SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-6564
NEW ENGLAND POWER COMPANY
(Exact name of registrant as specified in charter)
| Massachusetts | 04-1663070 |
| (state or other | (I.R.S. Employer |
| jurisdiction of | Identification No.) |
| incorporation) |
25 Research Drive, Westborough, Massachusetts 01582
(Address of principal executive offices)
Registrant's telephone number, including area code
(508-389-2000)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes (X) No ( )
Common stock, par value $20 per share, authorized and outstanding: 3,619,896 shares at June 30, 2002.
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
NEW ENGLAND POWER COMPANY
Statements of Income
Periods Ended June 30
(In thousands)
(Unaudited)
Three Months
- --------------------------------------------------------------------- ---------------------------------------------------
2002 2001
- --------------------------------------------------------------------- ------------------------- -------------------------
Operating revenue, principally from affiliates $143,488 $145,016
Operating expenses:
Fuel for generation 1,082 1,056
Purchased electric energy:
Contract termination and nuclear unit shutdown
charges 56,833 58,455
Other 16,474 21,294
Other operation 14,823 13,835
Maintenance 7,372 3,917
Depreciation and amortization 7,640 7,726
Taxes, other than income taxes 4,821 4,740
Income taxes 12,552 11,159
- ------- ------------------------------------------------------------- ------------------------- -------------------------
Total operating expenses 121,597 122,182
- ------- --- --------------------------------------------------------- ------------------------- -------------------------
Operating income 21,891 22,834
Other income:
Equity in income of nuclear power companies 689 929
Other income, net 7 697
- ------- ------------------------------------------------------------- ------------------------- -------------------------
Operating and other income 22,587 24,460
- ------- --- --------------------------------------------------------- ------------------------- -------------------------
Interest:
Interest on long-term debt 1,942 3,835
Other interest 247 254
- ------- --- --------------------------------------------------------- ------------------------- -------------------------
Total interest 2,189 4,089
- ------- --- --------------------------------------------------------- ------------------------- -------------------------
Net income $ 20,398 $ 20,371
- --------------------------------------------------------------------- ------------------------- -------------------------
Statements of Retained Earnings
(In thousands)
Retained earnings at beginning of period $136,798 $ 60,110
Net income 20,398 20,371
Dividends declared on cumulative preferred stock (22) (22)
- --------------------------------------------------------------------- ------------------------- -------------------------
Retained earnings at end of period $157,174 $ 80,459
- --------------------------------------------------------------------- ------------------------- -------------------------
Statements of Comprehensive Income
(In thousands)
Net Income $ 20,398 $ 20,371
Unrealized gain (loss) on securities, net of tax (117) 58
- --------------------------------------------------------------------- ------------------------- -------------------------
Comprehensive income $ 20,281 $ 20,429
- --------------------------------------------------------------------- ------------------------- -------------------------
The accompanying notes are an integral part of these financial statements.
Per share data is not relevant because the Company's common stock is wholly owned by National Grid USA.
NEW ENGLAND POWER COMPANY
Balance Sheets
(In thousands)
(Unaudited)
ASSETS
June 30, March 31,
2002 2002
- -------------------------------------------------------------------------- -------------------------- -----------------------
Utility plant, at original cost $911,402 $909,043
Less accumulated provisions for depreciation and amortization 334,350 329,927
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
577,052 579,116
Construction work in progress 10,677 7,466
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
Net utility plant 587,729 586,582
- ----- ---- --------------------------------------------------------------- -------------------------- -----------------------
Goodwill, net of amortization 338,188 338,188
Investments:
Nuclear power companies, at equity 40,268 40,339
Decommissioning trust funds 19,297 18,810
Nonutility property and other investments 11,202 11,515
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
Total investments 70,767 70,664
- ----- ---- --------------------------------------------------------------- -------------------------- -----------------------
Current assets:
Cash and temporary cash investments (including $111,525
and $99,300 with affiliates) 111,672 103,467
Accounts receivable (less reserves of $153 and $153):
Affiliated companies 51,459 41,408
Others 80,112 67,460
Fuel, materials, and supplies, at average cost 6,310 6,215
Prepaid and other current assets 1,797 1,402
Regulatory assets - purchased power obligations and accrued Yankee
nuclear plant costs 167,098 172,556
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
Total current assets 418,448 392,508
- ----- ---- --------------------------------------------------------------- -------------------------- -----------------------
Regulatory assets 1,283,446 1,297,079
Deferred charges and other assets 53,972 55,184
- -------------------------------------------------------------------------- -------------------------- -----------------------
$2,752,550 $2,740,205
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
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 157,174 136,798
Accumulated other comprehensive loss (227) (110)
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
Total common equity 961,319 941,060
Cumulative preferred stock, par value $100 per share 1,436 1,436
Long-term debt 410,286 410,285
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
Total capitalization 1,373,041 1,352,781
- ----- ---- --------------------------------------------------------------- -------------------------- -----------------------
Current liabilities:
Accounts payable (including $8,263 and $14,059 to affiliates) 49,287 47,358
Accrued liabilities:
Taxes 20,812 14,367
Interest 1,009 773
Purchased power obligations and accrued Yankee nuclear
plant costs 167,098 172,556
Other accrued expenses 4,223 3,094
Dividends payable 22 22
- ----- -------------------------------------------------------------------- -------------------------- -----------------------
Total current liabilities 242,451 238,170
- ----- ---- --------------------------------------------------------------- -------------------------- -----------------------
Deferred federal and state income taxes 259,877 257,302
Unamortized investment tax credits 8,666 8,795
Accrued Yankee nuclear plant costs 136,219 141,869
Purchased power obligations 511,044 513,599
Other reserves and deferred credits 221,252 227,689
- -------------------------------------------------------------------------- -------------------------- -----------------------
$2,752,550 $2,740,205
- -------------------------------------------------------------------------- -------------------------- -----------------------
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND POWER COMPANY
Statements of Cash Flows
Periods Ended June 30
(In thousands)
(Unaudited)
Three Months
- ---------------------------------------------------------------------- ------------------------- --------------------------
2002 2001
- ---------------------------------------------------------------------- ------------------------- --------------------------
Operating activities:
Net income $ 20,398 $ 20,371
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization 20,908 21,844
Deferred income taxes and investment tax credits, net 2,932 (6,602)
Allowance for funds used during construction (81) (746)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, net (22,703) 3,157
Increase in fuel, materials, and supplies (95) (477)
Decrease in regulatory assets 3,192 47,963
Decrease (increase) in prepaid and other current assets (395) 931
Increase (decrease) in accounts payable 1,929 (4,294)
Decrease in purchased power contract obligations (8,053) (37,746)
Increase in other current liabilities 7,810 17,113
Decrease in other non-current liabilities (12,047) (7,888)
Other, net 1,824 464
- ------ ---- ---------------------------------------------------------- ------------------------- --------------------------
Net cash provided by operating activities 15,619 $ 54,090
- ------ ---- ---------------------------------------------------------- ------------------------- --------------------------
Investing activities:
Plant expenditures, excluding allowance for funds used during
construction $(6,942) $ (8,460)
Proceeds from divestiture of generating assets - 25,000
Other investing activities (450) (46)
- ------ --------------------------------------------------------------- ------------------------- --------------------------
Net cash provided by (used) in investing activities $(7,392) $ 16,494
- ------ ---- ---------------------------------------------------------- ------------------------- --------------------------
Financing activities:
Dividends paid on preferred stock $ (22) $ (22)
- ---------------------------------------------------------------------- ------------------------- --------------------------
Net cash used in financing activities $ (22) $ (22)
- ------ ---- ---------------------------------------------------------- ------------------------- --------------------------
Net increase in cash and cash equivalents $ 8,205 $ 70,562
Cash and cash equivalents at beginning of period 103,467 22,360
- ---------------------------------------------------------------------- ------------------------- --------------------------
Cash and cash equivalents at end of period $111,672 $ 92,922
- ---------------------------------------------------------------------- ------------------------- --------------------------
Supplemental disclosures of cash flow information:
- ---------------------------------------------------------------------- ------------------------- --------------------------
Interest paid $ 1,456 $1,925
Federal and state income taxes paid 2,891 3,067
Dividends received from investments at equity $ 1,238 $2,476
- ---------------------------------------------------------------------- ------------------------- --------------------------
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND POWER COMPANY
Notes To Unaudited Financial Statements
1
Note A - 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. New England Power Company (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.
Note B - Nuclear Units
- ----------------------
At June 30, 2002, the Company had minority interests in four Yankee Nuclear Power Companies (the
Yankees): Yankee Atomic, Maine Yankee, Connecticut Yankee and Vermont Yankee. These ownership interests are
accounted for by the equity method. Three of the Yankees operated units that have been permanently shut down, and
one operated a unit that was sold July 30, 2002. 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. In addition the Company has a minority,
non-operating ownership interest in the Seabrook Nuclear Generating Station (Seabrook). The Company's share of
expenses for Seabrook is accounted for in "Other operation" and "Maintenance" expenses on the income statement.
Nuclear Units Permanently Shut Down
Yankee Atomic, Maine Yankee and Connecticut Yankee own nuclear generating units that have been
permanently shut down. 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 Federal Energy
Regulatory Commission (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 & Webster, Inc. (S&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&W and negotiated an arrangement with S&W to continue work through June 2000. In
June 2000, S&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&W's
bankruptcy proceedings, subsequently removed to US District Court in Maine, which alleged that Maine Yankee
improperly terminated its contract with S&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&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.
Yankee Atomic has commenced moving its spent nuclear fuel to dry cask storage. This process is expected
to be complete by the end of 2002. Connecticut Yankee and Maine Yankee expect to begin this process shortly.
Due to rate recovery mechanisms, the S&W claims and decommissioning delays that are being experienced
are not expected to materially affect the Company's earnings.
Operating Nuclear Units
The Company is engaged in efforts to divest its minority interest in Seabrook Station, an operating
nuclear generating unit. The Company sold its 16.2 percent interest in Millstone 3 to Dominion Resources, Inc.
(Dominion) on March 31, 2001 and sold its 23.9 percent interest in the Vermont Yankee Nuclear plant to Entergy
Nuclear Vermont Yankee, LLC (ENVY) on July 30, 2002. Until such time as the Company divests its Seabrook
operating nuclear interest, 80 percent of the revenues and reasonable operating costs related to the units will
be allocated to the customers through contract termination charges (CTCs), with shareholders being allocated the
balance. Net proceeds attributed to the divestiture of the units will be allocated to customers through CTCs.
Vermont Yankee
On August 15, 2001, Vermont Yankee announced that it had reached an Agreement (the Agreement)
to sell the Vermont Yankee nuclear power plant to ENVY for $180 million. The sale was completed on July 30, 2002.
The Company's portion of the sale price was 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. As part of the
transaction, ENVY assumed the decommissioning liability for the plant and Vermont Yankee owners, including the
Company, will purchase power from the plant through 2012. Any net proceeds from the sale will be credited to the
Company's customers through CTCs.
The sale had been in jeopardy when ENVY notified Vermont Yankee on July 17, 2002, that it was
unwilling to close the transaction unless a modification to the Agreement required by the Vermont Public Service
Board (VPSB) could be undone prior to termination of the Agreement on July 31, 2002. The VPSB approval was
conditioned upon the modification of a provision in the Agreement entitling ENVY to keep 50 percent of any
potential surplus remaining in the decommissioning trust fund upon completion of decommissioning. ENVY and the
sellers reached a compromise whereby the non-Vermont sellers (including the Company) assigned to ENVY all rights
to any potential excess decommissioning funds in return for a payment at closing of $1.5 million. The Company's
share is $750,000. This payment represents the present-value of the estimated value of the non-Vermont owners'
share of any excess decommissioning funds that might become available following the completion of decommissioning.
The Vermont Yankee Board of Directors has reached a consensus that it will offer to repurchase
all of the remaining equity of the non-Vermont owners, subject to a definitive agreement among the parties and
all required regulatory approvals.
Seabrook
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 USA 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
Nuclear Regulatory Commission (NRC), the New Hampshire Nuclear Decommissioning Financing Committee (NHNDFC).
Issues have been raised in the State regulatory proceedings about the treatment of excess decommissioning funds.
The FERC and the Federal Trade Commission have approved the transaction. The plant owners expect to complete the
sale by the end of November 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.
Note C - Nuclear Decommissioning
- --------------------------------
The Company is liable for its share of decommissioning costs for Seabrook, Yankee Atomic, Connecticut
Yankee and Maine Yankee. 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 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 cost obligation for
Yankee Atomic, subject to a final reconciliation of costs upon completion of decommissioning work.
In New Hampshire, legislation was enacted in 1998 that makes owners of Seabrook, 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 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.
During July 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 New Hampshire 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.
During November 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 $59 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 Seabrook. Prior to 1998, the Company recovered this
fee through its fuel clause. Under settlement agreements, substantially all of these costs are recovered 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. Yankee Atomic, Connecticut Yankee and Maine
Yankee 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 (ISFSI) located at the plant sites.
On July 9, 2002, a Petition was filed with the NRC alleging that Maine Yankee's storage of spent fuel at
its ISFSI violates the Atomic Energy Act (the Act) because Maine Yankee has not analyzed the consequences of
possible terrorist activities. Maine Yankee believes it is not in violation of the Act. Following normal
procedure, there is a 75 day public comment period regarding the Petition. Maine Yankee does not expect the NRC
to grant the action requested in the Petition.
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, Yankee Atomic, Connecticut Yankee or Maine
Yankee 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. Under settlement agreements, the Company is permitted to recover decommissioning costs through
CTCs.
Note D - Town of Norwood Dispute
- --------------------------------
From 1983 until 1998, the Company was the wholesale power supplier for the Town of Norwood,
Massachusetts (Norwood). In April 1998, Norwood began taking power from another supplier. Pursuant to a tariff
amendment approved by the FERC in May 1998, the Company has been assessing Norwood a CTC. Through June 30, 2002,
the charges assessed Norwood amount to approximately $47 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 were decided. (For a full discussion of the events leading up to the Superior Court's decision,
see Note E-5, "Town of Norwood Dispute" in the notes to the Financial Statements in the Company's 2002 Annual
Report.) In March 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 in April 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.
Note E - ICAP Deficiency Charge
- -------------------------------
As previously reported in the Company's 2002 Annual Report, there has been litigation regarding
the FERC order to increase the installed capacity (ICAP) deficiency charge to $8.75 per kilowatt-month (kW-month)
instead of the rate proposed by Independent System Operator-New England (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. An agreement in principle has been reached among parties to the FERC proceeding regarding the
appropriate ICAP deficiency charge for the period January to July 2000. The parties plan to file the settlement
with the FERC in August 2002. On July 31, 2002, the FERC issued a formal notice of proposed rulemaking (NOPR)
regarding standard market design. In the NOPR the FERC proposed to replace ICAP programs nationally with a new
mechanism for ensuring long-term resource adequacy. At this time, it is not clear how any new resource adequacy
requirement will differ from the ICAP program that currently exists in New England.
Note F - Regulatory Asset Recovery
- ----------------------------------
The Company's financial statements conform to generally accepted accounting principles ("GAAP"),
including the accounting principles for rate-regulated entities with respect to its regulated operations.
Substantively, the Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("SFAS No. 71") permits a public utility, regulated on a cost-of-service basis, to defer
certain costs (because they are expected to be refunded through customers billings), which would otherwise be
charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory
assets. In 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board (FASB) concluded that
a utility that had received regulatory approval to recover stranded costs through 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 June 30, 2002, this amounted to approximately $1.4 billion, including $0.9 billion
related to the above-market costs of purchased power contracts, $0.1 billion related to accrued Yankee nuclear
plant costs, and $0.4 billion related to other net CTC regulatory assets.
Note G - Summary of Significant Accounting Policies
- ---------------------------------------------------
Basis of Presentation
The Company, in the opinion of the management, has included all adjustments (which include normal
recurring adjustments) necessary for a fair statement of the results of its operations for the interim periods
presented. These financial statements for the year ended March 31, 2003 are subject to adjustment at the end of
the year when they will be audited by independent accountants. These financial statements and notes thereto
should be read in conjunction with the notes to the financial statements included in the Company's Annual Report
for the period ended March 31, 2002.
Comprehensive Income
Comprehensive income is the change in the equity of a company not including those changes that result
from shareholder transactions. While the primary component of comprehensive income is reported net income or
loss, the other component for the Company is unrealized losses associated with certain investments held as
available for sale.
New Accounting Standards
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities
to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of
the related long-lived asset. The provisions of SFAS No. 143 will be effective for fiscal years beginning after
June 15, 2002. The Company is currently evaluating the effect of this statement on its financial position and
results of operations.
The Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (FAS
144) effective April 1, 2002, the beginning of the 2003 fiscal year. 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. The adoption of FAS 144 had no material impact on the Company's financial position and results of
operations.
The Company adopted SFAS No. 145, "Recision of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and Technical Corrections", (FAS 145), during the quarter ended June 30, 2002. FAS 145 rescinds
SFAS No. 4, "Reporting Gains and Losses from Extinguishments 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. This statement is effective for fiscal years beginning after May
15, 2002. The adoption of FAS 145 had no material impact on the Company's financial position and results of
operations.
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
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This section contains management's assessment of New England Power Company's (the Company) financial
condition and the principal factors having an impact on the results of operations. This discussion should be read
in conjunction with the Company's financial statements and footnotes and the Annual Report on Form 10-K for the
period ended March 31, 2002.
All of the common stock of the Company is owned by National Grid USA.
FERC Proceedings
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In general, the regulatory structure and regulations that 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)
will affect how the Company does business. 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 an RTO
structure in which independent transmission companies could manage certain transmission functions within the RTO.
However, it is not clear what sort of RTO structure will ultimately result from these negotiations. In fact, based
on an announcement in January 2002 by the New York and New England ISOs that they were exploring the formation of their
own RTO, even the geographic scope of the RTO in which the Company will participate is still an open question.
The Company expects a more detailed filing to be made in August 2002.
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
that the Company believes are very favorable to generators and unfavorable and partially 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 (SMD)
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. As a result, the North American Standards Energy Board (NAESB), an
independent voluntary organization that develops and promotes the use of business practice and related electronic
communications standards, has formed a Wholesale Electric Quadrant (WEQ). The Company's parent, National Grid
USA, has joined the transmission sector of the WEQ. The FERC also solicited comments earlier this year 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. On
July 31, 2002, the FERC issued a formal notice of proposed rulemaking (NOPR) on these matters. The proposed rules
would, among other things, require the Company to file by July 31, 2004, a new transmission tariff to replace its
current tariff. The Company would have to meet the requirements of an independent transmission provider or permit
an independent transmission provider to operate its transmission facilities. In addition, it would authorize an
independent transmission provider to file proposed changes to the Company's transmission rates with the FERC.
The FERC has also proposed that it assumed jurisdiction over transmission rates to retail customers, but has not
specified the mechanism under which retail costs, including stranded costs, would be charged to these customers.
The Company is currently unable to determine whether the final outcome of this NOPR will have a material impact
on its financial position or results of operations.
The New England Power Pool (NEPOOL) and ISO New England have a separate SMD initiative that is
proceeding in parallel to the FERC initiative. On July 15, 2002, NEPOOL filed with the FERC its own SMD proposal
to conform the procedures by which energy is bought and sold in New England to those of PJM. Although NEPOOL
asked for an implementation date in December 2002, significant comments and protests to the proposal are expected
and will likely affect the terms of the SMD and the implementation date.
To the extent the Company wishes to pursue opportunities to propose financial incentives related to
transmission projects 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 that 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 believed did not comport with the FERC's orders, and the Company filed another protest. On
July 3, 2002, the FERC issued a ruling in this case that was again favorable to the Company.
On September 27, 2001, the FERC initiated a NOPR 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.
In several recent cases at the FERC and in recent activities in NEPOOL, a number of parties have
expressed the desire to alter the way in which certain high voltage direct current (HVDC) facilities in the
Northeast are treated with respect to cost recovery and access for transmission services. Currently, companies
that provide the financial support for the lines control access to these HVDC lines. The Company currently
controls and supports approximately 4 percent of the capacity on one such HVDC facility, known as the
Hydro-Quebec Phase I and II facilities. Along with recovering the cost of its support payments from its
transmission customers, the Company receives revenues in the form of ICAP credits and charges to entities taking
temporary assignments of the Company's capacity rights. Parties seeking to change this paradigm are proposing to
roll in the costs of all HDVC facilities into the regional transmission rates administered by NEPOOL and to allow
open access to the facilities under NEPOOL's open access transmission tariff. Depending on how this is
accomplished, the cost recovery responsibility of the Company's transmission customers may increase
significantly, while diminishing the Company's access to the line and eliminating the Company's revenues
associated with ICAP credits and temporary capacity rights assignments. The potential impact of these changes in
the treatment of HVDC lines could amount to as much as a $20 million a year cost shift to the Company's
customers, in addition to the Company's own potential for lost revenues.
Earnings
- --------
Net income was comparable for the quarters ended June 30, 2002 and 2001. The Company's decreased operating and other
income were offset by lower interest expense on variable rate long-term debt.
Operating Revenue
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Operating revenue for the quarter ended June 30, 2002, decreased approximately $2 million compared with the same period
in 2001. The decrease in revenue for the quarter is primarily due to reduced kilowatthour (kWh) sales as a result
of the termination of the standard offer service to Rhode Island, effective December 1, 2001. Partially
offsetting the decrease were increased kWh sales to the open market and increased transmission revenues. The
transmission charge is a formula rate that recovers the Company's actual costs plus a return on actual investment.
Operating Expenses
- ------------------
Operating expenses for the quarter ended June 30, 2002, decreased approximately $1 million compared with the same period
in 2001.
Purchased power expense decreased approximately $2 million for the quarter ended June 30, 2002, compared with the same
period in 2001. The decrease was primarily due to the absence of open market power purchases during the quarter
ended June 30, 2002. The Company terminated open market power purchases during fiscal 2002.
Nuclear operation and maintenance expenses for the quarter ended June 30, 2002, increased approximately $4 million compared
with the same period in 2001. The increased cost is primarily the result of a refueling outage at Seabrook
during the quarter ended June 30, 2002.
Depreciation and amortization expenses were comparable for the quarters ended June 30, 2002 and 2001.
Other Income-net
- ----------------
Other income-net for the quarter ended June 30, 2002, decreased approximately $1 million compared with the same period
in 2001. The decrease is due primarily to reduced allowance for equity funds used during construction during the
quarter ended June 30, 2002.
Interest Expense
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Interest expense for the quarter ended June 30, 2002 decreased approximately $2 million compared with the same period
in 2001 primarily due to decreased interest rates on the Company's variable rate long-term debt.
Utility Plant Expenditures and Financing
- ----------------------------------------
Cash expenditures for utility plant totaled approximately $7 million during the quarter ended June 30, 2002, and were
primarily transmission-related. The funds necessary for utility plant expenditures during the period were
primarily provided by internally generated funds.
The Company plans to make a payment of approximately $80 million during the third fiscal quarter under
a 1997 Agreement with the purchaser of its generation assets regarding power purchase agreements. The payment
formally releases the Company as the obligor from one of the power purchase agreements covered by the 1997
Agreement and reduces future payments under the contract. The Company may fund the payment from internally
generated funds or secure long-term financing from affiliated or external sources.
At June 30, 2002, 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, 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 June 30, 2002, 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
June 30, 2002. Fees are paid on the lines and facilities in lieu of compensating balances.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
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New England Power Company's (the Company) major financial market risk exposure is changing interest rates. Changing
interest rates will affect interest paid on variable-rate debt. At June 30, 2002, 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 three months ended June 30, 2002, was approximately 1.78 percent.
For a full discussion of the Company's risk associated with the Installed Capacity deficiency charge, refer to Note
E in the Notes to Unaudited Financial Statements.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
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Information concerning several Federal Energy Regulatory Commission proceedings, discussed in this
report in the FERC Proceedings section of Management's Discussion and Analysis of Financial Condition and Results
of Operations (Part I, Item II) and in Note E of Notes to Unaudited Financial Statements, is incorporated herein
and made a part hereof.
Information concerning the Company's collection action against the Town of Norwood, Massachusetts and
appeals of related actions, discussed in this report in Note D of Notes to Unaudited Financial Statements, is
incorporated herein and made a part hereof.
Item 4. Submission of Matters to a Vote of Security Holders
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On April 17, 2002, the Annual Meeting of Shareholders was held.
By unanimous vote of the 3,619,896 shares present of 3,634,257 total shares having general voting rights:
The number of directors for the ensuing year was fixed at nine.
The following were elected as directors:
L. Joseph Callan
John G. Cochrane
Peter G. Flynn
Michael E. Jesanis
Robert G. Powderly
Lawrence J. Reilly
Terry L. Schwennesen
Richard P. Sergel
Philip R. Sharp
James S. Robinson was elected as Treasurer and Gregory A. Hale was elected as Clerk.
PricewaterhouseCoopers was selected as Auditor for the year 2002.
Item 6. Exhibits and Reports on Form 8-K
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Form 8-K filings
-----------------
The Company filed a report on Form 8-K dated April 22, 2002 containing Items 5 and 7.
Exhibits
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99.1 Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.2 Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
NEW ENGLAND POWER COMPANY
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this
report on Form 10-Q for the quarter ended June 30, 2002 to be signed on its behalf by the undersigned thereunto
duly authorized.
NEW ENGLAND POWER COMPANY
s:\Edward A. Capomacchio
Edward A. Capomacchio, Controller,
Authorized Officer, and
Principal Accounting Officer
Date: August 13, 2002