Annual Report 1998
New England Power Company
A Subsidiary of
New England Electric System
[LOGO] New England Power
A NEES Company
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of January 1, 1999)
Peter G. Flynn
President of the Company
Alfred D. Houston
Chairman of the Company and Chairman of New England Electric
System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of New England Electric
System
Richard P. Sergel
President and Chief Executive Officer of New England Electric
System
Officers
(As of January 1, 1999)
Alfred D. Houston
Chairman of the Company and Chairman of New England Electric
System
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief
Financial Officer of New England Electric System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of New England Electric
System
John F. Malley
Vice President of the Company
Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates
James S. Robinson
Vice President of the Company
Robert King Wulff
Clerk of the Company and of certain affiliates, Secretary or
Assistant Clerk of certain affiliates and Assistant Secretary of
an affiliate
John G. Cochrane
Treasurer of the Company and of certain affiliates, Vice
President of an affiliate, Assistant Treasurer of an affiliate
and Treasurer of New England Electric System
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates, and
Secretary, Assistant Secretary or Clerk of certain affiliates
Howard W. McDowell
Assistant Treasurer and Controller of the Company and of certain
affiliates, Senior Vice President of an affiliate, Treasurer or
Controller of certain affiliates and Assistant Secretary of an
affiliate
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, BankBoston, N.A., Boston, Massachusetts
This report is not to be considered an offer to sell or buy or
solicitation of an offer to sell or buy any security.
New England Power Company
New England Power Company, (the Company) a wholly owned
subsidiary of New England Electric System (NEES), is a
Massachusetts corporation qualified to do business in
Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine,
and Vermont. The Company is subject, for certain purposes, to
the jurisdiction of the regulatory commissions of these six
states, the Securities and Exchange Commission, under the Public
Utility Holding Company Act of 1935, the Federal Energy
Regulatory Commission and the Nuclear Regulatory Commission. The
Company's business is primarily the transmission of electric
energy in wholesale quantities to other electric utilities,
principally its distribution affiliates Granite State Electric
Company, Massachusetts Electric Company, Nantucket Electric
Company, and The Narragansett Electric Company (Narragansett
Electric). In September 1998, the Company and Narragansett
Electric completed the divestiture of substantially all of their
nonnuclear generating business. However, the Company continues
to own minority interests in two joint owned nuclear generating
units as well as minority equity interests in 4 nuclear
generating companies. For further information on industry
restructuring and the divestiture of NEES' nonnuclear generating
business, refer to the "Industry Restructuring" section of
Financial Review.
In December 1998, NEES agreed to a merger with The National
Grid Group plc, whose principal subsidiary operates the
transmission system in England and Wales.
In February 1999, NEES entered into an agreement to acquire
Eastern Utilities Associates, a utility holding company serving
approximately 300,000 customers in Massachusetts and Rhode
Island. For further information on these proposed mergers, refer
to the "Merger Agreements" sections of Financial Review.
Report of Independent Accountants
New England Power Company, Westborough, Massachusetts:
In our opinion, the accompanying balance sheets and the
related statements of income, of retained earnings, and of cash
flows present fairly, in all material respects, the financial
position of New England Power Company (the Company), a wholly
owned subsidiary of New England Electric System, at December 31,
1998 and 1997, and the results of its operations and its cash
flows for each of the three years in the period ended December
31, 1998 in conformity with generally accepted accounting
principles. These financial statements are the responsibility of
the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with
generally accepted auditing standards 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.
Boston, Massachusetts PricewaterhouseCoopers LLP
February 23, 1999
New England Power Company
Financial Review
Merger Agreement with The National Grid Group plc
On December 11, 1998, New England Electric System (NEES), The
National Grid Group plc (National Grid), and NGG Holdings LLC
(Holdings), a directly and indirectly wholly owned subsidiary of
National Grid, entered into an Agreement and Plan of Merger
(Merger Agreement). Pursuant to the Merger Agreement, Holdings
will merge with and into NEES (the Merger), with NEES becoming a
wholly owned subsidiary of National Grid. New England Power
Company (the Company) will remain a wholly owned subsidiary of
NEES.
The Merger is subject to approval by a majority vote of NEES
shareholders as well as National Grid shareholder approval. In
addition, the Merger is subject to a number of regulatory and
other approvals and consents, including approvals by the
Securities and Exchange Commission (SEC), under the Public
Utility Holding Company Act of 1935 (1935 Act), Federal Energy
Regulatory Commission (FERC), and Nuclear Regulatory Commission
(NRC), support or approval from the states in which NEES
subsidiaries operate, and clearance under both the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
and the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988. National Grid has obtained
governmental clearance in the United Kingdom for the Merger. The
Merger is expected to be completed by early 2000.
Merger Agreement with Eastern Utilities Associates
On February 1, 1999, NEES, Eastern Utilities Associates
(EUA), and Research Drive LLC (Research Drive), a directly and
indirectly wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA
Agreement, Research Drive will merge with and into EUA, with EUA
becoming a wholly owned subsidiary of NEES.
The acquisition of EUA is subject to approval by a two-thirds
vote of EUA shareholders. In addition, the acquisition is subject
to a number of regulatory and other approvals and consents,
including approvals by the SEC, under the 1935 Act, FERC, and
NRC, support or approval from the states in which EUA
subsidiaries operate, and clearance under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. The EUA
acquisition is expected to be completed by early 2000. Following
the acquisition of EUA, the subsidiaries of NEES and EUA whose
operations are similar are expected to be consolidated.
Industry Restructuring
During 1998, pursuant to legislation enacted in
Massachusetts, Rhode Island, and New Hampshire, and settlement
agreements approved by state and federal regulators (the
Settlement Agreements), all customers were provided the right to
purchase electricity from the power supplier of their choice. The
NEES companies remain obligated to deliver that electricity over
its transmission and distribution systems, with such delivery
services provided under regulated rates approved by state and
federal regulators. As described below, those delivery rates
include a non-bypassable charge for the costs of NEES' former
generating business which were not recovered through the sale of
that business ("stranded costs"), which was substantially
completed in 1998. As a result of the Settlement Agreements,
customers' choice of power supplier has no impact on NEES'
transmission and distribution business or on its ability to
recover stranded costs. In order to facilitate the implementation
of customer choice, the Settlement Agreements provided for the
termination of the Company's requirements contracts with its
affiliated distribution customers. The Company's requirements
contracts with unaffiliated customers have also generally been
terminated pursuant to settlement agreements or tariff
provisions. However, the Company remains obligated to provide
transition power supply service to new customer load in Rhode
Island.
On September 1, 1998, the Company and The Narragansett
Electric Company (Narragansett Electric) (collectively, the
Sellers) completed the sale of substantially all of their
nonnuclear generating business, all of which had a book value of
approximately $1.1 billion, to USGen New England, Inc. (USGen),
an indirect wholly owned subsidiary of PG&E Corporation. The
Sellers received $1.59 billion for the sale. In addition, the
Company was reimbursed approximately $140 million for costs
associated with early retirements and special severance programs
for employees affected by industry restructuring, and the value
of inventories. USGen assumed responsibility for environmental
conditions at the Sellers' nonnuclear generating stations. USGen
also assumed the Sellers' obligations under long-term fuel and
fuel transportation contracts, and certain collective bargaining
agreements.
As part of the sale, the Company also signed a purchased
power transfer agreement through which USGen purchased the
Company's entitlement to approximately 1,100 megawatts (MW) of
power procured under long-term contracts in exchange for monthly
fixed payments by the Company averaging $9.5 million per month
through January 2008 (having a net present value of $833 million)
toward the above-market cost of those contracts. In some cases,
these transfers involved formal assignment of the contracts to
USGen and a release of the Company from further obligations to
the power supplier, while others did not. For those that involved
formal assignment, the Company was required to make a lump sum
payment equivalent to the present value of the monthly fixed
payment obligations of those contracts. On or prior to the
closing date, the Company made lump sum payments totaling
approximately $340 million and was released from further
obligations relating to two of the contracts. These lump sum
payments are separate from the $833 million figure referred to
above.
As part of the divestiture plan, in February 1998, New
England Energy Incorporated (NEEI), a wholly owned subsidiary of
NEES, whose costs had been supported by the Company, sold its oil
and gas properties for approximately $50 million. NEEI's loss on
the sale of approximately $120 million, before tax, has been
reimbursed by the Company.
In addition, the Company agreed under the Settlement
Agreements to endeavor to sell its minority interest in three
nuclear power plants and a 60 MW interest in a fossil-fueled
generating station in Maine. In February 1999, Vermont Yankee
Nuclear Power Corporation entered into a letter of intent to sell
its assets. For further information, refer to the "Nuclear
Units" section of this Financial Review.
The Settlement Agreements provide that the Company's stranded
costs are to be recovered from its wholesale customers through
contract termination charges (CTC). The affiliated wholesale
customers, in turn, are recovering those costs through their
delivery charges to distribution customers. Under the Settlement
Agreements, the recovery of the Company's stranded costs is
divided into several categories. Unrecovered costs associated
with generating plants (nuclear and nonnuclear) and most
regulatory assets will be fully recovered through the CTC by the
end of 2000 and earn a return on equity averaging 9.7 percent.
The Company's obligation relating to the above-market cost of
purchased power contracts and nuclear decommissioning costs are
recovered through the CTC over a longer period of time, as such
costs are actually incurred. The CTC rate was originally set at
2.8 cents per kilowatthour (kWh), and subsequently reduced to
approximately 1.5 cents or less per kWh upon completion of the
sale of the Company's nonnuclear generating business. As the CTC
rate declines, the Company, under certain of the Settlement
Agreements, earns incentives based on successful mitigation of
its stranded costs. These incentives supplement the Company's
return on equity. Finally, the Settlement Agreements provide that
until such time as the Company divests its operating nuclear
interests, the Company will share with customers, through the
CTC, 80 percent of the revenues and operating costs related to
the units, with shareholders retaining the balance.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of these
charges because they are expected to be included in future
customer charges. In 1997, the Emerging Issues Task Force (EITF)
of the Financial Accounting Standards Board (FASB) concluded that
a utility that had received approval to recover stranded costs
through regulated transmission and distribution rates would be
permitted to continue to apply FAS 71 to the recovery of stranded
costs.
The Company has received authorization from the FERC to
recover through the CTC substantially all of the costs associated
with its former generating business not recovered through the
sale of that business. Additionally, FERC Order No. 888 enables
transmission companies to recover their specific costs of
providing transmission service. Therefore, substantially all of
the Company's business, including the recovery of its stranded
costs, remains under cost-based rate regulation. The Company
believes these factors and the EITF conclusion allow it to
continue to apply FAS 71. Because of the nuclear cost-sharing
provisions related to the Company's CTC, the Company ceased
applying FAS 71 in 1997 to 20 percent of its ongoing nuclear
operations, the impact of which is immaterial.
Currently, there is much regulatory and other movement toward
establishing performance-based rates. It is possible that the
adoption of performance-based rates for the Company or its
affiliates, future regulatory rules, or other circumstances could
cause the application of FAS 71 to be discontinued. This
discontinuation would result in a noncash write-off of previously
established regulatory assets, including those being recovered
through the Company's CTC.
As a result of applying FAS 71, the Company has recorded a
regulatory asset for the costs that are recoverable from
customers through the CTC. The regulatory asset reflects the loss
on the sale of NEES' oil and gas business and the unrecovered
plant costs in operating nuclear plants (assuming no market
value), the costs associated with permanently closed nuclear
power plants, and the present value of the payments associated
with the above-market costs of purchased power contracts, reduced
by the gain from the sale of the nonnuclear generating business.
At December 31, 1998, the regulatory asset related to the CTC was
approximately $1.5 billion, of which $1.2 billion related to the
above-market costs of purchased power contracts.
As described above, the CTC regulatory asset includes the
unrecovered plant costs associated with the Company's interest in
operating nuclear plants. This balance sheet treatment is due to
the Company's conclusion that its interests in the Millstone 3
and Seabrook 1 nuclear generating units have little, if any,
market value. Three proposed sales of nuclear units by other
utilities have required the seller to set aside amounts for
decommissioning in excess of the proceeds from the sale of the
units. Two of these proposed sales were agreed upon prior to the
end of the third quarter of 1998. As a result, at the end of the
third quarter of 1998, the Company recorded an impairment
writedown in its reserve for depreciation of approximately $390
million, which represents the net book value at December 31,
1995, less applicable depreciation subsequent to that date, of
Millstone 3 and Seabrook 1. Because the Settlement Agreements
permit the Company to recover its pre-1996 investment as well as
decommissioning expenses through the CTC, the Company established
a regulatory asset in an amount equal to the impairment
writedown. Should the Company's efforts to sell its nuclear
interests result in a gain over the amounts remaining in the
plant account, such gain will be credited to customers through
the CTC.
Overview of Financial Results
Net income for 1998 decreased $22 million compared with 1997
primarily due to the sale of the Company's non-nuclear generating
business on September 1, 1998. The decrease is also attributable
to reduced revenues as a result of the termination of its
all-requirements contracts with its primary customers. For
further information on the termination of these contracts, see
the "Operating Revenue" section.
Net income for 1997 decreased $8 million compared with 1996.
The decrease was primarily due to increased operation and
maintenance costs, partially offset by a transmission rate
increase, decreased purchased electric energy costs, excluding
fuel, and decreased depreciation and amortization.
Operating Revenue
Operating revenue for 1998 decreased $460 million compared
with 1997.
Under the provisions of all-requirements contracts, the
Company historically furnished all electrical requirements to its
affiliated wholesale customers, obligating the Company to supply
such requirements at its standard resale rates. As a result of
the Settlement Agreements, the all-requirements provisions of the
contracts with the Company's primary customers in Rhode Island,
Massachusetts, and New Hampshire were terminated effective
January 1, 1998, March 1, 1998, and July 1, 1998, respectively.
As of those dates, the Company continued to supply power to the
affiliates to meet their standard offer generation service
obligations, but at lower rates. On September 1, 1998, the
Company sold its nonnuclear generating business, and USGen and
TransCanada Power Marketing, Ltd. became the principal wholesale
suppliers for the affiliated companies.
Partially offsetting this revenue decrease is billings of
CTCs and an increase in transmission billings.
Operating revenue for 1997 increased $78 million compared
with 1996 primarily due to increased fuel recovery, the effect of
a transmission rate increase that went into effect in mid-1996,
and stranded investment recovery related to amounts recovered in
connection with retail wheeling pilot programs and the first
phase of customer choice in Rhode Island. These increases were
offset by decreased sales due to a decrease in peak demand
billing as a result of milder weather in the first quarter of
1997 and reduced load due to retail wheeling pilot programs. For
a discussion of fuel recovery revenues, see the discussion of the
1997 increase in fuel costs in the "Operating Expenses" section.
Operating Expenses
Operating expenses for 1998 decreased $426 million compared
with 1997. The September 1, 1998 sale of the Company's nonnuclear
generating business had the impact of decreasing all categories
of operating expenses. The decrease in operating expenses also
reflects reduced charges of $22 million from the Maine Yankee
nuclear power plant, which was closed in mid-1997 and reduced
charges of $3 million and $12 million from the partially owned
Seabrook 1 and Millstone 3 nuclear generating facilities,
respectively. Operating expenses were also lower due to lower
charges related to postretirement benefits other than pensions
(PBOPs), reflecting the completion of the accelerated
amortization of NEP's deferred PBOP costs in 1997 under the terms
of a 1995 rate agreement.
The decrease in depreciation and amortization expense related
to the sale of the nonnuclear generating business was more than
offset by CTC amortization and the accelerated amortization of
Millstone 3, a portion of which was attributable to the
completion of the PBOP amortization discussed above.
Operating expenses for 1997 increased $91 million compared
with 1996 primarily due to increased fuel costs, increased
charges from the Maine Yankee nuclear power plant, and increased
other operation and maintenance expenses.
Fuel costs represented fuel for generation and the portion of
purchased electric energy permitted in the past to be recovered
through the Company's fuel adjustment clause. The increase in
fuel costs reflected increased power supply to other utilities,
increased replacement power costs due to the reduced generation
from partially owned nuclear units, and an increase in the cost
of short-term purchased power.
The increase in other operation and maintenance expenses in
1997 was due to an increase in transmission wheeling costs,
increased maintenance costs at the partially owned Seabrook 1 and
Millstone 3 nuclear facilities, an increase in deferred PBOP
amortization, an overall increase in general and administrative
costs, start-up costs associated with the new regional
transmission control organization, and the Company's share of
costs associated with the restoration to service of previously
idled facilities throughout New England in response to a
tightening regional power supply.
The increase in operating expenses in 1997 was partially
offset by a decrease in purchased power charges from the
Connecticut Yankee nuclear power plant, which was permanently
closed in December 1996. This decrease was partially offset by
increased charges from the Maine Yankee nuclear power plant,
which was permanently closed in mid-1997.
Nuclear Units
Nuclear Units Permanently Shut Down
Three regional nuclear generating companies in which the
Company has a minority interest own nuclear generating units that
have been permanently shut down. These three units are as
follows:
Future
Estimated
NEP's Billings
Investment Date to NEP
Unit % $ (millions) Retired $ (millions)
- ----------------------------------------------------- ------------
Yankee Atomic 30 6 Feb 1992 24
Connecticut Yankee 15 16 Dec 1996 75
Maine Yankee 20 16 Aug 1997 143
In the case of each of these units, the Company has recorded a
liability and an offsetting regulatory asset reflecting the
estimated future billings from the companies. In a 1993 decision,
the FERC allowed Yankee Atomic to recover its undepreciated
investment in the plant as well as unfunded nuclear
decommissioning costs and other costs. Connecticut Yankee and
Maine Yankee have both filed similar requests with the FERC.
Several parties have intervened in opposition to both filings. In
August 1998, a FERC Administrative Law Judge (ALJ) issued an
initial decision which would allow for full recovery of
Connecticut Yankee's unrecovered investment, but precluded a
return on that investment. Connecticut Yankee, the Company, and
other parties have filed with the FERC exceptions to the ALJ's
decision. Should the FERC uphold the ALJ's initial decision in
its current form, the Company's share of the loss of the return
component would total approximately $12 million to $15 million
before taxes. In January 1999, parties in the Maine Yankee
proceeding filed a comprehensive settlement agreement with the
FERC, under which Maine Yankee would recover all unamortized
investment in the plant, including a return on its equity
investment of 6.5 percent, as well as decommissioning costs and
other costs. This settlement agreement requires FERC approval.
The Company's industry restructuring settlements allow it to
recover all costs that the FERC allows these Yankee companies to
bill to the Company.
The Company and several other shareholders (Sponsors) of Maine
Yankee are parties to 27 contracts (Secondary Purchase
Agreements) under which they sold portions of their entitlements
to Maine Yankee power output through 2002 to various entities,
primarily municipal and cooperative systems in New England
(Secondary Purchasers). Virtually all of the Secondary Purchasers
had ceased making payments under the Secondary Purchase
Agreements, claiming that such agreements excuse further payments
upon plant shutdown. In February 1999, a settlement agreement
which fully resolves the dispute between the Sponsors and
Secondary Purchasers was filed with the FERC, under which the
Secondary Purchasers would be required to make certain payments
to Maine Yankee, and, in turn, to the Company, related to both
past and future obligations under the Secondary Purchase
Agreements. This settlement agreement requires FERC approval.
Shutdown costs are recoverable from customers under the
Settlement Agreements.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall.
Operating Nuclear Units
The Company has minority interests in three other nuclear
generating units: Vermont Yankee, Millstone 3, and Seabrook 1.
Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Vermont Yankee, are
increasing rapidly and could adversely affect their service
lives, availability, and costs. These uncertainties stem from a
combination of factors, including the acceleration of competitive
pressures in the power generation industry and increased NRC
scrutiny. The Company performs periodic economic viability
reviews of operating nuclear units in which it holds ownership
interests.
Vermont Yankee
On February 25, 1999, the Board of Directors of Vermont Yankee
Nuclear Power Corporation granted an exclusive right to AmerGen
Energy Company (AmerGen), a joint venture by PECO Energy and
British Energy to conduct a due diligence review over the next
120 days and negotiate a possible agreement to purchase the
assets of Vermont Yankee, Vermont's sole nuclear generating
plant. Provided the due diligence review leads to successful
completion of negotiations for a sale, consummation of such a
sale would be contingent on regulatory approvals by the NRC, the
SEC, under the 1935 Act, and the Vermont Public Service Board,
among others. The sale process could take eight to twelve months
or longer. In past negotiations for the sale of nuclear plants,
due diligence review has not guaranteed that a sale will occur.
The Company has a 20 percent ownership interest in Vermont Yankee
and an investment of approximately $11 million at December 31,
1998.
Millstone 3
In July 1998, Millstone 3 returned to full operation after
being shut down since April 1996. Millstone 3 remains on the NRC
"Watch List," signifying that it continues to warrant increased
NRC attention. Millstone 3 is operated by a subsidiary of
Northeast Utilities (NU). The Company is not an owner of the
Millstone 2 nuclear generating unit, which is temporarily shut
down under NRC orders, or the Millstone 1 nuclear generating
unit, which has been permanently shut down. A criminal
investigation related to Millstone 3 is ongoing.
In August 1997, the Company sued NU in Massachusetts Superior
Court for damages resulting from the tortious conduct of NU that
caused the shutdown of Millstone 3. The Company's damages include
the costs of replacement power during the outage, costs necessary
to return Millstone 3 to safe operation, and other additional
costs. Most of the Company's incremental replacement power costs
have been recovered from customers, either through fuel
adjustment clauses or through provisions in the Settlement
Agreements. The Company also seeks punitive damages. The Company
also sent a demand for arbitration to Connecticut Light & Power
Company and Western Massachusetts Electric Company, both
subsidiaries of NU, seeking damages resulting from their breach
of obligations under an agreement with the Company and others
regarding the operation and ownership of Millstone 3. The
arbitration is scheduled for October 1999. In July 1998, the
court denied NU's motion to dismiss and its motion to stay
pending arbitration. The Company subsequently amended its
complaint by, among other things, adding NU's Trustees as
defendants. In December 1998, NU moved for summary judgement. The
Company's suit has been consolidated with suits filed by other
joint owners. The court is in the process of scheduling a trial
date. Some or all of the damages awarded from the lawsuit would
be refunded to customers.
Year 2000 Readiness Disclosure
Over the next year, most companies will face a potentially
serious information systems (computer) problem because many
software applications and operational programs written in the
past may not properly recognize calendar dates associated with
the year 2000 (Y2K). This could cause computers to either shut
down or lead to incorrect calculations.
During 1996, the NEES companies began the process of
identifying the changes required to their computer software and
hardware to mitigate Y2K issues. The NEES companies established a
Y2K Project team to manage these issues, which has consisted of
as many as 70 full-time equivalent staff at some points in time,
primarily external consultants being overseen by an internal Y2K
management team. To facilitate the Y2K Project, NEES entered
into contracts with Keane, Inc. and International Business
Machines Corporation to provide personnel support to the Y2K
Project. Through December 31, 1998, the NEES companies have
spent approximately $14 million with these vendors, which is
included in the cost figures disclosed below. The Y2K Project
team reports project progress to a Y2K Executive Oversight
Committee each month. The team also makes regular reports to
NEES' Board of Directors and its Audit Committee. The NEES
companies have separated their Y2K Project into four parts as
shown below, along with the estimated completion dates for each
part.
Substantial Contingency Testing
Completion Documentation,
of Critical and Clean
Category Specific Example Systems Management
- -------- ---------------- ----------- -------------------
Mainframe/Midrange Accounting/Customer Completed Throughout 1999
systems service integrated
systems
Desktop systems Personal computers/ June 30, 1999 Throughout 1999
Department software/
Networks
Operational/ Dispatching systems/ June 30, 1999 Throughout 1999
Embedded Transmission and
systems Distribution systems/
Telephone systems
External issues Electronic Data June 30, 1999 Throughout 1999
Interchange/Vendor
communications
The NEES companies are using a three-phase approach in
coordinating their Y2K Project for system-related issues: (I)
Assessment and Inventory, (II) Pilot Testing, and (III)
Renovation, Conversion, or Replacement of Application and
Operating Software Packages and Testing. Phase I, which was an
initial assessment of all systems and devices for potential Y2K
defects, was completed in mid-1997. These assessments included,
but were not limited to, the review of program code for mainframe
and midrange systems, analysis of personal computer hardware and
network equipment for desktop systems, reaching consensus with
key "data exchange" partners regarding the approach and execution
of plans to address Y2K-related issues, and coordination with
other New England Power Pool (NEPOOL) member utilities related to
operational systems, such as transmission systems. Phase II,
which consisted of renovation pilots for a cross-section of
systems in order to facilitate the establishment of templates for
Phase III work, was completed in late 1997. Phase III, which is
currently ongoing, requires the renovation, conversion, or
replacement of the remaining applications and operating software
packages.
Critical systems include major operational and informational
systems such as the NEES companies' financial-related and
customer information systems. These mission critical systems
were first addressed at an individual component level, and then,
upon satisfactory completion of that testing, reviewed at an
integrated level, during which the Y2K Project team tested for
Y2K problems which could be caused by various system interfaces.
Additionally, contingency plans are being formulated for mission
critical systems, as described below.
The overall Y2K Project has also been designed such that Y2K-
related work performed by external consultants is reviewed by
NEES employees, and vice-versa. The Y2K Project team management
periodically benchmarks its progress against the recommended
progress schedule documented by the North American Electric
Reliability Council (NERC), and is currently ahead of the
recommended schedule.
The NEES companies have also implemented a formalized
communication process with third parties to give and receive
information related to their progress in remediating their own
Y2K issues, and to communicate the NEES companies' progress in
addressing the Y2K issue. These third parties include major
customers, suppliers, and significant businesses with which the
NEES companies have data links (such as banks). The NEES
companies have identified standard offer generation service
providers, telecommunications companies, and the Independent
System Operator-New England (ISO New England) as critical to
business operations. The NEES companies have been in contact
with all of these parties regarding the progress of their Y2K
remediation efforts, and will continue to monitor their ongoing
remediation efforts through continued communications. The NEES
companies cannot predict the outcome of other companies'
remediation efforts. Therefore, contingency plans are being
developed, as described below.
The NEES companies believe total costs associated with making
the necessary modifications to all centralized and noncentralized
systems will be approximately $28 million. These costs include
the replacement of approximately one thousand desktop computers.
In addition, the NEES companies are spending $4 million related
to the replacement of the human resources and payroll system, in
part due to the Y2K issue. To date, total Y2K-related costs of
$25 million have been incurred, of which $3 million has been
capitalized. The NEES companies continually review their cost
estimates based upon the overall Y2K Project status, and update
these estimates as warranted.
The NEES companies are in the process of developing Y2K
contingency plans to allow for critical information and operating
systems to function from January 1, 2000 forward. If required,
these plans are intended to address both internal risks as well
as potential external risks related to suppliers and customers.
Part of the contingency planning for accounting and desktop
systems will include taking extensive data back-ups prior to
year-end closing. For operational systems, the NEES companies
have in place an overall disaster recovery program, which already
includes periodic disaster simulation training (for outages due
to severe weather, for instance). As part of Y2K contingency
planning, the NEES companies will review their disaster recovery
plans, modifying them for Y2K-specific issues, such as a
potential loss of telecommunication services. The NEES companies
expect that these contingency plans will be in place by the third
quarter of 1999.
Interregional and regional contingency plans are being
formulated that address emergency scenarios due to the
interconnection of utility systems throughout the United States.
At a regional level, the NEES companies are participating and
cooperating with NEPOOL and ISO New England. Overall regional
activities, including those of NEPOOL and ISO New England, will
be coordinated by the Northeast Power Coordinating Council, whose
activities will be incorporated into the interregional
coordinating effort by NERC. The target for the completion of
this planning process is mid-1999. The NEES companies have noted
that the Y2K coordination efforts by ISO New England began in May
1998, resulting in a demanding and difficult schedule to attain
regional and interregional target dates.
The NEES companies believe the worst case scenario with a
reasonable chance of occurring is temporary disruptions of
electric service. This scenario could result from a failure to
adequately remediate Y2K problems at NEES company facilities or
could be caused by the inability of entities, such as ISO New
England, to maintain the short-term reliability of various
generators and/or transmission lines on a regional or
interregional basis. The NEES companies believe that the
contingency plans being developed both internally and on a
regional level, as described above, should substantially mitigate
the risks of this potential scenario. In the event that a
short-term disruption in service occurs, NEES does not expect
that it would have a material impact on its financial position
and results of operations.
While the NEES companies believe that their overall Y2K
program will satisfactorily address all critical operational and
system-related issues, significant risks remain. These risks
include, but are not limited to, the Y2K readiness of third
parties, including other utilities and power suppliers, cost and
timeline estimates of remaining Y2K mitigation efforts, and the
overall accuracy of assumptions made related to future events in
the development of the Y2K mitigation effort.
New Accounting Standards
In 1997, the FASB released Statement of Financial Accounting
Standards No. 130, Reporting of Comprehensive Income (FAS 130),
which was adopted by the Company in the first quarter of 1998.
FAS 130 establishes standards for reporting comprehensive income
and its components. Comprehensive income for the period is equal
to net income plus "other comprehensive income," which for the
Company, consists of the change in unrealized holding gains on
available-for-sale securities during the period. Other
comprehensive income was immaterial for the Company for the year
ended December 31, 1998.
Also in 1997, the FASB released Statement of Financial
Accounting Standards No. 131, Disclosure about Segments of an
Enterprise and Related Information (FAS 131), which went into
effect in 1998. FAS 131 requires the reporting in financial
statements of certain new additional information about operating
segments of a business. FAS 131 does not currently impact the
Company's reporting requirements.
In February 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits (FAS 132), which
revises disclosure requirements for pension and other
postretirement benefits. The Company has adopted FAS 132 in its
financial statements for the year ended December 31, 1998.
The adoption of FAS 130, FAS 131, and FAS 132 had no impact on
the Company's operating results, financial position, or cash
flows.
In June 1998, the FASB issued Statement of Financial
Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (FAS 133), which establishes
accounting and reporting standards for such instruments. FAS 133
is effective for fiscal years beginning after June 15, 1999.
Currently, the Company has no such derivative holdings.
Risk Management
The Company's major financial market risk exposure is changing
interest rates. Changing interest rates will affect interest paid
on variable rate debt. At December 31, 1998, the Company's
variable rate debt had a fair value of $372 million, a weighted
average interest rate of 3.28 percent, and maturity dates of
greater than five years.
See the "Industry Restructuring" section above for a
discussion of the Company's purchased power transfer agreement
with USGen. The Company retained one purchased power contract,
with Vermont Yankee, which carries fixed payment requirements of
approximately $35 million in 1999, $30 million in 2000, $35
million in 2001 and 2002, $30 million in 2003, and approximately
$300 million thereafter.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $64 million in
1998. These expenditures were primarily transmission-related.
The funds necessary for utility plant expenditures during 1998
were primarily provided by internally generated funds and the
proceeds from the sale of the nonnuclear generating business.
Cash expenditures for 1999 are estimated to be $65 million,
principally related to transmission functions. Internally
generated funds are expected to fully cover the Company's capital
expenditures in 1999.
In 1998, the Company defeased or retired all of its mortgage
bonds. The Company also paid down all of its short-term debt
outstanding.
In 1998, the Company repurchased or redeemed preferred stock
with an aggregate par value of $38 million.
In 1998, the Company repurchased 2.7 million shares of its
common stock from NEES for $418 million. Approximately $194
million in connection with the repurchase was charged to retained
earnings.
At December 31, 1998, the Company had lines of credit and
standby bond purchase facilities with banks totaling $455
million. These lines and facilities were available at December
31, 1998 for liquidity support for $372 million of the Company's
bonds in tax-exempt commercial paper mode and for other corporate
purposes. There were no borrowings under these lines of credit
at December 31, 1998.
New England Power Company
Statements of Income
Year ended December 31, (In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Operating revenue, principally
from affiliates $1,218,340 $1,677,903 $1,600,309
Operating expenses:
Fuel for generation 223,828 372,734 342,545
Purchased electric energy 399,836 527,647 508,910
Other operation 155,065 241,506 203,456
Maintenance 60,239 89,820 79,118
Depreciation and amortization 99,924 98,024 104,209
Taxes, other than income taxes 48,492 67,311 66,416
Income taxes 73,594 90,009 91,894
---------- ---------- ----------
Total operating expenses 1,060,978 1,487,051 1,396,548
---------- ---------- ----------
Operating income 157,362 190,852 203,761
Other income:
Allowance for equity funds
used during construction 633 - -
Equity in income of nuclear
power companies 5,284 5,189 5,159
Other income (expense), net 118 (3,404) (1,851)
---------- ---------- ----------
Operating and other income 163,397 192,637 207,069
---------- ---------- ----------
Interest:
Interest on long-term debt 30,775 42,277 45,111
Other interest 10,688 7,055 10,066
Allowance for borrowed funds used
during construction - credit (961) (1,238) (591)
---------- ---------- ----------
Total interest 40,502 48,094 54,586
---------- ---------- ----------
Net income $ 122,895 $ 144,543 $ 152,483
========== ========== ==========
Statements of Retained Earnings
Year ended December 31, (In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Retained earnings at beginning
of year $ 407,630 $ 400,610 $ 385,309
Net income 122,895 144,543 152,483
Dividends declared on cumulative
preferred stock (1,230) (2,075) (2,574)
Dividends declared on common stock,
$20.25, $21.00, and $20.80
per share, respectively (130,610) (135,448) (134,158)
Premium on redemption of
preferred stock (264) - (450)
Repurchase of common stock (193,818) - -
--------- --------- ---------
Retained earnings at end of year $ 204,603 $ 407,630 $ 400,610
========= ========= =========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
At December 31, (In thousands) 1998 1997
- -----------------------------------------------------------------------------
Assets
Utility plant, at original cost $1,262,461 $3,057,749
Less accumulated provisions
for depreciation and amortization 837,637 1,196,972
---------- ----------
424,824 1,860,777
Construction work in progress 33,289 29,015
---------- ----------
Net utility plant 458,113 1,889,792
---------- ----------
Investments:
Nuclear power companies, at equity (Note E-1) 48,538 49,825
Nonutility property and other investments 39,583 34,723
---------- ----------
Total investments 88,121 84,548
---------- ----------
Current assets:
Cash and temporary cash investments (including
$109,911 and $-0- with affiliates) 179,413 1,643
Accounts receivable:
Affiliated companies 107,878 233,308
Accrued NEEI revenues - 11,419
Others 32,573 26,638
Fuel, materials, and supplies, at average cost 9,220 47,492
Prepaid and other current assets 21,569 17,837
---------- ----------
Total current assets 350,653 338,337
---------- ----------
Regulatory assets (Note B) 1,512,562 441,038
Deferred charges and other assets 5,339 9,377
---------- ----------
$2,414,788 $2,763,092
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
Authorized - 6,449,896 shares
Outstanding - 3,749,896 and 6,449,896 shares $ 74,998 $ 128,998
Premium on capital stock 50,371 86,779
Other paid-in capital 190,852 289,818
Retained earnings 204,603 407,630
Unrealized gain on securities, net 72 34
---------- ----------
Total common equity 520,896 913,259
Cumulative preferred stock, par value
$100 per share (Note I) 1,567 39,666
Long-term debt 371,765 647,720
---------- ----------
Total capitalization 894,228 1,600,645
---------- ----------
Current liabilities:
Long-term debt due in one year - 50,000
Short-term debt, including $-0- and $3,125
to affiliates - 111,250
Accounts payable (including $119,657
and $14,373 to affiliates) 162,360 109,121
Accrued liabilities:
Taxes 15,009 39
Interest 2,440 8,905
Other accrued expenses (Note H) 20,086 23,554
Dividends payable 24 35,474
---------- ----------
Total current liabilities 199,919 338,343
---------- ----------
Deferred federal and state income taxes 165,115 369,757
Unamortized investment tax credits 30,870 53,463
Accrued Yankee nuclear plant costs (Note E-2) 242,138 299,564
Purchased power obligations 832,668 -
Other reserves and deferred credits 49,850 101,320
Commitments and contingencies (Note E)
---------- ----------
$2,414,788 $2,763,092
========== ==========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Cash Flows
Year ended December 31, (In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Operating activities:
Net income $ 122,895 $ 144,543 $ 152,483
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 104,331 101,186 108,338
Deferred income taxes and
investment tax credits, net (226,722) (12,728) (7,458)
Allowance for funds used
during construction (1,594) (1,238) (591)
Reimbursement to New England Energy
Incorporated of loss on sale of oil
and gas properties (120,900) - -
Buyout of purchased power contracts (326,590) - -
Decrease (increase) in
accounts receivable 130,914 (25,128) 19,629
Decrease (increase) in fuel,
materials, and supplies (10,270) 11,217 (4,045)
Decrease (increase) in prepaid
and other current assets (8,778) 7,213 2,936
Increase (decrease) in accounts payable (31,761) (18,105) (36,565)
Increase (decrease) in other
current liabilities 5,037 (1,905) 9,640
Other, net (49,611) 19,919 28,582
----------- --------- ---------
Net cash provided by (used in)
operating activities $ (413,049) $ 224,974 $ 272,949
=========== ========= =========
Investing activities:
Proceeds from sale of generating assets $ 1,688,863 $ - $ -
Plant expenditures, excluding allowance
for funds used during construction (64,446) (69,863) (65,981)
Other investing activities (5,474) (4,040) (3,878)
----------- --------- ---------
Net cash provided by (used in)
investing activities $ 1,618,943 $ (73,903) $ (69,859)
----------- --------- ---------
Financing activities:
Capital contribution from parent $ 34,881 $ - $ -
Dividends paid on common stock (166,084) (127,386) (138,995)
Dividends paid on preferred stock (1,206) (2,075) (2,574)
Changes in short-term debt (111,250) 17,650 (31,550)
Long-term debt - issues - - 47,850
Long-term debt - retirements (328,000) (38,500) (57,850)
Repurchase of common shares (417,960) - -
Preferred stock - retirements (38,505) - (19,532)
Premium on reacquisition of long-term debt - (2,163) -
----------- --------- ---------
Net cash used in
financing activities $(1,028,124) $(152,474) $(202,651)
----------- --------- ---------
Net increase (decrease) in
cash and cash equivalents $ 177,770 $ (1,403) $ 439
Cash and cash equivalents
at beginning of year 1,643 3,046 2,607
----------- --------- ---------
Cash and cash equivalents at end of year $ 179,413 $ 1,643 $ 3,046
=========== ========= =========
Supplementary Information:
Interest paid less amounts capitalized $ 43,419 $ 46,033 $ 51,212
----------- --------- ---------
Federal and state income taxes paid $ 282,076 $ 109,109 $ 96,006
----------- --------- ---------
Dividends received from
investments at equity $ 6,571 $ 3,267 $ 4,313
----------- --------- ---------
The accompanying notes are an integral part of these financial statements.
New England Power Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of operations:
New England Power Company (the Company), a wholly owned
subsidiary of New England Electric System (NEES), is a
Massachusetts corporation and is qualified to do business in
Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine,
and Vermont. The Company is subject, for certain purposes, to the
jurisdiction of the regulatory commissions of these six states,
the Securities and Exchange Commission (SEC), under the Public
Utility Holding Company Act of 1935 (1935 Act), the Federal
Energy Regulatory Commission (FERC) and the Nuclear Regulatory
Commission (NRC). The Company's business is primarily the
transmission of electric energy in wholesale quantities to other
electric utilities, principally its distribution affiliates
Granite State Electric Company, Massachusetts Electric Company
(Massachusetts Electric), Nantucket Electric Company, and The
Narragansett Electric Company (Narragansett Electric). See Note C
for a discussion of industry restructuring and Note D for a
discussion of the Company's divestiture of its nonnuclear
generating business. The Company also owns minority interests in
two joint owned nuclear generating units as well as minority
equity interests in 4 nuclear generating companies. The output
from these generating facilities is sold to third parties.
2. System of accounts:
The accounts of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by regulatory bodies
having jurisdiction.
In preparing the financial statements, management is required
to make estimates that affect the reported amounts of assets and
liabilities and disclosures of asset recovery and contingent
liabilities as of the date of the balance sheets, and revenues
and expenses for the period. These estimates may differ from
actual amounts if future circumstances cause a change in the
assumptions used to calculate these estimates.
3. Allowance for funds used during construction (AFDC):
The Company capitalizes AFDC as part of construction costs.
AFDC represents the composite interest and equity costs of
capital funds used to finance that portion of construction costs
not yet eligible for inclusion in rate base. AFDC is capitalized
in "Utility plant" with offsetting noncash credits to "Other
income" and "Interest." This method is in accordance with an
established rate-making practice under which a utility is
permitted a return on, and the recovery of, prudently incurred
capital costs through their ultimate inclusion in rate base and
in the provision for depreciation.
4. Depreciation and amortization:
The depreciation and amortization expense included in the
statements of income is composed of the following:
Year ended December 31
(In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Depreciation - transmission related $12,553 $11,828 $ 10,931
Depreciation - all other 46,256 68,432 67,256
Nuclear decommissioning costs (Note E-2) 2,719 2,638 2,629
Amortization:
Investment in Seabrook 1
pursuant to rate settlement - - 15,210
Seabrook 2 property losses - 113 6,279
Millstone 3 additional amortization,
pursuant to 1995 rate settlement 22,040 15,013 1,904
Regulatory assets covered by
CTC (See Note C) 16,356 - -
------- -------- --------
Total depreciation and
amortization expense $99,924 $98,024 $104,209
======= ======== ========
Depreciation is provided annually on a straight-line basis.
The provision for depreciation as a percentage of weighted
average depreciable transmission property was 2.3 percent in
1998, 1997, and 1996. Amortization of Seabrook and Millstone 3
investments above normal depreciation accruals was in accordance
with rate settlement agreements.
5. Cash:
The Company classifies short-term investments with a maturity
of 90 days or less as cash.
6. New Accounting Standards:
In 1997, the Financial Accounting Standards Board (FASB)
released Statement of Financial Accounting Standards No. 130,
Reporting of Comprehensive Income (FAS 130), which was adopted by
the Company in the first quarter of 1998. FAS 130 establishes
standards for reporting comprehensive income and its components.
Comprehensive income for the period is equal to net income plus
"other comprehensive income," which for the Company, consists of
the change in unrealized holding gains on available-for-sale
securities during the period. Other comprehensive income was
immaterial for the Company for the year ended December 31, 1998.
Also in 1997, the FASB released Statement of Financial
Accounting Standards No. 131, Disclosure about Segments of an
Enterprise and Related Information (FAS 131), which went into
effect in 1998. FAS 131 requires the reporting in financial
statements of certain new additional information about operating
segments of a business. FAS 131 does not currently impact the
Company's reporting requirements.
In February 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits (FAS 132), which
revises disclosure requirements for pension and other
postretirement benefits. The Company has adopted FAS 132 in its
financial statements for the year ending December 31, 1998.
The adoption of FAS 130, FAS 131, and FAS 132 had no impact on
the Company's operating results, financial position, or cash
flows.
In June 1998, the FASB issued Statement of Financial
Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (FAS 133), which establishes
accounting and reporting standards for such instruments. FAS 133
is effective for fiscal years beginning after June 15, 1999.
Currently, the Company has no such derivative holdings.
Note B - Merger Agreements
Merger Agreement with The National Grid Group plc
On December 11, 1998, NEES, The National Grid Group plc
(National Grid), and NGG Holdings LLC (Holdings), a directly and
indirectly wholly owned subsidiary of National Grid, entered into
an Agreement and Plan of Merger (Merger Agreement). Pursuant to
the Merger Agreement, Holdings will merge with and into NEES (the
Merger), with NEES becoming a wholly owned subsidiary of National
Grid. The Company will remain a wholly owned subsidiary of NEES.
The Merger is subject to approval by a majority vote of NEES
shareholders as well as National Grid shareholder approval. In
addition, the Merger is subject to a number of regulatory and
other approvals and consents, including approvals by the SEC,
under the 1935 Act, FERC and NRC, support or approval from the
states in which NEES subsidiaries operate, and clearance under
both the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended, and the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988. National Grid has obtained
governmental clearance in the United Kingdom for the Merger. The
Merger is expected to be completed by early 2000.
Merger Agreement with Eastern Utilities Associates
On February 1, 1999, NEES, Eastern Utilities Associates (EUA),
and Research Drive LLC (Research Drive), a directly and
indirectly wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA
Agreement, Research Drive will merge with and into EUA, with EUA
becoming a wholly owned subsidiary of NEES.
The acquisition of EUA is subject to approval by a two-thirds
vote of EUA shareholders. In addition, the acquisition is subject
to a number of regulatory and other approvals and consents,
including approvals by the SEC, under the 1935 Act, FERC, and
NRC, support or approval from the states in which EUA
subsidiaries operate, and clearance under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. The EUA
acquisition is expected to be completed by early 2000. Following
the acquisition of EUA, the subsidiaries of NEES and EUA whose
operations are similar are expected to be consolidated.
Note C - Industry Restructuring
During 1998, pursuant to legislation enacted in Massachusetts,
Rhode Island, and New Hampshire, and settlement agreements
approved by state and federal regulators (the Settlement
Agreements), all customers were provided the right to purchase
electricity from the power supplier of their choice. The NEES
companies remain obligated to deliver that electricity over its
transmission and distribution systems, with such delivery
services provided under regulated rates approved by State and
federal regulators. As described below, those delivery rates
include a non-bypassable charge for the costs of NEES' former
generating business which were not recovered through the sale of
that business ("stranded costs"), which was substantially
completed in 1998. As a result of the Settlement Agreements,
customers' choice of power supplier has no impact on NEES'
transmission and distribution business or on its ability to
recover stranded costs. In order to facilitate the
implementation of customer choice, the Settlement Agreements
provided for the termination of the Company's requirements
contracts with its affiliated distribution customers. The
Company's requirements contracts with unaffiliated customers have
also generally been terminated pursuant to settlement agreements
or tariff provisions. However, the Company remains obligated to
provide transition power supply service to new customer load in
Rhode Island.
The Settlement Agreements provide that the Company's stranded
costs are to be recovered from its wholesale customers through
contract termination charges (CTC). The affiliated wholesale
customers, in turn, are recovering those costs through their
delivery charges to distribution customers. Under the Settlement
Agreements, the recovery of the Company's stranded costs is
divided into several categories. Unrecovered costs associated
with generating plants (nuclear and nonnuclear) and most
regulatory assets will be fully recovered through the CTC by the
end of 2000 and earn a return on equity averaging 9.7 percent.
The Company's obligation relating to the above-market cost of
purchased power contracts and nuclear decommissioning costs are
recovered through the CTC over a longer period of time, as such
costs are actually incurred. The CTC rate was originally set at
2.8 cents per kilowatthour (kWh), and subsequently reduced to
approximately 1.5 cents or less per kWh upon completion of the
sale of the Company's nonnuclear generating business. As the CTC
rate declines, the Company, under certain of the Settlement
Agreements, earns incentives based on successful mitigation of
its stranded costs. These incentives supplement the Company's
return on equity. Finally, the Settlement Agreements provide that
until such time as the Company divests its operating nuclear
interests, the Company will share with customers, through the
CTC, 80 percent of the revenues and operating costs related to
the units, with shareholders retaining the balance.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of these
charges because they are expected to be included in future
customer charges. In 1997, the Emerging Issues Task Force (EITF)
of the FASB concluded that a utility that had received approval
to recover stranded costs through regulated transmission and
distribution rates would be permitted to continue to apply FAS 71
to the recovery of stranded costs.
The Company has received authorization from the FERC to
recover through the CTC substantially all of the costs associated
with its former generating business not recovered through the
sale of that business. Additionally, FERC Order No. 888 enables
transmission companies to recover their specific costs of
providing transmission service. Therefore, substantially all of
the Company's business, including the recovery of its stranded
costs, remains under cost-based rate regulation. The Company
believes these factors and the EITF conclusion allow it to
continue to apply FAS 71. Because of the nuclear cost-sharing
provisions related to the Company's CTC, the Company ceased
applying FAS 71 in 1997 to 20 percent of its ongoing nuclear
operations, the impact of which is immaterial.
Currently, there is much regulatory and other movement toward
establishing performance-based rates. It is possible that the
adoption of performance-based rates for the Company or its
affiliates, future regulatory rules, or other circumstances could
cause the application of FAS 71 to be discontinued. This
discontinuation would result in a noncash write-off of previously
established regulatory assets, including those being recovered
through the Company's CTC.
As a result of applying FAS 71, the Company has recorded a
regulatory asset for the costs that are recoverable from
customers through the CTC. The regulatory asset reflects the loss
on the sale of NEES' oil and gas business and the unrecovered
plant costs in operating nuclear plants (assuming no market
value), the costs associated with permanently closed nuclear
power plants, and the present value of the payments associated
with the above-market cost of purchased power contracts, reduced
by the gain from the sale of the nonnuclear generating business.
At December 31, 1998, the regulatory asset related to the CTC was
approximately $1.5 billion, of which $1.2 billion related to the
above-market costs of purchased power contracts.
As described above, the CTC regulatory asset includes the
unrecovered plant costs associated with the Company's interest in
operating nuclear plants. This balance sheet treatment is due to
the Company's conclusion that its interests in the Millstone 3
and Seabrook 1 nuclear generating units have little, if any,
market value. Three proposed sales of nuclear units by other
utilities have required the seller to set aside amounts for
decommissioning in excess of the proceeds from the sale of the
units. Two of these proposed sales were agreed upon prior to the
end of the third quarter of 1998. As a result, at the end of the
third quarter of 1998, the Company recorded an impairment
writedown in its reserve for depreciation of approximately $390
million, which represents the net book value at December 31,
1995, less applicable depreciation subsequent to that date, of
Millstone 3 and Seabrook 1. Because the Settlement Agreements
permit the Company to recover its pre-1996 investment as well as
decommissioning expenses through the CTC, the Company established
a regulatory asset in an amount equal to the impairment
writedown. Should the Company's efforts to sell its nuclear
interests result in a gain over the amounts remaining in the
plant account, such gain will be credited to customers through
the CTC.
Note D - Divestiture of Generating Business
On September 1, 1998, the Company and Narragansett Electric
(collectively, the Sellers) completed the sale of substantially
all of their nonnuclear generating business, all of which had a
book value of approximately $1.1 billion, to USGen New England,
Inc. (USGen), an indirect wholly owned subsidiary of PG&E
Corporation. The Sellers received $1.59 billion for the sale. In
addition, the Company was reimbursed approximately $140 million
for costs associated with early retirements and special severance
programs for employees affected by industry restructuring, and
the value of inventories. USGen assumed responsibility for
environmental conditions at the Sellers' nonnuclear generating
stations. USGen also assumed the Sellers' obligations under
long-term fuel and fuel transportation contracts, and certain
collective bargaining agreements.
As part of the sale, the Company also signed a purchased power
transfer agreement through which USGen purchased the Company's
entitlement to approximately 1,100 megawatts (MW) of power
procured under long-term contracts in exchange for monthly fixed
payments by the Company averaging $9.5 million per month through
January 2008 (having a net present value of $833 million) toward
the above-market cost of those contracts. In some cases, these
transfers involved formal assignment of the contracts to USGen
and a release of the Company from further obligations to the
power supplier, while others did not. For those that involved
formal assignment, the Company was required to make a lump sum
payment equivalent to the present value of the monthly fixed
payment obligations of those contracts. On or prior to the
closing date, the Company made lump sum payments totaling
approximately $340 million and was released from further
obligations relating to two of the contracts. These lump sum
payments are separate from the $833 million figure referred to
above. USGen is responsible for the balance of the costs under
the purchased power contracts. The present value of the future
monthly fixed payments is recorded as a liability on the balance
sheet. This liability, as well as the lump sum payments
previously made, net of amortization, are also recorded as a
regulatory asset on the balance sheet.
As part of the divestiture plan, in February 1998, New England
Energy Incorporated (NEEI), a wholly owned subsidiary of NEES,
whose costs had been supported by the Company, sold its oil and
gas properties for approximately $50 million. NEEI's loss on the
sale of approximately $120 million, before tax, has been
reimbursed by the Company.
In addition, the Company agreed under the Settlement
Agreements to endeavor to sell its minority interest in three
nuclear power plants and a 60 MW interest in a fossil-fueled
generating station in Maine. In February 1999, Vermont Yankee
Nuclear Power Corporation entered into a letter of intent to sell
its assets. For further information refer to the "Nuclear Units"
section of Financial Review.
Note E - Commitments and Contingencies
1. Yankee Nuclear Power Companies (Yankees)
The Company has minority interests in four Yankee Nuclear
Power Companies. These ownership interests are accounted for on
the equity method. The Company's share of the expenses of the
Yankees is accounted for in "Purchased electric energy" on the
statements of income.
A summary of combined results of operations, assets, and
liabilities of the four Yankees is as follows:
(In thousands) 1998 1997 1996
- ----------------------------------------------------------------------------
Operating revenue $ 439,046$ 660,742$ 697,054
=================================
Net income $ 23,218$ 29,959$ 27,567
=================================
Company's equity in net income $ 5,284$ 5,189$ 5,159
=================================
Net plant 171,582 204,689 401,049
Other assets 2,810,613 3,100,589 2,031,336
Liabilities and debt (2,723,454) (3,036,845) (2,177,068)
---------------------------------
Net assets $ 258,741$ 268,433$ 255,317
=================================
Company's equity in net assets $ 48,538$ 49,825$ 47,902
=================================
Company's purchased electric energy:
Vermont Yankee $ 35,108$ 31,240$ 32,676
All other Yankees $ 48,543$ 75,900$ 78,102
=================================
At December 31, 1998, $15 million of undistributed earnings of
the Yankees were included in the Company's retained earnings.
2. Nuclear Units
Nuclear Units Permanently Shut Down
Three regional nuclear generating companies in which the
Company has a minority interest own nuclear generating units that
have been permanently shut down. These three units are as
follows:
Future
Estimated
NEP's Billings
Investment Date to NEP
Unit % $ (millions) Retired $(millions)
- -----------------------------------------------------------------
Yankee Atomic 30 6 Feb 1992 24
Connecticut Yankee 15 16 Dec 1996 75
Maine Yankee 20 16 Aug 1997 143
In the case of each of these units, the Company has recorded a
liability and an offsetting regulatory asset reflecting the
estimated future billings from the companies. In a 1993 decision,
the FERC allowed Yankee Atomic to recover its undepreciated
investment in the plant as well as unfunded nuclear
decommissioning costs and other costs. Connecticut Yankee and
Maine Yankee have both filed similar requests with the FERC.
Several parties have intervened in opposition to both filings. In
August 1998, a FERC Administrative Law Judge (ALJ) issued an
initial decision which would allow for full recovery of
Connecticut Yankee's unrecovered investment, but precluded a
return on that investment. Connecticut Yankee, the Company, and
other parties have filed with the FERC exceptions to the ALJ's
decision. Should the FERC uphold the ALJ's initial decision in
its current form, the Company's share of the loss of the return
component would total approximately $12 million to $15 million
before taxes. In January 1999, parties in the Maine Yankee
proceeding filed a comprehensive settlement agreement with the
FERC, under which Maine Yankee would recover all unamortized
investment in the plant, including a return on its equity
investment of 6.5 percent, as well as decommissioning costs and
other costs. This settlement agreement requires FERC approval.
The Company's industry restructuring settlements allow it to
recover all costs that the FERC allows these Yankee companies to
bill to the Company.
The Company and several other shareholders (Sponsors) of Maine
Yankee are parties to 27 contracts (Secondary Purchase
Agreements) under which they sold portions of their entitlements
to Maine Yankee power output through 2002 to various entities,
primarily municipal and cooperative systems in New England
(Secondary Purchasers). Virtually all of the Secondary Purchasers
had ceased making payments under the Secondary Purchase
Agreements, claiming that such agreements excuse further payments
upon plant shutdown. In February 1999, a settlement agreement
which fully resolves the dispute between the Sponsors and
Secondary Purchasers was filed with the FERC, under which the
Secondary Purchasers would be required to make certain payments
to Maine Yankee, and, in turn, to the Company, related to both
past and future obligations under the Secondary Purchase
Agreements. This settlement agreement requires FERC approval.
Shutdown costs are recoverable from customers under the
Settlement Agreements.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall.
Operating Nuclear Units
The Company has minority interests in three other nuclear
generating units: Vermont Yankee, Millstone 3, and Seabrook 1.
Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Vermont Yankee, are
increasing rapidly and could adversely affect their service
lives, availability, and costs. These uncertainties stem from a
combination of factors, including the acceleration of competitive
pressures in the power generation industry and increased NRC
scrutiny. The Company performs periodic economic viability
reviews of operating nuclear units in which it holds ownership
interests.
Vermont Yankee
On February 25, 1999, the Board of Directors of Vermont Yankee
Nuclear Power Corporation granted an exclusive right to AmerGen
Energy Company (AmerGen), a joint venture by PECO Energy and
British Energy to conduct a due diligence review over the next
120 days and negotiate a possible agreement to purchase the
assets of Vermont Yankee, Vermont's sole nuclear generating
plant. Provided the due diligence review leads to successful
completion of negotiations for a sale, consummation of such a
sale would be contingent on regulatory approvals by the NRC, the
SEC, under the 1935 Act, and the Vermont Public Service Board,
among others. The sale process could take eight to twelve months
or longer. In past negotiations for the sale of nuclear plants,
due diligence review has not guaranteed that a sale will occur.
The Company has a 20 percent ownership interest in Vermont Yankee
and an investment of approximately $11 million at December 31,
1998.
Millstone 3
In July 1998, Millstone 3 returned to full operation after
being shut down since April 1996. Millstone 3 remains on the NRC
"Watch List," signifying that it continues to warrant increased
NRC attention. Millstone 3 is operated by a subsidiary of
Northeast Utilities (NU). The Company is not an owner of the
Millstone 2 nuclear generating unit, which is temporarily shut
down under NRC orders, or the Millstone 1 nuclear generating
unit, which has been permanently shut down. A criminal
investigation related to Millstone 3 is ongoing.
In August 1997, the Company sued NU in Massachusetts Superior
Court for damages resulting from the tortious conduct of NU that
caused the shutdown of Millstone 3. The Company's damages include
the costs of replacement power during the outage, costs necessary
to return Millstone 3 to safe operation, and other additional
costs. Most of the Company's incremental replacement power costs
have been recovered from customers, either through fuel
adjustment clauses or through provisions in the Settlement
Agreements. The Company also seeks punitive damages. The Company
also sent a demand for arbitration to Connecticut Light & Power
Company and Western Massachusetts Electric Company, both
subsidiaries of NU, seeking damages resulting from their breach
of obligations under an agreement with the Company and others
regarding the operation and ownership of Millstone 3. The
arbitration is scheduled for October 1999. In July 1998, the
court denied NU's motion to dismiss and its motion to stay
pending arbitration. The Company subsequently amended its
complaint by, among other things, adding NU's Trustees as
defendants. In December 1998, NU moved for summary judgement. The
Company's suit has been consolidated with suits filed by other
joint owners. The court is in the process of scheduling a trial
date. Some or all of the damages awarded from the lawsuit would
be refunded to customers.
Nuclear Decommissioning
The Company is liable for its share of decommissioning costs
for Millstone 3, Seabrook 1, and all of the Yankees.
Decommissioning costs include not only estimated costs to
decontaminate the units as required by the NRC, but also costs to
dismantle the uncontaminated portion of the units. The Company
records decommissioning costs on its books consistent with its
rate recovery. The Company is recovering its share of projected
decommissioning costs for Millstone 3 and Seabrook 1 through
depreciation expense. In addition, the Company is paying its
portion of projected decommissioning costs for all of the Yankees
through purchased power expense. Such costs reflect estimates of
total decommissioning costs approved by the FERC.
In New Hampshire, legislation was recently enacted which makes
owners of Seabrook 1, in which the Company owns a 10 percent
interest, proportional guarantors for decommissioning costs in
the event that an owner without a franchise service territory
fails to fund its share of decommissioning costs. Currently, a
single owner of an approximate 12 percent share of Seabrook 1 has
no franchise service territory.
The New Hampshire Nuclear Decommissioning Finance Committee is
reviewing Seabrook Station's decommissioning estimate and
associated annual funding levels. Among the items being
considered is the imposition of joint and several liability among
the Seabrook joint owners for decommissioning funding. The
Company cannot predict what additional liability, if any, may be
imposed on it.
The Nuclear Waste Policy Act of 1982 establishes that the
federal government (through the Department of Energy (DOE)) is
responsible for the disposal of spent nuclear fuel. The federal
government requires the Company to pay a fee based on its share
of the net generation from the Millstone 3 and Seabrook 1 nuclear
generating units. Prior to 1998, the Company recovered this fee
through its fuel clause. Under the Settlement Agreements,
substantially all of these costs are recovered through CTCs.
Similar costs are billed to the Company by Vermont Yankee and
also recovered from customers through the same mechanism. In
November 1997, ruling on a lawsuit brought against the DOE by
numerous utilities and state regulatory commissions, the U.S.
Court of Appeals for the District of Columbia (the Appeals Court)
held that the DOE was obligated to begin disposing of utilities'
spent nuclear fuel by January 31, 1998. The DOE failed to meet
this deadline, and is not expected to have a temporary or
permanent repository for spent nuclear fuel for many years. In
February 1998, Maine Yankee petitioned the Appeals Court to
compel the DOE to remove Maine Yankee's spent fuel from the site.
In May 1998, the Appeals Court rejected the petitions of Maine
Yankee and the other utilities and state regulatory commissions,
stating that the issue of damages was a contractual matter. The
operators of the units in which the Company has an obligation,
including Maine Yankee, Connecticut Yankee, and Yankee Atomic,
continue to pursue damage claims against the DOE in the Federal
Court of Claims (Claims Court). In October 1998, the Claims Court
ruled that the DOE violated a commitment to remove spent fuel
from Yankee Atomic. The Claims Court issued similar rulings in
November 1998 related to cases brought by Connecticut Yankee and
Maine Yankee. Further proceedings will be scheduled by the Claims
Court to decide the amount of damages.
Decommissioning Trust Funds
Each nuclear unit in which the Company has an ownership
interest has established a decommissioning trust fund or escrow
fund into which payments are being made to meet the projected
costs of decommissioning. The table below lists information on
each operating nuclear plant in which the Company has an
ownership interest.
NEP's share of (millions of dollars)
-------------------------------------------
Nep's Estimated Decommissioning
Ownership Net Decommissioning Fund License
Unit Interest (%) Plant Assets Cost (in 1998 $) Balances* Expiration
- -----------------------------------------------------------------------------------------
Vermont Yankee 20 34 105 38 2012
Millstone 3 12 9** 67 21 2025
Seabrook 1 10 15** 50 10 2026
<FN>
* Certain additional amounts are anticipated to be available through tax deductions.
** Represents post-December 1995 spending including nuclear fuel. See Note C for a
discussion of an impairment writedown and establishment of an offsetting regulatory asset.
</FN>
There is no assurance that decommissioning costs actually
incurred by Vermont Yankee, Millstone 3, or Seabrook 1 will not
substantially exceed these amounts. For example, decommissioning
cost estimates assume the availability of permanent repositories
for both low-level and high-level nuclear waste; those
repositories do not currently exist. The temporary low-level
repository located in Barnwell, South Carolina may become
unavailable, which could increase the cost of decommissioning the
Yankee Atomic, Connecticut Yankee, and Maine Yankee plants. If
any of the operating units were shut down prior to the end of
their operating licenses, which the Company believes is likely,
the funds collected for decommissioning to that point would be
insufficient. Under the Settlement Agreements discussed in Note
C, the Company will recover decommissioning costs through CTCs.
Nuclear Insurance
The Price-Anderson Act limits the amount of liability claims
that would have to be paid in the event of a single incident at a
nuclear plant to $9.7 billion (based upon 108 licensed reactors).
The maximum amount of commercially available insurance coverage
to pay such claims is $200 million. The remaining $9.5 billion
would be provided by an assessment of up to $88.1 million per
incident levied on each of the participating nuclear units in the
United States, subject to a maximum assessment of $10 million per
incident per nuclear unit in any year. The maximum assessment,
which was most recently adjusted in 1998, is adjusted for
inflation at least every five years. The Company's current
interest in Vermont Yankee, Millstone 3, and Seabrook 1 would
subject the Company to a $35.4 million maximum assessment per
incident. The Company's payment of any such assessment would be
limited to a maximum of $4.0 million per year. As a result of the
permanent cessation of power operation of the Yankee Atomic,
Connecticut Yankee, and Maine Yankee plants, these units have
received from the NRC an exemption from participating in the
secondary financial protection system under the Price-Anderson
Act. However, these plants must continue to maintain $100 million
of commercially available nuclear liability insurance coverage.
Each of the nuclear units in which the Company has either an
ownership or purchased power interest also carries nuclear
property insurance to cover the costs of property damage,
decontamination, and premature decommissioning resulting from a
nuclear incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units
covered by this insurance occur in a prior six-year period. The
Company's maximum potential exposure for these assessments,
either directly or indirectly, is approximately $4.6 million with
respect to the current policy period.
3. Plant expenditures
The Company's utility plant expenditures are estimated to be
approximately $65 million in 1999. At December 31, 1998,
substantial commitments had been made relative to future planned
expenditures.
4. Hydro-Quebec Interconnection
Three affiliates of the Company were created to construct and
operate transmission facilities to transmit power from Hydro-
Quebec to New England. Under support agreements entered into at
the time these facilities were constructed, the Company agreed to
guarantee a portion of the project debt. That portion at
December 31, 1998 amounted to $23 million.
5. Long-term contracts for the purchase of electricity
Historically, the Company purchased a portion of its
electricity requirements pursuant to long-term contracts with
owners of various generating units. These contracts expire in
various years from 1998 to 2029. See Note D for a discussion of
USGen's purchase of the Company's entitlement to approximately
1,100 MW of power procured under long-term contracts.
The Company retained one purchased power contract, with
Vermont Yankee, which requires minimum fixed payments, even when
the supplier is unable to deliver power, to cover a proportionate
share of the capital and fixed operating costs of the unit. This
contract has fixed payment requirements of approximately $35
million in 1999, $30 million in 2000, $35 million in 2001 and
2002, $30 million in 2003, and approximately $300 million
thereafter. The Company holds an ownership interest in Vermont
Yankee.
6. Hazardous waste
The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly known as the "Superfund" law,
imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous
substances. A number of states, including Massachusetts, have
enacted similar laws.
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. The Company currently has in place an
internal environmental audit program and an external waste
disposal vendor audit and qualification program intended to
enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous
products and by-products.
The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for
six sites at which hazardous waste is alleged to have been
disposed. Private parties have also contacted or initiated legal
proceedings against the Company regarding hazardous waste
cleanup. The Company is currently aware of other possible
hazardous waste sites, and may in the future become aware of
additional sites, that they may be held responsible for
remediating.
Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult. There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by the Company. The NEES
companies have recovered amounts from certain insurers, and,
where appropriate, intend to seek recovery from other insurers
and from other PRPs, but it is uncertain whether, and to what
extent, such efforts will be successful. The Company believes
that hazardous waste liabilities for all sites of which it is
aware are not material to its financial position.
7. Town of Norwood dispute
In September 1998, the United States District Court (District
Court) for the District of Massachusetts dismissed the lawsuit
filed in April 1997 by the Town of Norwood, Massachusetts against
NEES and the Company. The Company had been a wholesale power
supplier for Norwood pursuant to rates approved by the FERC. In
the lawsuit, Norwood had alleged that the Company's divestiture
of its power generating assets would violate the terms of a 1983
power contract. Norwood also alleged that the divestiture and
recovery of stranded investment costs contravened federal
antitrust laws. The District Court judge granted NEES' and the
Company's motion for dismissal on the grounds that the contract
did not require the Company to retain its generating units, that
the FERC-approved filed rates govern these matters, and that
Norwood had adequate opportunity at the FERC to litigate these
matters. Norwood filed a motion to alter or amend the order of
dismissal, which was denied. In December 1998, Norwood filed a
second motion to amend judgement and also filed an appeal with
the First Circuit Court of Appeals (First Circuit). In March
1999, the District Court denied Norwood's second motion to amend
judgement.
In March 1998, Norwood gave notice of its intent to terminate
its contract with the Company, without accepting responsibility
for its share of the Company's stranded costs, and began taking
power from another supplier commencing in April 1998. In May
1998, the FERC ruled that the Company could assess a CTC to any
of the Company's unaffiliated customers that choose to terminate
their wholesale power contracts early. Norwood claimed that the
CTC approved by the FERC did not apply to Norwood; however, in
denying Norwood's motion for rehearing, the FERC ruled that the
charge did apply to Norwood. Norwood has appealed this decision
to the First Circuit. The Company's billings to Norwood for this
charge through December 1998 have been approximately $6 million,
which remain unpaid. The Company filed a collection action with
the Massachusetts Superior Court in December 1998 to recover
these amounts. Norwood filed a motion to dismiss or stay in
January 1999.
Norwood also appealed the FERC's orders approving the
divestiture and the Massachusetts and Rhode Island industry
restructuring settlement agreements (including modification of
the Company's contracts with Massachusetts Electric and
Narragansett Electric) to the First Circuit, despite the FERC's
finding that those settlement agreements do not apply to Norwood.
The First Circuit has consolidated all three of Norwood's
appeals from the FERC's orders with two other appeals filed by
the Northeast Center for Social Issue Studies, which challenge
the FERC's approval of the Company's sale of its hydroelectric
facilities. The case is to be fully briefed by May 1999.
Note F - Employee Benefits
1. Pension Plans:
The Company participates with other subsidiaries of NEES in
noncontributory, defined-benefit plans covering substantially all
employees of the Company. The plans provide pension benefits
based on the employee's compensation during the five years prior
to retirement. Absent unusual circumstances, the Company's
funding policy is to contribute each year the net periodic
pension cost for that year. However, the contribution for any
year will not be less than the minimum contribution required by
federal law or greater than the maximum tax deductible amount.
Net pension cost for 1998, 1997, and 1996 included the following components:
- -----------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------------------------------------
Service cost - benefits earned during the period $ 2,430$ 2,887 $ 2,769
Plus (less):
Interest cost on projected benefit obligation 7,435 7,003 6,669
Return on plan assets at expected long-term rate (8,675) (7,842) (7,204)
Amortization of transition obligation (184) (175) (171)
Amortization of prior service cost 161 171 168
Amortization of net (gain)/loss 159 65 273
Curtailment (gain)/loss (5,680) - -
- -----------------------------------------------------------------------------------------
Benefit cost $ (4,354)$ 2,109 $ 2,504
- -----------------------------------------------------------------------------------------
Special termination benefits not included above $ 10,911$ - $ -
- -----------------------------------------------------------------------------------------
The funded status of the plans cannot be presented separately
for the Company as the Company participates in the plans with
other NEES subsidiaries. The following table sets forth the
funded status of the NEES companies' plans at December 31:
- ---------------------------------------------------------------------------
(millions of dollars) 1998 1997
- ---------------------------------------------------------------------------
Benefit obligation $843 $819
Unrecognized prior service costs (6) (8)
Transition liability not yet recognized (amortized) (2) (4)
Additional minimum liability 7 4
- ---------------------------------------------------------------------------
842 811
- ---------------------------------------------------------------------------
Plan assets at fair value 837 834
Transition asset not yet recognized (amortized) (6) (8)
Net (gain)/loss not yet recognized (amortized) (92) (52)
- ---------------------------------------------------------------------------
739 774
- ---------------------------------------------------------------------------
Accrued pension/(prepaid) payments
recorded on books $103 $ 37
- ---------------------------------------------------------------------------
The following provides a reconciliation of benefit obligations
and plan assets:
- ---------------------------------------------------------------------------
(millions of dollars) 1998 1997
- ---------------------------------------------------------------------------
Changes in benefit obligation:
Benefit obligation at January 1 $819 $807
Service cost 14 15
Interest cost 55 53
Actuarial (gain)/loss (5) 59
Benefits paid from plan assets (94) (47)
Special termination benefits 64 -
Curtailment (11) -
Plan amendments 1 -
Dispositions (Yankee Atomic) - (68)
- ---------------------------------------------------------------------------
Benefit obligation at December 31 $843 $819
- ---------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $834 $812
Actual return on plan assets during year 93 130
Company contributions 4 8
Benefits paid from plan assets (94) (47)
Dispositions (Yankee Atomic) - (69)
- ---------------------------------------------------------------------------
Fair value of plan assets at December 31 $837 $834
- ---------------------------------------------------------------------------
Year ended December 31 1999 1998 1997 1996
- ----------------------------------------------------------------------
Assumptions used to determine pension cost:
Discount rate 6.75% 6.75% 7.25% 7.25%
Average rate of increase in
future compensation level 4.13% 4.13% 4.13% 4.13%
Expected long-term rate of
return on assets 8.50% 8.50% 8.50% 8.50%
The plans' funded status at December 31, 1998 and 1997 were
calculated using the assumed rates from 1999 and 1998,
respectively, and the 1983 Group Annuity Mortality table.
Plan assets are composed primarily of corporate equity, debt
securities, and cash equivalents.
2. Postretirement Benefit Plans Other than Pensions (PBOPs):
The Company provides health care and life insurance coverage
to eligible retired employees. Eligibility is based on certain
age and length of service requirements and in some cases retirees
must contribute to the cost of their coverage.
The Company's total cost of PBOPs for 1998, 1997, and 1996
included the following components:
- -----------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------------------------------------
Service cost - benefits earned during the period $ 1,109 $ 1,363 $ 1,407
Plus (less):
Interest cost on projected benefit obligation 3,244 3,545 3,580
Return on plan assets at expected long-term rate (2,656) (2,343) (1,832)
Amortization of transition obligation 1,732 2,556 2,556
Amortization of prior service cost 5 8 8
Amortization of net (gain)/loss (1,138) (983) (697)
Curtailment (gain)/loss 27,149 - -
- -----------------------------------------------------------------------------------------
Benefit cost $29,445 $ 4,146 $ 5,022
- -----------------------------------------------------------------------------------------
Special termination benefits not included above $ 439 $ - $ -
- -----------------------------------------------------------------------------------------
The following table sets forth the Company's benefits earned
and the plans' funded status:
- -----------------------------------------------------------------------------
At December 31 (millions of dollars) 1998 1997
- -----------------------------------------------------------------------------
Benefit obligation $ 41 $ 51
Unrecognized prior service costs - -
Transition liability not yet recognized (amortized) (1) (38)
- -----------------------------------------------------------------------------
40 13
- -----------------------------------------------------------------------------
Plan assets at fair value 36 34
Net (gain)/loss not yet recognized (amortized) (26) (21)
- -----------------------------------------------------------------------------
10 13
- -----------------------------------------------------------------------------
Accrued pension/(prepaid) payments recorded on books $ 30 $ -
- -----------------------------------------------------------------------------
The following provides a reconciliation of benefit obligations
and plan assets:
- -----------------------------------------------------------------------------
(millions of dollars) 1998 1997
- -----------------------------------------------------------------------------
Changes in benefit obligation:
Benefit obligation at January 1 $ 51 $ 54
Service cost 1 1
Interest cost 3 4
Actuarial (gain)/loss 2 (6)
Benefits paid from plan assets (2) (2)
Special termination benefits - -
Curtailment (14) -
- -----------------------------------------------------------------------------
Benefit obligation at December 31 $ 41 $ 51
- -----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $ 34 $ 29
Actual return on plan assets during year 4 6
Company contributions - 1
Benefits paid from plan assets (2) (2)
- -----------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 36 $ 34
- -----------------------------------------------------------------------------
Year ended December 31 1999 1998 1997 1996
- ----------------------------------------------------------------------
Assumptions used to determine postretirement benefit cost:
Discount rate 6.75% 6.75% 7.25% 7.25%
Expected long-term rate of
return on assets 8.25% 8.25% 8.25% 8.25%
Health care cost rate -
1996 to 1999 5.25% 5.25% 8.00% 8.00%
Health care cost rate -
2000 to 2004 5.25% 5.25% 6.25% 6.25%
Health care cost rate -
2005 and beyond 5.25% 5.25% 5.25% 5.25%
The plans' funded status at December 31, 1998 and 1997 were
calculated using the assumed rates in effect for 1999 and 1998,
respectively.
The assumptions used in the health care cost trends have a
significant effect on the amounts reported. A one percentage
point change in the assumed rates would increase the accumulated
postretirement benefit obligation (APBO) as of December 31, 1998
by approximately $5 million or decrease the APBO by approximately
$4 million, and change the net periodic cost for 1998 by
approximately $1 million.
The Company generally funds the annual tax-deductible
contributions. Plan assets are invested in equity and debt
securities and cash equivalents.
3. Early Retirement and Special Severance Programs:
In 1998, the Company offered a voluntary early retirement
program to all employees who were at least 55 years old with 10
years of service. This program was part of an organizational
review with the goal of streamlining operations and reducing the
work force to reflect the sale of the nonnuclear generating
business. The early retirement offer was accepted by 104
employees. A special severance program was also utilized in 1998
for employees affected by the organizational restructuring, but
who were not eligible for, or did not accept, the early
retirement offer. The cost of these programs was in part
reimbursed by USGen at the closing of the sale of the nonnuclear
generating business and will be recovered in part from customers
as a component of stranded cost recovery.
Note G - Income Taxes
The Company and other subsidiaries participate with NEES in
filing consolidated federal income tax returns. The Company's
income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by
the Internal Revenue Service through 1993.
Total income taxes in the statements of income are as follows:
Year ended December 31, (In thousands) 1998 1997 1996
- ----------------------------------------------------------------
Income taxes charged to operations $ 73,594 $90,009 $91,894
Income taxes charged (credited) to
"Other income" (19,582) (373) 555
-------- ------- -------
Total income taxes $ 54,012 $89,636 $92,449
======== ======= =======
Total income taxes, as shown above, consist of the following
components:
Year ended December 31, (In thousands) 1998 1997 1996
- ----------------------------------------------------------------
Current income taxes $ 280,734 $102,364 $99,907
Deferred income taxes (204,129) (10,705) (5,435)
Investment tax credits, net (22,593) (2,023) (2,023)
--------- -------- -------
Total income taxes $ 54,012 $ 89,636 $92,449
========= ======== =======
Investment tax credits (ITC) have been deferred and amortized
over the estimated lives of the property giving rise to the
credits. The increase in amortization of ITC in 1998 results
from the recognition in income of unamortized ITC relating to the
generating assets divested during 1998.
Total income taxes, as shown above, consist of federal and
state components as follows:
Year ended December 31, (In thousands) 1998 1997 1996
- ----------------------------------------------------------------
Federal income taxes $41,255 $73,077 $76,656
State income taxes 12,757 16,559 15,793
------- ------- -------
Total income taxes $54,012 $89,636 $92,449
======= ======= =======
With regulatory approval from the FERC, the Company has
adopted comprehensive interperiod tax allocation (normalization)
for temporary book/tax differences.
Total income taxes differ from the amounts computed by
applying the federal statutory tax rates to income before taxes.
The reasons for the differences are as follows:
Year ended December 31, (In thousands) 1998 1997 1996
- ----------------------------------------------------------------
Computed tax at statutory rate $ 61,917 $81,963 $85,726
Increases (reductions) in tax
resulting from:
Amortization of investment
tax credits (15,157) (2,023) (2,023)
State income taxes, net of
federal income tax benefit 8,292 10,763 10,265
All other differences (1,040) (1,067) (1,519)
-------- ------- -------
Total income taxes $ 54,012 $89,636 $92,449
======== ======= =======
The following table identifies the major components of total
deferred income taxes:
At December 31, (In millions) 1998 1997
- ----------------------------------------------------------------
Deferred tax asset:
Plant related $ 76 $ 87
Investment tax credits 13 22
All other 24 44
----- -----
113 153
----- -----
Deferred tax liability:
Plant related (22) (418)
Equity AFDC (31) (43)
All other (225) (62)
----- -----
(278) (523)
----- -----
Net deferred tax liability $(165) $(370)
===== =====
Note H - Short-term Borrowings and Other Accrued Expenses
At December 31, 1998, the Company had no short-term debt
outstanding. NEES and certain subsidiaries, including the
Company, with regulatory approval, operate a money pool to more
effectively utilize cash resources and to reduce outside
short-term borrowings. Short-term borrowing needs are met first
by available funds of the money pool participants. Borrowing
companies pay interest at a rate designed to approximate the cost
of outside short-term borrowings. Companies which invest in the
pool share the interest earned on a basis proportionate to their
average monthly investment in the money pool. Funds may be
withdrawn from or repaid to the pool at any time without prior
notice.
At December 31, 1998, the Company had lines of credit and
standby bond purchase facilities with banks totaling $455
million. These lines and facilities were used at December 31,
1998 for liquidity support for $372 million of the Company's
bonds in tax-exempt commercial paper mode (see Note J) and for
other corporate purposes. There were no borrowings under these
lines of credit at December 31, 1998. Fees are paid on the lines
and facilities in lieu of compensating balances.
The components of other accrued expenses are as follows:
At December 31, (In thousands) 1998 1997
- ----------------------------------------------------------------
Accrued wages and benefits $3,059 $ 9,838
Capital lease obligations due within one year - 4,333
Rate adjustment mechanisms 16,781 6,957
Other 246 2,426
------- -------
$20,086 $23,554
------- -------
Note I - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1998
and 1997 is as follows (in thousands of dollars except for share
data):
Shares Dividends Call
Outstanding Amount Declared Price
- ------------------------------------------------------------------------------
1998 1997 1998 1997 1998 1997
- ------------------------------------------------------------------------------
$100 par value
6.00% Series 15,672 75,020 $1,567 $ 7,502 $ 277 $ 451 (a)
4.56% Series - 100,000 - 10,000 247 456
4.60% Series - 80,140 - 8,014 236 368
4.64% Series - 41,500 - 4,150 98 192
6.08% Series - 100,000 - 10,000 372 608
- ------------------------------------------------------------------------------
Total 15,672 396,660 $1,567 $39,666 $1,230 $2,075
<FN>
(a) Noncallable.
</FN>
The annual dividend requirement for total cumulative preferred
stock was $94,000 and $2,075,000 at the end of 1998 and 1997,
respectively. In 1998, the Company repurchased or redeemed
preferred stock with an aggregate par value of $38 million.
Note J - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In thousands)
Series Rate % Maturity 1998 1997
- -----------------------------------------------------------------------------
General and Refunding (G&R) Mortgage Bonds:
W(93-2) 6.17 February 2, 1998 $ - 4,300
W(93-4) 6.14 February 2, 1998 - 1,300
W(93-5) 6.17 February 3, 1998 - 5,000
W(93-7) 6.10 February 4, 1998 - 10,000
W(93-9) 6.04 February 4, 1998 - 29,400
Y(94-4) 8.28 December 21, 1999 - 10,000
W(93-6) 6.58 February 10, 2000 - 5,000
Y(95-1) 7.94 February 14, 2000 - 5,000
Y(95-2) 7.93 February 14, 2000 - 10,000
Y(95-3) 7.40 March 21, 2000 - 10,000
Y(95-4) 6.69 June 5, 2000 - 25,000
W(93-1) 7.00 February 3, 2003 - 25,000
Y(94-2) 8.33 November 8, 2004 - 10,000
U 8.00 August 1, 2022 - 134,500
Y(94-1) 8.53 September 20, 2024 - 5,000
Pollution Control Revenue Bonds (a):
K 7.25 October 15, 2015 - 38,500
MIFA 1 (b) variable March 1, 2018 79,250 79,250
BFA 1 (c) variable November 1, 2020 135,850 135,850
BFA 2 (c) variable November 1, 2020 50,600 50,600
MIFA 2 (b) variable October 1, 2022 106,150 106,150
Unamortized discounts (85) (2,130)
-------- --------
Total long-term debt 371,765 697,720
======== ========
Long-term debt due in one year - (50,000)
-------- --------
$371,765 $647,720
======== ========
<FN>
(a) Prior to September 1, 1998, the following debt was secured by G&R
mortgage bonds.
(b) MIFA = Massachusetts Industrial Finance Authority
(c) BFA = Business Finance Authority of the State of New Hampshire
</FN>
At December 31, 1998, interest rates on the Company's variable
rate bonds ranged from 3.05 percent to 3.45 percent.
At December 31, 1998, the Company's long-term debt had a
carrying value and fair value of $372,000,000. The fair value of
debt that reprices frequently at market rates approximates
carrying value.
In order to satisfy certain terms of its mortgage indenture,
the Company defeased or retired all $641 million of its mortgage
bonds outstanding at the time of the sale of its nonnuclear
generating business. The Company retired $372 million of
mortgage bonds securing the issuance of a like amount of
pollution control revenue bonds (PCRBs), leaving the underlying
PCRBs outstanding as unsecured obligations of the Company.
Pursuant to a tender offer, the Company purchased $183 million of
bonds. Provisions for the payment of the remaining mortgage
bonds were made by depositing with trustees approximately $97
million of U.S. treasury obligations sufficient to pay principal,
interest, and premium, as applicable, to the maturity date, or to
the first date on which the bonds could be redeemed. Both the
U.S. treasury obligations and defeased bonds were removed from
the balance sheet effective September 30, 1998.
Note K - Common Stock
The Company repurchased shares of its common stock in 1998 as
follows (dollar amounts expressed in thousands):
Reductions to :
-----------------------------------------
Common stock
Number of Cash and related Other paid- Retained
Year Shares Paid premium in capital earnings
- ------------------------------------------------------------------------------------
1998 2,700,000 $417,960 $90,266 $133,876 $193,818
Note L - Supplementary Income Statement Information
Advertising expenses, expenditures for research and
development, and rents were not material and there were no
royalties paid in 1998, 1997, or 1996. Taxes, other than income
taxes, charged to operating expenses are set forth by classes as
follows:
Year ended December 31, (In thousands) 1998 1997 1996
- ----------------------------------------------------------------
Municipal property taxes $42,080 $59,102 $58,942
Federal and state payroll
and other taxes 6,412 8,209 7,474
------- ------- -------
$48,492 $67,311 $66,416
======= ======= =======
New England Power Service Company, an affiliated service
company operating pursuant to the provisions of Section 13 of the
1935 Act, furnished services to the Company at the cost of such
services. These costs amounted to $74,203,000, $91,985,000, and
$85,124,000, including capitalized construction costs of
$21,281,000, $24,347,000, and $19,412,000, for each of the years
1998, 1997, and 1996, respectively.
New England Power Company
Selected Financial Information
Year ended December 31,
(In millions) 1998 1997 1996 1995 1994
- -----------------------------------------------------------------------------------
Operating revenue $1,218 $1,678 $1,600 $1,571 $1,541
Net income $ 123 $ 145 $ 152 $ 151 $ 149
Total assets $2,415 $2,763 $2,648 $2,648 $2,613
Capitalization:
Common equity $ 521 $ 913 $ 906 $ 889 $ 877
Cumulative preferred stock 1 40 40 61 61
Long-term debt 372 648 733 735 695
------ ------ ------ ------ ------
Total capitalization $ 894 $1,601 $1,679 $1,685 $1,633
Preferred dividends declared $ 1 $ 2 $ 3 $ 3 $ 3
Common dividends declared $ 131 $ 135 $ 134 $ 135 $ 119
------ ------ ------ ------ ------
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
1998
Operating revenue $401,147 $358,320 $321,569 $137,304
Operating income $ 48,740 $ 32,523 $ 54,647 $ 21,452
Net income $ 35,950 $ 20,425 $ 47,956 $ 18,564
1997
Operating revenue $438,048 $396,049 $443,774 $400,032
Operating income $ 50,652 $ 30,028 $ 64,535 $ 45,637
Net income $ 37,945 $ 19,515 $ 52,019 $ 35,064
Per share data is not relevant because the Company's common
stock is wholly owned by New England Electric System.
A copy of New England Power Company's Annual Report on Form
10-K to the Securities and Exchange Commission for the year ended
December 31, 1998 will be available on or about April 1, 1999,
upon request at no charge by contacting: Merrill IR Edge, 33
Boston Post Road, Suite 270, Marlborough, MA 01752, Telephone:
508-786-1907, Fax: 508-786-1915,
E-mail: iredge@merrillcorp.com.