<PAGE>
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of June 20, 2000)
L. Joseph Callan
Former Executive Director for Operations,
Nuclear Regulatory Commission
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief
Financial Officer of National Grid USA
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of National Grid USA
Robert G. Powderly
Vice President of National Grid USA
Terry L. Schwennesen
Vice President of the Company
Richard P. Sergel
President and Chief Executive Officer of National Grid USA
Philip R. Sharp
Lecturer, Harvard University, John F. Kennedy School of Government
Officers
(As of June 20, 2000)
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief
Financial Officer of National Grid USA
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of National Grid USA
<PAGE>
Marc F. Mahoney
Vice President of the Company and of certain affiliates
John F. Malley
Vice President of the Company
James S. Robinson
Vice President of the Company
Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates
Terry L. Schwennesen
Vice President of the Company
Gregory A. Hale
Clerk of the Company and of certain affiliates, Assistant Secretary
or Assistant Clerk of certain affiliates and 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 Vice
President and Treasurer of National Grid USA
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates,
Secretary or Clerk of certain affiliates and Assistant Secretary of
an affiliate
Patricia C. Easterly
Assistant Treasurer of the Company and Treasurer of an affiliate
Nancy B. Kellogg
Assistant Treasurer of the Company and of certain affiliates
Kwong O. Nuey
Controller of the Company and of certain affiliates
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, Fleet National Bank, 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.
<PAGE>
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of June 20, 2000)
L. Joseph Callan
Former Executive Director for Operations,
Nuclear Regulatory Commission
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief
Financial Officer of National Grid USA
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of National Grid USA
Robert G. Powderly
Vice President of National Grid USA
Terry L. Schwennesen
Vice President of the Company
Richard P. Sergel
President and Chief Executive Officer of National Grid USA
Philip R. Sharp
Lecturer, Harvard University, John F. Kennedy School of Government
Officers
(As of June 20, 2000)
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief
Financial Officer of National Grid USA
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of National Grid USA
Marc F. Mahoney
Vice President of the Company and of certain affiliates
John F. Malley
Vice President of the Company
James S. Robinson
Vice President of the Company
Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates
Terry L. Schwennesen
Vice President of the Company
Gregory A. Hale
Clerk of the Company and of certain affiliates, Assistant Secretary
or Assistant Clerk of certain affiliates and 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 Vice
President and Treasurer of National Grid USA
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates,
Secretary or Clerk of certain affiliates and Assistant Secretary of
an affiliate
Patricia C. Easterly
Assistant Treasurer of the Company and Treasurer of an affiliate
Nancy B. Kellogg
Assistant Treasurer of the Company and of certain affiliates
Kwong O. Nuey
Controller of the Company and of certain affiliates
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, Fleet National Bank, 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.
<PAGE>
New England Power Company
New England Power Company, (the Company) a wholly owned
subsidiary of National Grid USA (formerly New England Electric
System), 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. The Company's transmission business
will also do business under the name of National Grid Transmission
USA.
<PAGE>
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 National Grid USA (formerly New England Electric System), at
March 31, 2000 and December 31, 1999 and 1998, and the results of
its operations and its cash flows for the three months ended March
31, 2000 and each of the three years in the period ended December
31, 1999 in conformity with accounting principles generally
accepted in the United States. 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 auditing standards generally accepted in the United States,
which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Boston, Massachusetts
June 20, 2000
<PAGE>
New England Power Company
Financial Review
Merger with National Grid
On March 22, 2000, the merger of New England Electric System
(NEES) and The National Grid Group plc (National Grid) was
completed, with NEES (renamed National Grid USA) becoming a wholly
owned subsidiary of National Grid. National Grid paid a total of $4
billion, including $3.2 billion in cash paid to shareholders
pursuant to the merger agreement, $642 million for National Grid
USA's merger with Eastern Utilities Associates (EUA) (discussed
below), an additional capital contribution of $141 million, and
merger related expenses of $37 million. New England Power Company
(the Company) will maintain its existing name and will remain a
wholly owned subsidiary of National Grid USA.
The merger of National Grid USA and National Grid has been
accounted for as an acquisition of National Grid USA by National
Grid using the purchase method of accounting. The application of
the purchase method, including the recognition of goodwill, is
being pushed down and reflected on the financial statements of the
National Grid USA subsidiaries, including the Company. Total
goodwill amounted to $1.7 billion, of which the Company was
allocated $334.1 million at the date of the merger. This amount was
determined pursuant to an independent study conducted by a third
party and is being amortized over 20 years. The annual amortization
expense will amount to approximately $16.7 million.
The purchase accounting method requires the Company to revalue
its assets and liabilities at their fair value. This revaluation
resulted in a net debit adjustment to the Company's pension and
postretirement benefit plans in the amount of approximately $61
million, with a corresponding offsetting credit to a regulatory
liability account (see Note E of the Notes to Financial
Statements).
Merger with EUA
The merger between the National Grid USA and EUA parent
companies was completed on April 19, 2000, with EUA merging into
National Grid USA. The impacts of this transaction will be
reflected in subsequent reporting periods. The price paid by
National Grid USA was $642 million, or $31.459 per share. On May 1,
2000, Montaup Electric Company (Montaup), formerly a subsidiary of
EUA, merged into the Company.
The merger of EUA and National Grid USA is being accounted for
by the purchase method, the application of which, including the
recognition of goodwill, is being pushed down and reflected on the
financial statements of the National Grid USA subsidiaries,
including the Company. Total goodwill amounted to $388 million, of
which the Company was allocated $7.7 million. This amount was
determined pursuant to an independent study conducted by a third
party and is being amortized over 20 years. The annual amortization
expense will amount to approximately $0.4 million.
Industry Restructuring
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
granted choice of power supplier in 1998. To facilitate the
implementation of customer choice, the settlement agreements
provided for the amendment of the Company's all-requirements
contracts with its affiliated distribution companies. The Company's
all-requirements contracts with some unaffiliated customers were
terminated pursuant to settlement agreements or tariff provisions.
However, the Company remains obligated to provide transition power
supply service at fixed rates to some new customer load in Rhode
Island. In addition, as a result of the Settlement Agreements, the
Company and its affiliate, The Narragansett Electric Company
(Narragansett Electric), sold substantially all of their nonnuclear
generating business (divestiture) in September 1998. As part of the
divestiture plan, New England Energy Incorporated sold its oil and
gas properties in 1998, resulting in a loss of approximately $120
million, before tax, which was reimbursed by the Company. The
Company also agreed to endeavor to sell its minority interest in
three nuclear power plants and a 60 megawatt interest in a fossil-
fueled generating station in Maine.
In conjunction with the divestiture, the Company transferred to
the buyer of its nonnuclear generating business (the buyer) its
entitlement to power procured under several 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
at March 31, 2000 of approximately $687 million) toward the
above-market cost of those contracts. The Company has recorded a
corresponding current liability of $75 million, and a long-term
liability of $612 million. For certain contracts which have been
formally assigned to the buyer, the Company has made lump sum
payments equivalent to the present value of the monthly fixed
payment obligations of those contracts (approximately $345 million
at date of purchase, which corresponds to approximately $290
million at March 31, 2000), which were separate from the $687
million figure referred to above.
<PAGE>
Under the Settlement Agreements, the Company is permitted to
recover costs associated with its former generating investments and
related contractual commitments that were not recovered through the
sale of those investments (stranded costs). These costs are
recovered from the Company's wholesale customers with which it has
settlement agreements through contract termination charges (CTC)
which the affiliated wholesale customers recover through delivery
charges to distribution customers. The recovery of the Company's
stranded costs is divided into several categories. The Company's
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 related to the
above-market cost of purchased power contracts and nuclear
decommissioning costs are recovered through the CTC as such costs
are actually incurred. 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. 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. For further information on the potential
sale of the Vermont Yankee and Millstone 3 nuclear generating
units, refer to the "Nuclear Units" section below.
Accounting Implications
Because electric utility rates have historically been based on
a utility's costs, electric utilities are subject to certain
accounting standards that are not applicable to other business
enterprises in general. The Company applies the provisions of
Statement of Financial Accounting Standards No. 71, Accounting for
the Effects of Certain Types of Regulation (FAS 71), which requires
regulated entities, in appropriate circumstances, to establish
regulatory assets or liabilities, and thereby defer the income
statement impact of certain charges or revenues because they are
expected to be collected or refunded through future customer
billings. In 1997, the Emerging Issues Task Force of the Financial
Accounting Standards Board concluded that a utility that had
received approval to recover stranded costs through regulated rates
would be permitted to continue to apply FAS 71 to the recovery of
stranded costs.
<PAGE>
As discussed above, the Company received authorization from the
Federal Energy Regulatory Commission (FERC) to recover through CTCs
substantially all of the costs associated with its former
generating business not recovered through the divestiture.
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. 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.
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. At March 31, 2000, this amounted to approximately
$1.3 billion, including $1.0 billion related to the above-market
costs of purchased power contracts, $0.3 billion related to accrued
Yankee nuclear plant costs, and other net CTC-related regulatory
assets.
Impact of Mergers on Transmission and CTC Rates
Under a rate consolidation plan accepted by the FERC in
September 1999, upon National Grid USA's acquisition of EUA and the
merger of Montaup, EUA's transmission company, into the Company on
May 1, 2000, the combined company charges a single system open
access transmission tariff based upon its total transmission costs.
Montaup will charge a separate CTC rate until a rate for the
combined company is established.
Change of Fiscal Year
National Grid USA and its subsidiaries, including the Company,
changed their fiscal year from a calendar year ending December 31
to a fiscal year ending March 31. The Company made this change in
order to align its fiscal year with that of National Grid USA's
parent company, National Grid. The Company's first new full fiscal
year began on April 1, 2000 and will end on March 31, 2001. The
Company has reported results of operations for the three month
transitional period ended March 31, 2000, the three month period
ended March 31, 1999, and the years ended December 31, 1999,
December 31, 1998, and December 31, 1997. The Company has also
reported balance sheets as of March 31, 2000, December 31, 1999,
and December 31, 1998, and statements of cash flows for the three
month periods ended March 31, 2000, and March 31, 1999, and the
years ended December 31, 1999, December 31, 1998, and December 31,
1997.
<PAGE>
Overview of Financial Results
Net income for the three months ended March 31, 2000 decreased
$6 million compared with the same period in 1999 primarily due to
the elimination of certain liabilities related to open access
transmission tariffs of approximately $5 million in the first
quarter of 1999.
Net income for the year ended December 31, 1999 decreased $52
million compared with the same period in 1998 as a result of the
continuing impacts of the divestiture and the restructuring of the
utility business. Partially offsetting the decrease was the
recovery of stranded cost mitigation incentives of approximately
$25 million in 1999 compared with $10 million in 1998, as well as
increased transmission revenues of approximately $13 million due to
the elimination of certain liabilities related to open access
transmission tariffs.
Net income for the year ended December 31, 1998 decreased $22
million compared with 1997. This decrease was also primarily due to
the divestiture and reduced revenues as a result of industry
restructuring.
Operating Revenue
Operating revenue for the three months ended March 31, 2000
decreased $33 million compared with the same period in 1999,
largely due to CTC revenue of approximately $21 million from
Narragansett Electric in 1999 related to its access charge
overcollections. This payment reduced Narragansett Electric's
future CTC obligations. This additional revenue in 1999 had a
corresponding impact to the amortization of CTC, discussed in
"Operating Expenses" below. The decrease is also due to the
elimination of certain liabilities related to open access
transmission tariffs of $5 million in 1999. This decrease is
partially offset by the impacts of increased standard offer rates
effective January 1, 2000 and increased kilowatthour sales in the
three months ended March 31, 2000 compared with the same period in
1999.
Operating revenue for the year ended December 31, 1999
decreased $622 million compared with 1998 due to the divestiture
and reduced CTC charges. Partially offsetting this decrease was an
increase in transmission revenues associated with the elimination
of certain liabilities related to open access transmission tariffs
discussed above.
<PAGE>
Operating revenue for the year ended December 31, 1998
decreased $460 million compared with 1997. This decrease was also
the result of the divestiture and reduced revenues due to industry
restructuring, partially offset by the recovery of stranded
investments and increased transmission billings.
Operating Expenses
Operating expenses for the three months ended March 31, 2000
decreased $27 million compared with the same period in 1999.
The increase in fuel and purchased power expense of
approximately $5 million reflects increased purchased power
expenses for standard offer requirements and increased
kilowatthours purchased.
Other operating expenses in the three months ended March 31,
2000 decreased approximately $3 million compared with the same
period in 1999 due to the reimbursement of start-up costs from 1999
of the Independent System Operator - New England (ISO New England)
in 2000. Maintenance expenses decreased approximately $1 million as
a result of reduced expenses at the partially owned Millstone 3 and
Seabrook 1 nuclear generating facilities.
Depreciation and amortization expenses in the three months
ended March 31, 2000 decreased $23 million compared with the same
period in 1999. This decrease is due to additional CTC amortization
in 1999 related to the additional payment of approximately $21
million by Narragansett Electric to the Company, discussed above.
Operating expenses for the year ended December 31, 1999
decreased $543 million compared with 1998. The divestiture reduced
all categories of operating expenses in 1999, with the exception of
depreciation and amortization expense.
The decrease in fuel expense and purchased power costs
reflected the divestiture and the assumption of the Company's
obligations under most of its previously existing purchased power
contracts by the buyer of its nonnuclear generating business. The
Company remains obligated to pay predetermined amounts to the buyer
related to the above-market cost of those contracts. In addition,
the Company also remains obligated under purchased power contracts
with the four Yankee nuclear power companies, the costs of which
decreased $8 million in 1999, reflecting reduced costs from Maine
Yankee and Connecticut Yankee, net of increased costs of a 1999
refueling outage at Vermont Yankee.
<PAGE>
In addition to the impact of the divestiture, which reduced
nonnuclear generation operation and maintenance expenses by $71
million, the decrease in other operation and maintenance expenses
reflected reduced general and administrative costs due primarily to
workforce reductions and reduced charges from New England Power
Service Company following the divestiture. In addition,
transmission costs decreased $16 million in 1999 due to the
assumption of transmission support agreements by the buyer and
reduced ISO New England start-up costs. These decreases were
partially offset by increased costs of $3 million associated with
the partially owned Millstone 3 and Seabrook 1 nuclear generating
facilities which experienced refueling outages in the second
quarter of 1999.
Operating expenses for the year ended December 31, 1998
decreased $426 million compared with 1997 as a result of the
divestiture, reduced charges of $22 million from Maine Yankee,
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
also decreased due to lower charges related to postretirement
benefits other than pensions (PBOPs), reflecting the completion of
the accelerated amortization of the Company's deferred PBOP costs
in 1997 under the terms of a 1995 rate agreement.
Depreciation and amortization expenses increased $3 million
and $2 million in the years ended December 31, 1999, and 1998,
respectively, due to the recovery and amortization of generation-
related stranded costs in those years being greater than the
depreciation and amortization of generation-related plant in the
prior years. The increase was also due to new transmission plant
expenditures.
Interest Expense and Other Income
The increase in interest expense for the three months ended
March 31, 2000 is primarily due to increased interest rates on
variable rate long-term debt and interest on short-term debt
borrowings not present in 1999.
The increase in other income for the three months ended March
31, 2000 is primarily due to decreased expenses related to employee
incentive plans from workforce reductions following the
divestiture, partially offset by merger related expenses in 2000.
The decrease in interest expense in the years ended December
31, 1999 and 1998 was principally due to reduced long-term and
short-term debt as a result of the divestiture.
<PAGE>
The increase in other income in the years ended December 31,
1999 and 1998 was due primarily to increased interest income
resulting from the reinvestment of the proceeds from the
divestiture. In 1999, this was partially offset by reduced equity
income from nuclear power companies as a result of reductions in
the rates of return for two of these companies.
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, including
Montaup's portion effective with the EUA merger, are as follows:
<TABLE>
<CAPTION>
Future
The Company's Estimated
Investment Billings to
as of 3/31/00 Date the Company
Unit % $(millions) Retired $(millions)
-----------------------------------------------------------------
<S> <C> <C> <C> <C>
Yankee Atomic 30 4 Feb 1992 4
Connecticut Yankee 15 16 Dec 1996 60
Maine Yankee 20 15 Aug 1997 124
Future
Montaup's Estimated
Investment Billings
as of 3/31/00 Date to Montaup
Unit % $(millions) Retired $(millions)
-----------------------------------------------------------------
Yankee Atomic 4.5 1 Feb 1992 1
Connecticut Yankee 4.5 5 Dec 1996 19
Maine Yankee 4.0 3 Aug 1997 26
</TABLE>
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, including a return on that investment, as
<PAGE>
well as unfunded nuclear decommissioning costs and other costs.
Maine Yankee recovers its costs, including a return, in accordance
with settlement agreements approved by the FERC in May 1999.
Connecticut Yankee filed a similar request with the FERC, to which
several parties intervened in opposition arguing that Connecticut
Yankee was entitled to recover only those costs directly related to
decommissioning, but should not recover any remaining unamortized
investment or return on equity. 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 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
(including Montaup's) of the loss of the return component would
total approximately $16 million to $20 million before taxes for the
entire recovery period. In April 2000, a settlement was reached
among Connecticut Yankee, the Connecticut Department of Public
Utility Control (CDPUC), the Office of Consumer Counsel (OCC), and
the Connecticut Municipal Electric Cooperative. The settlement
resolves all issues in the case, except the OCC has reserved its
right to appeal recovery of any costs other than decommissioning.
Billings will be reduced prospectively. There will be no refund of
any amounts collected up to the effective date of the settlement.
Connecticut Yankee had reserved for potential refunds and will be
reversing that reserve. Prospectively, Connecticut Yankee has
agreed to reduce annual collections for decommissioning through the
use of its pre-1983 spent fuel trust funds and to limit its return
on equity to 6 percent. In addition, Connecticut Yankee has pursued
litigation against the Department of Energy to assume financial
responsibility for storage of spent nuclear fuel and has agreed to
pass to ratepayers any recovery after litigation expenses. The
settlement is pending before the FERC.
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.
Under the provisions of the Settlement Agreements, the Company
recovers all costs, including shutdown costs, that the FERC allows
these Yankee companies to bill to the Company.
<PAGE>
Maine Yankee had hired Stone & Webster, Inc., an engineering,
construction, and consulting company, as the principal contractor
to decommission the unit. Stone & Webster recently announced plans
to file for Chapter 11 bankruptcy protection due to financial
difficulties. Stone & Webster also announced that it has negotiated
the sale of substantially all of its assets. In May 2000, Maine
Yankee terminated its long-term contract with Stone & Webster and
negotiated an arrangement with Stone & Webster to continue work
until June 2000. On June 2, 2000, Stone & Webster filed for Chapter
11 bankruptcy protection. Maine Yankee is considering its options
for decommissioning the unit beyond June 30, 2000. At this time,
the Company is unable to determine the potential impact, if any, of
this development.
Operating Nuclear Units
The Company has minority interests in three operating nuclear
generating units which the Company is engaged in efforts to divest:
Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties
regarding the future of nuclear generating stations, particularly
older units, such as Vermont Yankee, have increased in recent years
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 Nuclear Regulatory Commission
(NRC) scrutiny. The Company performs periodic economic viability
reviews of operating nuclear units in which it holds ownership
interests. 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.
Vermont Yankee
The following tables summarize the interests of the Company,
and of Montaup (effective with the EUA merger), in the Vermont
Yankee Nuclear Power Corporation as of March 31, 2000:
<PAGE>
<TABLE>
<CAPTION>
The Company's Interest
(millions of dollars)
----------------------------------------------
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning Fund License
Interest (%) Investment Assets Cost (in 1999$) Balance Expiration
------------ ---------- ------ --------------- ------- ----------
<S> <C> <C> <C> <C> <C>
20 $11 $33 $86 $43 2012
Montaup's Interest
(millions of dollars)
----------------------------------------------
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning Fund License
Interest (%) Investment Assets Cost (in 1999$) Balance Expiration
------------ ---------- ------ --------------- ------- ----------
2.5 $1 $4 $11 $5 2012
</TABLE>
In November 1999, the Vermont Yankee Nuclear Power Corporation
entered into an agreement with AmerGen Energy Company (AmerGen), a
joint venture between PECO Energy and British Energy, to sell the
assets of Vermont Yankee. Under the terms of the agreement, after
a Vermont Yankee contribution toward the plant's decommissioning
trust fund, AmerGen will take over the fund and assume
responsibility for the actual cost of decommissioning the plant.
The agreement also requires the existing power purchasers
(including the Company) to continue to purchase the output of the
plant or to buy out of the purchased power obligation. In November
1999, the Company signed an agreement to buy out of its obligation,
requiring future payments which will be recovered through the
Company's CTC. The Company has recorded an accrued liability and an
offsetting regulatory asset of $80 million for its share of future
liabilities related to Vermont Yankee, including the purchased
power contract termination payment obligation, but excluding
interest and a return allowance. The proposed sale is contingent
upon regulatory approvals by the NRC, the Securities and Exchange
Commission (SEC), under the Public Utility Holding Company Act of
1935 (1935 Act), and the Vermont Public Service Board (VPSB), among
others. The Vermont Public Service Department has identified
several issues that must be resolved to its satisfaction for it to
support the VPSB's approval of the sale.
<PAGE>
Millstone 3
In August 1997, the Company sued Northeast Utilities (NU) in
Massachusetts Superior Court for damages, alleging that NU engaged
in tortious conduct that caused the shutdown of Millstone 3, which
is operated by a subsidiary of NU. The Company's claim for damages
included 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.
In August 1997, the Company also sent a demand for arbitration
to Connecticut Light & Power Company and Western Massachusetts
Electric Company, both subsidiaries of NU, seeking damages for
breach of obligations under an agreement with the Company and
others regarding the operation and ownership of Millstone 3. In
July 1998, Millstone 3 returned to full operation after being shut
down for more than two years.
In November 1999, the Company executed an agreement which
settled the litigation and arbitration. Under the settlement
agreement, the NU companies paid the Company $23.7 million and paid
Montaup $7.8 million. The settlement also includes an agreement by
NU to include the Company's and Montaup's share of Millstone 3 in
an auction of NU's share of the unit. Upon the closing of the sale,
NU will pay the Company and Montaup a combined total of $25
million, regardless of the actual sale price, and reimburse the
Company and Montaup for any capital expenditures in excess of pre-
budgeted levels incurred after October 1999. The Company and
Montaup will also be reimbursed for fuel procurement expenditures
which increase net nuclear fuel account balances above current
balances. The settlement also requires NU to indemnify the Company
and Montaup and assume any residual liabilities resulting from the
sale, including any requirements that the sellers continue to
purchase output from the unit. In addition, the settlement requires
NU to pay the Company and Montaup an additional combined total of
$1 million per month for every month beyond April 1, 2001 that the
closing does not occur. The auction process is being conducted by
the CDPUC and is ongoing. Amounts received pursuant to a sale will,
after reimbursement of the Company's transaction costs and net
investment in Millstone 3, be credited to customers.
<PAGE>
Seabrook 1
As part of its restructuring settlement with the State of New
Hampshire, Public Service Company of New Hampshire (PSNH), through
its affiliate, North Atlantic Energy Corporation (NAEC), has
committed to seek New Hampshire Public Utilities Commission (NHPUC)
approval of a definitive plan to sell, via public auction, its
share of Seabrook 1, with such sale to occur no later than December
31, 2003. NAEC is the majority owner of the plant with a 35.98
percent interest and is also the plant operator. As part of its
settlement, PSNH has also agreed to make all reasonable efforts to
bundle its interests with those of other owners (including the
Company) seeking to sell their interests. This would allow for an
auction of a majority interest. The NHPUC granted conditional
approval of the settlement on April 19, 2000. The New Hampshire
legislature approved the necessary legislation on May 31, 2000.
Final resolution by the NHPUC approving the settlement in
compliance with the legislation is expected this summer.
Year 2000 Disclosure
In 1999, National Grid USA and its subsidiaries completed
their remediation of the potential information systems (computer)
problem resulting from the fact that many software applications and
operational programs written in the past might not have recognized
calendar dates associated with the year 2000 (Y2K). As a result of
their remediation efforts, National Grid USA and its subsidiaries
have experienced no significant disruptions in any of their
enterprise or operational computer systems.
National Grid USA's and its subsidiaries' costs of making the
necessary Y2K modifications were approximately $28 million. In
addition, National Grid USA and its subsidiaries spent
approximately $9 million (of which approximately $7 million has
been capitalized) related to the replacement of the human resources
and payroll system, in part due to the Y2K issue.
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 March 31, 2000, the Company's variable
rate long-term debt had a carrying value and fair value of
approximately $372 million and maturity dates greater than five
years. The weighted average variable interest rate for the three
months ended March 31, 2000, was 3.75 percent.
<PAGE>
As discussed in the "Industry Restructuring" section, the
Company remains obligated to provide transition power supply
service at fixed rates to some new customer load in Rhode Island.
The Company meets this obligation by periodically procuring the
necessary power supply at market prices. The Company cannot predict
whether the resulting revenues will be sufficient to cover the
costs to procure such power over the term of the obligation. In the
short term, it appears that due to current high market prices, it
is probable the Company will incur losses this summer. At this
point, management cannot reasonably estimate the level of such
losses.
Utility Plant Expenditures and Financing
Cash expenditures for the Company for utility plant totaled
$12 million for the three months ended March 31, 2000 and were
primarily transmission-related. The funds necessary for utility
plant expenditures during the period were primarily provided by
internal funds. Cash expenditures for fiscal year 2001 for the
Company and Montaup are estimated to be approximately $45 million,
principally related to transmission functions. Internally generated
funds are expected to fully cover capital expenditures in fiscal
year 2001.
On February 8, 1999, the Company repurchased 130,000 shares of
its common stock from NEES for $18 million. Approximately $7
million of the repurchase price was charged to retained earnings.
Dividends payable at March 31, 2000, in the amount of $256
million were paid on June 27, 2000.
The Company has regulatory approval to issue up to $375
million of short-term debt. In 1999, the Company issued $39 million
of short-term tax-exempt debt. This debt remains outstanding as of
March 31, 2000. The Company plans to seek the necessary regulatory
approvals in 2000 which would allow the $39 million of variable
rate debt to remain outstanding through 2015. This would result in
classifying the debt as long-term rather than short-term.
<PAGE>
At March 31, 2000, the Company had lines of credit and standby
bond purchase facilities with banks totaling $460 million which are
available to provide liquidity support for $410 million of the
Company's short-term and long-term bonds in tax-exempt commercial
paper mode (including the $39 million discussed above), and for
other corporate purposes. There were no borrowings under these
lines of credit at March 31, 2000.
<PAGE>
<TABLE>
<CAPTION>
New England Power Company
Statements of Income
3 Months ended Year ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
-------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue, principally
from affiliates $134,564$167,177 $ 596,341$1,218,340 $1,677,903
Operating expenses:
Fuel for generation 3,548 3,058 12,803 223,828 372,734
Purchased electric energy:
Contract termination and nuclear
unit shutdown charges 47,405 46,873 187,777 97,469 43,876
Other 14,682 11,111 56,731 302,367 483,771
Other operation 15,760 19,210 70,936 155,065 241,506
Maintenance 4,320 5,766 28,536 60,239 89,820
Depreciation and amortization 17,328 40,367 103,080 99,924 98,024
Taxes, other than income taxes 5,561 5,634 20,282 48,492 67,311
Income taxes 9,641 13,100 37,633 73,594 90,009
---------------- --------- ---------- ----------
Total operating expenses 118,245 145,119 517,778 1,060,9781,487,051
---------------- --------- ---------- ----------
Operating income 16,319 22,058 78,563 157,362 190,852
Other income:
Allowance for equity funds
used during construction (393) 588 1,958 633 -
Equity in income of nuclear
power companies 862 515 2,939 5,284 5,189
Other income (expense), net 1,850 434 2,087 118 (3,404)
---------------- --------- ---------- ----------
Operating and other income 18,638 23,595 85,547 163,397 192,637
---------------- --------- ---------- ----------
Interest:
Interest on long-term debt 3,749 3,143 14,052 30,775 42,277
Other interest 853 240 1,003 10,688 7,055
Allowance for borrowed funds
used during construction (426) (133) (522) (961) (1,238)
---------------- --------- ---------- ----------
Total interest 4,176 3,250 14,533 40,502 48,094
---------------- --------- ---------- ----------
Net income $ 14,462$ 20,345 $ 71,014 $ 122,895 $ 144,543
================ ========= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Statements of Retained Earnings 3 Months ended Year ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
-------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained earnings at beginning
of period $ 27,287$204,603 $ 204,603$ 407,630 $ 400,610
Net income 14,462 20,345 71,014 122,895 144,543
Dividends declared on cumulative
preferred stock (24) (24) (94) (1,230) (2,075)
Dividends declared on common stock,
$6.66, $-0-, $66.69, $20.25, and $21.00
per share, respectively (24,098) -(241,415) (130,610)(135,448)
Premium on redemption of
preferred stock - - 264 (264) -
Repurchase of common stock - (7,085) (7,085) (193,818) -
Purchase accounting adjustment (16,212) - - - -
---------------- --------- ---------- ----------
Retained earnings at end of period$ 1,415$217,839 $ 27,287 $ 204,603 $ 407,630
================ ========= ========== ==========
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Power Company
Balance Sheets
At March 31, At December 31,
(In thousands) 2000 1999 1998
--------------------------------------------------------------------------------------
<S> <C> <C> <C>
Assets
Utility plant, at original cost $1,318,026 $1,312,384 $1,262,461
Less accumulated provisions
for depreciation and amortization 854,309 849,694 837,637
---------- ---------- ----------
463,717 462,690 424,824
Construction work in progress 35,730 30,063 33,289
---------- ---------- ----------
Net utility plant 499,447 492,753 458,113
---------- ---------- ----------
Total goodwill, net of amortization 333,771 - -
Investments:
Nuclear power companies,
at equity (Note D-1) 45,966 46,233 48,538
Decommissioning trust funds (Note D-2) 36,279 36,279 31,281
Nonutility property and other investments 7,490 7,248 8,302
---------- ---------- ----------
Total investments 89,735 89,760 88,121
---------- ---------- ----------
Current assets:
Cash and temporary cash investments
(including $37,820, $59,039, and
$109,911 with affiliates) 226,921 204,344 179,413
Accounts receivable:
Affiliated companies 72,780 73,444 107,878
Others 48,139 44,301 32,573
Fuel, materials, and supplies,
at average cost 10,345 9,471 9,220
Prepaid and other current assets 25,377 39,315 21,569
Regulatory asset purchased power obligations 74,988 73,369 128,931
---------- ---------- ----------
Total current assets 458,550 444,244 479,584
---------- ---------- ----------
Regulatory assets (Note C) 1,210,800 1,272,463 1,383,631
Deferred charges and other assets 37,271 3,445 5,339
---------- ---------- ----------
$2,629,574 $2,302,665 $2,414,788
========== ========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Capitalization and Liabilities
<S> <C> <C> <C>
Capitalization:
Common stock, par value $20 per share,
Authorized - 6,449,896 shares
Outstanding - 3,619,896, 3,619,896,
and 3,749,896 shares $ 72,398 $ 72,398 $ 74,998
Premium on capital stock - 48,623 50,371
Other paid-in capital (Note J) 582,983 183,937 190,852
Retained earnings 1,415 27,287 204,603
Unrealized gain on securities, net - 91 72
---------- ---------- ----------
Total common equity 656,796 332,336 520,896
Cumulative preferred stock, par value
$100 per share (Note H) 1,567 1,567 1,567
Long-term debt 371,773 371,771 371,765
---------- ---------- ----------
Total capitalization 1,030,136 705,674 894,228
---------- ---------- ----------
Current liabilities:
Short-term debt 38,500 38,500 -
Accounts payable (including $26,993,
$25,620, and $119,657 to affiliates) 51,584 63,212 162,360
Accrued liabilities:
Taxes 2,394 3,889 15,009
Interest 1,900 3,378 2,440
Purchased power contract obligations 74,988 73,369 128,931
Other accrued expenses (Note G) 10,879 15,693 20,086
Dividends payable 256,487 232,365 24
---------- ---------- ----------
Total current liabilities 436,732 430,406 328,850
---------- ---------- ----------
Deferred federal and state income taxes 176,351 179,686 165,115
Unamortized investment tax credits 16,733 19,060 30,870
Accrued Yankee nuclear plant
costs (Note D-2) 268,855 277,932 242,138
Purchased power obligations 611,802 630,368 703,737
Other reserves and deferred credits 88,965 59,539 49,850
Commitments and contingencies (Note D)
---------- ---------- ----------
$2,629,574 $2,302,665 $2,414,788
========== ========== ==========
The accompanying notes are an integral part of these financial statements.
</TABLE>
<TABLE>
<CAPTION>
New England Power Company
Statements of Cash Flows
3 Months ended Year ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
--------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating activities:
Net income $ 14,462$ 20,345$ 71,014 $ 122,895 $ 144,543
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 19,165 42,170 108,789 104,331 101,186
Deferred income taxes and
investment tax credits, net (2,908) 5,726 14,111 (226,722)(12,728)
Allowance for funds used
during construction (33) (720) (2,480) (1,594) (1,238)
Reimbursement to New England Energy
Incorporated of loss on sale of oil
and gas properties - - - (120,900) -
Buyout of purchased power contracts - - (3,472) (326,590) -
Decrease (increase) in
accounts receivable (3,174) 37,890 22,706 130,914 (25,128)
Decrease (increase) in fuel,
materials, and supplies (874) 648 (251) (10,270) 11,217
Decrease (increase) in regulatory asset
purchased power obligations (1,619) 19,956 55,562 (128,931) -
Decrease (increase) in prepaid
and other current assets 13,938 6,154 (17,746) (8,778) 7,213
Increase (decrease) in
accounts payable (11,628)(81,950)(99,148) (31,761)(18,105)
Increase (decrease) in current
purchased power contract payable 1,619 (19,956)(55,562) 128,931 -
Increase (decrease) in other
current liabilities (7,787)(11,147)(14,575) 5,037 (1,905)
Other, net 13,577 (709) (3,995) (49,611) 19,919
------------------------ ----------- ---------
Net cash provided by (used in)
operating activities $ 34,738$ 18,407$ 74,953 $ (413,049) $ 224,974
------------------------ ----------- ---------
Investing activities:
Proceeds from sale of
generating assets $ -$ -$ - $ 1,688,863 $ -
Plant expenditures, excluding allowance
for funds used during construction (11,890) $(13,739) (56,887)(64,446) (69,863)
Other investing activities (271) (20) (4,411) (5,474) (4,040)
------------------------ ----------- ---------
Net cash provided by (used in)
investing activities $(12,161) $(13,759) $(61,298) $ 1,618,943 $ (73,903)
------------------------ ----------- ---------
Financing activities:
Capital contribution from parent $ -$ -$ - $ 34,881 $ -
Dividends paid on common stock - - (9,050) (166,084) (127,386)
Dividends paid on preferred stock - (24) (118) (1,206) (2,075)
Changes in short-term debt - - 38,500 (111,250) 17,650
Long-term debt - retirements - - - (328,000)(38,500)
Repurchase of common shares - (18,056)(18,056) (417,960) -
Preferred stock - retirements - - - (38,505) -
Premium on reacquisition
of long-term debt - - - - (2,163)
------------------------ ----------- ---------
Net cash provided by (used in)
financing activities $ -$(18,080) $ 11,276 $(1,028,124) $(152,474)
------------------------ ----------- ---------
Net increase (decrease) in
cash and cash equivalents $ 22,577$(13,432) $ 24,931 $ 177,770 $ (1,403)
Cash and cash equivalents
at beginning of period 204,344 179,413 179,413 1,643 3,046
------------------------ ----------- ---------
Cash and cash equivalents
at end of period $226,921$165,981$204,344 $ 179,413 $ 1,643
======================== =========== =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Supplementary Information:
Interest paid less amounts capitalized $ 5,322$ 2,042 $ 11,849 $ 43,419 $ 46,033
------------------------ ----------- ---------
Federal and state income taxes paid$ (15) $ 11,321 $ 55,134 $ 282,076 $ 109,109
------------------------ ----------- ---------
Dividends received from
investments at equity $ 1,129$ 1,730$ 5,243 $ 6,571 $ 3,267
------------------------ ----------- ---------
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
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 National Grid USA (formerly 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 (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, Nantucket
Electric Company, and The Narragansett Electric Company (Narragansett
Electric). In addition, the Company also owns minority interests in two
joint owned nuclear generating units as well as minority equity
interests in four nuclear generating companies (Yankees), three of which
own generating facilities that are permanently shut down. The output
from these generating facilities is sold to third parties.
2. Change of Fiscal Year:
National Grid USA and its subsidiaries, including the Company, changed
their fiscal year from a calendar year ending December 31 to a fiscal
year ending March 31. The Company made this change in order to align its
fiscal year with that of National Grid USA's parent company, The
National Grid Group plc (National Grid). The Company's first new full
fiscal year began on April 1, 2000 and will end on March 31, 2001. The
Company has reported results of operations for the three month
transitional period ended March 31, 2000, the three month period ended
March 31, 1999, and the years ended December 31, 1999, December 31,
1998, and December 31, 1997. The Company has also reported balance
sheets as of March 31, 2000,
<PAGE>
December 31, 1999, and December 31, 1998, and statements of cash flows
for the three month periods ended March 31, 2000, and March 31, 1999,
and the years ended December 31, 1999, December 31, 1998, and December
31, 1997.
3. 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. In
addition, certain presentation adjustments have been made to conform
prior years with the current presentation.
4. 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. The composite AFDC rates were 3.7
percent for the three month period ended March 31, 2000, 8.1 percent for
the three month period ended March 31, 1999, and 7.6 percent, 6.1
percent, and 5.9 percent for the years ended December 31, 1999, 1998,
and 1997, respectively.
<PAGE>
5. Depreciation and Amortization:
The depreciation and amortization expense included in the statements
of income is composed of the following:
<TABLE>
<CAPTION>
Three Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
--------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Depreciation - transmission related $ 3,269$ 3,440$ 13,222$12,553 $11,828
Depreciation - all other (15) 354 1,286 46,256 68,432
Nuclear decommissioning costs (Note D-2) 923 699 3,637 2,719 2,638
Amortization:
Seabrook 2 property losses - - - - 113
Millstone 3 additional amortization,
pursuant to 1995 rate settlement - - - 22,040 15,013
Regulatory assets covered by contract
termination charges (Note C) 12,785 35,874 84,935 16,356 -
Goodwill 366 - - - -
----------------------------- -------
Total depreciation and
amortization expense $17,328$40,367$103,080$99,924 $98,024
============================= =======
</TABLE>
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 for the three month
periods ended March 31, 2000, and March 31, 1999, and the years ended
December 31, 1999, 1998, and 1997. Amortization of Seabrook and
Millstone investments above normal depreciation accruals and
amortization of regulatory assets covered by contract termination
charges (CTC) was in accordance with rate settlement agreements.
The Company will amortize goodwill associated with the mergers of
National Grid and National Grid USA, and National Grid USA and Eastern
Utilities Associates (EUA) over a 20 year period on a straight line
basis.
<PAGE>
6. Cash:
The Company classifies short-term investments with a maturity at
purchase date of 90 days or less as cash.
Note B - Mergers with National Grid and EUA
Merger with National Grid
On March 22, 2000, the merger of NEES and National Grid was
completed, with NEES (renamed National Grid USA) becoming a wholly owned
subsidiary of National Grid. National Grid paid a total of $4 billion,
including $3.2 billion in cash paid to shareholders pursuant to the
merger agreement, $642 million for National Grid USA's merger with EUA
(discussed below), an additional capital contribution of $141 million,
and merger related expenses of $37 million. The Company will maintain
its existing name and will remain a wholly owned subsidiary of National
Grid USA.
The merger of National Grid USA and National Grid has been
accounted for as an acquisition of National Grid USA by National Grid
using the purchase method of accounting. The application of the purchase
method, including the recognition of goodwill, is being pushed down and
reflected on the financial statements of the National Grid USA
subsidiaries, including the Company. Total goodwill amounted to $1.7
billion, of which the Company was allocated $334.1 million at the date
of the merger. This amount was determined pursuant to an independent
study conducted by a third party and is being amortized over 20 years.
The annual amortization expense will amount to approximately $16.7
million.
The purchase accounting method requires the Company to revalue its
assets and liabilities at their fair value. This revaluation resulted
in a net debit adjustment to the Company's pension and postretirement
benefit plans in the amount of approximately $61 million, with a
corresponding offsetting credit to a regulatory liability account (see
Note E).
<PAGE>
Merger with EUA
The merger between the National Grid USA and EUA parent companies
was completed on April 19, 2000, with EUA merging into National Grid
USA. The impacts of this transaction will be reflected in subsequent
reporting periods. The price paid by National Grid USA was $642 million,
or $31.459 per share. On May 1, 2000, Montaup Electric Company
(Montaup), formerly a subsidiary of EUA, merged into the Company.
The merger of EUA and National Grid USA is being accounted for by
the purchase method, the application of which, including the recognition
of goodwill, is being pushed down and reflected on the financial
statements of the National Grid USA subsidiaries, including the Company.
Total goodwill amounted to $388 million, of which the Company was
allocated $7.7 million. This amount was determined pursuant to an
independent study conducted by a third party and is being amortized over
20 years. The annual amortization expense will amount to approximately
$0.4 million.
Note C - Industry Restructuring
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 granted
choice of power supplier in 1998. To facilitate the implementation of
customer choice, the Settlement Agreements provided for the amendment
of the Company's all-
requirements contracts with its affiliated distribution companies. The
Company's all-requirements contracts with some unaffiliated customers
were terminated pursuant to settlement agreements or tariff provisions.
However, the Company remains obligated to provide transition power
supply service at fixed rates to some new customer load in Rhode Island.
In addition, as a result of the Settlement Agreements, the Company and
its affiliate, Narragansett Electric, sold substantially all of their
nonnuclear generating business (divestiture) in September 1998. As part
of the divestiture plan, New England Energy Incorporated sold its oil
and gas properties in 1998, resulting in a loss of approximately $120
million, before tax, which was reimbursed by the Company. The Company
also agreed to endeavor to sell its minority interest in three nuclear
power plants and a 60 megawatt interest in a fossil-
fueled generating station in Maine.
<PAGE>
In conjunction with the divestiture, the Company transferred to the
buyer of its nonnuclear generating business (the buyer) its entitlement
to power procured under several 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 at March 31, 2000 of
approximately $687 million) toward the above-market cost of those
contracts. The Company has recorded a corresponding current liability
of $75 million, and a long-term liability of $612 million. For certain
contracts which have been formally assigned to the buyer, the Company
has made lump sum payments equivalent to the present value of the
monthly fixed payment obligations of those contracts (approximately $345
million at date of purchase, which corresponds to approximately $290
million at March 31, 2000), which were separate from the $687 million
figure referred to above.
Under the Settlement Agreements, the Company is permitted to
recover costs associated with its former generating investments and
related contractual commitments that were not recovered through the sale
of those investments (stranded costs). These costs are recovered from
the Company's wholesale customers with which it has settlement
agreements through CTCs which the affiliated wholesale customers recover
through delivery charges to distribution customers. The recovery of the
Company's stranded costs is divided into several categories. The
Company's 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 related to the above-market cost
of purchased power contracts and nuclear decommissioning costs are
recovered through the CTC as such costs are actually incurred. 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. 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. For further information on the
potential sale of the Vermont Yankee and Millstone 3 nuclear generating
units, refer to the "Nuclear Units" section below.
<PAGE>
Accounting Implications
Because electric utility rates have historically been based on a
utility's costs, electric utilities are subject to certain accounting
standards that are not applicable to other business enterprises in
general. The Company applies the provisions of Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types
of Regulation (FAS 71), which requires regulated entities, in
appropriate circumstances, to establish regulatory assets or
liabilities, and thereby defer the income statement impact of certain
charges or revenues because they are expected to be collected or
refunded through future customer billings. In 1997, the Emerging Issues
Task Force of the Financial Accounting Standards Board concluded that
a utility that had received approval to recover stranded costs through
regulated rates would be permitted to continue to apply FAS 71 to the
recovery of stranded costs.
As discussed above, the Company received authorization from the
FERC to recover through CTCs substantially all of the costs associated
with its former generating business not recovered through the
divestiture. 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. 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.
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. At March 31, 2000, this amounted to approximately $1.3
billion, including $1.0 billion related to the above-market costs of
purchased power contracts, $0.3 billion related to accrued Yankee
nuclear plant costs, and other net CTC-related regulatory assets.
<PAGE>
Note D - Commitments and Contingencies
1. Yankee Nuclear Power Companies
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 income statement. A summary
of combined results of operations, assets, and liabilities of the four
Yankees is as follows:
<TABLE>
<CAPTION>
Three Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue $ 81,225 $ 89,244$ 377,039$ 439,046 $ 660,742
=========== ====================== =========== ===========
Net income $ 5,310 $ 5,138$ 13,890 $ 23,218 $ 29,959
=========== ====================== =========== ===========
Company's equity in
net income $ 862 $ 515$ 2,939 $ 5,284 $ 5,189
=========== ====================== =========== ===========
Net plant 167,317 166,062 172,100 171,582 204,689
Other assets 2,520,887 2,798,948 2,631,750 2,810,613 3,100,589
Liabilities and debt (2,437,609) (2,707,749)(2,554,261) (2,723,454) (3,036,845)
----------- ---------------------- ----------- -----------
Net assets $ 250,595 $ 257,261$ 249,589 $ 258,741 $ 268,433
=========== ====================== =========== ===========
Company's equity in
net assets $ 45,966 $ 47,323$ 46,233 $ 48,538 $ 49,825
=========== ====================== =========== ===========
Company's purchased electric energy:
Vermont Yankee $ 7,761 $ 7,874$ 37,551 $ 35,108 $ 31,240
All other Yankees $ 9,324 $ 9,370$ 37,765 $ 48,543 $ 75,900
=========== ====================== =========== ===========
</TABLE>
<PAGE>
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, including Montaup's portion
effective with the EUA merger, are as follows:
<TABLE>
<CAPTION>
Future
The Company's Estimated
Investment Billings to
as of 3/31/00 Date the Company
Unit % $(millions) Retired $(millions)
-----------------------------------------------------------------
<S> <C> <C> <C> <C>
Yankee Atomic 30 4 Feb 1992 4
Connecticut Yankee 15 16 Dec 1996 60
Maine Yankee 20 15 Aug 1997 124
Future
Montaup's Estimated
Investment Billings
as of 3/31/00 Date to Montaup
Unit % $(millions) Retired $(millions)
-----------------------------------------------------------------
Yankee Atomic 4.5 1 Feb 1992 1
Connecticut Yankee 4.5 5 Dec 1996 19
Maine Yankee 4.0 3 Aug 1997 26
</TABLE>
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,
including a return on that investment, as well as unfunded nuclear
decommissioning costs and other costs. Maine Yankee recovers its costs,
including a return, in accordance
<PAGE>
with settlement agreements approved by the FERC in May 1999. Connecticut
Yankee filed a similar request with the FERC, to which several parties
intervened in opposition arguing that Connecticut Yankee was entitled
to recover only those costs directly related to decommissioning, but
should not recover any remaining unamortized investment or return on
equity. 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 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
(including Montaup's) of the loss of the return component would total
approximately $16 million to $20 million before taxes for the entire
recovery period. In April 2000, a settlement was reached among
Connecticut Yankee, the Connecticut Department of Public Utility Control
(CDPUC), the Office of Consumer Counsel (OCC), and the Connecticut
Municipal Electric Cooperative. The settlement resolves all issues in
the case, except the OCC has reserved its right to appeal recovery of
any costs other than decommissioning. Billings will be reduced
prospectively. There will be no refunds of any amounts collected up to
the effective date of the settlement. Connecticut Yankee had reserved
for potential refunds and will be reversing that reserve. Prospectively,
Connecticut Yankee has agreed to reduce annual collections for
decommissioning through the use of its pre-1983 spent fuel trust funds
and to limit its return on equity to 6 percent. In addition, Connecticut
Yankee has pursued litigation against the Department of Energy (DOE) to
assume financial responsibility for storage of spent nuclear fuel and
has agreed to pass to ratepayers any recovery after litigation expenses.
The settlement is pending before the FERC.
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.
Under the provisions of the Settlement Agreements, the Company
recovers all costs, including shutdown costs, that the FERC allows these
Yankee companies to bill to the Company.
<PAGE>
Maine Yankee had hired Stone & Webster, Inc., an engineering,
construction, and consulting company, as the principal contractor to
decommission the unit. Stone & Webster recently announced plans to file
for Chapter 11 bankruptcy protection due to financial difficulties.
Stone & Webster also announced that it has negotiated the sale of
substantially all of its assets. In May 2000, Maine Yankee terminated
its long-term contract with Stone & Webster and negotiated an
arrangement with Stone & Webster to continue work until June 2000. On
June 2, 2000, Stone & Webster filed for Chapter 11 bankruptcy
protection. Maine Yankee is considering its options for decommissioning
the unit beyond June 30, 2000. At this time, the Company is unable to
determine the potential impact, if any, of this development.
Operating Nuclear Units
The Company has minority interests in three operating nuclear
generating units which the Company is engaged in efforts to divest:
Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the
future of nuclear generating stations, particularly older units, such
as Vermont Yankee, have increased in recent years 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. 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.
Vermont Yankee
The following tables summarize the interests of the Company, and
of Montaup (effective with the EUA merger), in the Vermont Yankee
Nuclear Power Corporation as of March 31, 2000:
<PAGE>
<TABLE>
<CAPTION>
The Company's Interest
(millions of dollars)
----------------------------------------------
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning Fund License
Interest (%) Investment Assets Cost (in 1999$) Balance Expiration
------------ ---------- ------ --------------- ------- ----------
<S> <C> <C> <C> <C> <C>
20 $11 $33 $86 $43 2012
Montaup's Interest
(millions of dollars)
----------------------------------------------
Equity Net Estimated Decommissioning
Ownership Equity Plant Decommissioning Fund License
Interest (%) Investment Assets Cost (in 1999$) Balance Expiration
------------ ---------- ------ --------------- ------- ----------
2.5 $1 $4 $11 $5 2012
</TABLE>
In November 1999, the Vermont Yankee Nuclear Power Corporation
entered into an agreement with AmerGen Energy Company (AmerGen), a joint
venture between PECO Energy and British Energy, to sell the assets of
Vermont Yankee. Under the terms of the agreement, after a Vermont Yankee
contribution toward the plant's decommissioning trust fund, AmerGen will
take over the fund and assume responsibility for the actual cost of
decommissioning the plant. The agreement also requires the existing
power purchasers (including the Company) to continue to purchase the
output of the plant or to buy out of the purchased power obligation. In
November 1999, the Company signed an agreement to buy out of its
obligation, requiring future payments which will be recovered through
the Company's CTC. The Company has recorded an accrued liability and an
offsetting regulatory asset of $80 million for its share of future
liabilities related to Vermont Yankee, including the purchased power
contract termination payment obligation, but excluding interest and a
return allowance. The proposed sale is contingent upon regulatory
approvals by the NRC, the SEC, under the 1935 Act, and the Vermont
Public Service Board (VPSB), among others. The
<PAGE>
Vermont Public Service Department has identified several issues that
must be resolved to its satisfaction for it to support the VPSB's
approval of the sale.
Millstone 3
In August 1997, the Company sued Northeast Utilities (NU) in
Massachusetts Superior Court for damages, alleging that NU engaged in
tortious conduct that caused the shutdown of Millstone 3, which is
operated by a subsidiary of NU. The Company's claim for damages included
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.
In August 1997, the Company also sent a demand for arbitration to
Connecticut Light & Power Company and Western Massachusetts Electric
Company, both subsidiaries of NU, seeking damages for breach of
obligations under an agreement with the Company and others regarding the
operation and ownership of Millstone 3. In July 1998, Millstone 3
returned to full operation after being shut down for more than two
years.
In November 1999, the Company executed an agreement which settled
the litigation and arbitration. Under the settlement agreement, the NU
companies paid the Company $23.7 million and paid Montaup $7.8 million.
The settlement also includes an agreement by NU to include the Company's
and Montaup's share of Millstone 3 in an auction of NU's share of the
unit. Upon the closing of the sale, NU will pay the Company and Montaup
a combined total of $25 million, regardless of the actual sale price,
and reimburse the Company and Montaup for any capital expenditures in
excess of pre-
budgeted levels incurred after October 1999. The Company and Montaup
will also be reimbursed for fuel procurement expenditures which increase
net nuclear fuel account balances above current balances. The settlement
also requires NU to indemnify the Company and Montaup and assume any
residual liabilities resulting from the sale, including any requirements
that the sellers continue to purchase output from the unit. In addition,
the settlement requires NU to pay the Company and Montaup an additional
combined total of
<PAGE>
$1 million per month for every month beyond April 1, 2001 that the
closing does not occur. The auction process is being conducted by the
CDPUC and is ongoing. Amounts received pursuant to a sale will, after
reimbursement of the Company's transaction costs and net investment in
Millstone 3, be credited to customers.
Seabrook 1
As part of its restructuring settlement with the State of New
Hampshire, Public Service Company of New Hampshire (PSNH), through its
affiliate, North Atlantic Energy Corporation (NAEC), has committed to
seek New Hampshire Public Utilities Commission (NHPUC) approval of a
definitive plan to sell, via public auction, its share of Seabrook 1,
with such sale to occur no later than December 31, 2003. NAEC is the
majority owner of the plant with a 35.98 percent interest and is also
the plant operator. As part of its settlement, PSNH has also agreed to
make all reasonable efforts to bundle its interests with those of other
owners (including the Company) seeking to sell their interests. This
would allow for an auction of a majority interest. The NHPUC granted
conditional approval of the settlement on April 19, 2000. The New
Hampshire legislature approved the necessary legislation on May 31,
2000. Final resolution by the NHPUC approving the settlement in
compliance with the legislation is expected this summer.
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 and
these costs are recorded as 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.
<PAGE>
In New Hampshire, legislation was enacted in 1998 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 15
percent share of Seabrook 1 has no franchise service territory. The
impact of this legislation to the Company is not considered material to
its financial position or results of operation.
The Nuclear Waste Policy Act of 1982 establishes that the federal
government (through the 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 are also
recovered from customers through CTCs. In 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 held
that the DOE was obligated to begin disposing of utilities' spent
nuclear fuel by January 1998. The DOE failed to meet this deadline and
is not expected to have a temporary or permanent repository for spent
nuclear fuel before 2010, at the earliest. Many utilities, including
Yankee Atomic, Connecticut Yankee, and Maine Yankee, are plaintiffs in
on-going litigation related to the DOE's failure to accept spent nuclear
fuel.
Decommissioning Trust Funds
Each nuclear unit in which the Company and Montaup have 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 tables below list information on the
operating nuclear plants in which the Company and Montaup are joint
owners.
<PAGE>
<TABLE>
<CAPTION>
The Company's share of (millions of dollars)
--------------------------------------------
Decommissioning
The Company's Net Estimated Fund
OwnershipPlant AssetsDecommissioning Balances* License
Unit Interest (%)(at 3/31/00) Cost (in 1999 $) (at 3/31/00) Expiration
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Millstone 3 12 12** 76 23 2025
Seabrook 1 10 14** 56 13 2026
Montaup's share of (millions of dollars)
--------------------------------------------
Decommissioning
The Company's Net Estimated Fund
OwnershipPlant AssetsDecommissioning Balances* License
Unit Interest (%)(at 3/31/00) Cost (in 1999 $) (at 3/31/00) Expiration
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Millstone 3 4 4** 25 8 2025
<FN>
*Certain additional amounts are anticipated to be available through tax deductions.
**Represents post-December 1995 spending including nuclear fuel. For further information,
refer to Note C.
</FN>
</TABLE>
There is no assurance that decommissioning costs actually incurred
will not substantially exceed the estimated 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 will gradually become unavailable
to units other than Connecticut Yankee and Millstone 3. 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, the Company will recover decommissioning costs
through CTCs.
<PAGE>
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 $9.5 billion (based upon 106 licensed reactors). The maximum
amount of commercially available insurance coverage to pay such claims
is $200 million. The remaining $9.3 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
Utility plant expenditures for the Company and Montaup are
estimated to be approximately $45 million in fiscal year 2001.
<PAGE>
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 (including Montaup's) at March
31, 2000, amounted to $24 million.
5. 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 several 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 it 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 Company
<PAGE>
has recovered amounts from certain insurers, and, where appropriate,
intends 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 the Company's hazardous waste
liabilities for all sites of which the Company is aware are not material
to its financial position.
6. Town of Norwood Dispute
From 1983 until 1998, the Company was the wholesale power supplier
for the Town of Norwood, Massachusetts (Norwood). In April 1998, Norwood
began taking power from another supplier. Pursuant to a tariff amendment
approved by the FERC in May 1998, the Company has been assessing Norwood
a CTC. Through March 2000, the charges assessed Norwood amount to
approximately $18 million, all of which remain unpaid. The Company has
filed a collection action in Massachusetts Superior Court.
Separately, Norwood filed suit in Federal District Court (District
Court) in April 1997 alleging that the divestiture violated the terms
of the 1983 power contract and contravened antitrust laws. The District
Court dismissed the lawsuit. On appeal, the First Circuit Court of
Appeals (First Circuit) consolidated appeals Norwood made from FERC's
orders approving the divestiture, the wholesale rate settlement between
the Company and its distribution affiliates, and the CTC tariff
amendment. On February 2, 2000, the First Circuit dismissed Norwood's
appeal from the FERC orders and dismissed its appeal from all but one
of Norwood's District Court claims, which relates to alleged generation
market power. On February 28, 2000 and March 3, 2000, respectively, the
First Circuit denied Norwood's petition for further review of its
District Court claims decision and its decision on the FERC orders. On
May 30, 2000, Norwood petitioned the US Supreme Court for review of the
First Circuit decisions.
Norwood has also appealed a 1999 FERC decision that rejected
Norwood's challenge to the calculation of the CTC based on the terms of
the 1983 power contract. On June 12, 2000, Norwood moved to amend its
complaint to reassert a claim for rescission with respect to the
Company's divestiture. The Company has filed a motion to dismiss.
<PAGE>
Note E - Employee Benefits
1. Pension Plans:
The Company participates with other subsidiaries of National Grid
USA 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 the three months ended March 31, 2000 and the
years ended December 31, 1999, 1998, and 1997 included the following
components:
<TABLE>
<CAPTION>
Three
Months Ended Year Ended
March 31, December 31,
----------------------------------------------------------------------------------------
(thousands of dollars) 2000 1999 1998 1997
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Service cost - benefits earned during the period$ 118 $ 527$ 2,430$ 2,887
Plus (less):
Interest cost on projected benefit obligation 1,760 7,044 7,435 7,003
Return on plan assets at expected long-term rate (2,200)(8,090)(8,675) (7,842)
Amortization of transition obligation (33) (170) (184) (175)
Amortization of prior service cost 24 115 161 171
Amortization of net (gain)/loss (100) 36 159 65
Curtailment (gain)/loss - - (5,680) -
-----------------------------------------------------------------------------------------
Benefit cost $ (431) $ (538)$(4,354) $ 2,109
-----------------------------------------------------------------------------------------
Special termination benefits not included above $ - $ -$10,911$ -
-----------------------------------------------------------------------------------------
</TABLE>
<PAGE>
The funded status of the plans cannot be presented separately for
the Company as the Company participates in the plans with other National
Grid USA subsidiaries. The following table sets forth the funded status
of the National Grid USA companies' plans:
<TABLE>
<CAPTION> At At
March 31, December 31,
---------------------------------------------------------------------------
(millions of dollars) 2000 1999 1998
---------------------------------------------------------------------------
<S> <C> <C> <C>
Benefit obligation $ 800 $ 789 $843
Unrecognized prior service costs - (5) (6)
Transition liability not yet
recognized (amortized) - (2) (2)
Additional minimum liability - 6 7
---------------------------------------------------------------------------
800 788 842
---------------------------------------------------------------------------
Plan assets at fair value 991 947 837
Transition asset not yet recognized (amortized) - (5) (6)
Net (gain)/loss not yet recognized (amortized) - (206) (92)
---------------------------------------------------------------------------
991 736 739
---------------------------------------------------------------------------
Accrued (prepaid) pension benefits
recorded on National Grid USA books $(191) $ 52 $103
---------------------------------------------------------------------------
</TABLE>
The following provides a reconciliation of benefit obligations and
plan assets:
<TABLE>
<CAPTION> At At
March 31, December 31,
---------------------------------------------------------------------------
(millions of dollars) 2000 1999 1998
---------------------------------------------------------------------------
<S> <C> <C> <C>
Changes in benefit obligation:
Benefit obligation at January 1 $789 $843 $819
Service cost 2 11 14
Interest cost 15 56 55
Actuarial (gain)/loss 10 (55) (5)
Benefits paid (16) (66) (94)
Special termination benefits - - 64
Curtailment - - (11)
Plan amendments - - 1
---------------------------------------------------------------------------
Benefit obligation end of period $800 $789 $843
---------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $947 $837 $834
Actual return on plan assets during year 59 117 93
Company contributions 1 59 4
Benefits paid from plan assets (16) (66) (94)
---------------------------------------------------------------------------
Fair value of plan assets end of period $991 $947 $837
---------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
March 31, December 31,
2001 2000 1999 1998 1997
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Assumptions used to determine pension cost:
Discount rate 7.75% 7.75% 6.75% 6.75% 7.25%
Average rate of increase in
future compensation level 5.10% 5.10% 4.13% 4.13% 4.13%
Expected long-term rate of
return on assets 8.50% 8.50% 8.50% 8.50% 8.50%
</TABLE>
The plans' funded status at March 31, 2000 and December 31, 1999
and 1998 were calculated using the assumed rates from 2001, 2000, and
1999, respectively, and the 1983 Group Annuity Mortality table.
Plan assets are composed primarily of equity and fixed income
securities. Fair value adjustments of approximately $33 million are
reflected in the Company's financial statements.
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 the three months ended March
31, 2000 and the years ended December 31, 1999, 1998, and 1997 included
the following components:
<PAGE>
<TABLE>
<CAPTION>
Three
Months Ended Year Ended
March 31, December 31,
-----------------------------------------------------------------------------------------
(thousands of dollars) 2000 1999 1998 1997
-----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Service cost - benefits earned during the period $ 47 $ 193 $ 1,109 $ 1,363
Plus (less):
Interest cost on projected benefit obligation 786 2,816 3,244 3,545
Return on plan assets at expected long-term rate (803) (2,896) (2,656) (2,343)
Amortization of transition obligation 19 85 1,732 2,556
Amortization of prior service cost - - 5 8
Amortization of net (gain)/loss (285) (1,252) (1,138) (983)
Curtailment (gain)/loss - - 27,149 -
-----------------------------------------------------------------------------------------
Benefit cost $(236) $(1,054)$29,445 $ 4,146
-----------------------------------------------------------------------------------------
Special termination benefits not included above $ - $ - $ 439 $ -
-----------------------------------------------------------------------------------------
</TABLE>
The following table sets forth the Company's benefits earned and
the plans' funded status, including fair value adjustments recorded in
the first quarter of 2000 of approximately $28 million:
<TABLE>
<CAPTION>
At At
March 31, December 31,
-----------------------------------------------------------------------------
(millions of dollars) 2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Benefit obligation $38 $ 42 $ 41
Unrecognized prior service costs - - -
Transition liability not yet recognized (amortized) - (1) (1)
-----------------------------------------------------------------------------
38 41 40
-----------------------------------------------------------------------------
Plan assets at fair value 40 39 36
Net (gain)/loss not yet recognized (amortized) - (25) (26)
-----------------------------------------------------------------------------
40 14 10
-----------------------------------------------------------------------------
Accrued (prepaid) PBOPs recorded on books $(2) $ 27 $ 30
-----------------------------------------------------------------------------
</TABLE>
<PAGE>
The following provides a reconciliation of benefit obligations and
plan assets:
<TABLE>
<CAPTION> At At
March 31, December 31,
-----------------------------------------------------------------------------
(millions of dollars) 2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Changes in benefit obligation:
Benefit obligation at January 1 $42 $41 $ 51
Service cost - - 1
Interest cost 1 3 3
Actuarial (gain)/loss (4) - 2
Benefits paid (1) (2) (2)
Special termination benefits - - -
Curtailment - - (14)
-----------------------------------------------------------------------------
Benefit obligation end of year $38 $42 $ 41
-----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $39 $36 $ 34
Actual return on plan assets during year 2 4 4
Company contributions - 1 -
Benefits paid from plan assets (1) (2) (2)
-----------------------------------------------------------------------------
Fair value of plan assets end of year $40 $39 $ 36
-----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
March 31, December 31,
2001 2000 1999 1998 1997
----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Assumptions used to determine
postretirement benefit cost:
Discount rate 7.75% 7.75% 6.75% 6.75% 7.25%
Expected long-term rate of
return on assets 8.40% 8.42% 8.35% 8.27% 8.21%
Health care cost rates:
1997 to 1999 5.25% 5.25% 8.00%
2000 8.25% 8.25% 5.25% 5.25% 6.25%
2001 6.75% 6.75% 5.25% 5.25% 6.25%
2002 to 2004 5.25% 5.25% 5.25% 5.25% 6.25%
2005 and beyond 5.25% 5.25% 5.25% 5.25% 5.25%
</TABLE>
<PAGE>
The plans' funded status at March 31, 2000 and December 31, 1999
and 1998 were calculated using the assumed rates in effect for 2001,
2000, and 1999, 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 March 31, 2000 by
approximately $4 million or decrease the APBO by approximately $4
million, and change the net periodic cost for fiscal year 2001 by
approximately $100,000.
The Company generally funds the annual tax-deductible
contributions. Plan assets are invested in equity and fixed income
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
industry restructuring. 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 the buyer at the closing of
the divestiture and will be recovered in part from customers as a
component of stranded cost recovery.
Note F - Income Taxes
The Company and other subsidiaries intend to elect to participate
with National Grid General Partnership, National Grid USA's parent
company that is wholly owned by National Grid, in filing a consolidated
federal income tax return. 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.
<PAGE>
Total income taxes in the statements of income are as follows:
<TABLE>
<CAPTION>
Three Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
--------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Income taxes charged to operations $9,641$13,100$37,633$ 73,594$90,009
Income taxes charged (credited) to
"Other income" (4) - 1,985 (19,582) (373)
-----------------------------------
Total income taxes $9,637$13,100$39,618$ 54,012$89,636
===================================
</TABLE>
Total income taxes, as shown above, consist of the following
components:
<TABLE>
<CAPTION>
Three Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
--------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Current income taxes $12,545$ 7,374$ 25,507 $ 280,734 $102,364
Deferred income taxes (581)10,732 25,921(204,129)(10,705)
Investment tax credits, net (2,327)(5,006)(11,810)(22,593) (2,023)
---------------------- --------- --------
Total income taxes $ 9,637$13,100$ 39,618 $ 54,012 $ 89,636
====================== ========= ========
</TABLE>
Investment tax credits (ITC) have been deferred and amortized over
the estimated lives of the property giving rise to the credits. ITC
amortization in 1999 reflects the accelerated amortization of the
property giving rise to the credits, while the increase in amortization
of ITC in 1998 compared with 1997 results from the recognition in income
of unamortized ITC related to the generating assets divested during
1998.
<PAGE>
Total income taxes, as shown above, consist of federal and state
components as follows:
<TABLE>
<CAPTION>
Three
Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
--------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Federal income taxes $8,035 $10,975 $33,746 $41,255 $73,077
State income taxes 1,602 2,125 5,872 12,757 16,559
------ ------- ------- ------- -------
Total income taxes $9,637 $13,100 $39,618 $54,012 $89,636
====== ======= ======= ======= =======
</TABLE>
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:
<PAGE>
<TABLE>
<CAPTION>
Three Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Computed tax at statutory rate $ 8,435 $11,706 $38,721 $ 61,917 $81,963
Increases (reductions) in tax
resulting from:
Amortization of investment
tax credits (1,513) (3,254) (7,677) (15,157) (2,023)
State income taxes, net of
federal income tax benefit 1,042 1,381 3,817 8,292 10,763
Rate recovery of deficiency
in deferred tax reserves 1,617 3,508 8,207 - -
Prior year tax adjustment - - (2,028) (188) (313)
All other differences 56 (241) (1,422) (852) (754)
------- ------- ------- -------- -------
Total income taxes $ 9,637 $13,100 $39,618 $ 54,012 $89,636
======= ======= ======= ======== =======
</TABLE>
<PAGE>
The following table identifies the major components of total deferred
income taxes:
<TABLE>
<CAPTION>
At March 31,At December 31,
(In millions) 2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Deferred tax asset:
Plant related $ 67 $ 67 $ 76
Investment tax credits 6 8 13
All other 3 2 24
----- ----- -----
76 77 113
----- ----- -----
Deferred tax liability:
Plant related (159) (157) (53)
All other, principally regulatory
assets (93) (100) (225)
----- ----- -----
(252) (257) (278)
----- ----- -----
Net deferred tax liability $(176) $(180) $(165)
===== ===== =====
</TABLE>
Note G - Short-term Borrowings and Other Accrued Expenses
At March 31, 2000, the Company had $39 million of short-term debt
outstanding. The Company has regulatory approval to issue up to $375
million of short-term debt. The Company plans to seek the necessary
regulatory approvals in 2000 which would allow the $39 million of
variable rate debt to remain outstanding through 2015. This would result
in classifying the debt as long-term rather than short-term. National
Grid USA 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 March 31, 2000, the Company had lines of credit and standby
bond purchase facilities with banks totaling $460 million which are
available to provide liquidity support for $410 million of the
Company's short-term and long-term bonds in tax-exempt commercial
paper mode (including the $39 million discussed above), and for other
corporate purposes. There were no borrowings under these lines of
credit at March 31, 2000. Fees are paid on the lines and facilities
in lieu of compensating balances.
The components of other accrued expenses are as follows:
<TABLE>
<CAPTION>
At March 31, At December 31,
(In thousands) 2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C>
Accrued wages and benefits $ 1,215 $ 1,063 $ 3,059
Rate adjustment mechanisms 9,110 14,550 16,781
Other 554 80 246
------- ------- -------
$10,879 $15,693 $20,086
------- ------- -------
</TABLE>
Note H - Cumulative Preferred Stock
A summary of cumulative preferred stock at March 31, 2000 and
December 31, 1999 and 1998 is as follows (in thousands of dollars except
for share data):
<PAGE>
<TABLE>
<CAPTION>
Shares Dividends
Outstanding Amount Declared
------------------------------------------------------------------------------
2000 1999 1998 2000 1999 1998 2000 1999 1998
------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
$100 par value
6.00% Series 15,67215,672 15,672$1,567$1,567$1,567 $24 $94 $277
4.56% Series - - - - - - - - 247
4.60% Series - - - - - - - - 236
4.64% Series - - - - - - - - 98
6.08% Series - - - - - - - - 372
------------------------------------------------------------------------------
Total 15,67215,672 15,672$1,567$1,567$1,567 $24 $94 $1,230
The 6.00% Series cumulative preferred stock is noncallable.
</TABLE>
The dividend requirement for cumulative preferred stock was $24,000
for the three months ended March 31, 2000, and the annual dividend
requirement was $94,000 as of December 31, 1999. In 1998, the Company
repurchased or redeemed preferred stock with an aggregate par value of
$38 million. The preferred dividend requirement for 1998 was $1.2
million.
There are no mandatory redemption provisions on the Company's
cumulative preferred stock.
Note I - Long-term Debt
A summary of long-term debt is as follows:
<PAGE>
<TABLE>
<CAPTION>
(In thousands)
At March 31,At December 31,
Series Rate % Maturity 2000 1999 1998
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Pollution Control Revenue Bonds:
MIFA 1 (a) variable March 1, 2018 $ 79,250 $ 79,250 $ 79,250
BFA 1 (b) variable November 1, 2020 135,850135,850 135,850
BFA 2 (b) variable November 1, 2020 50,600 50,600 50,600
MIFA 2 (a) variable October 1, 2022 106,150106,150 106,150
Unamortized discounts (77) (79) (85)
-------- -------- --------
Total long-term debt $371,773 $371,771 $371,765
======== ======== ========
<FN>
(a) MIFA = Massachusetts Industrial Finance Authority
(b) BFA = Business Finance Authority of the State of New Hampshire
</FN>
</TABLE>
At March 31, 2000, interest rates on the Company's variable rate
long-term bonds ranged from 3.45 percent to 3.95 percent.
At March 31, 2000, the Company's long-term debt had a carrying
value and fair value of approximately $372,000,000. The fair value of
debt that reprices frequently at market rates approximates carrying
value.
Note J - Common Stock
The purchase accounting method was used in National Grid's merger
with National Grid USA, which resulted in a purchase accounting
adjustment of approximately $16 million to the Company's retained
earnings to reflect post merger net income. This also resulted in a
reduction to the premium on capital stock of $49 million, a reduction
in the unrealized gain on securities - net of $73,000, and an increase
of $399 million in other paid-in-capital due to the push down of
goodwill.
<PAGE>
The Company repurchased shares of its common stock in 1999 and 1998
as follows (dollar amounts expressed in thousands):
<TABLE>
<CAPTION>
Reductions to:
---------------------------------------
Common stock
Number of Cash and related Other paid- Retained
Year Shares Paid premium in capital earnings
----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1999 130,000 $ 18,056 $ 4,348 $ 6,623 $ 7,085
1998 2,700,000 $417,960 $90,266 $133,876 $193,818
</TABLE>
Note K - Supplementary Income Statement Information
Advertising expenses, expenditures for research and development,
and rents were not material and there were no royalties paid in the
three months ended March 31, 2000, and March 31, 1999, and the years
ended December 31, 1999, 1998, or 1997. Taxes, other than income taxes,
charged to operating expenses are set forth by classes as follows:
<TABLE>
<CAPTION>
Three Months Ended Year Ended
March 31, December 31,
(In thousands) 2000 1999 1999 1998 1997
(unaudited)
--------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Municipal property taxes $4,718 $4,618 $17,640 $42,080 $59,102
Federal and state payroll
and other taxes 843 1,016 2,642 6,412 8,209
------ ------ ------- ------- -------
$5,561 $5,634 $20,282 $48,492 $67,311
====== ====== ======= ======= =======
</TABLE>
<PAGE>
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 $11,514,000, $10,088,000, $43,584,000, $74,203,000,
and $91,985,000, including capitalized construction costs of $4,597,000,
$3,415,000, $17,229,000, $21,281,000, and $24,347,000, in the three
months ended March 31, 2000, the three months ended March 31, 1999, and
the years ended
December 31, 1999, 1998, and 1997, respectively.
<TABLE>
<CAPTION>
New England Power Company
Selected Financial Information
Three
Months Ended
March 31, Year Ended December 31,
(In millions) 2000 1999 1999 1998 1997 1996 1995
(unaudited)
--------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenue $ 135 $ 167$ 596 $1,218 $1,678 $1,600 $1,571
Net income $ 14 $ 20$ 71 $ 123 $ 145 $ 152 $ 151
Total assets $2,630 $2,282$2,303 $2,415 $2,763 $2,648 $2,648
Capitalization:
Common equity $ 657 $ 523$ 332 $ 521 $ 913 $ 906 $ 889
Cumulative preferred stock 1 1 2 1 40 40 61
Long-term debt 372 372 372 372 648 733 735
------ ------------ ------ ------ ------ ------
Total capitalization $1,030 $ 896$ 706 $ 894 $1,601 $1,679 $1,685
Preferred dividends declared $ - $ -$ - $ 1 $ 2 $ 3 $ 3
Common dividends declared $ 24 $ -$ 241 $ 131 $ 135 $ 134 $ 135
------ ------------ ------ ------ ------ ------
</TABLE>
Selected Quarterly Financial Information (Unaudited)
<PAGE>
<TABLE>
<CAPTION>
Three
Months Ended First Second Third Fourth
March 31, Quarter Quarter Quarter Quarter
(In thousands) 2000 1999 1999 1999 1999
------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenue $134,564 $167,177 $139,620 $142,066 $147,478
Operating income $ 16,319 $ 22,058 $ 13,796 $ 18,782 $ 23,927
Net income $ 14,462 $ 20,345 $ 14,254 $ 17,669 $ 18,746
First Second Third Fourth
Quarter Quarter Quarter Quarter
1998 1998 1998 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
</TABLE>
Per share data is not relevant because the Company's common stock
is wholly owned by National Grid USA, a wholly owned subsidiary of The
National Grid Group plc.
