Annual Report 1997
New England Power Company
A Subsidiary of
New England Electric System
[LOGO] New England Power
A NEES Company
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Directors
(As of March 18, 1998)
Lawrence E. Bailey
President of the Company
Alfred D. Houston
Chairman of the Company and Executive Vice President of New
England Electric System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of New England Electric
System
Richard P. Sergel
President and Chief Executive Officer of New England Electric
System Officers
(As of March 18, 1998)
Alfred D. Houston
Chairman of the Company and Executive Vice President of New
England Electric System
Lawrence E. Bailey
President of the Company
Andrew H. Aitken
Vice President of the Company
Michael E. Hachey
Vice President of the Company
Michael E. Jesanis
Vice President of the Company and Senior Vice President and Chief
Financial Officer of New England Electric System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Senior Vice
President, General Counsel, and Secretary of New England Electric
System
John F. Malley
Vice President of the Company
Masheed H. Rosenqvist*
Vice President of the Company
Arnold H. Turner**
Vice President of the Company
Jeffrey W. VanSant
Vice President of the Company
Robert King Wulff
Clerk of the Company and of certain affiliates, Secretary or
Assistant Clerk of certain affiliates and Assistant Secretary of
an affiliate
John G. Cochrane
Treasurer of the Company and of certain affiliates, Vice
President of an affiliate, Assistant Treasurer of an affiliate
and Treasurer of New England Electric System
Kirk L. Ramsauer
Assistant Clerk of the Company and of certain affiliates, and
Secretary, Assistant Secretary or Clerk of certain affiliates
Howard W. McDowell
Assistant Treasurer and Controller of the Company and of certain
affiliates, Treasurer or Controller of certain affiliates and
Assistant Secretary of an affiliate
* Effective April 1, 1998
** Mr. Turner plans to retire
effective April 1, 1998.
Transfer Agent and Dividend Paying Agent of Preferred Stock
Bank of Boston, Boston, Massachusetts
Registrar of Preferred Stock
State Street Bank and Trust Company, Boston, Massachusetts
This report is not to be considered an offer to sell or buy or
solicitation of an offer to sell or buy any security.
New England Power Company
New England Power Company, (the Company) a wholly owned
subsidiary of New England Electric System (NEES), is a
Massachusetts corporation qualified to do business in
Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine,
and Vermont. The Company is subject, for certain purposes, to
the jurisdiction of the regulatory commissions of these six
states, the Securities and Exchange Commission (SEC), and the
Federal Energy Regulatory Commission (FERC). The Company's
business is currently that of generating, purchasing,
transmitting, and selling electric energy in wholesale quantities
to other electric utilities, principally its distribution
affiliates Granite State Electric Company (Granite State
Electric), Massachusetts Electric Company (Massachusetts
Electric), Nantucket Electric Company (Nantucket Electric), and
The Narragansett Electric Company (Narragansett Electric). In
August 1997, the Company and Narragansett Electric entered into
an agreement to sell their nonnuclear generating business to an
independent third party. See the "Divestiture of Generation
Business" section of Financial Review.
In accordance with industry restructuring settlements in both
Massachusetts and Rhode Island, the Company's wholesale contracts
with its distribution affiliates have been amended. These
amendments allow for termination of the all-requirements services
under those contracts. They also allow the Company to recover
the cost of its above-market generation commitments allocable to
Massachusetts Electric and Narragansett Electric (95 percent of
the total costs) through a transition access charge, which the
distribution affiliates will collect from customers. In February
1998, a comprehensive settlement agreement was reached with
parties in the state of New Hampshire, which, upon receipt of all
required regulatory approvals, would provide for arrangements
similar to those of the Massachusetts and Rhode Island
settlements. Efforts are ongoing with unaffiliated customers to
secure recovery of the balance of the Company's above-market
commitments. See the "Industry Restructuring" section of
Financial Review for further discussion.
Report of Independent Accountants
New England Power Company, Westborough, Massachusetts:
We have audited the accompanying balance sheets of New
England Power Company (the Company), a wholly owned subsidiary of
New England Electric System, as of December 31, 1997 and 1996 and
the related statements of income, retained earnings, and cash
flows for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of the Company as of December 31, 1997 and 1996, and the results
of its operations and its cash flows for each of the three years
in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
March 2, 1998
New England Power Company
Financial Review
Industry Restructuring
On August 5, 1997, the Company and its Rhode Island
distribution affiliate Narragansett Electric reached an agreement
to sell their nonnuclear generating business to USGen New
England, Inc (USGen), an indirect wholly owned subsidiary of PG&E
Corporation. The divestiture of the nonnuclear generating
business is in connection with the restructuring of the electric
utility industry.
Historically, electric utilities have provided their customers
bundled electric service within exclusive franchise service
territories. As the result of a number of trends, including a
disparity in electric rates among regions of the country and new
regulations and legislation intended to foster competition,
retail customers are being allowed to choose their power
supplier, with incumbent utilities required to deliver that
electricity over their transmission and distribution
systems. Because of legislation enacted in the states served by
the NEES companies, most customers served by the NEES companies
will have the ability to choose their power supplier by the first
quarter of 1998.
When customers are allowed to choose their power supplier,
utilities face the risk that market prices may not be sufficient
to recover the costs of the commitments incurred to supply
customers under a regulated structure. The amounts by which such
costs exceed market prices are commonly referred to as stranded
costs." As described below, the Company has reached settlement
agreements with all of its distribution affiliates and with
parties representing the distribution customers of those
affiliates. In each case, these settlements provide for recovery
of stranded costs.
Massachusetts Legislation and Settlement Agreement
In November 1997, legislation was enacted which provides
customers of Massachusetts' investor-owned utilities with the
ability to choose their power supplier beginning on March 1,
1998. The legislation requires electric companies to provide
customers who do not choose a power supplier with a transition
rate (or "standard offer generation service") which results in a
10 percent rate reduction, with the discount increasing to 15
percent on or before September 1, 1999. The legislation also
provides a mechanism for the recovery of stranded costs resulting
from the introduction of customer choice.
In December 1997, the Massachusetts Department of
Telecommunications and Energy (MDTE) (formerly the Massachusetts
Department of Public Utilities (MDPU)) found that a settlement
agreement (the Massachusetts Settlement) previously reached among
the Company, the Company's Massachusetts distribution affiliates
Massachusetts Electric and Nantucket Electric, and various
governmental agencies and other interested parties substantially
complies with or is consistent with the Massachusetts statute.
The Massachusetts Settlement was also conditionally approved by
the FERC in November 1997, subject to a compliance filing to
clarify the impact of the settlement on nonsettling parties.
In accordance with the Massachusetts Settlement, the Company's
wholesale contracts with Massachusetts Electric and Nantucket
Electric have been amended effective March 1, 1998. The
Massachusetts Settlement provides that Massachusetts Electric's
and Nantucket Electric's share of the Company's stranded costs
will be recovered from distribution customers through a
transition access charge, which will be collected by these
distribution companies. Under the Massachusetts Settlement, the
recovery of the Company's stranded costs is divided into several
categories. Unrecovered costs associated with generating plants
and regulatory assets would be recovered over 12 years and would
earn a return on equity of 9.4 percent. The above-market
component of purchased power contracts and nuclear
decommissioning costs would be recovered as incurred over the
life of those obligations, a period expected to extend beyond 12
years. Initially, the transition access charge was set at 2.8
cents per kilowatthour (kWh). The MDTE has approved a reduction
of the initial transition access charge to 2.7 cents per kWh for
Massachusetts Electric and Nantucket Electric, effective March
1, 1998. The Company's filing with the FERC to approve this
reduction is pending. The transition access charge would be
reduced further upon completion of the sale of the Company's
generating business, as described below. As the transition
access charge declines, the Company would earn incentives based
on successful mitigation of its stranded costs. These incentives
would supplement the Company's return on equity.
In addition to addressing customer choice and the recovery of
stranded costs, the Massachusetts Settlement also required the
NEES companies to divest their nonnuclear generating business.
In August 1997, the Company and Narragansett Electric entered
into an agreement to sell substantially all of their nonnuclear
generating business to USGen. See "Divestiture of Generating
Business" below. The net proceeds from the sale of the
nonnuclear generating business to USGen will be used to reduce
the transition access charge to approximately 1.5 cents per kWh.
In addition, the FERC accepted the NEES companies proposal in
conjunction with their divestiture filing that the recovery of
the remaining above-market nuclear generating plant investment
and regulatory assets be completed by the end of the year 2000.
A referendum question which asks voters to repeal the
Massachusetts statute is expected to be on the ballot in November
1998. The NEES companies are unable to predict the outcome.
While by itself, repeal of the statute is not expected to
materially impair the effectiveness of the previously approved
Massachusetts Settlement, the potential exists that following
repeal, there could be legislative or regulatory actions which
could be materially adverse to the NEES companies.
Rhode Island Legislation and Settlement Agreement
In August 1996, the state of Rhode Island enacted legislation
that allows customers in that state the opportunity to choose
their power supplier. Under the Rhode Island statute, state
accounts, certain new customers, and the largest manufacturing
customers were able to choose their power supplier beginning on
July 1, 1997. The balance of Rhode Island customers gained the
ability to choose their power supplier on January 1, 1998. The
Rhode Island statute also provided utilities with the ability to
recover stranded costs.
In November 1997, the FERC conditionally approved a settlement
agreement among the Company, its Rhode Island distribution
affiliate Narragansett Electric, the Rhode Island Public
Utilities Commission and the Rhode Island Division of Public
Utilities and Carriers, to implement the stranded cost recovery
provisions of the Rhode Island statute, subject to a compliance
filing to clarify the impact of the settlement on nonsettling
parties. The terms of the Rhode Island Settlement are
substantially the same as the Massachusetts Settlement.
New Hampshire Legislation and Settlement Agreement
On February 3, 1998, the Company and its New Hampshire
distribution affiliate Granite State Electric reached a
comprehensive settlement agreement with the Governor's office of
the State of New Hampshire and a number of other interested
parties on a plan to provide choice of power supplier to its
customers by no later than July 1, 1998. This settlement
agreement was reached in response to a previously enacted New
Hampshire statute which requires customer choice of power
supplier. The principal terms of the New Hampshire settlement
agreement, which require approval by state and federal
regulators, are substantially similar to the Massachusetts
Settlement and the Rhode Island Settlement, including rate
reductions for customers and the ability to recover stranded
costs.
Unaffiliated Customers
Agreements have not yet been reached with certain wholesale
customers that represent less than 2 percent of the Company's
stranded cost exposure. In March 1998, the largest of these
customers, the Town of Norwood, Massachusetts, gave notice of its
intent to terminate its contract with the Company, without
accepting responsibility for its share of the Company's stranded
costs, and to begin taking power from another supplier. The
Company has filed with the FERC for permission to charge Norwood
a contract termination charge for its share of the Company's
stranded costs.
Divestiture of Generating Business
As described above, in August 1997, the Company and
Narragansett Electric (collectively, the Sellers) reached an
agreement to sell their nonnuclear generating business to USGen.
The nonnuclear generating business includes three fossil-fueled
generating stations and 15 hydroelectric generating stations,
totaling approximately 4,000 megawatts (MW) of capacity, as well
as NEES' interest in Narragansett Energy Resources Company
(NERC), a 20 percent general partner in the Ocean State Power
project, all of which has a book value of $1.1 billion. USGen
will pay the Sellers $1.59 billion in cash, of which $225 million
will be contingent upon the introduction of customer choice of
power supplier in Massachusetts. Based on the enactment of the
Massachusetts statute, the NEES companies believe that the
conditions for payment of the full purchase price have been met.
USGen will also reimburse the NEES companies for $85 million of
costs associated with early retirement and special severance
programs for employees affected by industry restructuring. USGen
will assume responsibility for environmental conditions at the
Sellers' nonnuclear generating stations. USGen will also assume
the Sellers' obligations under long-term fuel and fuel
transportation contracts and certain collective bargaining
agreements for nonnuclear facilities.
In addition to the purchase of the generating stations, USGen
will purchase the Company's entitlement to approximately 1,100 MW
of power procured under long-term contracts. The Company will
make a monthly fixed contribution toward the above-market cost of
the purchased power of between $12.5 million and $14.2 million
per month from closing through January 2008. USGen will be
responsible for the balance of the costs under the purchased
power contracts.
The sale is subject to approval by various state and federal
regulatory agencies. Several parties have objected to the sale
on various grounds, including allegations that following the
sale, USGen would be able to exercise unlawful levels of market
power. On February 25, 1998, the FERC issued an order that
rejected the market power allegations, approved the sale and
conditionally approved most supporting filings. On February 27,
1998, the FERC approved the transfer of the hydroelectric
generating licenses to USGen. While the timing of receipt of
final regulatory approvals is uncertain, receipt of all approvals
is unlikely before mid-1998. Closing is contingent upon all
regulatory approvals being obtained by February 1999.
In order to meet the terms of the Company's mortgage
indenture, the Company will be required, prior to the
consummation of the sale, to either defease or call approximately
$278 million of its mortgage bonds. Any defeasance of bonds
would be by deposit of cash representing principal and interest
to the maturity date, or interest, principal, and general
redemption premium to an earlier redemption date. In addition,
the Company will retire approximately $372 million of mortgage
bonds securing the issuance of a like amount of pollution control
revenue bonds (PCRBs) by various public agencies. However, the
Company expects that substantially all of the underlying PCRBs
will remain outstanding as unsecured obligations of the Company.
In addition, the long-term debt of NERC will be retired prior to
the closing.
Upon completion of the divestiture of the Company's nonnuclear
generation business, the Company's stranded costs that will be
recovered from distribution customers through a transition
access charge, which will be collected by the Company's
distribution affiliates, will be reduced from $4.5 billion to
$2.1 billion.
As part of the divestiture plan, in February 1998, New England
Energy Incorporated (NEEI) (a wholly owned subsidiary of NEES)
sold its oil and gas properties for approximately $50 million.
NEEI's loss on the sale of approximately $120 million, before
tax, has been reimbursed by the Company.
At the divestiture date, any gain or loss from the divestiture
of nonnuclear generating assets and oil and gas assets will be
recorded as a regulatory asset or liability to be recovered as
part of the Company's stranded costs, through the ongoing
transition access charge, consistent with the settlement
agreements. The Company may be required to record a liability
for the monthly fixed contribution towards the above-market cost
of purchased power. In such an event, the Company would also
record a regulatory asset consistent with the settlement
agreements.
In addition, the Company will endeavor to sell, or otherwise
transfer, its minority interest in three nuclear power plants and
a 60 MW interest in a fossil-fueled generating station in Maine
to nonaffiliates. Until such time as the nuclear interests are
divested, the Company will share with customers 80 percent of the
revenues and operating costs related to the units, with
shareholders retaining the balance. In the event that the
Company determines that it has an impairment of its nuclear plant
balances under Statement of Financial Accounting Standards No.
121, Accounting for Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of (FAS 121), it will record any such impairment
as a regulatory asset.
Workforce Reduction
The NEES companies expect to implement substantial workforce
reductions beginning in 1998 as a result of industry
restructuring and the sale of the nonnuclear generating business.
The NEES companies are in the process of offering early
retirement programs to their union and non-union employees,
contingent upon the closing of the sale of the nonnuclear
generating business to USGen. In addition, the NEES companies
intend to offer enhanced severance benefits to affected
employees. As previously described, the costs of the early
retirement and severance programs for all NEES companies are
expected to be substantially recovered from the proceeds of the
sale of the nonnuclear generating business. Since the early
retirement program is contingent upon the divestiture, its cost
will not be accrued until that time.
Risk Factors
While the Company believes that the previously described
settlements and legislation and the sale agreement with USGen and
other developments, including the New Hampshire Settlement,
constitute substantial progress in reducing the impacts
associated with industry restructuring, significant risks remain.
These include, but are not limited to: (i) the potential that
ultimately the settlements will not be implemented in the manner
anticipated by the Company, (ii) the possibility that a voter
referendum in November 1998 could overturn the Massachusetts
legislation, followed by materially adverse legislative or
regulatory actions, (iii) the possibility of federal legislation
that would increase the risks above those contained in the
settlements and the Massachusetts and Rhode Island statutes, (iv)
the potential for adverse stranded cost recovery decisions
involving wholesale customers with whom settlements have not yet
been reached and (v) the failure to complete the sale of the
generating business to USGen.
This report contains statements that may be considered forward
looking under the securities laws. Actual results may differ
materially for the reasons discussed in this Financial Review.
Upon the introduction of consumer choice, settlement agreements
related to recovery of stranded costs will limit the Company's
return on equity to approximately 9.4 percent, before mitigation
incentives, which is significantly lower than that earned by the
Company in recent years. Following completion of the sale of the
nonnuclear generating business, the Company's earnings will also
be affected by the return on the reinvestment of sale proceeds,
which is expected, at least in the near term, to be considerably
less than the return historically earned by the generating
business.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of certain
items of income and expense expected to be reflected in future
rates. At December 31, 1997, the Company had approximately $420
million in net regulatory assets in compliance with FAS 71. This
amount excludes any effects related to the divestiture of NEEI's
oil and gas properties discussed above.
In response to concerns expressed by the staff of the SEC, the
Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board took under consideration how FAS 71 should be
applied in light of recent changes within the regulated utility
industry. In July 1997, the EITF concluded that a utility whose
ongoing generation operations would not permit the application of
FAS 71, but had otherwise 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
the stranded costs.
The restructuring settlements and statutes each provide for
recovery of substantially all applicable stranded costs of
generating assets and oil and gas related assets (including
regulatory assets) not recoverable from the proceeds of the
divestiture of the Company's generating business. The cost of
these assets would be recovered as part of a cost-based
transition access charge imposed on all distribution customers.
Additionally, FERC Order No. 888 enables transmission companies
to recover their specific costs of providing transmission
service. Therefore, after the proposed divestiture,
substantially all of the Company's business, including the
recovery of its stranded costs, would remain under cost-based
rate regulation. The Company believes these factors and the
EITF conclusion will allow it to continue to apply FAS 71. As a
result of the FERC approval of the restructuring settlements in
November 1997, the Company was required to cease to apply FAS 71
to the 20 percent of its ongoing nuclear operations, as described
under "Divestiture of Generation Business," the impact of which
is expected to be immaterial.
Despite the progress made to date, it is possible that future
regulatory rules or other circumstances could cause the
application of FAS 71 to be discontinued, which would result in a
noncash write-off of previously established regulatory assets
related to the affected operations. In addition, write-downs of
plant assets under FAS 121 could be required, including a
write-off of any gain or loss from the divestiture of the
generating business.
Overview of Financial Results
Net income for 1997 decreased $8 million compared with 1996.
The decrease was primarily due to increased operation and
maintenance costs. The decrease was partially offset by a
transmission rate increase, decreased purchased electric energy
costs, excluding fuel, and decreased depreciation and
amortization.
Net income increased by $1 million in 1996. This increase
reflected a reduction in purchased electric energy, excluding
fuel and a reduction in operation and maintenance expense.
Partially offsetting these increases were decreases in allowance
for funds used during construction (AFDC) and increased property
taxes, both primarily due to the completion in the second half of
1995 of the Manchester Street generating station, as well as
increased integrated facilities credits to the Company's
affiliate, Narragansett Electric. The Company also experienced
reduced peak demand charge billings in 1996.
Operating Revenue
The following table summarizes the changes in operating
revenue:
Increase (Decrease) in Operating Revenue
(In millions) 1997 1996
---- ----
Sales growth, peak demand charges, and
stranded investment recovery $ 2 $(4)
Fuel recovery 55 48
Narragansett integrated facilities credit 5 (9)
Other, including transmission revenues 16 (5)
--- ---
$78 $30
=== ===
Sales decreased in 1997 primarily due to a decrease in peak
demand billing as a result of milder weather in the first quarter
of 1997, as well as reduced load due to retail wheeling pilot
programs instituted by Massachusetts Electric and Granite State
Electric. These decreases are more than offset by stranded
investment recovery, which represents amounts being recovered in
connection with these retail wheeling pilot programs, and with
the first phase of retail competition by Narragansett Electric.
For a discussion of fuel recovery revenues, see the fuel costs
discussion in the "Operating Expenses" section.
The entire output of Narragansett Electric's generating
capacity is made available to the Company. Narragansett Electric
receives a credit on its purchased power bill from the Company
for its fuel costs and other generation and transmission related
costs. The reduction in these credits in 1997 reflects a
reduction in dismantlement costs being incurred by Narragansett
Electric on a previously retired generating facility. The
increased credits in 1996 relate to costs associated with the
dismantlement of the previously retired South Street generating
facility and with Narragansett Electric's portion of costs
associated with the repowered Manchester Street generating
station that entered commercial operation in the second half of
1995.
The increase in other revenues in 1997 is primarily due to a
transmission rate increase that went into effect in mid-1996.
Operating Expenses
The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
(In millions) 1997 1996
---- ----
Fuel costs $ 55 $ 52
Purchased energy excluding fuel (6) (28)
Other operation and maintenance 49 (22)
Depreciation and amortization (6) 1
Taxes (1) 8
---- ----
$ 91 $ 11
==== ====
Fuel costs represent fuel for generation and the portion of
purchased electric energy permitted in the past to be recovered
through the Company's fuel adjustment clause. After the
divestiture of the nonnuclear generating business, the Company
will not require such a mechanism. The increase in fuel costs in
1997 and 1996 reflects increased power supply to other utilities,
increased replacement power costs due to the reduced generation
from partially owned nuclear units, and an increase in the cost
of short-term purchased power. The increase in 1996 is also due
to fixed pipeline demand charges that, prior to the completion of
the Manchester Street Station, were being partially deferred for
amortization and recovery after the unit went into service in the
second half of 1995.
The decrease in purchased power costs, excluding fuel, during
1997 reflects reduced charges from the Connecticut Yankee nuclear
power plant, which was permanently closed in December 1996. This
decrease was partially offset by increased charges from the Maine
Yankee nuclear power plant, which was permanently closed in mid-
1997. The decrease in 1996 reflected the expiration of certain
purchased power contracts.
The decrease in depreciation and amortization expense reflects
the completion of the amortization of the Company's pre-1988
investment in the Seabrook 1 nuclear unit and the Company's
investment in the canceled Seabrook 2 nuclear unit. In
accordance with 1995 settlement agreement, upon completion of the
amortization of Seabrook 1 and Seabrook 2, the Company agreed to
accelerate its amortization of previously deferred costs
associated with postretirement benefits other than pensions
(PBOPs). Upon completion of the PBOP amortization, which
occurred in July 1997, the Company was required to accelerate its
depreciation of its investment in the Millstone 3 nuclear unit.
This accelerated depreciation is recorded as a regulatory
liability.
The increase in other operation and maintenance expenses in
1997 is due to an increase of $8 million in transmission wheeling
costs, increased maintenance costs of $14 million at the
partially owned Millstone 3 and Seabrook 1 nuclear facilities, an
$11 million increase in deferred PBOP amortization mentioned
above, an overall increase in general and administrative costs,
start-up costs associated with the new regional transmission
control organization, and the Company's share of costs associated
with the restoration to service of previously idled facilities
throughout New England in response to a tightening regional power
supply. The decrease in operation and maintenance in 1996
reflected reduced thermal and hydro generating plant overhaul
activity, partially offset by $13 million of costs to correct
deficiencies at the Millstone 3 nuclear unit, in which the
Company has a 12 percent ownership interest. The Company also
experienced a reduction in transmission wheeling costs, pension
costs, PBOPs, and other general and administrative costs.
Allowance for Funds Used During Construction (AFDC)
The decrease in AFDC in 1996 is due to the completion of the
Manchester Street plant repowering project.
Nuclear Units
Nuclear Units Permanently Shut Down
Three of the four regional nuclear generating companies in
which the Company has a minority interest own nuclear generating
units which have been permanently shut down. These three units
are as follows:
NEP's Investment Future Estimated
Unit Percent Amount Date Retired Billings to NEP($)
- -----------------------------------------------------------------------------
Yankee Atomic 30 7 million Feb 1992 44 million
Connecticut Yankee 15 17 million Dec 1996 92 million
Maine Yankee 20 16 million Aug 1997 164 million
In the case of each of these units, the Company has recorded
an estimate of the total future payment obligation as a liability
and an offsetting regulatory asset, reflecting estimated future
billings from the companies. In a 1993 decision, the FERC
allowed Yankee Atomic to recover its undepreciated investment in
the plant as well as unfunded nuclear decommissioning costs and
other costs. Connecticut Yankee and Maine Yankee have both filed
similar requests with the FERC. Several parties have intervened
in opposition to both filings. The Company's stranded cost
settlements allow it to recover all costs that the FERC allows
the Yankee companies to bill to the Company.
In October 1997, the Citizen's Awareness Network and Nuclear
Information and Resource Service filed a petition with the
Nuclear Regulatory Commission (NRC) that would require formal
NRC approval of a plant decommissioning plan for the Connecticut
Yankee and Maine Yankee plants. In 1998, the petitioners
indicated their intention to file a request with the NRC designed
to overturn a current NRC rule on decommissioning. The Company
cannot predict what impact, if any, these activities will have on
the cost of decommissioning the plants.
At Maine Yankee, the NRC has identified numerous apparent
violations of its regulations, which may result in the assessment
of significant civil penalties.
In the 1970s, the Company and several other shareholders
(Sponsors) of Maine Yankee entered into 27 contracts (Secondary
Purchase Agreements) under which they sold portions of their
entitlement to Maine Yankee power output through 2002 to various
entities, primarily municipal and cooperative systems in New
England (Secondary Purchasers). Virtually all of the Secondary
Purchasers have ceased making payments under the Secondary
Purchase Agreements and have demanded arbitration, claiming that
such agreements excuse further payments upon plant shutdown. The
Company has notified the Secondary Purchasers that the shutdown
does not relieve them of their obligation to make payments under
the Secondary Purchase Agreements and that they are in default of
such agreements. The Company has asked the FERC to enforce the
Company's rights under the agreements. In the event that no
further payments are forthcoming from Secondary Purchasers, the
Company, as a primary obligor to Maine Yankee, would be required
to pay an additional $9 million of future shutdown costs. These
costs are not included in the $164 million estimate disclosed in
the table above. Shutdown costs are recoverable from customers
under the stranded cost settlements.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall.
Operating Nuclear Units
The Company has minority interests in three other nuclear
generating units, Vermont Yankee, Millstone 3, and Seabrook 1.
In October 1996, the NRC issued letters to operators of nuclear
power plants requiring them to document that the plants are
operated and maintained within their design and licensing bases,
and that any deviations are reconciled in a timely manner. The
Seabrook 1 and Vermont Yankee nuclear power plants responded to
the NRC letters in February 1997. Millstone 3 is currently shut
down and has been placed on the NRC "Watch List," signifying that
its safety performance exhibits sufficient weakness to warrant
increased NRC attention. Millstone 3 may not restart without NRC
approval.
Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Vermont Yankee, are
increasing rapidly and could adversely affect their service
lives, availability, and costs. These uncertainties stem from a
combination of factors, including the acceleration of competitive
pressures in the power generation industry and increased NRC
scrutiny. The Company performs periodic economic viability
reviews of operating nuclear units in which it holds ownership
interests.
Millstone 3
In April 1996, the NRC ordered Millstone 3, which has
experienced numerous technical and nontechnical problems, to
remain shut down pending verification that the unit's operations
are in accordance with NRC regulations and the unit's operating
license. Millstone 3 is operated by a subsidiary of Northeast
Utilities (NU). The Company is not an owner of the Millstone 1
and 2 nuclear generating units, which are also shut down under
NRC orders.
A number of significant prerequisites must be fulfilled prior
to restart of Millstone 3, including certification by NU that the
unit adequately conforms to its design and licensing bases, an
independent verification of corrective actions taken at the unit,
an NRC assessment concluding a safety conscious work environment
exists, public meetings, and a vote of the NRC Commissioners.
The Company cannot predict when Millstone 3 will be allowed by
the NRC to restart, but believes restart of the unit is unlikely
prior to the summer of 1998.
Since April 1996, the Company has incurred an estimated $35
million in incremental replacement power costs, which it has been
recovering from customers through its fuel clause. During the
outage, the Company is incurring incremental replacement power
costs of approximately $2 million per month.
Several criminal investigations related to Millstone 3 are
ongoing. In December 1997, the NRC assessed civil penalties
totaling $2.1 million for numerous violations at the three
Millstone units. The Company's share of this fine was less than
$100,000. The Connecticut Department of Environmental Protection
and Connecticut Attorney General have filed suit against NU for
alleged wastewater discharge violations at the Millstone units,
which may result in the assessment of substantial civil
penalties.
In August 1997, the Company filed suit against NU in
Massachusetts Superior Court for damages resulting from the
tortious conduct of NU relating to Millstone 3. The Company is
seeking compensation for the losses it has suffered, including
the costs of lost power and costs necessary to assure that
Millstone 3 can safely return to operation. The Company also
seeks punitive damages. NU has filed for dismissal of the suit
and sought to consolidate it with suits filed by other joint
owners in Massachusetts Superior Court.
The Company also sent a demand for arbitration to Connecticut
Light & Power Company and Western Massachusetts Electric Company,
both subsidiaries of NU, seeking damages resulting from their
breach of obligations under an agreement with the Company and
others regarding the operation and ownership of Millstone 3.
Brayton Point
In October 1996, the Environmental Protection Agency (EPA)
announced it was beginning a process to determine whether to
modify or revoke and reissue the Company's water discharge permit
for its Brayton Point 1,576 MW power plant. This action came two
years before the permit expiration date. The EPA stated it took
this step in response to a request from the Rhode Island
Department of Environmental Management (RIDEM). A RIDEM report
asserted a statistical correlation between the decline in the
fish population in Mount Hope Bay and a change in operations at
Brayton Point that occurred in the mid-1980s.
In April 1997, the Company signed a memorandum of agreement
negotiated with the various federal and state environmental
agencies under which the Company will voluntarily operate under
more stringent conditions than under its existing permit. The
agreement was in lieu of any immediate action on the permit, and
will remain in effect until a renewal permit is issued. On
January 16, 1998, the Company applied for a new water discharge
permit with both the EPA and the Massachusetts Department of
Environmental Protection. The Company cannot predict at this
time what permit changes will be required or the impact on
Brayton Point's operations and economics. However, permit
changes may substantially impact the plant's capacity and ability
to produce energy and/or require substantial capital expenditures
to construct equipment to address the concerns raised by the
environmental agencies.
Year 2000 Computer Issues
In the next two years, most large companies will face a
potentially serious information systems (computer) problem
because most software applications and operational programs
written in the past will not properly recognize calendar dates
beginning in the year 2000. This could force computers to either
shut down or lead to incorrect calculations. The NEES companies
began the process of identifying the changes required to their
computer programs and hardware during 1996. The necessary
modifications to the NEES companies' centralized financial,
customer, and operational information systems are expected to be
completed by the end of 1998. Noncentralized systems are also
being reviewed for Year 2000 problems. The NEES companies
believe total costs associated with making the necessary
modifications to all centralized and noncentralized systems will
be approximately $25 million, of which approximately $8 million
has been incurred as of December 31, 1997. Most of the remaining
costs are expected to be incurred prior to December 31, 1998.
The Company's share of the total costs is expected to be
approximately $10 million.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $70 million for
1997. The funds necessary for utility plant expenditures during
the period were provided by net cash from operating activities,
after the payment of dividends. Cash expenditures for utility
plant for 1998 are estimated to be $55 million, principally
related to transmission functions. Internally generated funds
are expected to fully cover the Company's 1998 capital
expenditures in 1998.
In 1997, the Company retired $3 million of maturing long-term
debt. The Company also retired $35 million of mortgage bonds
prior to maturity and incurred premiums of $2.2 million
associated with the early retirement.
At December 31, 1997, the Company had $111 million of
short-term debt outstanding including $108 million of commercial
paper borrowings and $3 million of borrowings from affiliates.
At December 31, 1997, the Company had lines of credit and bond
purchase facilities with banks totaling $580 million which are
available to provide liquidity support for commercial paper
borrowings and for $372 million of the Company's outstanding
variable rate mortgage bonds in tax-exempt commercial paper mode
and for other corporate purposes. There were no borrowings under
these lines of credit at December 31, 1997.
New Accounting Standards
In 1997, the Financial Accounting Standards Board released two
new Statements of Financial Accounting Standards (FAS), FAS 130
and FAS 131, both of which will go into effect in 1998. FAS 130,
Reporting Comprehensive Income, requires the reporting in
financial statements of a new additional item called
comprehensive income, which will incorporate amounts not
previously included in reported net income. FAS 131, Disclosure
about Segments of an Enterprise and Related Information, requires
the reporting in financial statements of certain new additional
information about operating segments of a business. The Company
is currently evaluating the impact that these new accounting
standards will have on its future reporting requirements.
New England Power Company
Statements of Income
Year ended December 31,
(In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Operating revenue, principally
from affiliates $1,677,903 $1,600,309 $1,570,539
Operating expenses:
Fuel for generation 372,734 342,545 279,849
Purchased electric energy 527,647 508,910 547,926
Other operation 241,506 203,456 211,872
Maintenance 89,820 79,118 92,954
Depreciation and amortization 98,024 104,209 102,758
Taxes, other than income taxes 67,311 66,416 58,716
Income taxes 90,009 91,894 91,051
---------- ---------- ----------
Total operating expenses 1,487,051 1,396,548 1,385,126
---------- ---------- ----------
Operating income 190,852 203,761 185,413
Other income:
Allowance for equity funds
used during construction - - 7,746
Equity in income of nuclear
power companies 5,189 5,159 5,721
Other income (expense), net (3,404) (1,851) (1,610)
---------- ---------- ----------
Operating and other income 192,637 207,069 197,270
---------- ---------- ----------
Interest:
Interest on long-term debt 42,277 45,111 46,797
Other interest 7,055 10,066 10,525
Allowance for borrowed funds used
during construction - credit (1,238) (591) (11,479)
---------- ---------- ----------
Total interest 48,094 54,586 45,843
---------- ---------- ----------
Net income $ 144,543 $ 152,483 $ 151,427
========== ========== ==========
Statements of Retained Earnings
Year ended December 31,
(In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Retained earnings at beginning
of year $ 400,610 $ 385,309 $ 372,763
Net income 144,543 152,483 151,427
Dividends declared on cumulative
preferred stock (2,075) (2,574) (3,433)
Dividends declared on common stock,
$21.00, $20.80, and $21.00
per share, respectively (135,448) (134,158) (135,448)
Premium on redemption of
preferred stock - (450) -
---------- --------- ----------
Retained earnings at end of year $ 407,630 $ 400,610 $ 385,309
========== ========= ==========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
At December 31, (In thousands) 1997 1996
- -----------------------------------------------------------------------------
Assets
Utility plant, at original cost $3,057,749 $2,991,797
Less accumulated provisions
for depreciation and amortization 1,196,972 1,118,340
---------- ----------
1,860,777 1,873,457
Construction work in progress 29,015 36,836
---------- ----------
Net utility plant 1,889,792 1,910,293
---------- ----------
Investments:
Nuclear power companies, at equity (Note D-1) 49,825 47,902
Nonutility property and other investments 34,723 30,591
---------- ----------
Total investments 84,548 78,493
---------- ----------
Current assets:
Cash 1,643 3,046
Accounts receivable:
Affiliated companies 233,308 201,370
Accrued NEEI revenues (Note D-3) 11,419 21,648
Others 26,638 23,219
Fuel, materials, and supplies, at average cost 47,492 58,709
Prepaid and other current assets 17,837 25,050
---------- ----------
Total current assets 338,337 333,042
---------- ----------
Accrued Yankee nuclear plant costs (Note D-2) 299,564 166,413
Deferred charges and other assets (Note B) 150,851 159,474
---------- ----------
$2,763,092 $2,647,715
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
authorized and outstanding 6,449,896 shares $ 128,998 $ 128,998
Premium on capital stock 86,779 86,779
Other paid-in capital 289,818 289,818
Retained earnings 407,630 400,610
Unrealized gain on securities, net 34 -
---------- ----------
Total common equity 913,259 906,205
Cumulative preferred stock, par value
$100 per share (Note H) 39,666 39,666
Long-term debt 647,720 733,006
---------- ----------
Total capitalization 1,600,645 1,678,877
---------- ----------
Current liabilities:
Long-term debt due in one year 50,000 3,000
Short-term debt (including $3,125
and $5,275 to affiliates) 111,250 93,600
Accounts payable (including $14,373
and $25,301 to affiliates) 109,121 127,226
Accrued liabilities:
Taxes 39 8,158
Interest 8,905 9,668
Other accrued expenses (Note G) 23,554 16,577
Dividends payable 35,474 27,412
---------- ----------
Total current liabilities 338,343 285,641
---------- ----------
Deferred federal and state income taxes 369,757 382,164
Unamortized investment tax credits 53,463 55,486
Accrued Yankee nuclear plant costs (Note D-2) 299,564 166,413
Other reserves and deferred credits 101,320 79,134
Commitments and contingencies (Note D)
---------- ----------
$2,763,092 $2,647,715
========== ==========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Statements of Cash Flows
Year ended December 31, (In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Operating activities:
Net income $ 144,543 $ 152,483 $ 151,427
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 101,186 108,338 108,384
Deferred income taxes and
investment tax credits, net (12,728) (7,458) 25,683
Allowance for funds used
during construction (1,238) (591) (19,225)
Decrease (increase) in
accounts receivable (25,128) 19,629 1,321
Decrease (increase) in fuel,
materials, and supplies 11,217 (4,045) 18,697
Decrease (increase) in prepaid
and other current assets 7,213 2,936 5,743
Increase (decrease) in accounts payable (18,105) (36,565) (15,970)
Increase (decrease) in other
current liabilities (1,905) 9,640 (2,150)
Other, net 19,919 28,582 (28,244)
--------- --------- ---------
Net cash provided by
operating activities $ 224,974 $ 272,949 $ 245,666
========== ========= =========
Investing activities:
Plant expenditures, excluding allowance
for funds used during construction $ (69,863) $ (65,981) $(162,766)
Other investing activities (4,040) (3,878) (3,614)
---------- --------- ---------
Net cash used in
investing activities $ (73,903) $ (69,859) $(166,380)
--------- --------- ---------
Financing activities:
Dividends paid on common stock $(127,386) $(138,995) $(103,198)
Dividends paid on preferred stock (2,075) (2,574) (3,433)
Changes in short-term debt 17,650 (31,550) (20,425)
Long-term debt - issues - 47,850 60,000
Long-term debt - retirements (38,500) (57,850) (10,000)
Preferred stock - retirements - (20,900) -
Premium on reacquisition of long-term debt (2,163) - -
Gain on redemption of preferred stock - 1,368 -
--------- --------- ---------
Net cash used in
financing activities $(152,474) $(202,651) $ (77,056)
--------- --------- ---------
Net increase (decrease) in
cash and cash equivalents $ (1,403) $ 439 $ 2,230
Cash and cash equivalents
at beginning of year 3,046 2,607 377
--------- --------- ---------
Cash and cash equivalents at end of year $ 1,643 $ 3,046 $ 2,607
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $ 46,033 $ 51,212 $ 41,557
--------- --------- ---------
Federal and state income taxes paid $ 109,109 $ 96,006 $ 57,948
--------- --------- ---------
Dividends received from
investments at equity $ 3,267 $ 4,313 $ 5,014
--------- --------- ---------
The accompanying notes are an integral part of these financial statements.
New England Power
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of operations:
The Company, a wholly owned subsidiary of New England Electric
System (NEES), is a Massachusetts corporation and is qualified to
do business in Massachusetts, New Hampshire, Rhode Island,
Connecticut, Maine, and Vermont. The Company is subject, for
certain purposes, to the jurisdiction of the regulatory
commissions of these six states, the Securities and Exchange
Commission (SEC), and the Federal Energy Regulatory Commission
(FERC). The Company's business is currently that of generating,
purchasing, transmitting, and selling electric energy in
wholesale quantities to other electric utilities, principally its
affiliates Granite State Electric Company (Granite State
Electric), Massachusetts Electric Company (Massachusetts
Electric), Nantucket Electric Company (Nantucket Electric), and
The Narragansett Electric Company (Narragansett Electric). See
Note B for a discussion of industry restructuring and Note C for
a discussion of the Company's planned divestiture of its
nonnuclear generating business.
2. System of accounts:
The accounts of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by regulatory bodies
having jurisdiction.
In preparing the financial statements, management is required
to make estimates that affect the reported amounts of assets and
liabilities and disclosures of asset recovery and contingent
liabilities as of the date of the balance sheets, and revenues
and expenses for the period. These estimates may differ from
actual amounts if future circumstances cause a change in the
assumptions used to calculate these estimates.
3. Allowance for funds used during construction (AFDC):
The Company capitalizes AFDC as part of construction costs.
AFDC represents the composite interest and equity costs of
capital funds used to finance that portion of construction costs
not yet eligible for inclusion in rate base. AFDC is
capitalized in "Utility plant" with offsetting noncash credits to
"Other income" and "Interest." This method is in accordance with
an established rate-making practice under which a utility is
permitted a return on, and the recovery of, prudently incurred
capital costs through their ultimate inclusion in rate base and
in the provision for depreciation. The composite AFDC rates were
5.9 percent, 5.8 percent, and 7.5 percent, in 1997, 1996, and
1995, respectively.
4. Depreciation and amortization:
The depreciation and amortization expense included in the
statements of income is composed of the following:
Year Ended December 31,
(In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Depreciation $80,260 $ 78,187 $ 66,309
Nuclear decommissioning costs (Note D-2) 2,638 2,629 2,629
Amortization:
Investment in Seabrook 1
pursuant to rate settlement - 15,210 23,074
Oil Conservation Adjustment (OCA) - - 4,467
Seabrook 2 property losses 113 6,279 6,279
Millstone 3 additional amortization,
pursuant to rate settlement 15,013 1,904 -
------- -------- --------
Total depreciation and
amortization expense $98,024 $104,209 $102,758
======= ======== ========
Depreciation is provided annually on a straight-line basis.
The provision for depreciation as a percentage of weighted
average depreciable property was 2.9 percent in 1997 and 1996,
and 2.7 percent in 1995.
Revenues from the OCA were used to accelerate the amortization
of expenditures for coal conversion facilities at the Company's
Salem Harbor Station. In addition, Seabrook 1 costs under the
1988 rate settlement were fully amortized at December 31, 1996.
Property losses associated with the Company's investment in the
canceled Seabrook 2 nuclear unit were fully amortized by March
31, 1997.
5. Cash:
The Company classifies short-term investments with a maturity
of 90 days or less at time of purchase as cash.
6. New Accounting Standards:
In 1997, the Financial Accounting Standards Board released two
new Statements of Financial Accounting Standards (FAS), FAS 130
and FAS 131, both of which will go into effect in 1998. FAS 130,
Reporting Comprehensive Income, requires the reporting in
financial statements of a new additional item called
comprehensive income, which will incorporate amounts not
previously included in reported net income. FAS 131, Disclosure
about Segments of an Enterprise and Related Information, requires
the reporting in financial statements of certain new additional
information about operating segments of a business. The Company
is currently evaluating the impact that these new accounting
standards will have on its future reporting requirements.
Note B - Industry Restructuring
As the result of legislation enacted in the states served by
the NEES companies, most customers served by the NEES companies
will have the ability to choose their power supplier by the first
quarter of 1998. When customers are allowed to choose their
power supplier, utilities face the risk that market prices may
not be sufficient to recover the costs of the commitments
incurred to supply customers under a regulated structure. The
amounts by which such costs exceed market prices are commonly
referred to as "stranded costs." As described below, the Company
has reached settlement agreements with all of its distribution
affiliates and with parties representing the distribution
customers of those affiliates. In each case, these settlements
provide for recovery of stranded costs. See the "Industry
Restructuring" section of Financial Review for a more in-depth
discussion of current developments in this area.
The settlements generally provide for the following:
- - introduction of choice of power supplier in Rhode Island,
Massachusetts, and New Hampshire by January 1, 1998, March 1,
1998, and July 1, 1998, respectively;
- - a transition rate, or "standard offer generation service,"
resulting in rate reductions of approximately 10 percent at
the date of commencement of retail choice;
- - termination of all-requirements contracts between the Company
and its distribution affiliates on terms which allow the
Company to recover its stranded costs through a transition
access charge, which the distribution affiliates will collect
from customers;
- - adjustments to stranded cost recovery to reflect the market
value of fossil-fueled and hydroelectric generating assets,
determined through divestiture of such assets.
Under the various settlements, the recovery of the Company's
stranded costs is divided into several categories. Unrecovered
costs associated with generating plants and regulatory assets
would be recovered over 12 years and would earn a return on
equity of approximately 9.4 percent. The above-market component
of purchased power contracts and nuclear decommissioning costs
would be recovered as incurred over the life of those
obligations, a period expected to extend beyond 12 years.
Initially, the transition access charge was set at 2.8 cents per
kilowatthour (kWh). The MDTE has approved a reduction of the
initial transition access charge to 2.7 cents per kWh for
Massachusetts Electric and Nantucket Electric, effective March 1,
1998. The Company's filing with the FERC to approve this
reduction is pending. The transition access charge would be
reduced further upon completion of the sale of the Company's
generating business, as described below. As the transition
access charge declines, the Company would earn incentives based
on successful mitigation of its stranded costs. These incentives
would supplement the Company's return on equity. The
Massachusetts and Rhode Island settlements were approved by the
FERC in November 1997, subject to a compliance filing to clarify
the impact of the settlements on nonsettling parties. The
Massachusetts Settlement was also found by the Massachusetts
Department of Telecommunications and Energy (formerly the
Massachusetts Department of Public Utilities) to be in
substantial compliance with or consistent with the Massachusetts
restructuring statute. The New Hampshire settlement is pending
before the New Hampshire Public Utilities Commission and the
FERC.
In August 1997, the Company and Narragansett Electric entered
into an agreement to sell substantially all of their nonnuclear
generating business to USGen New England, Inc. (USGen), an
indirect wholly owned subsidiary of PG&E Corporation. The net
proceeds from the sale of its nonnuclear generating business to
USGen will be used to reduce the transition access charge to
approximately 1.5 cents per kWh. In addition, the FERC accepted
the NEES companies proposal in conjunction with their divestiture
filing that the recovery of the remaining above-market nuclear
generating plant costs and regulatory assets be fully recovered
by the end of the year 2000. (see Note C for a discussion of the
Company's planned divestiture of its nonnuclear generating
business).
Accounting implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of certain
items of income and expense expected to be reflected in future
rates.
In response to concerns expressed by the staff of the SEC, the
Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board took under consideration how FAS 71 should be
applied in light of recent changes within the regulated utility
industry. In July 1997, the EITF concluded that a utility whose
ongoing generation operations would not permit the application of
FAS 71, but had otherwise 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
the stranded costs.
The restructuring settlements and statutes each provide for
recovery of substantially all applicable stranded costs of
generating assets and oil and gas related assets (including
regulatory assets) not recoverable from the proceeds of the
divestiture of the Company's generating business. The cost of
these assets would be recovered as part of a cost-based
transition access charge imposed on all distribution customers.
Additionally, FERC Order No. 888 enables transmission companies
to recover their specific costs of providing transmission
service. Therefore, after the proposed divestiture,
substantially all of the Company's business, including the
recovery of its stranded costs, would remain under cost-based
rate regulation. The Company believes these factors and the EITF
conclusion will allow it to continue to apply FAS 71. As a
result of the FERC approval of the industry restructuring
settlements, the Company was required to cease to apply FAS 71 to
the 20 percent of its ongoing nuclear operations, as described in
Note C, the impact of which is expected to be immaterial.
Despite the progress made to date, it is possible that future
regulatory rules or other circumstances could cause the
application of FAS 71 to be discontinued, which would result in a
noncash write-off of previously established regulatory assets
related to the affected operations. In addition, write-downs of
plant assets under Statement of Financial Accounting Standards
No. 121, Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of (FAS 121) could be
required, including a write-off of any gain or loss from the
divestiture of the generating business. At December 31, 1997,
the Company had approximately $420 million in regulatory assets
in compliance with FAS 71, as detailed in the table below. This
amount excludes any effects related to the divestiture of New
England Energy Incorporated's (NEEI) (a wholly owned subsidiary
of NEES) oil and gas properties, discussed in Note C.
The components of regulatory assets are as follows:
At December 31, (In Thousands) 1997 1996
- ----------------------------------------------------------------------------
Regulatory assets included in current
assets and liabilities:
Accrued NEEI losses (see Note D-3) $ 11,419 $ 21,648
Rate adjustment mechanisms (6,957) (4,790)
------- --------
4,462 16,858
Regulatory assets included in deferred charges
and other reserves and deferred credits:
Accrued costs - Yankee nuclear
plants (See Note D-2) 299,564 166,413
Unamortized losses on reacquired debt 31,197 31,353
Deferred FAS No. 106 costs (see Note E-2) - 13,680
Deferred FAS No. 109 costs (see Note F) 25,738 27,461
Purchased power contract termination costs 15,662 19,578
Deferred gas pipeline charges (see Note D-6) 52,570 59,733
Accelerated amortization - Millstone 3 (16,917) (1,904)
Other 4,837 4,884
------- --------
412,651 321,198
-------- --------
$417,113 $338,056
======== ========
Note C - Divestiture of Generating Business
As described above, in August 1997, the Company and
Narragansett Electric (collectively, the Sellers) reached an
agreement to sell their nonnuclear generating business to USGen.
The nonnuclear generating business includes three fossil-fueled
generating stations and 15 hydroelectric generating stations,
totaling approximately 4,000 megawatts (MW) of capacity, as well
as Narragansett Energy Resources Company's (NERC) partnership
interest in the Ocean State Power project, all of which has a
book value of $1.1 billion. USGen will pay the Sellers $1.59
billion in cash, of which $225 million will be contingent upon
the introduction of customer choice of power supplier in
Massachusetts. Based on the enactment of the Massachusetts
statute, the NEES companies believe that the conditions for
payment of the full purchase price have been met. USGen will
also reimburse the NEES companies for $85 million of costs
associated with early retirement and special severance programs
for employees affected by industry restructuring. Since the
early retirement program is contingent upon the divestiture, its
cost will not be accrued until that time. USGen will assume
responsibility for environmental conditions at the Sellers'
nonnuclear generating stations. USGen will also assume the
Sellers' obligations under long-term fuel and fuel
transportation contracts and certain collective bargaining
agreements for nonnuclear facilities.
In addition to the purchase of the generating stations, USGen
will purchase the Company's entitlement to approximately 1,100 MW
of power procured under long-term contracts. The Company will
make a monthly fixed contribution toward the above-market cost of
the purchased power of between $12.5 million and $14.2 million
per month from closing through January 2008. USGen will be
responsible for the balance of the costs under the purchased
power contracts.
The sale is subject to approval by various state and federal
regulatory agencies. Several parties have objected to the sale
on various grounds, including allegations that following the
sale, USGen would be able to exercise unlawful levels of market
power. On February 25, 1998, the FERC issued an order that
rejected the market power allegations, approved the sale and
conditionally approved most supporting filings. On February 27,
1998, the FERC approved the transfer of the hydroelectric
generating licenses to USGen. While the timing of receipt of
final regulatory approvals is uncertain, receipt of all approvals
is unlikely before mid-1998. Closing is contingent upon all
regulatory approvals being obtained by February 1999.
In order to meet the terms of the Company's mortgage
indenture, the Company will be required, prior to the
consummation of the sale, to either defease or call approximately
$278 million of its mortgage bonds. Any defeasance of bonds
would be by deposit of cash representing principal and interest
to the maturity date, or interest, principal, and general
redemption premium to an earlier redemption date. In addition,
the Company will retire approximately $372 million of mortgage
bonds securing the issuance of a like amount of pollution control
revenue bonds (PCRBs) by various public agencies. However, the
Company expects that substantially all of the underlying PCRBs
will remain outstanding as unsecured obligations of the Company.
In addition, the long-term debt of NERC will be retired prior to
the closing.
As part of the divestiture plan, in February 1998, NEEI sold
its oil and gas properties for approximately $50 million. NEEI's
loss on the sale of approximately $120 million, before tax, has
been reimbursed by the Company.
At the divestiture date, any gain or loss from the divestiture
of nonnuclear generating assets and oil and gas assets will be
recorded as a regulatory asset or liability to be recovered as
part of the Company's stranded costs, through the ongoing
transition access charge, consistent with the settlement
agreements. The Company may be required to record a liability
for the monthly fixed contribution towards the above-market cost
of purchased power. In such an event, the Company would also
record a regulatory asset consistent with the settlement
agreements.
In addition, the Company will endeavor to sell, or otherwise
transfer, its minority interest in three nuclear power plants and
a 60 MW interest in a fossil-fueled generating station in Maine
to nonaffiliates. Until such time as the nuclear interests are
divested, the Company will share with customers 80 percent of the
revenues and operating costs related to the units, with
shareholders retaining the balance. In the event that the
Company determines that it has an impairment of its nuclear plant
balances under FAS 121, it will record any such impairment as a
regulatory asset.
Note D - Commitments and Contingencies
1. Yankee Nuclear Power Companies (Yankees):
The Company has minority interests in four Yankee Nuclear Power
Companies. These ownership interests are accounted for on the
equity method. The Company's share of the expenses of the
Yankees is accounted for in "Purchased electric energy" on the
statements of income.
A summary of combined results of operations, assets, and
liabilities of the four Yankees is as follows:
(In thousands) 1997 1996 1995
- ----------------------------------------------------------------------------
Operating revenue $ 660,742$ 697,054$ 695,781
=================================
Net income $ 29,959$ 27,567$ 31,657
=================================
Company's equity in net income $ 5,189$ 5,159$ 5,721
=================================
Net plant 204,689 401,049 443,967
Other assets 3,100,589 2,031,336 1,418,681
Liabilities and debt (3,036,845) (2,177,068) (1,612,843)
---------------------------------
Net assets $ 268,433$ 255,317$ 249,805
=================================
Company's equity in net assets $ 49,825$ 47,902$ 47,055
=================================
Company's purchased electric energy $ 107,140$ 110,778$ 115,647
=================================
At December 31, 1997, $16 million of undistributed earnings of
the Yankees were included in the Company's retained earnings.
2. Nuclear Units
Nuclear Units Permanently Shut Down
Three of the four regional nuclear generating companies in
which the Company has a minority interest own nuclear generating
units which have been permanently shut down. These three units
are as follows:
NEP's Investment Future Estimated
Unit Percent Amount Date Retired Billings to NEP($)
- ----------------------------------------------------------------------------
Yankee Atomic 30 7 million Feb 1992 44 million
Connecticut Yankee 15 17 million Dec 1996 92 million
Maine Yankee 20 16 million Aug 1997 164 million
- -----------------------------------------------------------------------------
In the case of each of these units, the Company has recorded
an estimate of the total future payment obligation as a liability
and an offsetting regulatory asset, reflecting estimated future
billings from the companies. In a 1993 decision, the FERC
allowed Yankee Atomic to recover its undepreciated investment in
the plant as well as unfunded nuclear decommissioning costs and
other costs. Connecticut Yankee and Maine Yankee have both filed
similar requests with the FERC. Several parties have intervened
in opposition to both filings. The Company's stranded cost
settlements allow it to recover all costs that the FERC allows
the Yankee companies to bill to the Company.
In October 1997, the Citizen's Awareness Network and Nuclear
Information and Resource Service filed a petition with the
Nuclear Regulatory Commission (NRC) that would require formal NRC
approval of a plant decommissioning plan for the Connecticut
Yankee and Maine Yankee plants. In 1998, the petitioners
indicated their intention to file a request with the NRC designed
to overturn a current NRC rule on decommissioning. The Company
cannot predict what impact, if any, these activities will have on
the cost of decommissioning the plants.
At Maine Yankee, the NRC has identified numerous apparent
violations of its regulations, which may result in the assessment
of significant civil penalties.
In the 1970s, the Company and several other shareholders
(Sponsors) of Maine Yankee entered into 27 contracts (Secondary
Purchase Agreements) under which they sold portions of their
entitlement to Maine Yankee power output through 2002 to various
entities, primarily municipal and cooperative systems in New
England (Secondary Purchasers). Virtually all of the Secondary
Purchasers have ceased making payments under the Secondary
Purchase Agreements and have demanded arbitration, claiming that
such agreements excuse further payments upon plant shutdown. The
Company has notified the Secondary Purchasers that the shutdown
does not relieve them of their obligation to make payments under
the Secondary Purchase Agreements and that they are in default of
such agreements. The Company has asked the FERC to enforce the
Company's rights under the agreements. In the event that no
further payments are forthcoming from Secondary Purchasers, the
Company, as a primary obligor to Maine Yankee, would be required
to pay an additional $9 million of future shutdown costs. These
costs are not included in the $164 million estimate disclosed in
the table above. Shutdown costs are recoverable from customers
under the stranded cost settlements.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for
the plant decommissioning, the owners of Maine Yankee are jointly
and severally liable for the shortfall.
Operating Nuclear Units
The Company has minority interests in three other nuclear
generating units, Vermont Yankee, Millstone 3, and Seabrook 1.
In October 1996, the NRC issued letters to operators of nuclear
power plants requiring them to document that the plants are
operated and maintained within their design and licensing bases,
and that any deviations are reconciled in a timely manner. The
Seabrook 1 and Vermont Yankee nuclear power plants responded to
the NRC letters in February 1997. Millstone 3 is currently shut
down and has been placed on the NRC "Watch List," signifying that
its safety performance exhibits sufficient weakness to warrant
increased NRC attention. Millstone 3 may not restart without NRC
approval.
Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Vermont Yankee, are
increasing rapidly and could adversely affect their service
lives, availability, and costs. These uncertainties stem from a
combination of factors, including the acceleration of competitive
pressures in the power generation industry and increased NRC
scrutiny. The Company performs periodic economic viability
reviews of operating nuclear units in which it holds ownership
interests.
Millstone 3
In April 1996, the NRC ordered Millstone 3, which has
experienced numerous technical and nontechnical problems, to
remain shut down pending verification that the unit's operations
are in accordance with NRC regulations and the unit's operating
license. Millstone 3 is operated by a subsidiary of Northeast
Utilities (NU). The Company is not an owner of the Millstone 1
and 2 nuclear generating units, which are also shut down under
NRC orders.
A number of significant prerequisites must be fulfilled prior
to restart of Millstone 3, including certification by NU that the
unit adequately conforms to its design and licensing bases, an
independent verification of corrective actions taken at the unit,
an NRC assessment concluding a safety conscious work environment
exists, public meetings, and a vote of the NRC Commissioners.
The Company cannot predict when Millstone 3 will be allowed by
the NRC to restart, but believes restart of the unit is unlikely
prior to the summer of 1998.
Since April 1996, the Company has incurred an estimated $35
million in incremental replacement power costs, which it has been
recovering from customers through its fuel clause. During the
outage, the Company is incurring incremental replacement power
costs of approximately $2 million per month.
Several criminal investigations related to Millstone 3 are
ongoing. In December 1997, the NRC assessed civil penalties
totaling $2.1 million for numerous violations at the three
Millstone units. The Company's share of this fine was less than
$100,000. The Connecticut Department of Environmental Protection
and Connecticut Attorney General have filed suit against NU for
alleged wastewater discharge violations at the Millstone units,
which may result in the assessment of substantial civil
penalties.
In August 1997, the Company filed suit against NU in
Massachusetts Superior Court for damages resulting from the
tortious conduct of NU relating to Millstone 3. The Company is
seeking compensation for the losses it has suffered, including
the costs of lost power and costs necessary to assure that
Millstone 3 can safely return to operation. The Company also
seeks punitive damages. NU has filed for dismissal of the suit
and sought to consolidate it with suits filed by other joint
owners in Massachusetts Superior Court.
The Company also sent a demand for arbitration to Connecticut
Light & Power Company and Western Massachusetts Electric Company,
both subsidiaries of NU, seeking damages resulting from their
breach of obligations under an agreement with the Company and
others regarding the operation and ownership of Millstone 3.
Decommissioning Trust Funds
Each nuclear unit in which the Company has an ownership
interest has established a decommissioning trust fund or escrow
fund into which payments are being made to meet the projected
costs of decommissioning. Listed below is information on each
operating nuclear plant in which the Company has an ownership
interest.
The Company is liable for its share of decommissioning costs
for Millstone 3, Seabrook 1, and all of the Yankees.
Decommissioning costs include not only estimated costs to
decontaminate the units as required by the NRC, but also costs to
dismantle the uncontaminated portion of the units. The Company
records decommissioning costs on its books consistent with its
rate recovery. The Company is recovering its share of projected
decommissioning costs for Millstone 3 and Seabrook 1 through
depreciation expense. In addition, the Company is paying its
portion of projected decommissioning costs for all of the Yankees
through purchased power expense. Such costs reflect estimates of
total decommissioning costs approved by the FERC.
NEP's share of (millions of dollars)
------------------------------------
NEP's EstimatedDecommissioning
Ownership Net Decommissioning Fund License
Unit Interest (%)Plant Assets Cost (in 1997 $) Balances* Expiration
- ---- ----------- ------------ --------------- --------------- ----------
Vermont Yankee 20 35 77 34 2012
Millstone 3 12 366 66 18** 2025
Seabrook 1*** 10 54 47 9** 2026
<FN>
*Certain additional amounts are anticipated to be available through tax deductions.
**Fund balances are included in "Other investments" on the balance sheets. Any
differences from market value are not material.
***Proposed legislation in New Hampshire would make owners of Seabrook 1 proportional
guarantors for decommissioning costs in the event that an owner without a franchise
territory fails to fund its share of decommissioning costs.
</FN>
There is no assurance that decommissioning costs actually
incurred by Vermont Yankee, Millstone 3, or Seabrook 1 will not
substantially exceed these amounts. For example, decommissioning
cost estimates assume the availability of permanent repositories
for both low-level and high-level nuclear waste; those
repositories do not currently exist. If any of the units were
shut down prior to the end of their operating licenses, which the
Company believes is likely, the funds collected for
decommissioning to that point would be insufficient. Under the
settlement agreements discussed in Note B, the Company will
recover decommissioning costs through transition access charges.
The Nuclear Waste Policy Act of 1982 establishes that the
federal government (through the Department of Energy (DOE)) is
responsible for the disposal of spent nuclear fuel. The federal
government requires the Company to pay a fee based on its share
of the net generation from the Millstone 3 and Seabrook 1 nuclear
units. The Company is recovering this fee through its fuel
clause. Similar costs are incurred by the Vermont Yankee nuclear
generating unit. These costs are billed to the Company and also
recovered from customers through the Company's fuel clause. In
November 1997, ruling on a lawsuit brought against the DOE by
numerous utilities and state regulatory commissions, the Court of
Appeals for the District of Columbia (Court) held that the DOE is
obligated to begin disposing of utilities' spent nuclear fuel by
January 31, 1998. The DOE failed to meet this deadline. The
utilities, including the operators of the units in which the
Company has an obligation, are assessing their future options.
In February 1998, Maine Yankee petitioned the Court to compel the
DOE to remove Maine Yankee's spent fuel from the site.
Nuclear insurance
The Price-Anderson Act limits the amount of liability claims
that would have to be paid in the event of a single incident at a
nuclear plant to $8.9 billion (based upon 110 licensed reactors).
The maximum amount of commercially available insurance coverage
to pay such claims is $200 million. The remaining $8.7 billion
would be provided by an assessment of up to $79.3 million per
incident levied on each of the participating nuclear units in the
United States, subject to a maximum assessment of $10 million per
incident per nuclear unit in any year. The maximum assessment,
which was most recently adjusted in 1993, is adjusted for
inflation at least every five years. The Company's current
interest in the Yankees (excluding Yankee Atomic), Millstone 3,
and Seabrook 1 would subject the Company to a $58 million maximum
assessment per incident. The Company's payment of any such
assessment would be limited to a maximum of $7.3 million per
incident per year. As a result of the permanent cessation of
power operation of the Yankee Atomic plant, Yankee Atomic has
received from the NRC a partial exemption from obligations under
the Price-Anderson Act. However, Yankee Atomic must continue to
maintain $100 million of commercially available nuclear insurance
coverage. Connecticut Yankee and Maine Yankee have filed with
the NRC for similar exemptions.
Each of the nuclear units in which the Company has an
ownership interest also carries nuclear property insurance to
cover the costs of property damage, decontamination or premature
decommissioning, and workers' claims resulting from a nuclear
incident. These policies may require additional premium
assessments if losses relating to nuclear incidents at units
covered by this insurance occurring in a prior six-year period
exceed the accumulated funds available. The Company's maximum
potential exposure for these assessments, either directly, or
indirectly through purchased power payments to the Yankees, is
approximately $8 million per year.
3. Oil and gas operations:
The Company's affiliate, NEEI, participated in a
rate-regulated domestic oil and gas exploration, development, and
production program through a partnership with a nonaffiliated oil
company. Losses from this program, calculated under the full
cost method of accounting, have been charged to the Company, and
ultimately to distribution customers, in accordance with SEC and
FERC approvals. Such losses were $11 million, $22 million, and
$44 million in 1997, 1996, and 1995, respectively. In February
1998, after a competitive bidding process, NEEI sold all of its
remaining oil and gas properties held as of December 31, 1997 to
its partner for $50 million. The loss on such disposition,
approximately $120 million, before tax, has been charged to the
Company. The settlements provide for the recovery of the NEEI
loss as part of the Company's stranded costs. See Note B for a
discussion of industry restructuring and Note C for a discussion
of the Company's planned divestiture of its nonnuclear generating
business.
4. Plant expenditures:
The Company's utility plant expenditures are estimated to be
approximately $55 million in 1998. At December 31, 1997,
substantial commitments had been made relative to future planned
expenditures.
5. Hydro-Quebec Interconnection and arbitration:
The Company is a participant in both the Hydro-Quebec Phase I
and Phase II projects. The Company's participation percentage in
both projects is approximately 18 percent. The Hydro-Quebec
Phase I and Phase II projects were established to transmit power
from Hydro-Quebec to New England. Three affiliates of the
Company were created to construct and operate transmission
facilities related to these projects. The participants,
including the Company, have entered into support agreements that
end in 2020, to pay monthly their proportionate share of the
total cost of constructing, owning, and operating the
transmission facilities. The Company accounts for these support
agreements as capital leases and accordingly recorded
approximately $65 million in utility plant at December 31, 1997.
Under the support agreements, the Company has agreed, in
conjunction with any Hydro-Quebec Phase II project debt
financings to guarantee its share of project debt. At December
31, 1997, the Company had guaranteed approximately $25 million of
project debt. In the event any Interconnection facilities are
abandoned for any reason, each participant is contractually
committed to pay its pro-rata share of the net investment in the
abandoned facilities. The Company's rights and obligations under
its support agreements will be transferred to USGen upon
completion of the sale of the Company's nonnuclear generating
business.
In 1996, various New England utilities which are members of
the New England Power Pool, including the Company, submitted a
dispute to arbitration regarding their Firm Energy Purchased
Power Contract with Hydro-Quebec. In June 1997, Hydro-Quebec
presented a damage claim of approximately $37 million for past
damages, of which the Company's share would have been
approximately $6 to $9 million. The claims involved a dispute
over the components of a pricing formula and additional costs
under the contract. With respect to on-going claims, the Company
had been paying Hydro-Quebec the higher amount (additional costs
of approximately $3 million per year) since July 1996 under
protest and subject to refund. In October 1997, an arbitrator
ruled in favor of the New England utilities in all respects. The
Company has made a demand for refund. Hydro-Quebec has not yet
refunded any monies and has appealed the decision. On November
9, 1997, the Company and the other utilities began a second
arbitration to enforce the first decision. Refunds received from
Hydro-Quebec will be passed on to customers.
6. Natural gas pipeline capacity:
In connection with serving the Company's gas-fueled electric
generation facilities, the Company has entered into several
contracts for natural gas pipeline capacity and gas supply.
These agreements require minimum fixed payments that are
currently estimated to be $59 million to $62 million per year
from 1998 to 2002. Under these agreements, remaining fixed
payments from 2003 through 2014 total approximately $501 million.
In connection with managing its fuel supply, the Company uses
a portion of this pipeline capacity to sell natural gas.
Proceeds from the sale of natural gas and pipeline capacity of
$41 million, $50 million, and $71 million in 1997, 1996, and
1995, respectively, have been passed on to customers through the
Company's fuel clause. These proceeds have been reflected as an
offset to the related fuel expense in "Fuel for generation" in
the Company's statements of income. Natural gas sales decreased
in 1996 as a result of the Manchester Street plant entering
commercial operation in the second half of 1995.
See Note C for a discussion of the Company's planned
divestiture of its nonnuclear generating business.
7. Hazardous waste:
The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly known as the "Superfund" law,
imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous
substances. A number of states, including Massachusetts, have
enacted similar laws.
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. The Company currently has in place an
internal environmental audit program and an external waste
disposal vendor audit and qualification program intended to
enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous
products and by-products.
The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for
six sites at which hazardous waste is alleged to have been
disposed. Private parties have also contacted or initiated legal
proceedings against the Company regarding hazardous waste
cleanup. The Company is currently aware of other 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 NEES
companies have recovered amounts from certain insurers, and,
where appropriate, the Company intends to seek recovery from its
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.
In October 1996, the American Institute of Certified Public
Accountants issued new accounting rules for Environmental
Remediation Liabilities which became effective in 1997. These
new rules did not have a material effect on the Company's
financial position or results of operations.
8. Long-term contracts for the purchase of electricity:
The Company purchases a portion of its electricity
requirements pursuant to long-term contracts with owners of
various generating units. These contracts expire in various
years from 1998 to 2029.
Certain of these contracts require the Company to make minimum
fixed payments, even when the supplier is unable to deliver
power, to cover the Company's proportionate share of the capital
and fixed operating costs of these generating units. The fixed
portion of payments under these contracts totaled $114 million in
1997, $127 million in 1996, and $150 million in 1995, excluding
contracts with Yankee Atomic, Connecticut Yankee, and Maine
Yankee (see Note D-2) for all periods presented. These contracts
have minimum fixed payment requirements of $110 million annually
from 1998 through 2001, $120 million in 2002, and approximately
$950 million thereafter. Approximately 97 percent of the
payments under these contracts are to Vermont Yankee and OSP,
entities in which NEES subsidiaries hold ownership interests.
The Company's other contracts, principally with nonutility
generators, require the Company to make payments only if power
supply capacity and energy are deliverable from such suppliers.
The Company's payments under these contracts amounted to $265
million in 1997, $230 million in 1996, and $245 million in 1995.
See Note C for a discussion of the Company's planned
divestiture of its nonnuclear generating business.
9. Town of Norwood dispute:
In April 1997, the Town of Norwood, Massachusetts filed a
lawsuit against the Company in the United States District Court
for the District of Massachusetts. The Company is a wholesale
power supplier for Norwood pursuant to rates approved by the
FERC. Norwood alleges that the Company's proposed divestiture of
its power generation assets would violate the terms of a 1983
power contract which settled an antitrust lawsuit brought by
Norwood against the Company. Norwood also alleges that the
Company's proposed divestiture plan and recovery of stranded
investment costs contravene federal antitrust laws. Norwood
seeks an injunction enjoining the divestiture and an unspecified
amount of treble damages (a specific claim for $450 million was
withdrawn). Norwood's motion for a preliminary injunction of the
divestiture was denied on September 8, 1997. On November 21,
1997, Norwood filed an amended complaint making new allegations
relating to the sale of the Company's generating assets and
naming as additional defendants, NEES, USGen and USGen's
affiliate, PG&E. The Company continues to believe that its
divestiture plan will promote competition in the wholesale power
generation market and that it has met and will continue to meet
its contractual commitments to Norwood. On January 9, 1998, the
defendants, including NEES and the Company, filed a motion to
dismiss the lawsuit. In March 1998, Norwood gave notice of its
intent to terminate its contract with the Company, without
accepting responsibility for its share of the Company's stranded
costs, and to begin taking power from another supplier. The
Company has filed with the FERC for permission to charge Norwood
a contract termination charge for its share of the Company's
stranded costs.
Note E - Employee Benefits
1. Pension plans:
The Company participates with other subsidiaries of NEES in
noncontributory, defined-benefit plans covering substantially all
employees of the Company. The plans provide pension benefits
based on the employee's compensation during the five years prior
to retirement. The Company's funding policy is to contribute
each year the net periodic pension cost for that year. However,
the contribution for any year will not be less than the minimum
contribution required by federal law or greater than the maximum
tax deductible amount.
The Company's net pension cost for 1997, 1996, and 1995
included the following components:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------------------
Service cost - benefits earned during the period $ 2,887 $ 2,769 $ 2,231
Plus (less):
Interest cost on projected benefit obligation 7,003 6,669 6,406
Return on plan assets at expected long-term rate (7,842) (7,204) (6,488)
Amortization 61 270 131
------- ------- -------
Net pension cost $ 2,109 $ 2,504 $ 2,280
======= ======= =======
Actual return on plan assets $18,362 $12,672 $17,108
======= ======= =======
Year ended December 31, 1998 1997 1996 1995
---- ---- ---- ----
Assumptions used to determine pension cost:
Discount rate 6.75% 7.25% 7.25% 8.25%
Average rate of increase in
future compensation levels 4.13% 4.13% 4.13% 4.63%
Expected long-term rate of
return on assets 8.50% 8.50% 8.50% 8.75%
The funded status of the plans cannot be presented separately
for the Company as the Company participates in the plans with
other NEES subsidiaries. The following table sets forth the
funded status of the NEES companies' plans at December 31:
At December 31, (In millions) 1997 1996
- -----------------------------------------------------------------------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $647 $640
Non-vested 18 19
---- ----
Total $665 $659
==== ====
Reconciliation of funded status
Actuarial present value of
projected benefit liability $757 $753
Unrecognized prior service costs (8) (9)
FAS No. 87 transition liability
not yet recognized (amortized) (1) (1)
Net gain (loss) not yet recognized (amortized) 61 40
---- ----
809 783
---- ----
Pension fund assets at fair value 834 812
FAS No. 87 transition asset
not yet recognized (amortized) (8) (10)
---- ----
826 802
---- ----
Accrued pension/(prepaid)
payments recorded on books $(17) $(19)
---- ----
The plans' funded status at December 31, 1997 and 1996 were
calculated using the assumed rates from 1998 and 1997,
respectively, and the 1983 Group Annuity Mortality table.
Plan assets are composed primarily of corporate equity, debt
securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions (PBOPs):
The Company provides health care and life insurance coverage
to eligible retired employees. Eligibility is based on certain
age and length of service requirements and in some cases retirees
must contribute to the cost of their coverage.
The Company's total cost of PBOPs for 1997, 1996, and 1995 included the
following components:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------------------
Service cost - benefits earned
during the period $ 1,363 $ 1,407 $ 1,344
Plus (less):
Interest cost on accumulated
benefit obligation 3,545 3,580 4,013
Return on plan assets at expected
long-term rate (2,343) (1,832) (1,374)
Amortization 1,581 1,867 2,079
------- ------- -------
Net postretirement benefit cost $ 4,146 $ 5,022 $ 6,062
======= ======= =======
Actual return on plan assets $ 5,387 $ 3,572 $ 4,137
======= ======= =======
Year ended December 31 1998 1997 1996 1995
- ----------------------------------------------------------------------------
Assumptions used to determine
postretirement benefit cost:
Discount rate 6.75% 7.25% 7.25% 8.25%
Expected long-term rate of
return on assets 8.25% 8.25% 8.25% 8.50%
Health care cost rate - 1995 to 1999 5.25% 8.00% 8.00% 8.50%
Health care cost rate - 2000 to 2004 5.25% 6.25% 6.25% 8.50%
Health care cost rate - 2005 and beyond 5.25% 5.25% 5.25% 6.25%
The following table sets forth the Company's benefits earned and the plans'
funded status:
At December 31, (In millions) 1997 1996
- ----------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $29 $32
Fully eligible active plan participants 2 2
Other active plan participants 20 20
--- ---
Total benefits earned 51 54
Unrecognized transition obligation (38) (41)
Unrecognized net gain 21 13
--- ---
34 26
--- ---
Plan assets at fair value 34 29
--- ---
Prepaid postretirement benefit
costs recorded on books $ - $3
=== ===
The plans' funded status at December 31, 1997 and 1996 were
calculated using the assumed rates in effect for 1998 and 1997,
respectively.
The assumptions used in the health care cost trends have a
significant effect on the amounts reported. Increasing the
assumed rates by 1 percent in each year would increase the
accumulated postretirement benefit obligation as of December 31,
1997 by approximately $6 million and the net periodic cost for
1997 by approximately $0.8 million.
The Company funds the annual tax-deductible contributions.
Plan assets are invested in equity and debt securities and cash
equivalents.
Note F - Income Taxes
The Company and other subsidiaries participate with NEES in
filing consolidated federal income tax returns. The Company's
income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by
the Internal Revenue Service through 1993.
Total income taxes in the statements of income are as follows:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Income taxes charged to operations $90,009 $91,894 $91,051
Income taxes charged (credited) to
"Other income" (373) 555 353
------- ------- -------
Total income taxes $89,636 $92,449 $91,404
======= ======= =======
Total income taxes, as shown above, consist of the following
components:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Current income taxes $102,364 $99,907 $65,721
Deferred income taxes (10,705) (5,435) 27,188
Investment tax credits, net (2,023) (2,023) (1,505)
-------- ------- -------
Total income taxes $ 89,636 $92,449 $91,404
======== ======= =======
Investment tax credits have been deferred and are being
amortized over the estimated lives of the property giving rise to
the credits.
Total income taxes, as shown above, consist of federal and state
components as follows:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Federal income taxes $73,077 $76,656 $74,590
State income taxes 16,559 15,793 16,814
------- ------- -------
Total income taxes $89,636 $92,449 $91,404
======= ======= =======
With regulatory approval from the FERC, the Company has
adopted comprehensive interperiod tax allocation (normalization)
for temporary book/tax differences.
Total income taxes differ from the amounts computed by
applying the federal statutory tax rates to income before taxes.
The reasons for the differences are as follows:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Computed tax at statutory rate $81,963 $85,726 $84,991
Increases (reductions) in tax
resulting from:
Amortization of investment
tax credits (2,023) (2,023) (2,227)
State income taxes, net of
federal income tax benefit 10,763 10,265 10,929
All other differences (1,067) (1,519) (2,289)
------- ------- -------
Total income taxes $89,636 $92,449 $91,404
======= ======= =======
The following table identifies the major components of total
deferred income taxes:
At December 31, (In millions) 1997 1996
- ----------------------------------------------------------------
Deferred tax asset:
Plant related $ 87 $ 97
Investment tax credits 22 23
All other 44 46
----- -----
153 166
----- -----
Deferred tax liability:
Plant related (418) (415)
Equity AFDC (43) (45)
All other (62) (88)
----- -----
(523) (548)
----- -----
Net deferred tax liability $(370) $(382)
===== =====
Note G - Short-term Borrowings and Other Accrued Expenses
At December 31, 1997, the Company had $111 million of
short-term debt outstanding including $108 million in commercial
paper borrowings and $3 million of borrowings from affiliates.
NEES and certain subsidiaries, including the Company, with
regulatory approval, operate a money pool to more effectively
utilize cash resources and to reduce outside short-term
borrowings. Short-term borrowing needs are met first by
available funds of the money pool participants. Borrowing
companies pay interest at a rate designed to approximate the cost
of outside short-term borrowings.
Companies which invest in the pool share the interest earned
on a basis proportionate to their average monthly investment in
the money pool. Funds may be withdrawn from or repaid to the
pool at any time without prior notice.
At December 31, 1997, the Company had lines of credit and
standby bond purchase facilities with banks totaling $375 million
which are available to provide liquidity support for commercial
paper borrowings and for $372 million of the Company's
outstanding variable rate mortgage bonds in tax-exempt commercial
paper mode (see Note I) and for other corporate purposes. There
were no borrowings under these lines of credit at December 31,
1997. Fees are paid on the lines and facilities in lieu of
compensating balances.
The weighted average rate on outstanding short-term borrowings
was 5.7 percent at December 31, 1997. The fair value of the
Company's short-term debt equals carrying value.
The components of other accrued expenses are as follows:
At December 31, (In thousands) 1997 1996
- ----------------------------------------------------------------
Accrued wages and benefits $ 9,838 $ 7,190
Capital lease obligations due within one year 4,333 4,328
Rate adjustment mechanisms 6,957 4,790
Other 2,426 269
------- -------
$23,554 $16,577
------- -------
Note H - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1997
and 1996 is as follows (in thousands of dollars except for share
data):
Shares
Authorized Dividends Call
and Outstanding Amount Declared Price
- ------------------------------------------------------------------------------
1997 1996 1997 1996 1997 1996
- ------------------------------------------------------------------------------
$100 Par value
6.00% Series 75,020 75,020 $ 7,502 $ 7,502 $ 451 $ 451 (a)
4.56% Series 100,000 100,000 10,000 10,000 456 456 $104.08
4.60% Series 80,140 80,140 8,014 8,014 368 368 $101.00
4.64% Series 41,500 41,500 4,150 4,150 192 328 $102.56
6.08% Series 100,000 100,000 10,000 10,000 608 608 $102.34
7.24% Series - - - - - 363 $103.06
- ------------------------------------------------------------------------------
Total 396,660 396,660 $39,666 $39,666 $2,075 $2,574
<FN>
(a) Noncallable.
</FN>
The annual dividend requirement for total cumulative preferred
stock was $2,075,000 for 1997 and for 1996.
During 1997, the Company's parent, NEES, purchased preferred
stock of the Company with a par value of $29 million.
In August 1996, the Company repurchased $6 million of its 4.64
percent series of cumulative preferred stock. In May 1996, the
Company redeemed all ($15 million) of its 7.24 percent series of
cumulative preferred stock.
Note I - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In thousands)
Series Rate % Maturity 1997 1996
- -----------------------------------------------------------------------------
General and Refunding Mortgage Bonds:
Y(94-3) 8.10 December 22, 1997 $3,000
W(93-2) 6.17 February 2, 1998 $4,300 4,300
W(93-4) 6.14 February 2, 1998 1,300 1,300
W(93-5) 6.17 February 3, 1998 5,000 5,000
W(93-7) 6.10 February 4, 1998 10,000 10,000
W(93-9) 6.04 February 4, 1998 29,400 29,400
Y(94-4) 8.28 December 21, 1999 10,000 10,000
W(93-6) 6.58 February 10, 2000 5,000 5,000
Y(95-1) 7.94 February 14, 2000 5,000 5,000
Y(95-2) 7.93 February 14, 2000 10,000 10,000
Y(95-3) 7.40 March 21, 2000 10,000 10,000
Y(95-4) 6.69 June 5, 2000 25,000 25,000
W(93-1) 7.00 February 3, 2003 25,000 25,000
Y(94-2) 8.33 November 8, 2004 10,000 10,000
K 7.25 October 15, 2015 38,500 38,500
X variable March 1, 2018 79,250 79,250
R variable November 1, 2020 135,850 135,850
S variable November 1, 2020 50,600 50,600
U 8.00 August 1, 2022 134,500 170,000
V variable October 1, 2022 106,150 106,150
Y(94-1) 8.53 September 20, 2024 5,000 5,000
Unamortized discounts (2,130) (2,344)
-------- --------
Total long-term debt 697,720 736,006
======== ========
Long-term debt due in one year (50,000) (3,000)
-------- --------
$647,720 $733,006
======== ========
Substantially all of the properties and franchises of the Company
are subject to the lien of the mortgage indentures under which the
general and refunding mortgage bonds have been issued.
The Company will make cash payments of $50 million in 1998, $10
million in 1999, and $55 million in 2000 to retire maturing
mortgage bonds. There are no cash payments required in either 2001
or 2002.
The terms of $372 million of variable rate PCRBs collateralized
by the Company's mortgage bonds at December 31, 1997 require the
Company to reacquire the bonds under certain limited circumstances.
At December 31, 1997, interest rates on the Company's variable rate
bonds ranged from 3.70 percent to 4.85 percent. See Note C for
information on potential bond defeasance.
At December 31, 1997, the Company's long-term debt had a carrying
value of $700,000,000 and had a fair value of approximately
$721,000,000. The fair value of debt that reprices frequently at
market rates approximates carrying value. For all other debt, the
fair market value of the Company's long-term debt was estimated
based on the quoted prices for similar issues or on the current
rates offered to the Company for debt of the same remaining
maturity.
Note J - Restrictions on Retained Earnings Available for Dividends
on Common Stock
Pursuant to the provisions of the Articles of Organization and
the By-Laws relating to the Dividend Series Preferred Stock,
certain restrictions on payment of dividends on common stock would
come into effect if the "junior stock equity" was, or by reason of
payment of such dividends became, less than 25 percent of "Total
capitalization." However, the junior stock equity at December 31,
1997 was 55 percent of total capitalization, including long-term
debt due in one year, and, accordingly, none of the Company's
retained earnings at December 31, 1997 were restricted as to
dividends on common stock under the foregoing provisions.
Under restrictions contained in the indentures relating to
general and refunding mortgage bonds (Series K), none of the
Company's retained earnings at December 31, 1997 were restricted as
to dividends on common stock. However, a portion of the Company's
retained earnings (less than $30 million) may be restricted due to
regulatory requirements related to hydroelectric licensed projects.
Note K - Supplementary Income Statement Information
Advertising expenses, expenditures for research and development,
and rents were not material and there were no royalties paid in
1997, 1996, or 1995. Taxes, other than income taxes, charged to
operating expenses are set forth by classes as follows:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Municipal property taxes $59,102 $58,942 $49,807
Federal and state payroll
and other taxes 8,209 7,474 8,909
------- ------- -------
$67,311 $66,416 $58,716
======= ======= =======
New England Power Service Company, an affiliated service company
operating pursuant to the provisions of Section 13 of the Public
Utility Holding Company Act of 1935, furnished services to the
Company at the cost of such services. These costs amounted to
$91,985,000, $85,124,000, and $106,411,000, including capitalized
construction costs of $24,347,000, $19,412,000, and $24,671,000,
for each of the years 1997, 1996, and 1995, respectively.
New England Power Company
Selected Financial Information
Year ended December 31,
(In millions) 1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------------
Operating revenue:
Electric sales (excluding
fuel cost recovery) $ 921 $ 918 $ 941 $ 942 $ 939
Fuel cost recovery 696 642 594 563 576
Other 61 40 36 36 34
------ ------ ------ ------ ------
Total operating revenue $1,678 $1,600 $1,571 $1,541 $1,549
Net income $ 145 $ 152 $ 151 $ 149 $ 141
Total assets $2,763 $2,648 $2,648 $2,613 $2,441
Capitalization:
Common equity $ 913 $ 906 $ 889 $ 877 $ 850
Cumulative preferred stock 40 40 61 61 61
Long-term debt 648 733 735 695 667
------ ------ ------ ------ ------
Total capitalization $1,601 $1,679 $1,685 $1,633 $1,578
Preferred dividends declared $ 2 $ 3 $ 3 $ 3 $ 5
Common dividends declared $ 135 $ 134 $ 135 $ 119 $ 111
------ ------ ------ ------ ------
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
1997
Operating revenue $438,048 $396,049 $443,774 $400,032
Operating income $ 50,652 $ 30,028 $ 64,535 $ 45,637
Net income $ 37,945 $ 19,515 $ 52,019 $ 35,064
1996
Operating revenue $400,460 $375,001 $431,420 $393,428
Operating income $ 55,277 $ 39,628 $ 63,782 $ 45,074
Net income $ 40,973 $ 26,768 $ 52,559 $ 32,183
Per share data is not relevant because the Company's common stock is
wholly owned by New England Electric System.
A copy of New England Power Company's Annual Report on Form 10-K to
the Securities and Exchange Commission for the year ended December 31,
1997 will be available on or about April 1, 1998, without charge, upon
written request to New England Power Company, Shareholder Services
Department, 25 Research Drive, Westborough, Massachusetts 01582.