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 September 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-6564
(LOGO) 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 or
organization)
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 September 30, 1999.
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
- ----------------------------
NEW ENGLAND POWER COMPANY
Statements of Income
Periods Ended September 30
(Unaudited)
Quarter Nine Months
-------- -----------
1999 1998 1999 1998
---- ---- ---- ----
(In Thousands)
Operating revenue, principally from affiliates $142,066 $321,569$ 448,863 $1,081,036
-------- -------- --------------------
Operating expenses:
Fuel for generation 3,857 62,442 9,129 221,429
Purchased electric energy 62,099 98,271 180,832 342,945
Other operation 17,665 40,464 52,935 132,874
Maintenance 5,569 784 22,737 52,704
Depreciation and amortization 21,210 25,199 82,570 84,345
Taxes, other than income taxes 5,316 10,258 16,709 45,749
Income taxes 7,568 29,504 29,315 65,080
-------- -------- --------------------
Total operating expenses 123,284 266,922 394,227 945,126
-------- -------- --------------------
Operating income 18,782 54,647 54,636 135,910
Other income:
Allowance for equity funds used
during construction 447 114 1,576 114
Equity in income of nuclear power companies1,001 1,544 2,483 4,158
Other income (expense), net 935 3,318 3,620 826
-------- -------- --------------------
Operating and other income 21,165 59,623 62,315 141,008
-------- -------- --------------------
Interest:
Interest on long-term debt 3,370 7,635 9,714 26,951
Other interest 246 4,299 692 10,549
Allowance for borrowed funds used during
construction (120) (267) (359) (823)
-------- -------- --------------------
Total interest 3,496 11,667 10,047 36,677
-------- -------- --------------------
Net income $ 17,669 $ 47,956 $ 52,268$ 104,331
======== ======== ====================
Statements of Retained Earnings
(In Thousands)
Retained earnings at beginning of period $232,070 $ 462,968 $204,603 $ 407,630
Net income 17,669 47,956 52,268 104,331
Dividends declared on cumulative
preferred stock (24) (142) (71) (1,179)
Dividends declared on common stock - (130,610) - (130,610)
Premium on redemption of preferred stock 264 - 264 -
Repurchase of common stock - (193,818) (7,085) (193,818)
-------- --------- -------- ---------
Retained earnings at end of period $249,979 $ 186,354 $249,979 $ 186,354
======== ========= ======== =========
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 New England Electric System.
NEW ENGLAND POWER COMPANY
Statements of Income
Twelve Months Ended September 30
(Unaudited)
1999 1998
---- ----
(In Thousands)
Operating revenue, principally from affiliates $ 586,167 $1,481,068
--------- ----------
Operating expenses:
Fuel for generation 11,528 309,795
Purchased electric energy 237,723 464,581
Other operation 75,126 189,582
Maintenance 30,272 75,560
Depreciation and amortization 98,149 112,035
Taxes, other than income taxes 19,452 61,347
Income taxes 37,829 86,621
--------- ----------
Total operating expenses 510,079 1,299,521
--------- ----------
Operating income 76,088 181,547
Other income:
Allowance for equity funds used during construction 2,095 114
Equity in income of nuclear power companies 3,609 5,466
Other income (expense), net 2,912 1,202
--------- ----------
Operating and other income 84,704 188,329
--------- ----------
Interest:
Interest on long-term debt 13,538 37,629
Other interest 831 12,454
Allowance for borrowed funds used during construction (497) (1,149)
--------- ----------
Total interest 13,872 48,934
--------- ----------
Net income $ 70,832 $ 139,395
========= ==========
Statements of Retained Earnings
(In Thousands)
Retained earnings at beginning of period $186,354 $ 408,559
Net income 70,832 139,395
Dividends declared on cumulative preferred stock (122) (1,698)
Dividends declared on common stock - (166,084)
Repurchase of common stock (7,085) (193,818)
-------- ---------
Retained earnings at end of period $249,979 $ 186,354
======== =========
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 New England Electric System.
NEW ENGLAND POWER COMPANY
Balance Sheets
(Unaudited)
September 30, December 31,
ASSETS 1999 1998
------ ---- ----
(In Thousands)
Utility plant, at original cost $1,313,115 $1,262,461
Less accumulated provisions for depreciation
and amortization 844,257 837,637
---------- ----------
468,858 424,824
Construction work in progress 16,982 33,289
---------- ----------
Net utility plant 485,840 458,113
---------- ----------
Investments:
Nuclear power companies, at equity 46,631 48,538
Non-utility property and other investments 39,836 39,583
---------- ----------
Total investments 86,467 88,121
---------- ----------
Current assets:
Cash, and temporary cash investments (including
$95,614,000 and $109,911,000 with affiliates) 242,155 179,413
Accounts receivable:
Affiliated companies 68,964 107,878
Others 45,005 32,573
Fuel, materials, and supplies, at average cost 9,778 9,220
Prepaid and other current assets 33,480 21,569
---------- ----------
Total current assets 399,382 350,653
---------- ----------
Regulatory assets 1,302,456 1,512,562
Deferred charges and other assets 4,973 5,339
---------- ----------
$2,279,118 $2,414,788
========== ==========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common stock, par value $20 per share,
Authorized - 6,449,896 shares
Outstanding - 3,619,896 shares and 3,749,896 shares $ 72,398 $ 74,998
Premium on capital stock 48,624 50,371
Other paid-in capital 183,937 190,852
Retained earnings 249,979 204,603
Unrealized gain on securities, net 68 72
---------- ----------
Total common equity 555,006 520,896
Cumulative preferred stock, par value $100 per share 1,567 1,567
Long-term debt 371,770 371,765
---------- ----------
Total capitalization 928,343 894,228
---------- ----------
Current liabilities:
Short-term debt 38,500 -
Accounts payable (including $44,737,000 and $119,657,000
to affiliates) 81,796 162,360
Accrued liabilities:
Taxes 5,485 15,009
Interest 1,556 2,440
Other accrued expenses 26,134 20,086
Dividends payable 24 24
---------- ----------
Total current liabilities 153,495 199,919
---------- ----------
Deferred federal and state income taxes 162,818 165,115
Unamortized investment tax credits 21,317 30,870
Accrued Yankee nuclear plant costs 211,843 242,138
Purchased power obligations 740,046 832,668
Other reserves and deferred credits 61,256 49,850
---------- ----------
$2,279,118 $2,414,788
========== ==========
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND POWER COMPANY
Statements of Cash Flows
Nine Months Ended September 30
(Unaudited)
1999 1998
---- ----
(In Thousands)
Operating Activities:
Net income $ 52,268 $ 104,331
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 87,040 87,375
Deferred income taxes and investment tax credits, net (2,649) (221,184)
Allowance for funds used during construction (1,935) (937)
Reimbursement to New England Energy Incorporated of loss - (120,900)
on sale of oil and gas properties
Buyout of purchased power contracts - (333,520)
Decrease (increase) in accounts receivable, net 26,482 84,894
Decrease (increase) in fuel, materials, and supplies (558) (10,789)
Decrease (increase) in prepaid and other current assets(11,911) 7,312
Increase (decrease) in accounts payable (80,564) (29,142)
Increase (decrease) in other current liabilities (4,360) 41,628
Other, net 20,100 (88,141)
-------- -----------
Net cash provided by (used in) operating activities$ 83,913 $ (479,073)
-------- -----------
Investing Activities:
Proceeds from sale of generating assets $ - $ 1,688,863
Plant expenditures, excluding allowance for
funds used during construction (41,325) (44,933)
Other investing activities (219) (445)
-------- -----------
Net cash provided by (used in) investing activities$(41,544)$ 1,643,485
-------- -----------
Financing Activities:
Capital contribution from parent $ - $ 34,881
Dividends paid on common stock - (166,084)
Dividends paid on preferred stock (71) (1,038)
Changes in short-term debt 38,500 (111,250)
Long-term debt - retirements - (328,000)
Repurchase of common shares (18,056) (417,960)
Redemption of preferred stock - (29,283)
-------- -----------
Net cash provided by (used in) financing activities$ 20,373 $(1,018,734)
-------- -----------
Net increase (decrease) in cash and cash equivalents $ 62,742 $ 145,678
Cash and cash equivalents at beginning of period 179,413 1,643
-------- -----------
Cash and cash equivalents at end of period $242,155 $ 147,321
======== ===========
The accompanying notes are an integral part of these financial statements.
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.
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 New England Electric System companies have recovered amounts from certain
insurers, and, where appropriate, intend to seek recovery from other insurers
and from other PRPs, but it is uncertain whether, and to what extent, such
efforts will be successful. The Company believes that hazardous waste
liabilities for all sites of which it is aware are not material to its
financial position.
Note B - Nuclear Units
- ----------------------
Yankee Nuclear Power Companies (Yankees)
The Company has minority interests in four Yankee Nuclear Power Companies.
These ownership interests are accounted for on the equity method. The
Company's share of the expenses of the Yankees is accounted for in "Purchased
electric energy" on the income statement. A summary of combined results of
operations, assets, and liabilities of the four Yankees is as follows:
Quarters Ended Nine Months Ended
September 30,
---------------------------------------
1999 1998 1999 1998
---- ---- ---- ----
(In Thousands)
Operating revenue $91,361 $104,210 $272,414 $343,041
======= ======== ======== ========
Net income $ 1,167 $ 6,314 $ 11,434 $ 20,820
======= ======== ======== ========
Company's equity in
net income recorded $ 1,001 $ 1,544 $ 2,483 $ 4,158
======= ======== ======== ========
September 30, December 31,
1999 1998
---- ----
(In Thousands)
Net plant $ 172,833 $ 171,582
Other assets 2,657,996 2,810,613
Liabilities and debt (2,579,217) (2,723,454)
----------- -----------
Net assets $ 251,612 $ 258,741
=========== ===========
Company's equity in net assets $ 46,631 $ 48,538
=========== ===========
The Company's share of the Yankees net income is recorded on a one-month
lagging basis with an estimate of the final month.
At September 30, 1999, $12,869,000 of undistributed earnings of the nuclear
power companies were included in the Company's retained earnings.
Nuclear Units Permanently Shut Down
Three regional nuclear generating companies in which the Company has a
minority interest own nuclear generating units that have been permanently
shut down. These three units are as follows:
Future
Estimated
NEP's Billings
Investment Date to NEP
Unit % $ (millions) Retired $(millions)
- -----------------------------------------------------------------
Yankee Atomic 30 4 Feb 1992 13
Connecticut Yankee 15 17 Dec 1996 67
Maine Yankee 20 15 Aug 1997 131
In the case of each of these units, the Company has recorded a liability
and an offsetting regulatory asset reflecting the estimated future billings
from the companies. In a 1993 decision, the Federal Energy Regulatory
Commission (FERC) allowed Yankee Atomic to recover its undepreciated
investment in the plant as well as unfunded nuclear decommissioning costs and
other costs. Connecticut Yankee has filed a similar request with the FERC.
Several parties have intervened in opposition to the filing. In August 1998,
a FERC Administrative Law Judge (ALJ) issued an initial decision which would
allow for full recovery of Connecticut Yankee's unrecovered investment, but
precluded a return on that investment. Connecticut Yankee, the Company, and
other parties have filed with the FERC exceptions to the ALJ's decision.
Should the FERC uphold the ALJ's initial decision in its current form, the
Company's share of the loss of the return component would total approximately
$12 million to $15 million before taxes. Maine Yankee recovers its costs in
accordance with settlement agreements approved by the FERC in May 1999.
A Maine statute provides that if both Maine Yankee and its decommissioning
trust fund have insufficient assets to pay for the plant decommissioning, the
owners of Maine Yankee are jointly and severally liable for the shortfall.
Under the provisions of industry restructuring settlement agreements
approved by state and federal regulators in 1998 (Settlement Agreements), the
Company recovers all costs, including shutdown costs, that the FERC allows
these Yankee companies to bill to the Company.
Operating Nuclear Units
The Company has minority interests in three other nuclear generating units:
Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the
future of nuclear generating stations, particularly older units, such as
Vermont Yankee, have increased in recent years and could adversely affect
their service lives, availability, and costs. These uncertainties stem from
a combination of factors, including the acceleration of competitive pressures
in the power generation industry and increased Nuclear Regulatory Commission
(NRC) scrutiny. The Company performs periodic economic viability reviews of
operating nuclear units in which it holds ownership interests.
Vermont Yankee
The Company is engaged in efforts to divest its interests in the three
operating nuclear units mentioned above. In October 1999, the Vermont Yankee
Nuclear Power Corporation Board of Directors announced its intention to sell
the assets of Vermont Yankee to AmerGen Energy Company (AmerGen), a joint
venture by PECO Energy and British Energy, for approximately $23.5 million.
Under the terms of the proposed agreement, Vermont Yankee will contribute
approximately $54 million toward the plant's decommissioning trust fund and
AmerGen will assume responsibility for the actual cost of decommissioning the
plant. The proposed agreement also requires the existing power purchasers
(including the Company) to continue to purchase the output of the plant or to
elect to buy out of the power purchase obligation. The proposed sale, which
is subject to the execution of a definitive agreement, received approval of
the owners of Vermont Yankee in November 1999 and is contingent upon
regulatory approvals by the NRC, the Securities and Exchange Commission,
under the Public Utility Holding Company Act of 1935, and the Vermont Public
Service Board, among others. The Company has a 20 percent ownership interest
in Vermont Yankee and an equity investment of approximately $10 million at
September 30, 1999.
Millstone 3
In July 1998, Millstone 3, which is operated by a subsidiary of Northeast
Utilities (NU), returned to full operation after being shut down since April
1996. In September 1999, NU agreed to pay $10 million in fines and donations
after its operating subsidiary pleaded guilty to environmental violations and
making false statements to federal nuclear regulators, ending a criminal
investigation of the NU subsidiaries related, in part, to Millstone 3.
In August 1997, the Company sued NU in Massachusetts Superior Court for
damages resulting from the tortious conduct of NU that caused the shutdown of
Millstone 3. The Company's claim for damages included the costs of
replacement power during the outage, costs necessary to return Millstone 3 to
safe operation, and other additional costs. Most of the Company's
incremental replacement power costs have been recovered from customers,
either through fuel adjustment clauses or through provisions in the
Settlement Agreements.
In August 1997, the Company also sent a demand for arbitration to
Connecticut Light & Power Company and Western Massachusetts Electric Company,
both subsidiaries of NU (subsidiaries), seeking damages resulting from their
breach of obligations under an agreement with the Company and others
regarding the operation and ownership of Millstone 3.
In November 1999, the Company, NU, and the subsidiaries executed an
agreement which settles the litigation and arbitration described above. The
settlement involves the payment of fixed and contingent amounts to the
Company, as well as an agreement by NU to include the Company's Millstone 3
interest when NU sells its Millstone 3 interest at auction. Amounts received
pursuant to the proposed settlement will, after reimbursement of the
Company's transaction costs and net investment in Millstone 3, be credited to
customers.
Note C - 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 tariffs approved by the FERC
in May 1998, the Company has been assessing Norwood a contract termination
charge (CTC). Through September 1999, the charges assessed Norwood amount
to approximately $13 million, all of which remain unpaid. Norwood has
appealed the FERC's authorization of CTCs as well as the FERC's approval of
the Settlement Agreements and the Company's divestiture of its nonnuclear
generating assets (the divestiture) to the First Circuit Court of Appeals
(First Circuit). The Company is pursuing a collection action in
Massachusetts Superior Court.
Separately, Norwood filed suit in Federal District Court (District Court)
in April 1997 alleging that the divestiture violated the terms of the 1983
power contract. Norwood has appealed to the First Circuit the District
Court's dismissal of Norwood's lawsuit.
Note D
- ------
In the opinion of the Company, these financial statements reflect all
adjustments (which include normal recurring adjustments) necessary for a fair
statement of the results of its operations for the periods presented and
should be considered in conjunction with the notes to the financial
statements in the Company's 1998 Annual Report.
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
- -----------------------------------------------------------------
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
1998 Annual Report on Form 10-K.
Merger Agreements
- -----------------
For a full discussion of New England Electric System's (NEES) merger
agreements with The National Grid Group plc (National Grid) and Eastern
Utilities Associates (EUA), see the Merger Agreements sections of the
Company's Form 10-K for 1998 and the Company's 1998 Annual Report.
Update of Merger Agreements with National Grid and EUA
The NEES/National Grid merger has received approval or clearance from
shareholders of both National Grid and NEES, the Federal Trade Commission
(FTC), the Committee on Foreign Investment in the United States, the Federal
Energy Regulatory Commission (FERC), the Vermont Public Service Board (VPSB),
the Connecticut Department of Public Utility Control (CDPUC), and the New
Hampshire Public Utilities Commission (NHPUC).
On November 3, 1999, the Office of the Consumer Advocate for New Hampshire
filed a motion seeking rehearing or reconsideration of the merger approval by
the NHPUC with respect to the treatment of the acquisition premium and
stranded costs. NEES and National Grid have opposed the motion for
rehearing.
NEES and National Grid have also filed for merger approval with the
Securities and Exchange Commission (SEC), under the Public Utility Holding
Company Act of 1935 (1935 Act). In connection with the SEC application, the
Massachusetts Department of Telecommunications and Energy (MDTE) and the
Rhode Island Public Utilities Commission (RIPUC) certified to the SEC that
the merger would not interfere with their authority or ability to protect
customers of NEES' distribution subsidiaries in Massachusetts and Rhode
Island, respectively.
In addition, NEES and National Grid have also filed for merger approval
with the Nuclear Regulatory Commission (NRC) to transfer ownership licenses
for its minority ownership interests in regional nuclear plants. In July
1999, three subsidiaries of Northeast Utilities (NU) filed a request for
hearing with the NRC with respect to financial qualifications and issues of
foreign ownership. In October 1999, the NRC issued an order granting the
request for hearing and directed NEES, National Grid, and the NU subsidiaries
to promptly determine whether the proceeding could be settled without a
hearing. In November 1999, NEES, National Grid, and the NU subsidiaries
executed an agreement with respect to these issues. As part of this
agreement, the NU subsidiaries agreed to withdraw their intervention and
request for hearing. Assuming the NRC grants the motion to withdraw, NEES
and National Grid anticipate that the remaining required regulatory approvals
from the SEC, under the 1935 Act, and the NRC will be obtained in a time
frame that will allow the merger to be completed by early 2000.
The NEES acquisition of EUA has received approval or clearance from EUA
shareholders, the FTC, the CDPUC, and the FERC. NEES and EUA have also made
appropriate filings with the SEC, under the 1935 Act, NRC, MDTE, VPSB, and
the RIPUC. The acquisition of EUA is expected to be completed by early 2000.
Industry Restructuring
- ----------------------
For a full discussion of industry restructuring activities, the Company's
divestiture of its nonnuclear generating business (the divestiture) and
stranded cost recovery, see the "Industry Restructuring" section of the
Company's Form 10-K for 1998 and the Company's 1998 Annual Report.
Regulatory Asset Recovery
- -------------------------
Historically, electric utility rates have been based on a utility's costs.
As a result, electric utilities are subject to certain accounting standards
that are not applicable to other business enterprises in general. Statement
of Financial Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated entities, in
appropriate circumstances, to establish regulatory assets, and thereby defer
the income statement impact of these charges because they are expected to be
included in future customer charges. In 1997, the Emerging Issues Task Force
(EITF) of the Financial Accounting Standards Board concluded that a utility
that had received approval to recover stranded costs through regulated
transmission and distribution rates would be permitted to continue to apply
FAS 71 to the recovery of stranded costs.
The Company has received authorization from the FERC to recover through
contract termination charges (CTC) 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. The Company
believes these factors and the EITF conclusion allow it to continue to apply
FAS 71. Because of the nuclear cost-sharing provisions related to the
Company's CTC, the Company ceased applying FAS 71 in 1997 to 20 percent of
its ongoing nuclear operations, the impact of which is immaterial.
As a result of applying FAS 71, the Company has recorded a regulatory asset
for the costs that are recoverable from customers through the CTC. The
regulatory asset reflects the loss on the sale of NEES' oil and gas business
and the unrecovered plant costs in operating nuclear plants (assuming no
market value), the costs associated with permanently closed nuclear power
plants, and the present value of the payments associated with the
above-market cost of purchased power contracts, reduced by the gain from the
divestiture. At September 30, 1999, the regulatory asset related to the CTC
was approximately $1.3 billion, of which $1.0 billion related to the
above-market costs of purchased power contracts.
Currently, there is much regulatory and other movement toward establishing
performance-based rates. It is possible that the adoption of
performance-based rates for the Company or its affiliates, future regulatory
rules, or other circumstances could cause the application of FAS 71 to be
discontinued. Absent the circumstances described in the next paragraph, this
discontinuation would result in a noncash write-off of previously established
regulatory assets, including those being recovered through the Company's CTC.
Massachusetts Electric Company (Massachusetts Electric) and The
Narragansett Electric Company (Narragansett Electric), distribution
affiliates of the Company, filed rate plans in April and May 1999,
respectively, which, if approved, may cause the application of FAS 71 to be
discontinued upon consummation of the NEES/National Grid merger. The Company
is recovering its stranded costs as a component of Massachusetts Electric's
and Narragansett Electric's distribution rates. As a result, the Company may
not be able to continue to apply FAS 71 to its recovery of stranded costs
after the merger is completed. Because the discontinuation of FAS 71 would be
coincident with the completion of the NEES/National Grid merger, the NEES
companies believe the appropriate accounting treatment would be that the
regulatory assets would not be written off but instead reclassified to either
an intangible asset account or a goodwill account.
Year 2000 Readiness Disclosure
- ------------------------------
Over the course of this year, most companies have faced and will continue
to face a potentially serious information systems (computer) problem because
many software applications and operational programs written in the past may
not properly recognize calendar dates associated with the year 2000 (Y2K).
This could cause computers to either shut down or lead to incorrect
calculations.
The NEES companies believe that their mission critical systems used to
deliver electricity are ready for date changes associated with Y2K, in
accordance with the criteria specified by the North American Electric
Reliability Council (NERC). Recognizing that neither the NEES companies nor
any other organization can make guarantees about something as complex as Y2K,
the NEES companies have also developed and implemented the contingency plans
described below (including contingency plans in the event of temporary
disruptions of electric service) to address potential problems caused by Y2K.
In the event that a short-term disruption in service occurs, NEES does not
expect that such a disruption would have a material impact on its financial
position or results of operation.
During 1996, the NEES companies began the process of identifying the
changes required to their computer software and hardware to mitigate Y2K
issues. The NEES companies established a Y2K Project team to manage these
issues, which consisted of as many as 70 full-time equivalent staff at some
points in time, primarily external consultants being overseen by an internal
Y2K management team. To facilitate the Y2K Project, NEES entered into
contracts with Keane, Inc. and IBM to provide personnel support to the Y2K
Project. Through September 30, 1999, the NEES companies have spent
approximately $18 million with these vendors, which is included in the cost
figures disclosed below. The Y2K Project team reports project progress to a
Y2K Executive Oversight Committee each month. The team also makes regular
reports to NEES' Board of Directors and its Audit Committee. The NEES
companies separated their Y2K Project into four parts as shown on the
following page.
Substantial ContingencyTesting,
Completion Documentation,
of Critical and Clean
Category Specific Example Systems Management
- -------- ---------------- ----------- -------------------
Mainframe/Midrange Accounting/Customer Completed Throughout 1999
systems service integrated
systems
Desktop systems Personal computers/ Completed Throughout 1999
Department software/
Networks
Operational/ Dispatching systems/ Completed Throughout 1999
Embedded Transmission and
systems Distribution systems/
Telephone systems
External issues Electronic Data Completed Throughout 1999
Interchange/Vendor
communications
The NEES companies used a three-phase approach in coordinating their Y2K
Project for system-related issues: (I) Assessment and Inventory, (II) Pilot
Testing, and (III) Renovation, Conversion, or Replacement of Application and
Operating Software Packages and Testing. Phase I, which was an initial
assessment of all systems and devices for potential Y2K defects, was
completed in mid-1997. These assessments included, but were not limited to,
the review of program code for mainframe and midrange systems, analysis of
personal computer hardware and network equipment for desktop systems,
reaching consensus with key "data exchange" partners regarding the approach
and execution of plans to address Y2K-related issues, and coordination with
other New England Power Pool (NEPOOL) member utilities related to operational
systems, such as transmission systems. Phase II, which consisted of
renovation pilots for a cross-section of systems in order to facilitate the
establishment of templates for Phase III work, was completed in late 1997.
Phase III, which was completed on June 30, 1999, required the renovation,
conversion, or replacement of the remaining applications and operating
software packages.
Critical systems include major operational and informational systems such
as the NEES companies' financial-related and customer information systems.
These mission critical systems were first addressed at an individual
component level, and then, upon satisfactory completion of that testing,
reviewed at an integrated level, during which the Y2K Project team tested for
Y2K problems which could be caused by various system interfaces.
Additionally, contingency plans have been implemented for mission critical
systems, as described below.
The overall Y2K Project was designed such that Y2K-related work performed
by external consultants was reviewed by NEES employees, and vice-versa. The
Y2K Project team management continuously benchmarked its progress against the
recommended progress schedule documented by NERC, and has met all recommended
schedules, including the issuance of its Year 2000 Readiness Letter to NERC
on June 30, 1999.
The NEES companies also implemented a formalized communication process with
third parties to give and receive information related to their progress in
remediating their own Y2K issues, and to communicate the NEES companies'
progress in addressing the Y2K issue. These third parties include major
customers, suppliers, and significant businesses with which the NEES
companies have data links (such as banks). The NEES companies have identified
standard offer (transition service) generation service providers,
telecommunications companies, and the Independent System Operator-New England
(ISO New England) as critical to business operations. The NEES companies
have been in contact with all of these parties regarding the progress of
their Y2K remediation efforts, and will continue to monitor their ongoing
remediation efforts through continued communications. The NEES companies
cannot predict the outcome of other companies' remediation efforts.
Therefore, contingency plans have been implemented, as described below.
The NEES companies believe total costs associated with making the necessary
modifications to all centralized and noncentralized systems will be
approximately $28 million, including the replacement of approximately one
thousand desktop computers. In addition, the NEES companies have spent $7
million (of which approximately $6 million has been capitalized) related to
the replacement of the human resources and payroll system, in part due to the
Y2K issue. As of September 30, 1999, substantially all Y2K-related costs
have been incurred. The NEES companies continually review their cost
estimates based upon the overall Y2K Project status, and update these
estimates as warranted.
The NEES companies developed and implemented Y2K contingency plans to allow
for critical information and operating systems to function from January 1,
2000, forward. These plans are intended to address both internal risks as
well as potential external risks related to suppliers and customers. Part of
the contingency plan implementation for accounting and desktop systems will
include taking extensive data back-ups prior to year-end closing. For
operational systems, the NEES companies have in place an overall disaster
recovery program, which already includes periodic disaster simulation
training (for outages due to severe weather, for instance). As part of the
Y2K contingency plan implementation, the NEES companies have reviewed their
disaster recovery plans and modified them for Y2K-specific issues, such as a
potential loss of telecommunication services. The NEES companies conducted
contingency plan drills on September 8, and 9, 1999.
Interregional and regional contingency plans have been finalized for
utility systems throughout the United States. At a regional level, the NEES
companies have participated and cooperated with NEPOOL and ISO New England.
Overall regional activities, including those of NEPOOL and ISO New England,
are being coordinated by the Northeast Power Coordinating Council, whose
activities have been incorporated into the interregional coordinating effort
by NERC. Drills of these interregional and regional contingency plans were
also conducted on September 8, and 9, 1999.
Earnings
- --------
Net income for the third quarter and first nine months of 1999 decreased
$30 million and $52 million, respectively, compared with the corresponding
periods in 1998. The decrease in earnings for the third quarter of 1999
reflects the continuing impact of the divestiture, as well as reduced CTC
rates effective January 1, 1999. Year-to-date earnings reflect these factors
as well as significant revenue reductions due to the impact of the
restructuring of the utility business. Partially offsetting the decrease in
revenues is the recovery of the Company's stranded investment costs,
including mitigation incentives of approximately $6 million and $19 million
in the third quarter and first nine months of 1999, respectively. In
addition, the decrease in earnings for the year-to-date period is also
partially offset by increased transmission revenues of approximately $11
million due to the elimination of certain liabilities related to open access
transmission tariffs.
Operating Revenue
- -----------------
Operating revenue decreased $180 million and $632 million in the third
quarter and first nine months of 1999, respectively, compared with the
corresponding periods in 1998. These decreases are due in part to the
divestiture, reduced CTC rates, and significant rate reductions implemented
in connection with industry restructuring. Partially offsetting these
decreases is the ability of the Company to recover stranded investments
including mitigation incentives and, on a year-to-date basis, an increase in
transmission revenues associated with the elimination of certain liabilities
related to open access transmission tariffs discussed above. The new rates
also include true-up mechanisms for stranded cost recovery billings and
nuclear operating and decommissioning costs.
Operating Expenses
- ------------------
Operating expenses for the third quarter and first nine months of 1999
decreased $144 million and $551 million, respectively, compared with the
corresponding periods in 1998. The divestiture reduced all categories of
operating expenses for the third quarter and first nine months of 1999, with
the exception of maintenance expenses for the third quarter.
The decrease in fuel expense and purchased power costs reflects the
divestiture and the assumption of the Company's obligations under most of its
previously existing purchased power contracts by the buyer of the Company's
nonnuclear generating business (the buyer). The Company remains obligated to
pay predetermined amounts to the buyer related to the above market cost of
those contracts. In addition, the Company also remains obligated under
purchased power contracts with the four Yankee nuclear power companies, the
costs of which decreased $10 million in the year-to-date period in connection
with the Maine Yankee and Connecticut Yankee nuclear power plants which are
shut down, as well as the effect of a 1998 refueling outage at the Vermont
Yankee nuclear power plant.
In addition to the impact of the divestiture, the decrease in other
operation and maintenance expenses on a combined basis reflects reduced
general and administrative costs due to workforce reductions and reduced Y2K
costs, as well as the allocation to the Company of fewer New England Power
Service Company costs after the divestiture. In addition, transmission
wheeling costs decreased $3 million and $14 million in the third quarter and
first nine months of 1999, respectively, as a result of such costs being
billed directly to the Company's distribution affiliates, the assumption of
transmission support agreements by the buyer, and, on a year-to-date basis,
the receipt of a transmission wheeling refund. These decreases are partially
offset by the third quarter 1998 reimbursement by the buyer to the Company
for certain previously incurred generation-related maintenance expenses, as
well as increased costs of $4 million for the year-to-date period associated
with the partially owned Millstone 3 and Seabrook 1 nuclear generating
facilities which experienced refueling outages in the second quarter of 1999.
Depreciation and amortization expenses decreased in the third quarter and
first nine months of 1999 due to the depreciation and amortization of
generation-related plant in 1998 being greater than the recovery and
amortization of generation-related stranded costs in 1999.
Interest Expense and Other Income
- ---------------------------------
The decrease in interest expense is due principally to reduced long-term
and short-term debt as a result of the divestiture.
The increase in other income for the year-to-date period is primarily due
to increased interest income resulting from the reinvestment of the proceeds
from the divestiture. However, interest income for the third quarter of 1999
declined.
Utility Plant Expenditures and Financing
- ----------------------------------------
Cash expenditures for utility plant for the first nine months of 1999
totaled $41 million and were primarily transmission-related. The funds
necessary for utility plant expenditures during the period were primarily
provided by internal funds.
On February 8, 1999, the Company repurchased 130,000 shares of its common
stock from NEES for $18 million. Approximately $7 million of the repurchase
price was charged to retained earnings.
In the first nine months of 1999, the Company increased its short-term debt
outstanding by $39 million. The Company has received regulatory approval
from the SEC, under the 1935 Act, to issue up to $375 million of short-term
debt.
At September 30, 1999, the Company had lines of credit and standby bond
purchase facilities with banks totaling $455 million which are available to
provide liquidity support for $372 million of the Company's bonds in tax-
exempt commercial paper mode and $39 million of short-term debt, and for
other corporate purposes. There were no borrowings under these lines of
credit at September 30, 1999.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Information concerning an agreement to settle a lawsuit brought by the
Company against Northeast Utilities on August 7, 1997 in Massachusetts
Superior Court, Worcester County concerning the Millstone 3 nuclear unit
and a demand for arbitration sent by the Company to Connecticut Light &
Power Company and Western Massachusetts Electric Company concerning the
Millstone 3 nuclear unit, discussed in this report in Note B of Notes to
Unaudited Financial Statements, is incorporated herein and made a part
hereof.
Information concerning dismissal of a lawsuit brought against the
Company by the Town of Norwood, Massachusetts and appeals of that lawsuit
and related Federal Energy Regulatory Commission orders, and the Company's
collection action, discussed in this report in Note C of Notes to Unaudited
Financial Statements, is incorporated herein and made a part hereof.
On August 31, 1999, the parties to an agreement for joint ownership,
construction and operation of the Wyman 4 generation unit, including the
Company, made a demand for arbitration to Central Maine Power Company (CMP)
for payments alleged due under the agreement upon CMP's sale of Wyman 4 to
FPL Energy, Inc. (FPL). Demand was also made to FPL as successor-in-
interest to CMP. The Company's portion of the claims under the agreement
could total approximately $7 million.
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
The Company is filing Financial Data Schedules.
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
September 30, 1999 to be signed on its behalf by the undersigned thereunto
duly authorized.
NEW ENGLAND POWER COMPANY
s/John G. Cochrane
John G. Cochrane, Treasurer,
Authorized Officer, and
Principal Financial Officer
Date: November 10, 1999