shares.
(g) In addition, Mr. Marple's spouse owns 363 common shares. Mr. Marple
disclaims any beneficial interest in such shares.
(h) Represents approximately nine-tenths of one percent of total outstanding
common shares.
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 should be considered in conjunction with the financial
statements included in this filing for the year ended December 31, 1999:
Schedule II - Valuation and Qualifying Accounts for the three years
ended December 31, 1999.
(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-seven supplements thereto (Exhibit A, File
No. 70-3015; Exhibit A-3, File No. 70-3371; Exhibit C to
Certificate of Notification, File No. 70-3371; Exhibit D to
Certificate of Notification, File No. 70-3619; Exhibit D to
Certificate of Notification, File No. 70-3798; Exhibit F to
Certificate of Notification, File No. 70-4164; Exhibit D to
Certificate of Notification, File No. 70-4748; Exhibit C to
Certificate of Notification, File No. 70-5195; Exhibit F to
Certificate of Notification, File No. 70-5379; Exhibit C to
Certificate of Notification, File No. 70-5719; Exhibit 5-24,
Registration No. 2-65785; Exhibit F to Certificate of
Notification, File No. 70-6463; Exhibit C to Certificate of
Notification, File No. 70-6608; Exhibit C to Certificate of
Notification, File No. 70-6737; Exhibit F to Certificate of
Notification, File No. 70-6851; Exhibit 4-31, Form 10-K of EUA for
1984, File No. 1-5366; Exhibit F to Certificate of Notification,
File No. 70-7254; Exhibit C to Certificate of Notification, File
No. 70-7373; Exhibit C to Certificate of Notification, File No.
70-7373; Exhibit C to Certificate of Notification, File No.
70-7373; Exhibit F to Certificate of Notification, File No. 70-
7511; Exhibit 4-34, Form 10-K of Eastern Edison for 1990, File No.
0-8480; Exhibit 4-24, Form 10-K of Eastern Edison for 1992, File
No. 0-8480; Exhibit 4-35, Form 10-K of Eastern Edison for 1990,
File No. 0-8480; Exhibit 4-36, Form 10-K of Eastern Edison for
1990, File No. 0-8480; Exhibit C-33 to Form U5S of EUA for 1993;
Exhibit C-34 to Form U5S of EUA for 1993; Exhibit 4-29.08, Form
10-K of Eastern Edison for 1994, File No. 0-8480; Exhibit 4-1.09,
Form 10-K of EUA for 1997, File No. 1-5366).
- 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 10% Debenture Bonds due 2008 of Montaup (Exhibit 5-3,
Registration No. 2-65785).
4-4.05 - 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).
4-5.05 - Form of 9% Debenture Bonds due 2020 of Montaup (Exhibit 4-10, Form
10-K of Eastern Edison for 1990, File No. 0-8480).
4-6.05 - Form of 9 3/8% Debenture Bonds due 2020 of Montaup (Exhibit 4-11,
Form 10-K of Eastern Edison for 1990, File No. 0-8480).
- Blackstone -
4-1.01 - First Mortgage Indenture and Deed of Trust dated as of December 1,
1980 of Blackstone (Exhibit A, Form 8-K of EUA dated January 14,
1981, File No. 1-5366) and two supplements thereto (Exhibit 4-33,
Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 4-3, Form 10-K
of BVE for 1990, File No. 0-2602).
4-4.01 - Loan Agreement between Rhode Island Industrial Facilities
Corporation and Blackstone dated as of December 1, 1984 (Exhibit
10-72, Form 10-K of EUA for 1984, File No. 1-5366).
- EUA Service -
4-1.07 - Note Purchase Agreement dated as of January 13, 1988 of Service
(Exhibit 4-38, Form 10-K of EUA for 1987, File No. 1-5366).
- EUA Cogenex -
4-1.10 - Note Agreement dated as of June 28, 1990 of EUA Cogenex with the
Prudential Insurance Company of America (Exhibit 4-46, Form 10-K
of EUA for 1990, File No. 1-5366).
4-2.10 - Note Agreement dated as of October 29, 1991 between EUA Cogenex
and Prudential Insurance Company of America (Exhibit 4-55, Form
10-K of EUA for 1991, File No. 1-5366).
4-3.10 - Indenture dated September 1, 1993 between EUA Cogenex and the Bank
of New York as Trustee (Exhibit 4-4.10, Form 10-K of EUA for 1993,
File No. 1-5366).
- Newport -
4-1.14 - Indenture of First Mortgage dated as of June 1, 1954 of Newport,
as supplemented on August 1, 1959, April 1, 1962, October 1, 1964,
April 1, 1967, September 1, 1969, September 1, 1970, June 1, 1978,
October 1, 1978, May 1, 1986, December 1, 1987 and November 1,
1989 (Exhibit 4-49, Form 10-K of EUA for 1990, File No. 1-5366).
4-2.14 - 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).
4-3.14 - 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).
4-4.14 - 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).
4-5.14 - 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;
Exhibit 10-18.03, Form 10-K of EUA for 1997, 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;
Exhibit 10-18.03, Form 10-K of EUA for 1997, File No. 1-5366).
10-2.03 - Eastern Utilities Associates Employees' Savings Plan Trust
Agreement (Exhibit 10-3, Form 10-K of EUA for 1992, File No. 1-
5366).
10-3.03 - Eastern Utilities Associates Employees' Savings Plan as amended
and restated effective January 1, 1989 (including amendments
through January 1, 1992) and December 21, 1994 (Exhibit 10-15.03,
Form 10-K of EUA for 1995, File No. 1-5366; Exhibit 10-17.03 Form
10-K of EUA for 1995, File No. 1-5366; Exhibit 10-15.03, Form 10-K
of EUA 1997, File No. 1-5366; Exhibit 10-16.03, Form 10-K
of EUA for 1997, File No. 1-5366; Exhibit 10-17.03, Form 10-K of
EUA for 1997, File No. 1-5366, Exhibit 10-15.03, Form 10-K of EUA
for 1998, File No. 1-5366, Exhibit 10-16.03, Form 10-K of EUA for
1998, 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 as
amended (Exhibit 10-13, EUA Form 10-K for 1992, File No. 1-5366;
Exhibit 10-19.03, Form 10-K of EUA for 1997, 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, Exhibit 10-17.03, Form 10-K of EUA for
1998, File No. 1-5366, Exhibit 10-18.03, Form 10-K of EUA for
1998, File No. 1-5366).
10-15.03 - Agreement and Plan of Merger dated as of February 1, 1999 by and
among New England Electric System, Research Drive LLC and Eastern
Utilities Associates (Exhibit 10-19.03, Form 10-K of EUA for 1998,
File No. 1-5366).
*10-16.03 - Fifth Amendment to the Employees' Retirement Plan of Eastern
Utilities Associates dated March 15, 1999.
*10-17.03 - Sixth Amendment to the Employees' Retirement Plan of Eastern
Utilities Associates dated April 19, 1999.
*10-18.03 - Seventh Amendment to the Employees' Retirement Plan of Eastern
Utilities Associates dated April 19, 1999.
- 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).
10-5.08 - Wholesale Standard Offer Service Agreement between Blackstone
Valley Electric Company, Eastern Edison Company, Newport Electric
Corporation and TransCanada Power Marketing LTD., dated April 7,
1998 (filed as Exhibit 10-5.08, Form 10-K of EUA for 1998, File
No. 1-5366).
10-6.08 - Wholesale Standard Offer Service Agreement between Blackstone
Valley Electric Company, Eastern Edison Company, Newport Electric
Corporation and NRG Energy Power Marketing, Inc., dated October
13, 1998 (filed a s Exhibit 10-6.08, Form 10-K of EUA for 1998,
File No. 1-5366).
10-7.08 - Wholesale Standard Offer Service Agreement (20.1775%)
between Blackstone Valley Electric Company, Eastern Edison
Company, Newport Electric Corporation and Constellation Power
Sources, Inc., dated December 21, 1 998 (filed as Exhibit 10-7.08,
Form 10-K of EUA for 1998, File No. 1-5366).
10-8.08 - Wholesale Standard Offer Service Agreement (35.7695%) between
Blackstone Valley Electric Company, Eastern Edison Company,
Newport Electric Corporation and Constellation Power Sources,
Inc., dated December 21, 1 998 (filed as Exhibit 10-8.08, Form 10-
K of EUA for 1998, File No. 1-5366).
- Montaup -
10-1.05 - Montaup Contract, as amended (Exhibit 4-B, Registration No. 2-
14119; Exhibit 13-A1, Registration No. 2-14718; Exhibit 4-B-2,
Registration No. 2-26509; Exhibit 4-B-3, Registration No. 2-33061;
Exhibits 13-3 and 13-4, Registration No. 2-48966; Exhibit B-2,
Form U5S of EUA for year 1974 and Exhibit 5-40, Registration No.
2-62862).
10-2.05 - Power Contract (composite copy) between Connecticut Yankee Atomic
Power Company and Montaup dated July 1, 1964 as amended and
supplemented March 1, 1978, August 22, 1980, October 15, 1982, and
December 4, 1996 (Exhibit B-1, File No. 70-4245; Exhibit 20, Form
10-K of EUA for 1977, File No. 1-5366; Exhibit 10-52, Form 10-K
for EUA for 1981, File No. 1-5366; Exhibit 10-67, Form 10-K for
EUA for 1983, File No. 1-5366; Exhibit 10-37.05, Form 10-K for
EUA for 1996, File No. 1-5366).
10-3.05 - Capital Funds Agreement (composite copy) between Connecticut
Yankee Atomic Power Company and Montaup dated September 1, 1964
(Exhibit B-2, File No. 70-4245).
10-4.05 - Stockholder Agreement (composite copy) among Connecticut Yankee
Atomic Power Company's Sponsors, including Montaup, dated July 1,
1964 (Exhibit B-4, File No. 70-4245).
10-5.05 - 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).
10-6.05 - 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).
10-7.05 - 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).
10-8.05 - 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).
10-9.05 - 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).
10-10.05 - Stockholder Agreement (composite copy) among Maine Yankee
Sponsors, including Montaup, dated May 20, 1968 (Exhibit B-4, File
70-4658).
10-11.05 - 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).
10-12.05 - Form of Agreement among Maine Yankee Atomic Power Company's
Sponsors dated as of May 20, 1969 (Exhibit B-5, File No. 70-4658).
10-13.05 - Form of New England Power Pool Agreement dated as of September 1,
1971, as amended as of July 1, 1972, March 1, 1973, April 2, 1973,
March 15, 1974, June 1, 1975, September 1, 1975, December 31,
1976, January 31, 1977, July 1, 1977, August 1, 1977, August 15,
1978, January 31, 1980, February 1, 1980, September 1, 1981,
December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983,
August 1, 1985, August 15, 1985, January 1, 1986, September 1,
1986, March 1, 1988, May 1, 1988, March 15, 1989, October 1, 1990,
September 15, 1992, May 1, 1993, and December 31, 1996, (Exhibit
13-45, Registration No. 2-41488; Exhibit 13-38, Registration No.
2-46612; Exhibits 13-39 and 13-40, Registration No. 2-48966;
Exhibit B-3, Form U5S of EUA for year 1974; Exhibit 13-35(a),
Registration No. 2-54449; Exhibit 13-35, Registration No. 2-55990,
Exhibits 5-69 and 5-70, Registration Exhibit 13-35(a),
Registration No. 2-54449; Exhibit 13-35, Registration No. 2-55990,
Exhibits 5-69 and 5-70, Registration No. 2-58625; Exhibit 6, Form
10-K of EUA for 1977, File No. 1-5366; Exhibit 1, Form 10-K
of EUA for 1979, File No. 1-5366; Exhibit No. 10-67, Registration
No. 2-80205; Exhibit 10-65, Form 10-K of EUA for 1983, File No. 1-
5366; Exhibit 10-66, Form 10-K of EUA for 1983, File No. 1-5366;
Exhibits 10-75, 10-76, and 10-77, Form 10-K of EUA for 1985, File
No. 1-5366; Exhibit 10-79, Form 10-K of EUA for 1986, File No. 1-
5366; Exhibits 10-99 and 10-100, Form 10-K of EUA for 1988, File
No. 1-5366; Exhibit 10-96, Form 10-K of EUA for 1989, File No. 1-
5366; Exhibit 10-81, Form 10-K of Eastern Edison for 1990, File
No. 0-8480; Exhibit 10-38.05, Form 10-K of EUA for 1995, File No.
1-5366; Exhibit 10-39.05, Form 10-K of EUA for 1995, File No. 1-
5366; Exhibit 10-40.05, Form 10-K of EUA for 1995, File No. 1-5366
Exhibit 10-38.05 Form 10-K of EUA for 1996, File No. 1-5366).
10-14.05 - 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).
10-15.05 - 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).
10-16.05 - 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).
10-17.05 - 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).
10-18.05 - 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).
10-19.05 - 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).
10-20.05 - Unit Power Agreement for the Sale of Unit Capacity and Energy from
Ocean State Power Project to Montaup Electric Company dated as of
May 14, 1986 as amended as of August 27, 1986, September 27, 1988,
October 21, 1988, July 21, 1989, February 7, 1990, December 21,
1990, and February 12, 1996 (Exhibits 10-101 and 10-102, Form 10-K
of EUA for 1986, File No. 1-5366; Exhibits 10-106 and 10-107, Form
10-K of EUA for 1988, File No. 1-5366; Exhibit 10-106, Form 10-K
of EUA for 1989, File No. 1-5366; Exhibits 10-86 and 10-87, Form
10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 10-39.05
and 10-40.05, Form 10-K of EUA for 1996, File No. 1-5366).
10-21.05 - 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).
10-22.05 - 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).
10-23.05 - Unit Power Agreement for the Sale of Second Unit Capacity and
Energy from Ocean State Power Project to Montaup Electric Company
dated as of September 28, 1988 as amended as of July 21, 1989,
February 7, 1990, and February 12, 1996 and a Supplemental
Agreement dated July 21, 1989 (Exhibit 10-104, Form 10-K
of EUA for 1989, File No. 1-5366; Exhibits 10-41.05 and 10-42.05,
Form 10-K of EUA for 1996, File No. 1-5366; Exhibit No. 10-88,
Form 10-K of Eastern Edison for 1990, File No. 0-8480).
10-24.05 - 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).
10-25.05 - Amended and Restated Power Sales Contract by and between Southern
Eenrgy Canal L.L.C. (as assignee of Canal Electric Company) and
Montaup Electric Company, dated December 18, 1998 and effective on
December 30, 1998 (Exhibit 10-34.05, Form 10-K of EUA for 1998,
File No. 1-5366).
10-26.05 - Third Amendment to the Pilgrim Power Sale Agreement between
Boston Edison Company and Montaup Electric Company, dated
Novemeber 18, 1998 (Exhibit 10-35.05, Form 10-K of EUA for 1998,
File No. 1-5366).
10-27.05 - Power Purchase Agreement between Entergy Nuclear Generation
Company and Montaup Electric Company, dated November 18, 1998
(Exhibit 10-36.05, Form 10-K of EUA for 1998, File No. 1-5366).
10-28.05 - Power Purchase and Sale Agreement between Montaup Electric
Company and Constellation Power Source, Inc., dated December 21,
1998 (Exhibit 10-37.05, Form 10-K of EUA for 1998, File No. 1-
5366).
10-29.05 - PPA Transfer Agreement between Montaup Electric Company and
TransCanada Power Marketing Ltd, dated April 7, 1998 (Exhibit 10-
38.05, Form 10-K of EUA for 1998, File No. 1-5366).
*10-30.05 - Fourth Amendment to the Pilgrim Power Sale Agreement between
Boston Edison Company and Montaup Electric Company, dated March 9,
1999.
*10-31.05 - Fifth Amendment to the Pilgrim Power Sale Agreement between Boston
Edison Company and Montaup Electric Company, dated June 11, 1999.
*10-32.05 - Reinstatement Amendment, dated as of July 6, 1999 by and among
Southern Energy Canal, L.L.C. and Montaup Electric Company.
- 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 - 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).
- See Exhibits 10-5.08, 10-6.08, 10-7.08 for Exhibits involving
Blackstone, Eastern Edison and Newport.
- 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).
- See Exhibits 10-5.08, 10-6.08, 10-7.08 and 10-8.08 for Exhibits
involving Blackstone, Eastern Edison and Newport.
- 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).
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 Montaup Electric Company
(Massachusetts). 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 December 8, 1999, EUA filed a Current Report on Form 8-K with respect to
Item 5 (Other Events).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Signature Title Date
EASTERN UTILITIES ASSOCIATES
By/s/John R. Stevens President and Chief Operating Officer March 20, 2000
John R. Stevens (Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/Donald G. Pardus
Donald G. Pardus Chairman and Chief Executive Officer
(Principal Executive Officer) and Trustee
/s/John R. Stevens President and Chief Operating Officer
John R. Stevens (Principal Accounting Officer) and Trustee
/s/Clifford J. Hebert, Jr. Treasurer
Clifford J. Hebert, Jr. (Principal Financial Officer)
/s/Russell A. Boss Trustee
Russell A. Boss
/s/Paul J. Choquette, Jr. Trustee
Paul J. Choquette, Jr.
March 20, 2000
/s/Peter S. Damon Trustee
Peter S. Damon
/s/Peter B. Freeman Trustee
Peter B. Freeman
/s/Larry A. Liebenow Trustee
Larry A. Liebenow
/s/Jacek Makowski Trustee
Jacek Makowski
/s/Wesley W. Marple, Jr. Trustee
Wesley W. Marple, Jr.
/s/Margaret M. Stapleton Trustee
Margaret M. Stapleton
Trustee
W. Nicholas Thorndike
EASTERN UTILITIES ASSOCIATES AND SUBSIDIARY COMPANIES
Item 14(a)(2). Financial Statement Schedule
Schedule II
Eastern Utilities Associates and Subsidiary Companies
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
For the Year Ended December 31, 1999:
Allowance for Doubtful Accounts $1,301 $1,555 $268 (a) $2,042 (b) $1,082
For the Year Ended December 31, 1998:
Allowance for Doubtful Accounts $1,109 $1,378 $893 (a) $2,079 (b) $1,301
For the Year Ended December 31, 1997:
Allowance for Doubtful Accounts $976 $1,090 $450 (a) $1,407 (b) $1,109
(a) Recoveries of accounts previously written off.
(b) Principally Accounts Receivable written off.
Quarterly Financial and Common Share Information (unaudited)
($ in thousands except per share amounts)
Basic and
Diluted Earnings
Consolidated per Average
Operating Operating Net Net Common
Revenues Income Income Earnings Share
FOR THE QUARTERS
ENDED 1999:
December 31 $139,723 $13,486 $8,764 $8,188 $0.40
September 30 141,723 17,463 12,303 11,727 0.57
June 30 133,443 12,867 (8,013) (8,590) (0.42)
March 31 138,877 11,451 6,169 5,593 0.27
FOR THE QUARTERS
ENDED 1998:
December 31 $133,416 $13,639 $9,085 $8,509 $0.42
September 30 136,033 15,461 9,788 9,212 0.45
June 30 130,046 12,531 6,449 5,872 0.29
March 31 139,306 18,492 11,693 11,117 0.54
Report of Independent Accountants
To the Trustees and Shareholders of Eastern Utilities Associates:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 8 on page 57 present fairly, in all material respects, the
financial position of Eastern Utilities Associates and its subsidiaries at
December 31, 1999 and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1999 in
conformity with accounting principles generally accepted in the United States.
In addition, in our opinion, the financial statement schedule listed in the
index appearing under Item 14(a)(2) on page 97 presents fairly, in all material
respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. These financial statements and
financial statement schedule are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. We conducted
our audits of these statements in accordance with auditing standards generally
accepted in the United States, which 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,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Boston, Massachusetts
March 6, 1999