Annual Report 2002
New England Power Company
[National Grid logo]
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of April 1, 2002)
L. Joseph Callan
Former Executive Director for Operations,
Nuclear Regulatory Commission
John G. Cochrane
Vice President of the Company and Chief Financial Officer and Vice President of National Grid USA
Peter G. Flynn
President of the Company
Michael E. Jesanis
Vice President of the Company and Executive Vice President of National Grid USA
Robert G. Powderly
Vice President of National Grid USA
Lawrence J. Reilly
Vice President and General Counsel of the Company and Senior Vice President,
General Counsel, and Secretary 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 April 1, 2002)
Peter G. Flynn
President of the Company
John G. Cochrane
Vice President of the Company and of an affiliate, President of certain affiliates,
Treasurer of certain affiliates, and
Vice President and Chief Financial Officer of National Grid USA
Michael E. Jesanis
Vice President of the Company and Executive Vice President of National Grid USA
Lawrence J. Reilly
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
James S. Robinson
Vice President and Treasurer of the Company and of certain affiliates
Masheed H. Rosenqvist
Vice President of the Company and of certain affiliates
Herb Schrayshuen
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, and Assistant Secretary
or Assistant Clerk of certain affiliates
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates and Secretary or Clerk of certain affiliates
Geraldine M. Zipser
Assistant Clerk of the Company and of certain affiliates, and Secretary or Clerk of certain affiliates
Robert G. Seega
Assistant Treasurer of the Company and of certain affiliates
Jennifer K. Zschokke
Assistant Treasurer of the Company and Vice President and Treasurer of certain affiliates
Edward A. Capomacchio
Controller of the Company and of certain affiliates and Vice President of an affiliate
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock
Bank of New York, New York, New York
This report is not to be considered an offer to sell or buy or solicitation of
an offer to sell or buy any security.
Financial Review
Regulatory Environment and Accounting Implications
Prior to divesting substantially all of its nonnuclear generation business in 1998, the Company was the wholesale supplier
of the electric energy requirements to its retail distribution affiliates as well as unaffiliated customers. The Company’s
all-requirements contracts with its affiliated distribution companies, as well as with some unaffiliated customers, were
generally terminated pursuant to settlement agreements and tariff provisions in 1998. However, the Company remained
obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but
did not have a regulatory agreement that necessarily allowed full recovery of the costs of such standard offer power.
Consequently, the Company was at risk for the difference between the actual cost of serving this load and the revenue
received from this obligation. For the year ended March 31, 2002, the impact on the Company’s financial position was
immaterial. Effective December 1, 2001, a third party assumed the responsibility for providing transitional standard offer
power service in Rhode Island, and the Company’s obligation terminated.
Under 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 whom it has settlement agreements through contract
termination charges (CTC) that the affiliated wholesale customers recover through delivery charges to distribution
customers. The recovery of the Company’s stranded costs (including Montaup Electric Company’s (Montaup), a former Eastern
Utilities Associates (EUA) subsidiary) 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
2009 and earn a return on equity (ROE) 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 ROE. 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.
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 fixed monthly payments by the Company.
Similar to the Company, Montaup also transferred its purchased power obligations as part of the divestiture and in return
agreed to make fixed monthly payments. These fixed monthly payments by the Company, inclusive of Montaup’s share, average
approximately $11 million per month through December 2009 toward the above-market cost of those contracts. The liability
relating to purchased power obligations, which is also reflected in regulatory assets, represents the net present value of
these fixed monthly payments. At March 31, 2002, the net present value is approximately $659 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 $453 million), which were separate from the $659
million figure referred to above.
FERC Proceedings
In general, the regulatory structure and regulations which relate to the Company's business are in a period of major
change and uncertainty. Decisions being made by the Federal Energy Regulatory Commission (FERC) and the Independent
System Operator-New England (ISO New England) will affect how the Company does business and whether it can enter new
endeavors. The Company is currently unable to determine whether these proceedings will have a material impact on its
financial position or results of operations.
The FERC has been reviewing the development of regional transmission organizations (RTOs). The FERC has indicated that it
wants RTOs to have large geographic scope. In July and August, 2001, the FERC ordered National Grid USA and other New England parties
and participants of the New York Independent System Operator (ISO), and the Pennsylvania-New Jersey-Maryland (PJM) ISO to
participate in a mediation process to develop a proposal for a larger RTO. The FERC has not yet ruled on the mediation report
issued in September 2001. Pending the ruling on the mediation report, the transmission owners have been working toward a hybrid
RTO structure in which an independent transmission company would manage the transmission grid for the RTO and an independent market
administrator would manage power markets for the RTO. However, it is not clear what sort of RTO structure will ultimately result
from these negotiations. In fact, based on a January 29, 2002 filing by the New York and New England ISOs to form their own RTO,
even the geographic scope of the RTO in which the Company will participate is still an open question.
In late 2001 and early 2002, the FERC convened an advanced rulemaking proceeding to enable transmission owners, such as the
Company, and generators to establish standardized procedures and agreements concerning the way generators would
interconnect with the transmission grid. On April 24, 2002, the FERC issued proposed rules very favorable to generators and
unfavorable, and, the Company believes, at times unworkable, for transmission owners. The Company has submitted comments
seeking significant changes in the proposed rules. The FERC is expected to issue final rules later this year.
In 2001, the FERC began an advanced rulemaking procedure to address Standard Market Design regarding the buying and selling
of power. In a December 2001 order, the FERC requested that all industry segments try to agree on a single standards
setting organization that would establish national standard business practices for the wholesale electric industry. The
FERC has also solicited comments on a wide range of issues, including: transmission pricing, pricing for electric energy
and capacity, transmission planning, generation dispatch, RTO governance, market monitoring, long term generation adequacy
(including installed capacity or “ICAP”), and resolution of “seams” - or conflicting practices or charges that inhibit
inter-regional energy transactions. All of these either directly or indirectly affect the Company’s business. It is
anticipated that the FERC will launch a formal notice of proposed rulemaking proceeding this summer.
NEPOOL and ISO New England have a separate standard market design initiative which is proceeding in parallel to the FERC
initiative. It is expected that either New England Power Pool (NEPOOL) or ISO New England will file a proposal to conform
the procedures by which energy is bought and sold in New England to those of PJM with the FERC this summer for
implementation by December 2002 or early 2003.
To the extent the Company wishes to pursue opportunities to manage or to be a member of an independent transmission company
or an RTO, with the opportunity to propose financial incentives to deliver greater value for customers and shareholders,
the FERC rulings in the standard market design proceeding and other proceedings may have an impact on the ability to do so.
In June 2001, the FERC issued an order relating to (NEPOOL’s proposed congestion management and multi-settlement systems.
In the June Order, the FERC found that "energy uplift" costs (which had been about $9 million per month for NEPOOL in 2000)
should be allocated on the basis of reliance on the energy markets administered by the ISO New England. This would have the
effect of relieving parties that procure power under bilateral contracts (such as the Company) from paying energy uplift
charges. However, the NEPOOL Participants Committee and ISO New England submitted a filing in July 2001 that the Company
believed did not comport with the FERC's order. The Company protested the filing, and received a favorable order from the
FERC on February 15, 2002. Nevertheless, the NEPOOL Participants Committee and ISO New England submitted another filing on
March 18, 2002 that the Company believes does not comport with the FERC's orders, and the Company has again filed another
protest.
On September 27, 2001, the FERC initiated a notice of proposed rulemaking regarding affiliate standards of conduct in both
the electric and gas industries. In its proposed rules, the FERC proposed a broad definition of “energy affiliate”, which
would include its affiliate National Grid USA Service Company, Inc. (Service Company) as well as the Company’s electric
distribution company affiliates. The proposed rules would impose significant restrictions on the ability of the Company to
interact with such “energy affiliates.” If not modified, the proposed rules could require significant reorganization
for the Company and possibly duplication of support functions that the Company depends on the Service Company to provide.
As previously reported, there has been litigation regarding the FERC order to increase the ICAP deficiency charge to $8.75
per kilowatt-month (kW-month) instead of the rate proposed by ISO New England of $0.17 per kW-month. In June 2001, after
significant litigation and a remand from the US Court of Appeals for the First Circuit, ISO New England made a Compliance
Filing with the FERC proposing a compromise ICAP regime, including an ICAP deficiency charge of $4.87 per kW-month. On
September 28, 2001, the FERC issued an order refusing to apply retroactively the $8.75 per kW-month deficiency charge for
the period January to June 2000. On November 20, 2001, the FERC issued an order on rehearing of the August order requiring
ISO New England to establish a prospective ICAP regime (i.e., one under which utility ICAP purchase requirements are known
in advance) in lieu of a retrospective requirement with a cure period. It is unclear what system will replace the ICAP
regime in the future. The issue of the appropriate ICAP deficiency charge for the period January to July 2000, is currently
back before the US Court of Appeals for the First Circuit for resolution. The FERC is also now addressing complaints by
power marketers about how ICAP should have been charged for the period January to July 2000. Both of these proceedings will
likely affect the Company’s ICAP exposure.
Overview of Financial Results
Net income for the twelve months ended March 31, 2002 increased approximately $18 million compared with the same period in
2001. The increase is primarily due to the adoption of Statement of Financial Accounting Standards No. 142 “Accounting for
Goodwill and Other Intangible Assets” (FAS 142), effective April 1, 2001, which requires the cessation of goodwill
amortization (see Note A-8). Also contributing to the increase in earnings is a decrease in interest expense due to
decreased interest rates on variable-rate long-term debt and the refinancing of short-term debt.
Net income for the twelve months ended March 31, 2001 decreased approximately $13 million compared with the twelve months
ended December 31, 1999. The decrease was primarily due to goodwill amortization from the merger of the Company’s parent
with National Grid Group plc and with EUA, increased purchased power costs, increased interest expense, and decreased
mitigation incentives. These increases were partially offset by increased income as a result of Montaup being merged into
the Company on May 1, 2000 and increased earnings from nuclear operations.
Net income for the three months ended March 31, 2000 decreased approximately $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.
Operating Revenue
Operating revenue for the twelve months ended March 31, 2002, decreased approximately $96 million compared with the same
period in 2001. The decrease is primarily attributable to reduced kilowatthour (kWh) sales due to the sale of the Millstone
3 nuclear generating unit and the effect of a refueling outage at the Vermont Yankee nuclear power plant during the quarter
ended June 30, 2001. The decrease is also related to reduced CTC revenue due to fully reconciling true-up mechanisms that
allow the Company to adjust revenues proportionately with correlating expenses. Partially offsetting these decreases were
increased transmission revenues. The transmission charge is a formula rate that recovers the Company’s actual costs plus a
return on investment.
Operating revenue for the twelve months ended March 31, 2001 increased approximately $60 million compared with the twelve
months ended December 31, 1999. The increase was due to increased sales and rates related to obligations to new customer
load in Rhode Island, and increased unit contract sales from partially owned nuclear units that experienced refueling
outages in 1999. These increases were also affected by the merger with Montaup, effective May 1, 2000. Partially offsetting
these increases were decreased CTC revenues.
Operating revenue for the three months ended March 31, 2000 decreased approximately $33 million compared with the same
period in 1999, largely due to CTC revenue of approximately $21 million from The Narragansett Electric Company
(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 was also due to the elimination of certain liabilities related to open access
transmission tariffs of $5 million in 1999. This decrease was partially offset by the impact of increased standard offer
rates effective January 1, 2000 and increased kWh sales in the three months ended March 31, 2000 compared with the same
period in 1999.
Operating Expenses
Operating expenses for the twelve months ended March 31, 2002 decreased approximately $94 million, compared with the same
period in 2001.
Fuel for generation expense for the twelve months ended March 31, 2002, decreased approximately $9 million, compared with
the same period in 2001, primarily due to the sale of Millstone 3 and decreased fuel expense at the Wyman 4 plant.
Purchased power expense for the twelve-month period ended March 31, 2002 decreased approximately $9 million compared with
the same period in 2001. The decreased cost is attributed to reduced open market power purchases to supply standard offer
service in Rhode Island. Effective December 1, 2001 a third party assumed the responsibility for providing transitional
standard offer power service in Rhode Island, and the Company’s obligation terminated. The decrease is partially offset by
increased costs attributed to a refueling outage at Vermont Yankee during the quarter ended June 30, 2001, the refund of
excess nuclear insurance and tax credits to Maine Yankee and Connecticut Yankee during the quarter ended December 31, 2000
and the inclusion of Montaup’s purchased power costs throughout the fiscal year ended March, 2002 in comparison to eleven
months in fiscal year 2001.
Nuclear operation and maintenance expenses for the twelve months ended March 31, 2002 decreased approximately $29 million
compared with the same period in 2001 as a result of the sale of Millstone 3. Other operating expenses for the twelve
months ended March 31, 2002 increased $2 million compared with the same period in 2001, primarily due to increased pension
costs, partially offset by a decrease in administrative expenses caused by the sale of Millstone 3.
Depreciation and amortization expenses for the twelve months ended March 31, 2002 decreased approximately $48 million
compared with the same period in 2001. This decrease is due to reduced nuclear depreciation and decommissioning expense as
a result of the sale of Millstone 3 in March 2001, and the full recovery of the Company’s CTC-related fixed costs
associated with its generating plants and regulatory assets (excluding Montaup’s fixed costs) at the end of 2000.
Operating expenses for the twelve months ended March 31, 2001 increased approximately $51 million compared with the twelve
months ended December 31, 1999.
Fuel for generation increased approximately $2 million for the twelve months ended March 31, 2001 compared with the twelve
months ended December 31, 1999 primarily related to charges at the Wyman 4 generating plant.
Purchased power expenses increased approximately $62 million for the same time period. This increase was primarily
attributed to the inclusion of Montaup’s purchased power costs effective May 1, 2000, increased fuel prices, and an
increase in standard offer purchases related to obligations to supply new customer load in Rhode Island, partially offset
by decreased purchased power charges from the Yankee Nuclear Power Companies (Yankees). Charges from Maine Yankee decreased
due to a refund for the termination of excess nuclear insurance coverage. Vermont Yankee purchased power charges decreased
due to the effect of a refueling outage during the quarter ended December 31, 1999. In addition, purchased power charges
from the Yankee Atomic nuclear power plant decreased as a result of the completion of the purchased power contract and
final billing in June 2000.
Nuclear operation and maintenance expenses increased approximately $7 million primarily due to the merger of Montaup’s
ownership percentage of Millstone 3 with the Company’s effective as of the merger date, as well as the effects of increased
expenses related to refueling outages and other maintenance at the Millstone 3 and Seabrook 1 nuclear generating units.
Other nonnuclear operation and maintenance expenses decreased approximately $5 million compared with the twelve months
ended December 31, 1999 primarily due to reduced pension and postretirement healthcare expenses and reduced transmission
costs. These decreases were partially offset by the receipt of a transmission wheeling refund that reduced expense in June
1999.
Depreciation and amortization expenses decreased approximately $24 million for the twelve months ended March 31, 2001
compared with the twelve months ended December 31, 1999. This decrease was primarily related to decreased CTC amortization
as a result of the full recovery of the Company’s CTC-related costs associated with its generating plants and regulatory
assets (excluding Montaup’s) at the end of 2000. This decrease was partially offset by the Company’s payments to increase
the Millstone 3 decommissioning trust fund to the level prescribed in the Release and Settlement Agreement with Northeast
Utilities (NU) (see the “Millstone 3” disclosure in the “Nuclear units” section), as well as the effect of the addition of
Montaup’s ownership percentage of Millstone 3 effective as of the merger date.
Operating expenses for the three months ended March 31, 2000, decreased approximately $27 million compared with the same
period in 1999.
The increase in fuel and purchased power expense of approximately $5 million reflected increased purchased power expenses
for standard offer requirements and increased kWh 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 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 approximately $23 million
compared with the same period in 1999. This decrease was due to additional CTC amortization in 1999 related to the
additional payment of approximately $21 million by Narragansett Electric to the Company, discussed above.
Other Income and Expense
Other income-net for the twelve months ended March 31, 2002 increased approximately $13 million compared with the same
period in 2001. The increase is due primarily to the cessation of goodwill amortization as a result of the adoption of FAS
142 and an increase in allowance for equity funds used during construction, partially offset by reduced earnings from the
Yankees and decreased interest income from other investing activities.
Other income-net for the twelve months ended March 31, 2001 increased approximately $4 million compared with the twelve
months ended December 31, 1999 primarily due to increased earnings from the Yankees, partially offset by a decrease in
allowance for equity funds used during construction.
The amortization of goodwill during fiscal 2001 of approximately $18 million resulted from the mergers with National Grid
and EUA.
Other income- net for the three months ended March 31, 2000 increased compared with the same period in 1999 as a result of
decreased expenses related to employee incentive plans from workforce reductions following the divestiture, partially
offset by merger related expenses in 2000.
Interest Expense
Interest expense for the twelve months ended March 31, 2002 decreased approximately $7 million compared with the same
period in 2001 primarily due to decreased interest rates on the Company’s variable-rate long-term debt and the refinancing
of short-term debt.
Interest expense increased approximately $8 million for the twelve months ended March 31, 2001 compared with the twelve
months ended December 31, 1999 primarily due to higher interest rates on variable rate long-term debt and increased
short-term debt borrowings, as well as interest related to Montaup’s CTC settlement.
Interest expense for the three months ended March 31, 2000 increased approximately $1 million compared with the same period
in 1999 primarily due to increased interest rates on variable rate long-term debt and interest on short-term debt
borrowings not present in 1999.
Nuclear Units
Nuclear Units Permanently Shut Down
Three of the Yankees in which the Company has a minority interest own nuclear generating units that have been permanently
shut down. These three units are as follows:
- --------------------------------------------- ---------------------------------- ----------------------- ------------------------
Future Estimated
The Company’s Investment as of Billings to the Company
3/31/02
Unit % $(millions) Date Retired $(millions)
- --------------------------------------------- ---------------- ----------------- ----------------------- ------------------------
Yankee Atomic 34.5 0.4 Feb 1992 0
Connecticut Yankee 19.5 13 Dec 1996 44
Maine Yankee 24.0 15 Aug 1997 123
Yankee Atomic has discontinued further billings to the Company subject to a final reconciliation of costs once
decommissioning at the plant has been completed. For Maine Yankee and Connecticut Yankee, the Company has recorded a
liability and a regulatory asset reflecting the estimated future billings from the companies.
Under the provisions of the Company’s industry restructuring settlement agreements approved by state and federal regulators
in 1998, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to
the Company.
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.
Maine Yankee had previously hired Stone and Webster, Inc. (S and W), an engineering, construction, and consulting company, as the
principal contractor to decommission the unit. In May 2000, Maine Yankee terminated its long-term contract with S and W and
negotiated an arrangement with S and W to continue work through June 2000. In June 2000, S and W filed for Chapter 11 bankruptcy
protection. Subsequently, Maine Yankee decided to self-manage the unit’s decommissioning process. In June 2000, Federal
Insurance Company (Federal) filed a complaint in S and W’s bankruptcy proceedings, subsequently removed to US District Court in
Maine, which alleged that Maine Yankee improperly terminated its contract with S and W and that Federal should be excused from
a $39 million performance bond and a $12 million payment bond to Maine Yankee.
In December 2001, Maine Yankee and Federal reached a settlement. Pursuant to the settlement agreement, Federal paid Maine
Yankee $44 million in January 2002. Maine Yankee deposited the payment in its decommissioning trust fund. With regard to
Maine Yankee’s August 2000 damage claim against S and W in the bankruptcy proceeding for $78.2 million (later decreased to $21
million to reflect, among other things, the recovery of $44 million from Federal), on May 30, 2002, the bankruptcy judge
held that Maine Yankee had proved damages of $20.8 million and estimated its claim at that amount. However, the amount
Maine Yankee actually recovers will depend on the magnitude of assets in the bankrupt estate available to pay creditors’
claims.
At Maine Yankee and Yankee Atomic, the contractor responsible for the movement of spent fuel from wet storage to dry
storage has incurred delays. Connecticut Yankee has experienced delays in its decommissioning process due to zoning and
other issues most of which are now resolved.
Due to rate recovery mechanisms, the S and W claims and decommissioning delays are not expected to materially affect the
Company’s earnings.
Operating Nuclear Units
The Company has minority interests in two operating nuclear generating units that the Company is engaged in efforts to
divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its 16.2 percent interest in Millstone 3 to Dominion
Resources, Inc. (Dominion) on March 31, 2001. Until such time as the Company divests its operating nuclear interests, 80
percent of the revenues and reasonable operating costs related to the units will be allocated to the customers through
CTCs, with shareholders being allocated the balance. Net proceeds attributed to the divestiture of the units will be
allocated to customers through CTC.
Vermont Yankee
The following table summarizes the Company’s interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2002:
The Company’s Interest
(millions of dollars)
------------------------------------------------------------------------------------------------
Net Decommissioning
Equity Ownership Equity Plant Estimated Decommissioning Fund License
Interest (%) Investment Assets Cost (in 2001$) Balance Expiration
- ------------------- ----------------- ------------- ---------------------------------------- ----------------------- ----------------
23.9 $12 $34 $107 $63 2012
In December 2001, Vermont Yankee reached a settlement with four equity owners, other than the Company, agreeing to
repurchase the Vermont Yankee shares held by these minority shareholders for $230 per share. The repurchase was consummated
in January 2002 for approximately $5.4 million. As a result of the repurchase, the Company’s ownership interest in Vermont
Yankee increased from 22.5 percent to 23.9 percent.
On August 15, 2001, Vermont Yankee announced that it had reached an Agreement (the Agreement) to sell the Vermont Yankee
nuclear power plant to Entergy Corporation (Entergy) for $180 million. The Company’s portion of the sale price would be
approximately $43 million ($35 million for the plant and related assets and $8 million for nuclear fuel) based on its 23.9
percent ownership interest. The plant’s decommissioning trust fund would be transferred to Entergy, and Entergy would
assume decommissioning liability for the plant. As part of the transaction, Vermont Yankee owners, including the Company,
would purchase power from the plant through 2012. Net proceeds from the sale would be credited to the Company’s customers
through the CTC. The sale of the plant is contingent upon the receipt of regulatory approvals by the Securities and
Exchange Commission, under the 1935 Act, the FERC, the Nuclear Regulatory Commission (NRC), the Vermont Public Service
Board (VPSB), and other state regulatory commissions with jurisdiction over other equity owners of Vermont Yankee. The
FERC, the NRC and the VPSB have approved the sale. On June 21, 2002, Entergy filed a motion seeking reconsideration by the
VPSB of a condition in its order approving the sale. The condition rejected a provision in the Agreement entitling Entergy
to keep 50 percent of any property remaining in the decommissioning trust fund upon completion of decommissioning. The
Agreement with Entergy terminates if the sale is not completed by July 31, 2002.
The Company previously resold 11.8 MW of its Vermont Yankee entitlement to a number of municipal and cooperative
utilities (Secondary Purchasers) located in Massachusetts under a “Vermont Yankee Secondary Purchaser Agreement” which
had a 30-year term expiring on November 30, 2002. On May 16, 2002, the FERC approved an early termination of the
Secondary Purchasers contract effective February 28, 2002. Pursuant to the settlement, the Secondary Purchasers agreed
not to oppose the plant sale in any regulatory proceeding.
The Citizens of Brattleboro, and eight other towns in Vermont, cast non binding votes at town meetings in March 2002 on
whether Vermont Yankee should be shut down. In the nine towns that voted on the issue, a narrow majority chose to keep the
plant open.
Seabrook 1
The following table summarizes the Company’s interest in the Seabrook 1 nuclear generating unit as of March 31, 2002:
The Company’s share of (millions of dollars)
------------------------------------------------------------------------------
The Company’s Decommissioning
Ownership Net Estimated Decommissioning Fund License
Interest (%) Plant Assets Cost (in 2001$) Balance* Expiration
- ------------------- -------------- ---------------------------------------- ---------------------- ---------------
10 $17 ** $55 $19 2026
* Certain additional amounts are anticipated to be available through tax deductions.
** Represents post-December 1995 spending including nuclear fuel.
On April 15, 2002, eight of the 11 joint owners of Seabrook, including the Company, announced that they had reached an
agreement to sell an 88.2 percent interest in Seabrook to FPL Energy Seabrook LLC (FPL Seabrook), a subsidiary of FPL
Group, for $836.6 million. The Company’s portion of the gross sales proceeds would be approximately $93.5 million. Pursuant
to the terms of the Company’s restructuring settlements, 98 percent of the Company’s proceeds, net of expenses related to
the sale, post-1995 capital additions and inventories, will be returned to National Grid customers in Massachusetts, Rhode
Island, and New Hampshire. FPL Seabrook will assume responsibility for ultimate decommissioning of Seabrook and will
receive the Seabrook decommissioning funds, including a top-off payment by the Company and other sellers. Approvals for the
transaction are needed from federal and state regulatory agencies, including public utility commissions in the sellers’
states, the NRC, the New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC), the FERC, and the Department of
Justice or the Federal Trade Commission. The plant owners are targeting to complete the sale by the end of 2002.
Millstone 3
In November 1999, the Company entered into an agreement with Northeast Utilities (NU) to settle claims made by the
Company regarding the operation of Millstone 3. Among other things, the settlement provided for NU to include the
Company’s 16.2 percent interest in Millstone 3 in an auction of NU’s share of the unit. Upon the closing of the sale, the
Company was to receive a fixed amount, regardless of the actual sale price.
In August 2000, Dominion agreed to purchase the Millstone units, including the Company’s interest in Millstone 3, for $1.3
billion. In March 2001, the sale was completed. In accordance with the prior settlement agreement, the Company was paid
approximately $27.9 million, including $25 million for the plant, and the Company paid approximately $5.8 million to
increase the decommissioning trust fund.
Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed an intent to challenge the
reasonableness of the settlement agreement as the Company would have received approximately $140 million of sale proceeds
without the agreement. The dispute will be resolved by the FERC. The Company believes it has a strong argument that it
acted prudently since the amount received under the settlement agreement was the highest sale price for a nuclear unit at
the time the agreement was reached.
Plant Security Costs
In view of potential terrorist activity following the events of September 11, 2001, security at nuclear plants has been
enhanced in concert with NRC advisory notices. The increased cost to the Company for security was approximately $1 million
for the fiscal year ended March 31, 2002. The Company expects security costs to increase. Due to rate recovery mechanisms,
these costs will not materially affect the Company’s earnings.
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, 2002 and 2001, the Company's tax exempt variable rate long-term debt had a
carrying value and fair value of approximately $410 million. While the ultimate maturity dates of the underlying loan
agreements range from 2015 through 2022, this debt is issued in tax exempt commercial paper mode. The various components
that comprise this debt are issued for periods ranging from one day to 270 days, and are remarketed through remarketing
agents at the conclusion of each period. The weighted average variable interest rate for the year ended March 31, 2002, was
approximately 2.52 percent.
As discussed in the “Regulatory Environment” section, despite the 1998 termination of the Company’s all-requirements
contract with its affiliated distribution companies, the Company remained obligated to provide transition power supply
service to new customer load in Rhode Island at the standard offer price, but did not have a regulatory agreement that
allowed full recovery of the costs of such standard offer power. Consequently, the Company was at risk for the difference
between the actual cost of serving this load and the revenue received from this obligation. For the year ended March 31,
2002, the impact on the Company’s financial position was immaterial. Effective December 1, 2001, a third party assumed the
responsibility for providing transitional standard offer power service in Rhode Island, and the Company’s obligation
terminated.
Utility Plant Expenditures and Financing
Cash expenditures for the Company for utility plant totaled $47 million for the twelve months ended March 31, 2002 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 2003 are estimated to be approximately $34 million,
principally related to transmission functions. Internally generated funds are expected to fully cover capital expenditures
in fiscal year 2003.
At March 31, 2002 and 2001, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up
to $375 million of short-term debt.
At March 31, 2002 and 2001, the Company had lines of credit and standby bond purchase facilities with banks totaling $456
million which are available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt
commercial paper mode, and for other corporate purposes. There were no borrowings under these lines of credit at March 31,
2002.
The Company’s capital obligations consist of amounts for purchased power, long-term debt maturities and operating leases.
The purchased power commitments are other than those reflected in the liabilities section of the balance sheet. Payments by
fiscal year are as follows:
- --------------------------------------- ---------------------------------------------------------------------------------------
Capital Requirements Payments Due by March 31,
(in thousands) 2003 2004 2005 2006 2007 2008+
- --------------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
Purchased Power Commitments $72,620 $69,209 $58,629 $42,043 $46,024 $263,740
Long Term Debt Maturities - - - - - 410,285
Operating Leases 485 448 430 415 174 7
- --------------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
- ------- ------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
Total $73,105 $69,657 $59,059 $42,458 $46,198 674,032
- ------- ------------------------------- ------------- --------------- ------------- ------------- --------------- -------------
Merger with National Grid
On March 22, 2000, the merger of New England Electric System (NEES) and National Grid Group plc (National Grid) was
completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. The Company
maintained its existing name and remained a wholly owned subsidiary of National Grid USA. The merger was accounted for by
the purchase method, the application of which, including the recognition of goodwill, was 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 approximately $348 million. This amount was determined pursuant to a study conducted by
an independent third party.
The purchase accounting method requires the revaluation of assets and liabilities to their fair value. This revaluation
resulted in an adjustment to the Company’s pension and postretirement benefit accounts in the amount of approximately $61
million, with an offsetting net credit to a regulatory liability account.
Acquisition of EUA
The acquisition of EUA by National Grid USA was completed on April 19, 2000 for $642 million. On May 1, 2000, Montaup, was
merged into the Company.
The acquisition of EUA was accounted for by the purchase method, the application of which, including the recognition of
goodwill, has been pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including
the Company. Total goodwill recognized in this transaction was approximately $402 million, of which the Company was
allocated approximately $8 million. This amount was determined pursuant to a study conducted by an independent third party.
The purchase accounting method requires the revaluation of assets and liabilities to their fair value. This revaluation
resulted in an adjustment to the Company’s pension and postretirement benefit accounts in the amount of approximately $3
million, with an offsetting net credit to a regulatory liability account.
In connection with the mergers referred to above, the Company adjusted its pension and PBOP accounts in the amount of
approximately $64 million, with an offsetting net credit to a regulatory liability account. This adjustment eliminated any
unrecognized net gain or loss, unrecognized prior service cost, or unrecognized transition obligation of the Company. The
regulatory liability is being amortized over the service period to pension and postretirement health care costs.
Critical Accounting Policies:
There are certain critical accounting policies that are based on assumptions and conditions that if changed could have a
material effect on the financial condition, results of operations and liquidity of the Company. The following accounting
policies are particularly important to the financial condition and results of operations of the Company: regulatory
accounting and goodwill accounting.
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 SFAS 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 FASB 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.
The Company has 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, 2002, this amounted to approximately $1.5 billion, including $1.0 billion related
to the above-market costs of purchased power contracts, $0.2 billion related to accrued Yankee nuclear plant costs, and
$0.3 billion related to other net CTC regulatory assets.
The Company applies the provisions of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible
Assets” (FAS 142). In accordance with FAS 142, goodwill must be reviewed for impairment within six months of adoption
(“transitional goodwill impairment test”), and at least annually thereafter. The Company utilized a discounted cash flow
approach incorporating its most recent business plan forecasts in the performance of the transitional goodwill impairment test and the
annual goodwill impairment test. The result of the transitional and annual analyses determined that no adjustment to the goodwill
carrying value was required.
For further discussion of Critical Accounting Policies see “Note A-Significant
Accounting Policies” and “Note B-Regulatory Environment and Accounting Implications”.
New Accounting Standards:
The Company adopted Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”
(FAS 142), effective April 1, 2001, the beginning of the 2002 fiscal year. FAS 142 requires that goodwill no longer be
amortized on a ratable basis. The following table presents pro forma information for the year ended March 31, 2001, and
the three months ended March 31, 2000, to reflect the reversal of goodwill amortization in accordance with FAS 142:
Year Ended Three Months Ended
March 31, 2001 March 31, 2000
(In thousands)
Net income, as reported $58,300 $14,462
Reversal of goodwill amortization 17,905 366
Proforma net income $76,205 $14,828
In accordance with FAS 142, goodwill must be reviewed for impairment within six months of adoption (“transitional goodwill
impairment test”), and at least annually thereafter. The Company utilized a discounted cash flow approach incorporating its
most recent business plan forecasts in the performance of the transitional goodwill impairment test and the annual goodwill
impairment test. The result of the transitional and annual analyses determined that no adjustment to the goodwill carrying
value was required.
FAS 142 also requires that recognizable intangible assets be amortized over their useful lives and tested for impairment.
Intangible assets with indefinite useful lives should be reviewed for impairment. The Company has concluded a review of its
intangible assets and no adjustment was deemed necessary effective with the adoption of FAS 142.
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, “Accounting for Derivative Instruments
and Hedging Activities”. In June 2000, the FASB issued SFAS No. 138, “Accounting for Certain Derivative Instruments and
Certain Hedging Activities“. These accounting pronouncements require that an entity recognize derivative instruments as
either assets or liabilities in the statement of financial position and the measure of those instruments at fair value. The
Company adopted the pronouncements effective at the beginning of fiscal 2002. The standards have not materially affected
the Company’s financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the
accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently evaluating the impact
of this standard on its financial position and results of operations.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (FAS 144).
FAS 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of” (FAS 121) and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30,
“Reporting the Results of Operations – Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions”, related to the disposal of a segment of a business. FAS 144 establishes a
single accounting model for long–lived assets to be disposed of by sale and resolves significant implementation issues
related to FAS 121. FAS 144 is effective for fiscal years beginning after December 15, 2001. The Company is currently
evaluating the impact of this standard on its financial position and results of operations.
In April 2002, the FASB issued SFAS No. 145, “Recision of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,”
SFAS No. 44, “Accounting for Intangible Assets of Motor Carriers,” and SFAS No. 64, “Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements.” The Statement amends SFAS No. 13, “Accounting for Leases,” to eliminate certain
inconsistencies. It also amends other existing authoritative pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed circumstances. Certain provisions of the standard are required to be
adopted for transactions occurring after May 15, 2002; other provisions are required to be adopted for financial statements
issued after May 15, 2002. The Company is currently evaluating the impact of this standard on its financial position and
results of operations.
New England Power Company, (the Company) a wholly owned subsidiary of National Grid USA, 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 all these states (except Connecticut),
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 facilities are part of National Grid USA’s transmission operations, which are represented under the name
National Grid Transmission USA.
Report of Independent Accountants
To the Stockholders and Board of Directors of
New England Power Company:
In our opinion, the accompanying balance sheets and the related statements of income, of comprehensive income, of
retained earnings, and of cash flows present fairly, in all material respects, the financial position of New England Power
Company at March 31, 2002 and 2001, and the results of its operations and its cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States of America. 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 of America, 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 our opinion.
As described in Note A-8, effective April 1, 2001, the Company changed its method of accounting for goodwill and other
intangible assets.
S:/PricewaterhouseCoopers LLP
Boston, Massachusetts
May 14, 2002, except for Note E-1,
as to which the date is June 21, 2002
Report of Independent Accountants
To the Stockholders and Board of Directors of
New England Power Company:
In our opinion, the accompanying statements of income, of comprehensive income, of retained earnings, and of cash flows present fairly,
in all material respects, the results and operations of New England Power Company and its cash flows for the three-month period ended
March 31, 2000 and the year ended December 30, 1999, in conformity with accounting principles generally accepted in the United States of
America. 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 of America, 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 our opinion.
S:/PricewaterhouseCoopers LLP
Boston, Massachusetts
May 14, 2002, except for Note E-1,
as to which the date is June 21, 2002
Statements of Income
================================================= ========================= ============================== ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================= ============ ============ ============== =============== ==================
================================================= ============ ============ ============== =============== ==================
Operating revenue, principally from $560,418 $656,272 $134,564 $167,177 $596,341
affiliates
Operating expenses:
Fuel for generation 5,428 14,342 3,548 3,058 12,803
Purchased electric energy:
Contract termination and
nuclear unit shutdown
charges 229,549 214,948 47,405 46,873 187,777
Other 68,675 91,844 14,682 11,111 56,731
Other operation 56,769 69,624 15,760 19,210 70,936
Maintenance 17,266 31,748 4,320 5,766 28,536
Depreciation and amortization
(Note A-4) 30,601 78,762 16,962 40,367 103,080
Taxes, other than income taxes
(Note K) 18,183 22,343 5,561 5,634 20,282
Income taxes (Note G) 47,593 44,946 9,641 13,100 37,633
- -------- ---------------------------------------- ------------ ------------ -------------- --------------- ------------------
- -------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
Total operating expenses 474,064 568,557 117,879 145,119 517,778
- -------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Operating income 86,354 87,715 16,685 22,058 78,563
Other income(expense):
Allowance for equity funds used
during construction 1,077 276 (393) 588 1,958
Equity in income of nuclear
power companies 3,332 6,703 862 515 2,939
Amortization of goodwill (Note A-8) - (17,905) (366) - -
Other income, net 791 3,559 1,850 434 2,087
- -------- ---------------------------------------- ------------ ------------ -------------- --------------- ------------------
- -------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
Operating and other income 91,554 80,348 18,638 23,595 85,547
- -------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Interest:
Interest on long-term debt 11,434 17,834 3,749 3,143 14,052
Other interest 3,509 4,883 853 240 1,003
Allowance for borrowed funds
used during construction (163) (669) (426) (133) (522)
- -------- ---------------------------------------- ------------ ------------ -------------- --------------- ------------------
- -------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
Total interest 14,780 22,048 4,176 3,250 14,533
- -------- ----- ---------------------------------- ------------ ------------ -------------- --------------- ------------------
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Net income $ 76,774 $ 58,300 $ 14,462 $ 20,345 $ 71,014
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
The accompanying notes are an integral part of these financial statements.
Statements of Comprehensive Income
================================================= ========================= ============================== ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================= ============ ============ ============== =============== ==================
================================================= ============ ============ ============== =============== ==================
Net Income $ 76,774 $ 58,300 $ 14,462 $ 20,345 $ 71,014
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Unrealized gain (loss) on securities, net of tax 35 (145) 17 1 19
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Comprehensive income (Note A-9) $ 76,809 $ 58,155 $ 14,479 $ 20,346 $ 71,033
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Statements of Retained Earnings
================================================= ========================= ============================== ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================= ============ ============ ============== =============== ==================
================================================= ============ ============ ============== =============== ==================
Retained earnings at beginning of period $ 60,110 $ 1,415 $ 27,287 $204,603 $ 204,603
Net income 76,774 58,300 14,462 20,345 71,014
Dividends declared on cumulative
preferred stock (86) (91) (24) (24) (94)
Dividends declared on common stock,
-0-, $-0-, $6.66, $-0-, and $66.69, per
share, respectively - - (24,098) - (241,415)
Gain on redemption of preferred stock - 21 - - 264
Repurchase of common stock - - - (7,085) (7,085)
Purchase accounting adjustment - - (16,212) - -
Acquisition adjustment - 465 - - -
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
Retained earnings at end of period $136,798 $60,110 $1,415 $217,839 $27,287
- ------------------------------------------------- ------------ ------------ -------------- --------------- ------------------
The accompanying notes are an integral part of these financial statements.
Balance Sheets
======================================================================================= ==================== ====================
At March 31 (In thousands) 2002 2001
======================================================================================= ==================== ====================
======================================================================================= ==================== ====================
Assets
Utility plant, at original cost $ 909,043 $846,935
Less accumulated provisions for depreciation and amortization 329,927 320,238
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
579,116 526,697
Construction work in progress 7,466 34,946
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
Net utility plant 586,582 561,643
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
Goodwill 338,188 338,188
Investments:
Nuclear power companies, at equity (Note D-1) 40,339 46,474
Decommissioning trust funds (Note E-1) 18,810 16,331
Nonutility property and other investments 11,515 14,374
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
Total investments 70,664 77,179
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
Current assets:
Cash and temporary cash investments (including $99,300 103,467 22,360
and $22,075 with affiliates)
Accounts receivable, (less reserves of $153 and $153)
Affiliated companies 41,408 61,191
Others 67,460 89,483
Fuel, materials, and supplies, at average cost 6,215 6,289
Prepaid and other current assets 1,402 2,051
Regulatory assets - purchased power obligations and accrued Yankee nuclear 172,556 174,441
plant costs
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
Total current assets 392,508 355,815
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
Regulatory assets (Note B) 1,297,079 1,506,226
Deferred charges and other assets 55,184 50,170
- --------------------------------------------------------------------------------------- -------------------- --------------------
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
$2,740,205 $2,889,221
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share, Authorized - 6,449,896 shares
Outstanding – 3,619,896 shares $ 72,398 $ 72,398
Other paid-in capital 731,974 731,974
Retained earnings 136,798 60,110
Accumulated other comprehensive loss (Note A-9) (110) (145)
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
Total common equity 941,060 864,337
Cumulative preferred stock, par value $100 per share (Note I) 1,436 1,436
Long-term debt 410,285 410,279
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
Total capitalization 1,352,781 1,276,052
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
Current liabilities:
Accounts payable (including $14,059 and $25,287 to affiliates) 47,358 66,017
Accrued liabilities:
Taxes 14,367 39,451
Interest 773 1,489
Purchased power obligations and accrued Yankee nuclear plant costs 172,556 174,441
Other accrued expenses 3,094 7,621
Dividends payable 22 22
- ------ -------------------------------------------------------------------------------- -------------------- --------------------
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
Total current liabilities 238,170 289,041
- ------ ---- --------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
Deferred federal and state income taxes 257,302 272,304
Unamortized investment tax credits 8,795 9,312
Accrued Yankee nuclear plant costs (Note E-1) 141,869 156,477
Purchased power obligations 513,599 636,848
Other reserves and deferred credits 227,689 249,187
Commitments and contingencies (Note E)
- --------------------------------------------------------------------------------------- -------------------- --------------------
- --------------------------------------------------------------------------------------- -------------------- --------------------
$2,740,205 $2,889,221
- --------------------------------------------------------------------------------------- -------------------- --------------------
The accompanying notes are an integral part of these financial statements.
Statements of Cash Flows
================================================= ========================= ============================== ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================= ============ ============ ============= ================ ==================
================================================= ============ ============ ============= ================ ==================
Operating activities:
Net income $76,774 $58,300 $ 14,462 $ 20,345 $71,014
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 86,383 85,123 18,799 42,170 108,789
Amortization of goodwill - 17,905 366 - -
Deferred income taxes and investment tax
credits, net (16,072) (11,480) (2,908) 5,726 14,111
Allowance for funds used during
construction (1,240) (945) (33) (720) (2,480)
Buyout of purchased power contracts - - - - (3,472)
Changes in assets and liabilities, net of
effects of acquisition:
Decrease (increase) in accounts
receivable, net 16,806 (7,914) (3,174) 37,890 22,706
Decrease (increase) in fuel,
materials, and supplies 74 4,160 (874) 648 (251)
Decrease in regulatory assets 145,949 152,533 60,044 82,801 166,730
Decrease (increase) in prepaid and
other current assets 649 26,501 13,938 6,154 (17,746)
Decrease in accounts payable (18,659) (813) (11,628) (81,950) (99,148)
Decrease in purchased power
contract obligations (127,069) (77,039) (16,947) (36,903) (128,931)
Increase (decrease) in other
current liabilities (30,327) 30,822 (7,787) (11,147) (14,575)
Increase (decrease) in other
non-current liabilities (34,171) (147,847) 20,349 (5,661) 45,483
Other, net 413 73,202 (49,869) (40,946) (87,277)
- ------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
- ------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
Net cash provided by operating $99,510 $ 202,508 $ 34,738 $ 18,407 $74,953
activities
- ------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
- ------------------------------------------------- ------------ ------------ ------------- ---------------- ------------------
Investing activities:
Proceeds from sale of generating assets $25,000 - - - -
Plant expenditures, excluding allowance for
funds used during construction (46,927) (56,558) (11,890) (13,739) (56,887)
Other investing activities 3,610 (3,270) (271) (20) (4,411)
- ------------------------------------------------- ------------ ------------ ------------- ---------------- ------------------
- ------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
Net cash used in investing $(18,317) $ (59,828) $(12,161) $(13,759) $ (61,298)
activities
- ------ ----- ------------------------------------ ------------ ------------ ------------- ---------------- ------------------
The accompanying notes are an integral part of these financial statements.
Statements of Cash Flows – (continued)
================================================= =========================== ============================= ===================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================= ============ ============== ============= =============== ===================
================================================= ============ ============== ============= =============== ===================
Financing activities:
Dividends paid on common stock $
$ - $(256,463) - $ - $ (9,050)
Dividends paid on preferred stock (86) (93) - (24) (118)
Changes in short-term debt - (38,500) - - 38,500
Long-term debt – issues - 38,500 - - -
Long-term debt – retirements - (90,575) - - -
Repurchase of common shares - - - (18,056) (18,056)
Preferred stock – retirements - (110) - - -
- ------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
- ------------ ------------------------------------ ------------ -------------- ------------- --------------- -------------------
Net cash provided by (used in) $ (86) $(347,241) - $(18,080) $11,276
financing activities
- ------------ ------------------------------------ ------------ -------------- ------------- --------------- -------------------
- ------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
Net increase (decrease) in cash and cash $81,107 $(204,561) $22,577 $(13,432) $24,931
equivalents
Cash and cash equivalents at beginning of period 22,360 226,921 204,344 179,413 179,413
- ------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
- ------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
Cash and cash equivalents at end of period $103,467 $ 22,360 $226,921 $165,981 $204,344
- ------------------------------------------------- ------------ -------------- ------------- --------------- -------------------
Supplementary Information:
Interest paid, less amounts capitalized $10,734 $18,296 $ 5,322 $ 2,042 $11,849
Federal and state income taxes paid (refunded) $90,810 $(3,233) $ (15) $ 11,321 $55,134
Dividends received from investments at equity $ 3,812 $13,986 $ 1,129 $ 1,730 $ 5,243
- ------------------------------------------------- ------------ ------------- -------------- --------------- ------------------
The accompanying notes are an integral part of these financial statements.
New England Power Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of Operations:
New England Power Company (the Company), a wholly owned subsidiary of National Grid USA, 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 (except Connecticut),
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. The Company’s transmission facilities are part of National Grid USA’s transmission operations, which are
represented under the name National Grid Transmission USA. In addition, the Company also owns a minority interest in one
joint owned nuclear generating unit and one fossil fuel generating unit, 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 and used to serve the Company’s load obligation.
2. System of Accounts:
The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory
bodies having jurisdiction.
National Grid USA and its subsidiaries changed their fiscal year in 2000 from a calendar year ending December 31 to a
fiscal year ending March 31. National Grid USA and its subsidiaries made this change in order to align their fiscal years
with that of National Grid Group plc. The Company’s first new full fiscal year began on April 1, 2000 and ended on March
31, 2001. The accompanying financial information as of March 31, 2002 and 2001, and for the years ended March 31, 2002 and
2001, reflects the new basis of accounting established for the Company’s assets and liabilities in connection with the
acquisition of National Grid USA by National Grid on March 22, 2000. The audited results of operations for the three month
period ended March 31, 2000 includes an immaterial amount of goodwill amortization for the ten day period from March 22 to
March 31, 2000. Due to the immateriality of this effect, this transitional period has not been separated into the period
preceding and the period following the pushdown of goodwill.
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 2002 presentation.
3. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC represents an allowance for the cost of funds used to
finance construction. 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 8.1 percent for the year ended March 31, 2002, 3.2 percent for
the year ended March 31, 2001, 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 for the year ended December 31, 1999.
4. Depreciation and Amortization:
The depreciation and amortization expense included in the statements of income is composed of the following:
================================================= ========================= ============================== ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
Depreciation - transmission related $16,238 $15,055 $ 3,269 $ 3,440 $ 13,222
Depreciation - all other 1,093 5,477 (15) 354 1,286
Nuclear decommissioning costs
(Note E-1) 2,394 9,901 923 699 3,637
Amortization:
Regulatory assets covered by contract
termination charges (Note B) 10,876 48,329 12,785 35,874 84,935
Total depreciation and -------------------------------------------------------------------------
amortization expense $ 30,601 $78,762 $16,962 $40,367 $103,080
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 all periods presented. Amortization of regulatory assets
covered by contract termination charges (CTC) is in accordance with rate settlement agreements.
5. Cash:
The Company classifies short-term investments with a maturity at purchase date of 90 days or less as cash.
6. Property, Plant, and Equipment:
The Company’s integrated system of transmission property consists of approximately 2,800 circuit miles of transmission
lines and 119 substations.
7. Income Taxes:
Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax
assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable
to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and
liabilities (see Note G).
8. New Accounting Standards:
The Company adopted Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”
(FAS 142), effective April 1, 2001, the beginning of the 2002 fiscal year. FAS 142 requires that goodwill no longer be
amortized on a ratable basis. The following table presents pro forma information for the year ended March 31, 2001, and
the three moths ended March 31, 2000, to reflect the reversal of goodwill amortization in accordance with FAS 142:
Year Ended Three Months Ended
March 31, 2001 March 31, 2000
(In thousands)
Net income, as reported $58,300 $14,462
Reversal of goodwill amortization 17,905 366
Proforma net income $76,205 $14,828
In accordance with FAS 142, goodwill must be reviewed for impairment within six months of adoption (“transitional goodwill
impairment test”), and at least annually thereafter. The Company utilized a discounted cash flow approach incorporating its
most recent business plan forecasts in the performance of the transitional goodwill impairment test and the annual goodwill
impairment test. The result of the transitional and annual analyses determined that no adjustment to the goodwill carrying
value was required.
FAS 142 also requires that recognizable intangible assets be amortized over their useful lives and tested for impairment.
Intangible assets with indefinite useful lives should be reviewed for impairment. The Company has concluded a review of its
intangible assets and no adjustment was deemed necessary effective with the adoption of FAS 142.
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No. 133, “Accounting for Derivative Instruments
and Hedging Activities“. In June 2000, the FASB issued SFAS No. 138, “Accounting for Certain Derivative Instruments and
Certain Hedging Activities”. These accounting pronouncements require that an entity recognize derivative instruments as
either assets or liabilities in the statement of financial position and the measure of those instruments at fair value. The
Company adopted the pronouncements effective at the beginning of fiscal 2002. The standards have not materially affected
the Company’s financial position or results of operations.
In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (FAS 143). FAS 143 provides the
accounting requirements for retirement obligations associated with tangible long-lived assets. FAS 143 is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently evaluating the impact
of this standard on its financial position and results of operations.
In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (FAS 144).
FAS 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of” (FAS 121) and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30,
“Reporting the Results of Operations – Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions”, related to the disposal of a segment of a business. FAS 144 establishes a
single accounting model for long–lived assets to be disposed of by sale and resolves significant implementation issues
related to FAS 121. FAS 144 is effective for fiscal years beginning after December 15, 2001. The Company is currently
evaluating the impact of this standard on its financial position and results of operations.
In April 2002, the FASB issued SFAS No. 145, “Recision of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections.” SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,”
SFAS No. 44, “Accounting for Intangible Assets of Motor Carriers,” and SFAS No. 64, “Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements.” The Statement amends SFAS No. 13, “Accounting for Leases,” to eliminate certain
inconsistencies. It also amends other existing authoritative pronouncements to make various technical corrections, clarify
meanings or describe their applicability under changed circumstances. Certain provisions of the standard are required to be
adopted for transactions occurring after May 15, 2002; other provisions are required to be adopted for financial statements
issued after May 15, 2002. The Company is currently evaluating the impact of this standard on its financial position and
results of operations.
9. Comprehensive Income:
Comprehensive income consists of net income and other gains and losses affecting common equity that, under generally
accepted accounting principles, are excluded from net income. Comprehensive income is presented net of tax. For the
fiscal years ended March 31, 2002 and 2001, and the three month periods ended 2000 and 1999 and for the year ended
December 31, 1999, tax charge (benefit) related to comprehensive income were approximately $22,000, ($94,000), $11,000, $1,000
and $12,000, respectively. For the Company, the components of accumulated other comprehensive (loss) consist of unrealized gains and
losses on marketable equity investments.
Note B – Regulatory Environment and Accounting Implications
Prior to divesting substantially all of its nonnuclear generation business in 1998, the Company was the wholesale supplier
of the electric energy requirements to its retail distribution affiliates as well as unaffiliated customers. The Company’s
all–requirements contracts with its affiliated distribution companies, as well as with some unaffiliated customers, were
generally terminated pursuant to settlement agreements and tariff provisions in 1998. However, the Company remained
obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but
did not have a regulatory agreement that necessarily allowed full recovery of the costs of such standard offer power.
Consequently, the Company was at risk for the difference between the actual cost of serving this load and the revenue
received from this obligation. For the year ended March 31, 2002, the impact on the Company’s financial position was
immaterial. Effective December 1, 2001, a third party assumed the responsibility for providing transitional standard offer
power service in Rhode Island, and the Company’s obligation terminated.
Under 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 (including Montaup Electric Company’s (Montaup), a former Eastern
Utilities Associates (EUA) subsidiary) 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
2009 and earn a return on equity (ROE) 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 ROE. 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.
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.
Similar to the Company, Montaup also transferred its purchased power obligations as part of the divestiture and in return
agreed to make fixed monthly payments. These fixed monthly payments by the Company, inclusive of Montaup’s share, average
approximately $11 million per month through December 2009 toward the above-market cost of those contracts. The liability
relating to purchased power obligations, which is also reflected in regulatory assets, represents the net present value of
these fixed monthly payments. At March 31, 2002, the net present value is approximately $659 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 $453 million), which were separate from the $659
million figure referred to above.
FERC Proceedings
In general, the regulatory structure and regulations which relate to the Company's business are in a period of major
change and uncertainty. Decisions being made by the Federal Energy Regulatory Commission (FERC) and the Independent
System Operator-New England (ISO New England) will affect how the Company does business and whether it can enter new
endeavors. The Company is currently unable to determine whether these proceedings will have a material impact on its
financial position or results of operations.
The FERC has been reviewing the development of regional transmission organizations (RTOs). The FERC has indicated that it
wants RTOs to have large geographic scope. In July and August, 2001, the FERC ordered National Grid USA and other New
England parties and participants of the New York Independent System Operator (ISO), and the Pennsylvania-New
Jersey-Maryland (PJM) ISO to participate in a mediation process to develop a proposal for a larger RTO. The FERC has not
yet ruled on the mediation report issued in September 2001. Pending the ruling on the mediation report, the transmission
owners have been working toward a hybrid RTO structure in which an independent transmission company would manage the
transmission grid for the RTO and an independent market administrator would manage power markets for the RTO. However, it
is not clear what sort of RTO structure will ultimately result from these negotiations. In fact, based on a January 29,
2002 filing by the New York and New England ISOs to form their own RTO, even the geographic scope of the RTO in which the
Company will participate is still an open question.
In late 2001 and early 2002, the FERC convened an advanced rulemaking proceeding to enable transmission owners, such as the
Company, and generators to establish standardized procedures and agreements concerning the way generators would
interconnect with the transmission grid. On April 24, 2002, the FERC issued proposed rules very favorable to generators and
unfavorable, and, the Company believes, at times unworkable, for transmission owners. The Company has submitted
comments seeking significant changes in the proposed rules. The FERC is expected to issue final rules later this
year.
In 2001, the FERC began an advanced rulemaking procedure to address Standard Market Design regarding the buying and selling
of power. In a December 2001 order, the FERC requested that all industry segments try to agree on a single standards
setting organization that would establish national standard business practices for the wholesale electric industry. The
FERC has also solicited comments on a wide range of issues, including: transmission pricing, pricing for electric energy
and capacity, transmission planning, generation dispatch, RTO governance, market monitoring, long term generation adequacy
(including installed capacity or “ICAP”), and resolution of “seams” – or conflicting practices or charges that inhibit
inter-regional energy transactions. All of these either directly or indirectly affect the Company’s business. It is
anticipated that the FERC will launch a formal notice of proposed rulemaking proceeding this summer.
NEPOOL and ISO New England have a separate standard market design initiative which is proceeding in parallel to the FERC
initiative. It is expected that either New England Power Pool (NEPOOL) or ISO New England will file a proposal to conform
the procedures by which energy is bought and sold in New England to those of PJM with the FERC this summer for
implementation by December 2002 or early 2003.
To the extent the Company wishes to pursue opportunities to manage or to be a member of an independent transmission company
or an RTO, with the opportunity to propose financial incentives to deliver greater value for customers and shareholders,
the FERC rulings in the standard market design proceeding and other proceedings may have an impact on the ability to do so.
In June 2001, the FERC issued an order relating to (NEPOOL’s proposed congestion management and multi–settlement systems.
In the June Order, the FERC found that “energy uplift” costs (which had been about $9 million per month for NEPOOL in 2000)
should be allocated on the basis of reliance on the energy markets administered by the ISO New England. This would have the
effect of relieving parties that procure power under bilateral contracts (such as the Company) from paying energy uplift
charges. However, the NEPOOL Participants Committee and ISO New England submitted a filing in July 2001 that the Company
believed did not comport with the FERC's order. The Company protested the filing, and received a favorable order from the
FERC on February 15, 2002. Nevertheless, the NEPOOL Participants Committee and ISO New England submitted another filing on
March 18, 2002 that the Company believes does not comport with the FERC's orders, and the Company has again filed another
protest.
On September 27, 2001, the FERC initiated a notice of proposed rulemaking regarding affiliate standards of conduct in both
the electric and gas industries. In its proposed rules, the FERC proposed a broad definition of “energy affiliate”, which
would include its affiliate National Grid USA Service Company, Inc. (Service Company) as well as the Company’s electric
distribution company affiliates. The proposed rules would impose significant restrictions on the ability of the Company to
interact with such “energy affiliates.” If not modified, the proposed rules could require significant reorganization for
the Company and possibly duplication of support functions that the Company depends on the Service Company to provide.
As previously reported, there has been litigation regarding a FERC order to increase the ICAP deficiency charge to $8.75
per kilowatt-month (kW-month) instead of the rate proposed by ISO New England of $0.17 per kW-month. In June 2001, after
significant litigation and a remand from the US Court of Appeals for the First Circuit, ISO New England made a Compliance
Filing with the FERC proposing a compromise ICAP regime, including an ICAP deficiency charge of $4.87 per kW-month. On
September 28, 2001, the FERC issued an order refusing to apply retroactively the $8.75 per kW-month deficiency charge for
the period January to June 2000. On November 20, 2001, the FERC issued an order on rehearing of the August order requiring
ISO New England to establish a prospective ICAP regime (i.e., one under which utility ICAP purchase requirements are known
in advance) in lieu of a retrospective requirement with a cure period. It is unclear what system will replace the ICAP
regime in the future. The issue of the appropriate ICAP deficiency charge for the period January to July 2000, is currently
back before the US Court of Appeals for the First Circuit for resolution. FERC is also now addressing complaints by power
marketers about how ICAP should have been charged for the period January to July 2000. Both of these proceedings will
likely affect the Company’s ICAP exposure.
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 SFAS 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 FASB 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.
The Company has 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, 2002, this amounted to approximately $1.5 billion, including $1.0 billion related
to the above-market costs of purchased power contracts, $0.2 billion related to accrued Yankee nuclear plant costs, and
$0.3 billion related to other net CTC regulatory assets.
Note C – Mergers and Acquisitions
Merger with National Grid
On March 22, 2000, the merger of New England Electric System (NEES) and National Grid Group plc (National Grid) was
completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. The Company
maintained its existing name and remained a wholly owned subsidiary of National Grid USA. The merger was accounted for by
the purchase method, the application of which, including the recognition of goodwill, was 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 approximately $348 million. This amount was determined pursuant to a study conducted by
an independent third party.
The purchase accounting method requires the revaluation of assets and liabilities to their fair value. This revaluation
resulted in an adjustment to the Company’s pension and postretirement benefit accounts in the amount of approximately $61
million, with an offsetting net credit to a regulatory liability account.
Acquisition of EUA
The acquisition of EUA by National Grid USA was completed on April 19, 2000 for $642 million. On May 1, 2000, Montaup,
formerly a subsidiary of EUA, was merged into the Company.
The acquisition of EUA was accounted for by the purchase method, the application of which, including the recognition of
goodwill, has been pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including
the Company. Total goodwill recognized in this transaction was approximately $402 million, of which the Company was
allocated approximately $8 million. This amount was determined pursuant to a study conducted by an independent third party.
The purchase accounting method requires the revaluation of assets and liabilities to their fair value. This revaluation
resulted in an adjustment to the Company’s pension and postretirement benefit accounts in the amount of approximately $3
million, with an offsetting net credit to a regulatory liability account.
In connection with the mergers referred to above, the Company adjusted its pension and PBOP accounts in the amount of
approximately $64 million, with an offsetting net credit to a regulatory liability account. This adjustment eliminated any
unrecognized net gain or loss, unrecognized prior service cost, or unrecognized transition obligation of the Company. The
regulatory liability is being amortized over the service period to pension and postretirement health care costs.
Note D – Accounting for Nuclear Power Companies
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. Three of the Yankees have been permanently shut down, and one is operating. The Company has power
contracts with each of the Yankees that require the Company to pay an amount equal to its share of total fixed and
operating costs (including decommissioning costs) of the plant plus a return on equity. The Company’s share of the expenses
of the Yankees is accounted for in “Purchased electric energy” on the income statement.
===================================== =================================== ================================= ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
===================================== =============== =================== ================ ================ ==================
===================================== =============== =================== ================ ================ ==================
Operating revenue $ 284,663 $ 291,628 $ 81,225 $ 89,244 $ 377,039
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Net income $ 14,711 $ 29,589 $ 5,310 $ 5,138 $ 13,890
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Company’s equity in net income $ 3,332 $ 6,703 $ 862 $ 515 $ 2,939
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Net plant 143,182 160,701 167,317 166,062 172,100
Other assets 1,812,032 1,893,733 2,520,887 2,798,948 2,631,750
Liabilities and debt (1,775,130) (1,855,775) (2,437,609) (2,707,749) (2,554,261)
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Net assets $ 180,084 $ 198,659 $ 250,595 $ 257,261 $ 249,589
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
Company’s equity in net assets $ 40,339 $ 46,474 $ 45,966 $ 47,323 $ 46,233
- ------------------------------------- --------------- ------------------- ---------------- ---------------- ------------------
- ----------------------------------------------------- ------------------- ---------------- ---------------- ------------------
Company's purchased electric energy:
Vermont Yankee $33,031 $ 31,899 $ 7,761 $ 7,874 $ 37,551
All other Yankees $24,420 $ 21,616 $ 9,324 $ 9,370 $ 37,765
- ------ ------------------------------ --------------- ------------------- ---------------- ---------------- ------------------
At March 31, 2002, approximately $8 million of undistributed earnings of the nuclear power companies were included in the
Company’s retained earnings.
2. Seabrook 1 Nuclear Generating Unit
The Company has a minority non-operating ownership interest in the Seabrook 1 Nuclear Generating Unit (Seabrook 1). The
Company’s share of expenses for Seabrook 1 is accounted for in “Other operation” and “Maintenance” expenses on the income
statement.
Note E - Commitments and Contingencies
1. Nuclear Units
Nuclear Units Permanently Shut Down
Three of the Yankees in which the Company has a minority interest own nuclear generating units that have been permanently
shut down. These three units are as follows:
- --------------------------------------------- ---------------------------------- ----------------------- ------------------------
Future Estimated
The Company’s Investment as of Billings to the Company
3/31/02
Unit % $(millions) Date Retired $(millions)
- --------------------------------------------- ---------------- ----------------- ----------------------- ------------------------
- --------------------------------------------- ---------------- ----------------- ----------------------- --------------- --------
Yankee Atomic 34.5 0.4 Feb 1992 0
Connecticut Yankee 19.5 13 Dec 1996 44
Maine Yankee 24.0 15 Aug 1997 123
Yankee Atomic has discontinued further billings to the Company, subject to a final reconciliation of costs once
decommissioning at the plant has been completed. For Maine Yankee and Connecticut Yankee, the Company has recorded a
liability and a regulatory asset reflecting the estimated future billings from the companies.
Under the provisions of the Company’s industry restructuring settlement agreements approved by state and federal regulators
in 1998, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to
the Company.
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.
Maine Yankee had previously hired Stone and Webster, Inc. (S and W), an engineering, construction, and consulting company, as the
principal contractor to decommission the unit. In May 2000, Maine Yankee terminated its long-term contract with S and W and
negotiated an arrangement with S and W to continue work through June 2000. In June 2000, S and W filed for Chapter 11 bankruptcy
protection. Subsequently, Maine Yankee decided to self-manage the unit’s decommissioning process. In June 2000, Federal
Insurance Company (Federal) filed a complaint in S and W’s bankruptcy proceedings, subsequently removed to US District Court in
Maine, which alleged that Maine Yankee improperly terminated its contract with S and W and that Federal should be excused from
$39 million performance bond and $12 million payment bond to Maine Yankee.
In December 2001, Maine Yankee and Federal reached a settlement. Pursuant to the settlement agreement, Federal paid Maine
Yankee $44 million in January 2002. Maine Yankee deposited the payment in its decommissioning trust fund. With regard to
Maine Yankee’s August 2000 damage claim against S and W in the bankruptcy proceeding for $78.2 million (later decreased to $21
million to reflect, among other things, the recovery of $44 million from Federal), on May 30, 2002, the bankruptcy judge
held that Maine Yankee has proved damages of $20.8 million and estimated its claim at that amount. However, the amount
Maine Yankee actually recovers will depend on the magnitude of assets in the bankrupt estate available to pay creditors
claims.
At Maine Yankee and Yankee Atomic, the contractor responsible for the movement of spent fuel from wet storage to dry
storage has incurred delays. Connecticut Yankee has experienced delays in its decommissioning process due to zoning and
other issues, most of which are now resolved.
Due to rate recovery mechanisms, the S and W claims and decommissioning delays are not expected to materially affect the
Company’s earnings.
Operating Nuclear Units
The Company has minority interests in two operating nuclear generating units that the Company is engaged in efforts to
divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its 16.2 percent interest in Millstone 3 to Dominion
Resources, Inc. (Dominion) on March 31, 2001. Until such time as the Company divests its operating nuclear interests, 80
percent of the revenues and reasonable operating costs related to the units will be allocated to the customers through
CTCs, with shareholders being allocated the balance. Net proceeds attributed to the divestiture of the units will be
allocated to customers through CTC.
Vermont Yankee
The following table summarizes the Company’s interest in the Vermont Yankee Nuclear Power Corporation as of March 31, 2002:
The Company’s Interest
(millions of dollars)
------------------------------------------------------------------------------------------------
----------------- ------------- ---------------------------------------- -----------------------
Equity Net Decommissioning
Ownership Equity Plant Estimated Decommissioning Fund License
Interest (%) Investment Assets Cost (in 2001$) Balance Expiration
- ------------------- ----------------- ------------- ---------------------------------------- ----------------------- -------------
- ------------------- ----------------- ------------- ---------------------------------------- ----------------------- -------------
23.9 $12 $34 $107 $63 2012
In December 2001, Vermont Yankee reached a settlement with four equity owners, other than the Company, agreeing to
repurchase the Vermont Yankee shares held by these minority shareholders for $230 per share. The repurchase was consummated
in January 2002 for approximately $5.4 million. As a result, of the repurchase, the Company’s ownership interest in Vermont
Yankee increased from 22.5 percent to 23.9 percent.
On August 15, 2001, Vermont Yankee announced that it had reached an Agreement (the Agreement) to sell the Vermont Yankee
nuclear power plant to Entergy Corporation (Entergy) for $180 million. The Company’s portion of the sale price would be
approximately $43 million ($35 million for the plant and related assets and $8 million for nuclear fuel) based upon its
23.9 percent ownership interest. The plant’s decommissioning trust fund would be transferred to Entergy, and Entergy would
assume decommissioning liability for the plant. As part of the transaction, Vermont Yankee owners, including the Company,
would purchase power from the plant through 2012. Net proceeds from the sale would be credited to the Company’s customers
through the CTC. The sale of the plant is contingent upon the receipt of regulatory approvals by the SEC, under the 1935
Act, the FERC, the NRC, the Vermont Public Service Board (VPSB), and other state regulatory commissions with jurisdiction
over other equity owners of Vermont Yankee. The FERC, the NRC and the VPSB have approved the sale. On June 21, 2002,
Entergy filed a motion seeking reconsideration by the VPSB of a condition in its order approving the sale. The condition
rejected a provision in the Agreement entitling Entergy to keep 50 percent of any property remaining in the decommissioning
trust fund upon completion of decommissioning. The Agreement with Entergy terminates if the sale is not completed by July
31, 2002.
The Company previously sold 11.8 MW of its Vermont Yankee entitlement to a number of municipal and cooperative utilities
(Secondary Purchasers) located in Massachusetts under a “Vermont Yankee Secondary Purchaser Agreement” which had a
30-year term expiring on November 30, 2002. On May 16, 2002, the FERC approved an early termination of the Secondary
Purchasers contract effective February 28, 2002. Pursuant to the settlement, the Secondary Purchasers agreed not to
oppose the plant sale in any regulatory proceeding.
The Citizens of Brattleboro, and eight other towns in Vermont, cast non binding votes at town meetings in March 2002 on
whether Vermont Yankee should be shut down. In the nine towns that voted on the issue, a narrow majority chose to keep the
plant open.
Seabrook 1
The following table summarizes the Company’s interest in the Seabrook 1 nuclear generating unit as of March 31, 2002:
The Company’s share of (millions of dollars)
------------------------------------------------------------------------------
-------------- ---------------------------------------- ----------------------
The Company’s Net Estimated Decommissioning Decommissioning License
Ownership Fund
Interest (%) Plant Assets Cost (in 2001$) Balance* Expiration
- ------------------- -------------- ---------------------------------------- ---------------------- ----------------
- ------------------- -------------- ---------------------------------------- ---------------------- ----------------
10 $17 ** $55 $19 2026
* Certain additional amounts are anticipated to be available through tax deductions.
** Represents post-December 1995 spending including nuclear fuel.
On April 15, 2002, eight of the 11 joint owners of Seabrook, including the Company, announced that they had reached an
agreement to sell an 88.2 percent interest in Seabrook to FPL Energy Seabrook LLC (FPL Seabrook), a subsidiary of FPL
Group, for $836.6 million. The Company’s portion of the gross sales proceeds would be approximately $93.5 million. Pursuant
to the terms of the Company’s restructuring settlements, 98 percent of the Company’s proceeds, net of expenses related to
the sale, post-1995 capital additions and inventories, will be returned to National Grid customers in Massachusetts, Rhode
Island, and New Hampshire. FPL Seabrook will assume responsibility for ultimate decommissioning of Seabrook and will
receive the Seabrook decommissioning funds, including a top-off payment by the Company and other sellers. Approvals for the
transaction are needed from federal and state regulatory agencies, including public utility commissions in the sellers’
states, the NRC, the New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC), the FERC, and the Department of
Justice or the Federal Trade Commission. The plant owners are targeting to complete the sale by the end of 2002.
Millstone 3
In November 1999, the Company entered into an agreement with Northeast Utilities (NU) to settle claims made by the
Company regarding the operation of Millstone 3. Among other things, the settlement provided for NU to include the
Company’s 16.2 percent interest in Millstone 3 in an auction of NU’s share of the unit. Upon the closing of the sale, the
Company was to receive a fixed amount, regardless of the actual sale price.
In August 2000, Dominion agreed to purchase the Millstone units, including the Company’s interest in Millstone 3, for $1.3
billion. In March 2001, the sale was completed. In accordance with the prior settlement agreement, the Company was paid
approximately $27.9 million, including $25 million for the plant, and the Company paid approximately $5.8 million to
increase the decommissioning trust fund.
Regulatory authorities from Rhode Island, New Hampshire and Massachusetts have expressed an intent to challenge the
reasonableness of the settlement agreement as the Company would have received approximately $140 million of sale proceeds
without the agreement. The dispute will be resolved by the FERC. The Company believes it has a strong argument that it
acted prudently since the amount received under the settlement agreement was the highest sale price for a nuclear unit at
the time the agreement was reached.
Nuclear Decommissioning
The Company is liable for its share of decommissioning costs for 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 units.
Such costs reflect estimates of total decommissioning costs approved by the FERC. The Company records decommissioning costs
on its books consistent with its rate recovery. The Company is recovering its share of projected decommissioning costs for
Seabrook 1 through depreciation expense. In addition, the Company is paying its portion of projected decommissioning costs
for Connecticut Yankee and Maine Yankee. The Company has completed its projected decommissioning obligation for Yankee
Atomic, subject to a final reconciliation of decommissioning costs.
In New Hampshire, legislation was enacted in 1998 that 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, there is a single owner of an approximate 15 percent
share of Seabrook 1 that is subject to the legislation. The impact of this legislation to the Company is not considered
material to its financial position or results of operation.
On July 6, 2001, legislation was enacted to modify New Hampshire’s current decommissioning law. This new legislation,
initiated and supported by Seabrook’s joint owners, including the Company, was designed to protect customers from future
decommissioning risks. The legislation reduces the standard for non-radiological decommissioning at the site and will
allow the buyer of the plant to retain any decommissioning funds in excess of those contributed by customers of the
present owners.
The NHNDFC has authority to implement the new decommissioning law. Under the new law, the NHNDFC is charged with assuring
that the buyer of Seabrook will have adequate funding to complete decommissioning in the event the plant is prematurely
shutdown.
On November 5, 2001, the NHNDFC issued an order substantially approving a settlement establishing proposed terms for
funding assurance. The terms of the settlement included a cash “top-off” payment to the decommissioning fund of
approximately $57 million at the time of the sale. In addition, the buyer of the plant would be required to accelerate its
annual decommissioning fund contributions through 2006 and provide a funding assurance package of approximately $125
million that would decline over time as additional annual contributions are made to the fund.
The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the Department of Energy (DOE)) is
responsible for the disposal of spent nuclear fuel. The federal government requires the Company to pay a fee based on its
share of the net generation from the Seabrook 1 nuclear generating unit. Prior to 1998, the Company recovered this fee
through its fuel clause. Under 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 filed claims
for money damages in the U.S. Court of Federal Claims for the costs associated with the DOE’s failure to begin to take fuel
in 1998. The court held that the DOE is liable for such failure in October 1998. The Yankee Companies have filed a further
action against the DOE to determine the level of damages. As an interim measure until the DOE meets its contractual
obligations to dispose of their spent fuel, those companies are proceeding with construction of independent spent fuel
storage installations on the plant sites.
Each nuclear unit in which the Company has an ownership interest has established a decommissioning trust fund or escrow
fund into which payments are being made to meet the projected costs of decommissioning. There is no assurance that
decommissioning costs actually incurred by Seabrook 1 or the Yankees 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 may become unavailable, which could increase the cost of decommissioning the Yankee Atomic, Connecticut
Yankee, and Maine Yankee plants. If either of the operating units were shut down prior to the end of its operating license,
the funds collected for decommissioning to that point would be insufficient. Under settlement agreements, the Company will
recover decommissioning costs through CTCs.
Nuclear Insurance
The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident
at a nuclear plant to $9.5 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 and
Seabrook 1 would subject the Company to a $29.8 million maximum assessment per incident. The Company’s payment of any such
assessment would be limited to a maximum of $3.4 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 $6.0 million with respect to the current policy period.
2. Plant Expenditures
The Company’s utility plant expenditures are estimated to be approximately $34 million for fiscal year 2003. At March 31,
2002, substantial commitments had been made relative to future planned expenditures.
3. 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. At March 31, 2002, the Company had guaranteed approximately $20
million of project debt, including $4 million originally guaranteed by Montaup, with terms through 2015. The Company’s
rights and obligations under its support agreements were transferred to the purchaser of its nonnuclear generation. The
Company remains an obligor under the support agreements, (excluding the Montaup obligations) until 2020. Costs associated
with these support agreements are recoverable through the Company’s transmission rates.
4. 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. Some of these sites relate to the
disposal of ash from fossil fuel generating plants formerly owned by the Company.
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 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 is currently recovering certain environmental cleanup costs in rates.
The Company believes that hazardous waste liabilities for all sites of which it is aware are not material to its financial
position.
5. 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 contract termination charge. Through March 2002, the charges assessed
Norwood amount to approximately $43 million, all of which remain unpaid. The Company filed a collection action in
Massachusetts Superior Court (Superior Court). The Superior Court deferred action until the various appeals described below
were decided. On March 14, 2001, the Superior Court ordered Norwood to pay the Company approximately $27 million including
interest, and affirmed Norwood’s obligation to make monthly contract termination charge payments to the Company of
approximately $600,000, plus interest. Norwood appealed the order on April 11, 2001. Pending the appeal, Norwood entered
into a consent order to establish a segregated account for the benefit of the Company in the amount of $14 million and to
make regular additions to the account.
Separately, Norwood filed suit in Federal District Court (District Court) in April 1997 alleging that the divestiture of
the Company’s nonnuclear generation business (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) also consolidated appeals Norwood made from the FERC’s orders approving the divestiture, the wholesale rate
settlement between the Company and its distribution affiliates, and the contract termination charge tariff amendment. In
February 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. Norwood filed several petitions for
review. Finally, in October 2000, the US Supreme Court refused Norwood’s petitions to review the First Circuit decisions.
In the District Court action, in April 2000, the Company renewed its motion to dismiss Norwood’s remaining claim. Norwood
amended its complaint to reassert a request for rescission of the divestiture, which it had earlier dropped. The Company’s
motion to dismiss on the ground that it is not a proper party was denied in July 2001. Still pending is a motion to dismiss
the action on the ground of issue preclusion filed by co-defendant PG and E and joined in by the Company.
6. Contracts for the Purchase of Electric Power
The Company has contracts for the purchase of electric power. The Company’s commitments for future fiscal periods, under
these long-term contracts as of March 31, 2002, is as follows (in thousands): 2003, $72,620; 2004, $69,209; 2005, $58,629;
2006, $42,043; 2007, $46,024; 2008 and thereafter, $263,740.
Note F - Employee Benefits
1. Pension Plan:
The Company participates with certain other subsidiaries of National Grid USA in a noncontributory, defined benefit plan
covering substantially all employees of the Company. The plan provides 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 years ended March 31, 2002 and 2001 included the following components:
=============================================================================== =================================================
Year Ended
March 31,
(In thousands) 2002 2001
=============================================================================== ============================ ====================
=============================================================================== ============================ ====================
Service cost - benefits earned during the period $ 809 $ 482
Plus (less):
Interest cost on projected benefit obligation 8,729 8,381
Return on plan assets at expected long-term rate (12,789) (12,440)
Amortization of prior service cost 195 -
- ------ ----- ------------------------------------------------------------------ ---------------------------- --------------------
Benefit income $(3,056) $(3,577)
- ------ ----- ------------------------------------------------------------------ ---------------------------- --------------------
- ------------------------------------------------------------------------------- ---------------------------- --------------------
Special termination benefits not included above $ 1,339 $ -
- ------------------------------------------------------------------------------- ---------------------------- --------------------
The funded status of the plan cannot be presented separately for the Company as the Company participates in the plan with
certain other National Grid USA subsidiaries (Massachusetts Electric Company, The Narragansett Electric Company, Granite
State Electric Company, Nantucket Electric Company and National Grid USA Service Company, Inc.). The following provides
a reconciliation of benefit obligations and plan assets for the National Grid USA companies’ plan at March 31:
====================================================================== =========================== ==========================
(In millions) 2002 2001
====================================================================== =========================== ==========================
====================================================================== =========================== ==========================
Change in benefit obligation:
Benefit obligation at beginning of period $ 1,055 $800
Service cost 14 12
Interest cost 76 72
Actuarial (gain)/loss (8) 47
Benefits paid (76) (90)
Acquisitions - 188
Special termination benefits 13 6
Plan amendments - 20
- ---------------------------------------------------------------------- --------------------------- --------------------------
- ---------------------------------------------------------------------- --------------------------- --------------------------
Benefit obligation at end of period 1,074 1,055
- ---------------------------------------------------------------------- --------------------------- --------------------------
- ---------------------------------------------------------------------- --------------------------- --------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period 1,082 991
Actual return on plan assets during year 39 (59)
Company contributions 8 8
Benefits paid from plan assets (76) (90)
Acquisitions - 232
- ---------------------------------------------------------------------- --------------------------- --------------------------
- ---------------------------------------------------------------------- --------------------------- --------------------------
Fair value of plan assets at end of period 1,053 1,082
- ---------------------------------------------------------------------- --------------------------- --------------------------
- ---------------------------------------------------------------------- --------------------------- --------------------------
Funded status (21) 27
Unrecognized actuarial loss 261 206
Unrecognized prior service cost 19 20
- ---------------------------------------------------------------------- --------------------------- --------------------------
Net amount recognized $259 $253
- ---------------------------------------------------------------------- --------------------------- --------------------------
- ---------------------------------------------------------------------- --------------------------- --------------------------
Amounts recognized in the statement of financial position consist
of:
Prepaid benefit cost 346 338
Accrued benefit liability (90) (90)
Accumulated other comprehensive income 3 5
- ---------------------------------------------------------------------- --------------------------- --------------------------
- ---------------------------------------------------------------------- --------------------------- --------------------------
Net amount recognized $259 $253
- ---------------------------------------------------------------------- --------------------------- --------------------------
====================================================================== ======================================================
March 31,
2002 2001
====================================================================== =========================== ==========================
====================================================================== =========================== ==========================
Assumptions used to determine pension cost:
Discount rate 7.50% 7.50%
Average rate of increase in future compensation level 4.63% 4.61%
Expected long-term rate of return on assets 8.75% 8.75%
Plan assets are composed primarily of equity and fixed income securities.
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 years ended March 31, 2002 and 2001 included the following components:
=================================================================================== ==========================================
Year Ended
March 31,
(In thousands) 2002 2001
=================================================================================== ======================= ==================
=================================================================================== ======================= ==================
Service cost - benefits earned during the period $ 225 $ 210
Plus (less):
Interest cost on projected benefit obligation 3,434 3,337
Return on plan assets at expected long-term rate (3,721) (3,537)
Amortization of net loss 120 -
- ------ ----- ---------------------------------------------------------------------- ----------------------- ------------------
Benefit cost $ 58 $ 10
- ------ ----- ---------------------------------------------------------------------- ----------------------- ------------------
- ----------------------------------------------------------------------------------- ----------------------- ------------------
Special termination benefits not included above $ 61 $ -
- ----------------------------------------------------------------------------------- ----------------------- ------------------
The following provides a reconciliation of benefit obligations and plan assets at March 31:
====================================================================== ========================= ============================
(In millions) 2002 2001
====================================================================== ========================= ============================
====================================================================== ========================= ============================
Change in benefit obligation:
Benefit obligation at beginning of period $47 $38
Interest cost 3 3
Actuarial loss 7 2
Benefits paid (4) (4)
Acquisitions - 8
- ---------------------------------------------------------------------- ------------------------- ----------------------------
- ---------------------------------------------------------------------- ------------------------- ----------------------------
Benefit obligation at end of period 53 47
- ---------------------------------------------------------------------- ------------------------- ----------------------------
- ---------------------------------------------------------------------- ------------------------- ----------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period 41 40
Actual return/(loss) on plan assets during year 1 (1)
Company contributions 3 2
Benefits paid from plan assets (4) (4)
Acquisitions - 4
- ---------------------------------------------------------------------- ------------------------- ----------------------------
- ---------------------------------------------------------------------- ------------------------- ----------------------------
Fair value of plan assets at end of period 41 41
- ---------------------------------------------------------------------- ------------------------- ----------------------------
- ---------------------------------------------------------------------- ------------------------- ----------------------------
Funded status (12) (6)
Unrecognized actuarial loss 16 7
- ---------------------------------------------------------------------- ------------------------- ----------------------------
Net amount recognized $4 $1
- ---------------------------------------------------------------------- ------------------------- ----------------------------
====================================================================== ======================================================
March 31,
(In thousands) 2002 2001
====================================================================== ========================= ============================
====================================================================== ========================= ============================
Assumptions used to determine postretirement benefit cost:
Discount rate 7.50% 7.50%
Expected long-term rate of return on assets 8.43% 8.48%
Health care cost rates:
2001 N/A 8.00%
2002 10.00% 6.50%
2003 9.00% 5.00%
2004 8.00% 5.00%
2005 7.00% 5.00%
2006 6.00% 5.00%
2007+ 5.00% 5.00%
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,
2002 by approximately $6 million or decrease the APBO by approximately $5 million, and increase or decrease the net
periodic cost for fiscal year 2002 by approximately $400,000.
The Company generally funds the annual tax-deductible contributions.
3. Voluntary Early Retirement
In January 2002, a limited Voluntary Early Retirement Offer (VERO) was extended to non-union employees who met certain
eligibility requirements. Eligible employees were in targeted functions and would be age 55 with at least ten years of
pension service by March 31, 2004. This program is intended to reduce the National Grid USA workforce through voluntary
means. The early retirement offer was accepted by 4 employees. The Company recorded a charge to earnings of approximately
$2 million after tax, ($3 million, before tax) to reflect these costs. This total includes the Company’s portion of its
affiliated service company’s cost of the program.
Note G – Income Taxes
The Company and other subsidiaries participate with National Grid General Partnership, a wholly owned subsidiary of
National Grid Group plc, in filing consolidated federal income tax returns. The Company’s income tax provision is
calculated on a separate return basis. Federal income tax returns have been examined and reported on by the Internal
Revenue Service through 1996.
Total income taxes in the statements of income are as follows:
================================================ ============================ ============================= ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Income taxes charged to operations $47,593 $44,946 $9,641 $13,100 $37,633
Income taxes charged (credited) to
"Other income" 1,694 (52) (4) - 1,985
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
- -------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------
Total income taxes $49,287 $44,894 $9,637 $13,100 $39,618
- -------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------
Total income taxes, as shown above, consist of the following components:
================================================ ============================ ============================= ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Current income taxes $65,359 $56,374 $12,545 $7,374 $ 25,507
Deferred income taxes (15,555) (1,111) (581) 10,732 25,921
Investment tax credits, net (517) (10,369) (2,327) (5,006) (11,810)
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
- -------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------
Total income taxes $49,287 $44,894 $9,637 $13,100 $ 39,618
- -------- --------------------------------------- ------------- -------------- ------------ ---------------- ------------------
Since 1998, the Company has been amortizing previously deferred investment tax credits (ITC) related to generation
investments over the CTC recovery period. Unamortized ITC related to generating units divested in 1998 and 2001 were
credited to other income pursuant to federal tax law. Previously recognized ITC related to transmission facilities are
amortized over their estimated productive lives.
Total income taxes, as shown above, consist of federal and state components as follows:
================================================ ============================ ============================= ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Federal income taxes $41,018 $ 38,350 $8,035 $10,975 $ 33,746
State income taxes 8,269 6,544 1,602 2,125 5,872
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
- ------- ---------------------------------------- ------------- -------------- ------------ ---------------- ------------------
Total income taxes $49,287 $ 44,894 $ 9,637 $13,100 $ 39,618
- ------- ---------------------------------------- ------------- -------------- ------------ ---------------- ------------------
With regulatory approval from the FERC, the Company has adopted comprehensive interperiod tax allocation (normalization)
for temporary book/tax differences.
Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes.
The reasons for the differences are as follows:
================================================ ============================ ============================= ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Computed tax at statutory rate $ 44,121 $36,118 $ 8,435 $11,706 $38,721
Increases (reductions) in tax resulting
from:
Amortization of investment tax
credits (336) (7,762) (1,513) (3,254) (7,677)
State income taxes, net of
federal income tax benefit 5,375 4,254 1,042 1,381 3,817
Rate recovery of deficiency in
deferred tax reserves 1,007 4,339 1,617 3,508 8,207
Amortization of goodwill - 6,267 - - -
Prior year tax adjustment - 773 - - (2,028)
Millstone 3 sale - 1,787 - - -
All other differences (880) (882) 56 (241) (1,422)
- ------- ---------------------------------------- ------------- -------------- ------------ ---------------- ------------------
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
Total income taxes $ 49,287 $44,894 $ 9,637 $13,100 $39,618
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
The Company adopted SFAS No. 109, “Accounting for Income Taxes”, which requires recognition of deferred income taxes for
temporary differences that are reported in different years for financial reporting and tax purposes using the liability
method. Under the liability method, deferred tax liabilities or assets are computed using the tax rates that will be in
effect when temporary differences reverse. Generally, for regulated companies, the change in tax rates may not be
immediately recognized in operating results because of rate-making treatment and provisions in the Tax Reform Act of 1986.
The following table identifies the major components of total deferred income taxes:
====================================================================== ========================= ============================
At March 31 (In millions) 2002 2001
====================================================================== ========================= ============================
====================================================================== ========================= ============================
Deferred tax asset:
Plant related $ 67 $67
Investment tax credits 3 4
All other 37 30
- ------- -------------------------------------------------------------- ------------------------- ----------------------------
- ------- -------------------------------------------------------------- ------------------------- ----------------------------
107 101
- ------- -------------------------------------------------------------- ------------------------- ----------------------------
- ---------------------------------------------------------------------- ------------------------- ----------------------------
Deferred tax liability:
Plant related (211) (211)
All other, principally regulatory assets (153) (162)
- ------- -------------------------------------------------------------- ------------------------- ----------------------------
- ------- -------------------------------------------------------------- ------------------------- ----------------------------
(364) (373)
- ------- -------------------------------------------------------------- ------------------------- ----------------------------
- ------- ------ ------------------------------------------------------- ------------------------- ----------------------------
Net deferred tax liability $ (257) $(272)
- ------- ------ ------------------------------------------------------- ------------------------- ----------------------------
There were no valuation allowances for deferred tax assets deemed necessary at March 31, 2002 and 2001, respectively.
Note H - Short-term Borrowings
At March 31, 2002, and 2001, the Company had no short-term debt outstanding. The Company has regulatory approval to issue
up to $375 million of short-term debt. 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 that 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, 2002 and 2001, the Company had lines of credit and standby bond purchase facilities with banks totaling $456
million which are available to provide liquidity support for $410 million of the Company’s long-term bonds in tax-exempt
commercial paper mode, and for other corporate purposes. There were no borrowings under these lines of credit at March 31,
2002. Fees are paid on the lines and facilities in lieu of compensating balances.
Note I - Cumulative Preferred Stock
A summary of cumulative preferred stock at March 31, 2002 and 2001, is as follows (in thousands of dollars except for
share data):
- -------------------------- ---------------------------- ---------------------------------- ---------------------------- ----------
Shares Outstanding Amount Dividends Declared Call
Price
- -------------------------- ---------------------------- ---------------------------------- ---------------------------- ----------
- -------------------------- ------------- -------------- ----------------- ---------------- -------------- ------------- ----------
2002 2001 2002 2001 2002 2001
- -------------------------- ------------- -------------- ----------------- ---------------- -------------- ------------- ----------
- -------------------------- ------------- -------------- ----------------- ---------------- -------------- ------------- ----------
$100 par value 6.00% 14,361 14,361 $1,436 $1,436 $86 $91 (a)
Series
(a) Noncallable.
The annual dividend requirement for cumulative preferred stock was approximately $86,000 for 2002 and 2001.
There are no mandatory redemption provisions on the Company’s cumulative preferred stock.
Note J - Long-term Debt
A summary of long-term debt is as follows:
At March 31 (In thousands)
======================== ====================== ================================= ====================== ====================
Series Rate % Maturity 2002 2001
======================== ====================== ================================= ====================== ====================
================================================================================= ====================== ====================
Pollution Control Revenue Bonds:
CDA (a) Variable October 15, 2015 $ 38,500 $ 38,500
MIFA 1 (b) Variable March 1, 2018 79,250 79,250
BFA 1 (c) Variable November 1, 2020 135,850 135,850
BFA 2 (c) Variable November 1, 2020 50,600 50,600
MIFA 2 (b) Variable October 1, 2022 106,150 106,150
Unamortized discounts (65) (71)
- ----------------------------------------------- --------------------------------- ---------------------- --------------------
- ----------------------------------------------- --------------------------------- ---------------------- --------------------
Total long-term debt $410,285 $410,279
- ----------------------------------------------- --------------------------------- ---------------------- --------------------
(a) CDA = Connecticut Development Authority
(b) MIFA = Massachusetts Industrial Finance Authority
(c) BFA = Business Finance Authority of the State of New Hampshire
At March 31, 2002, interest rates on the Company's variable rate long-term bonds ranged from 1.15 percent to 1.75 percent.
At March 31, 2002, the Company's long-term debt had a carrying value and fair value of approximately $410,000,000. The fair
value of debt that reprices frequently at market rates approximates carrying value.
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 years ended March 31, 2002 or 2001, the three months ended March 31, 2000 or 1999, or the year ended December
31, 1999. Taxes, other than income taxes, charged to operating expenses are set forth by class as follows:
================================================ ============================ ============================= ==================
Year Ended Three Months Ended March 31, Year Ended
March 31, December 31,
2002 2001 2000 1999 1999
(In thousands) (unaudited)
================================================ ============= ============== ============ ================ ==================
================================================ ============= ============== ============ ================ ==================
Municipal property taxes $ 16,045 $19,334 $4,718 $4,618 $17,640
Federal and state payroll and other taxes 2,138 3,009 843 1,016 2,642
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
$ 18,183 $22,343 $5,561 $5,634 $20,282
- ------------------------------------------------ ------------- -------------- ------------ ---------------- ------------------
Transactions between the Company and other affiliated companies for sales of electric energy and other sales amounted to
approximately $354,396,000, $385,982,000, $90,934,000, $120,700,000, and $338,295,000, for the year ended March 31, 2002,
the year ended March 31, 2001, the three months ended March 31, 2000, the three months ended March 31, 1999, and the year
ended December 31, 1999, respectively.
National Grid USA Service Company, Inc., 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 $43,487,000,
$43,271,000, $11,514,000, $10,088,000, and $43,584,000, including capitalized construction costs of $15,178,000,
$19,117,000, $4,597,000, $3,415,000, and $17,229,000, in the year ended March 31, 2002, the year ended March 31, 2001, the
three months ended March 31, 2000, the three months ended March 31, 1999, and the year ended December 31, 1999,
respectively.
Selected Quarterly Financial Information (Unaudited)
========================================== ===================== ===================== ===================== =====================
(In thousands) Quarter Ended Quarter Ended Quarter Ended Quarter Ended
June 30, 2001 Sept. 30, 2001 Dec. 31, 2001 March 31, 2002
========================================== ===================== ===================== ===================== =====================
========================================== ===================== ===================== ===================== =====================
Operating revenue $145,016 $147,151 $136,065 $132,186
Operating income $22,834 $25,062 $20,221 $18,237
Net income $20,371 $22,573 $17,852 $15,978
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Quarter Ended Quarter Ended Quarter Ended Quarter Ended
(In thousands) June 30, 2000 Sept. 30, 2000 Dec. 31, 2000 March 31, 2001
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Operating revenue $156,190 $175,390 $156,396 $168,296
Operating income $15,908 $25,232 $22,040 $24,535
Net income $14,223 $16,460 $14,780 $12,837
Per share data is not relevant because the Company's common stock is wholly owned by National Grid USA, a wholly owned
subsidiary of National Grid Group plc.
New England Power Company
Selected Financial Information
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Year Ended Three Months Ended March
March 31, 31, Year Ended December 31,
2002 2001 2000 1999 1999 1998 1997
(In millions) (unaudited)
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Operating revenue $ 560 $ 656 $ 135 $ 167 $ 596 $1,218 $1,678
Net income $ 77 $ 58 $ 14 $ 20 $ 71 $ 123 $145
Total assets $2,740 $2,889 $2,630 $2,282 $2,303 $2,415 $2,763
Capitalization:
Common equity $ 941 $ 865 $ 657 $ 523 $ 332 $ 521 $913
Cumulative preferred stock 2 1 1 1 2 1 40
Long-term debt 410 410 372 372 372 372 648
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Total capitalization $1,353 $1,276 $1,030 $ 896 $ 706 $ 894 $1,601
Preferred dividends declared $ - $ - $ - $ - $ - $ 1 $ 2
Common dividends declared $ - $ - $ 24 $ - $ 241 $ 131 $135
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New England Power (NEWEN) Inactive
Filed: 1 Jul 02, 12:00am