Annual Report 1996
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 January 1, 1997)
Joan T. Bok
Chairman of the Board of New England Electric System
Alfred D. Houston
Executive Vice President and Chief Financial Officer of New
England Electric System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Vice
President, General Counsel, and Secretary of New England Electric
System
John W. Rowe
Chairman of the Company and President and Chief Executive Officer
of New England Electric System
Jeffrey D. Tranen
President of the Company and Senior Vice President of New England
Electric System
Officers
(As of January 1, 1997)
John W. Rowe
Chairman of the Company and President and Chief Executive Officer
of New England Electric System
Jeffrey D. Tranen
President of the Company and Senior Vice President of New England
Electric System
Cheryl A. LaFleur
Vice President and General Counsel of the Company and Vice
President, General Counsel, and Secretary of New England Electric
System
Andrew H. Aitken
Vice President
Lawrence E. Bailey
Vice President
Jeffrey A. Donahue
Vice President
John L. Levitt
Vice President
John F. Malley
Vice President
Arnold H. Turner
Vice President
Jeffrey W. VanSant
Vice President
Michael E. Jesanis
Treasurer of the Company and Vice President and Treasurer of New
England Electric System
Robert King Wulff
Clerk of the Company and of certain affiliates and Assistant
Clerk of certain affiliates
John G. Cochrane
Assistant Treasurer of the Company and of certain affiliates and
Vice President of an affiliate
Kirk L. Ramsauer
Assistant Clerk of the Company and Clerk of certain affiliates
Howard W. McDowell
Controller of the Company and of certain affiliates and Treasurer
of certain affiliates
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, 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 and the Federal Energy Regulatory Commission.
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, Massachusetts Electric
Company, Nantucket Electric Company, and The Narragansett
Electric Company. On October 1, 1996, the NEES companies,
including the Company announced their intention to divest their
generating business. The Company's wholesale contracts with its
distribution affiliates have been amended to allow for early
termination of all-requirements service under those contracts.
The amendment, which is subject to regulatory approval, provides
that upon early termination, the distribution affiliates in
Massachusetts and Rhode Island will recover their share (95
percent) of the cost of the Company's above-market generation
commitments through a contract termination charge. This charge
will, in turn, be paid by the distribution affiliate's
facilities. Efforts are ongoing with New Hampshire and
unaffiliated customers to secure recovery of the balance of the
Company's above-market commitments. (See "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, 1996 and 1995 and the
related statements of income, retained earnings, and cash flows
for each of the three years in the period ended December 31,
1996. 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, 1996 and 1995, and the results
of its operations and its cash flows for each of the three years
in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
February 28, 1997
New England Power Company
Financial Review
Industry Restructuring
On October 1, 1996, the New England Electric System (NEES)
companies, including the Company, announced their intention to
divest their generating business. The decision to divest the
generating business was due to a combination of factors,
discussed below, relating to the restructuring of the electric
utility industry.
For the past several years, the electric utility business has
been subjected to rapidly increasing competitive pressures
stemming from a number of trends, including the presence of
surplus generating capacity, a disparity in electric rates among
regions of the country, improvements in generation efficiency,
increasing demand for customer choice, and new regulations and
legislation intended to foster competition.
In the recent past, this competition was most prominent in the
bulk power market, in which nonutility generators have
significantly increased their market share. Despite increased
competition in the bulk power market, competition in the retail
market has been limited as electric utilities have maintained
exclusive franchises for the retail sale of electricity in
specified service territories.
In states across the country, including Massachusetts, Rhode
Island, and New Hampshire, there have been proposals to allow
retail customers to choose their electricity supplier, with
incumbent utilities required to deliver that electricity over
their transmission and distribution systems (also known as
"retail wheeling"). When electricity customers are allowed to
choose their electricity supplier, utilities across the country
will 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 costs exceed
market prices are commonly referred to as "stranded costs."
The Company provides electric service to its distribution
affiliates, Massachusetts Electric Company (Massachusetts
Electric), Nantucket Electric Company (Nantucket), The
Narragansett Electric Company (Narragansett), and Granite State
Electric Company (Granite State). Each of these affiliates
purchases electricity on behalf of its customers under wholesale
all-requirements contracts with the Company. The Company also
provides all-requirements service to seven unaffiliated electric
utilities. The Company estimates that at December 31, 1996, its
above-market commitments on behalf of its all-requirements
customers are as much as $4.5 billion on a present-value basis
(before the application of the proceeds from the sale of its
generating business).
As described below, comprehensive legislation was enacted in
Rhode Island and a settlement agreement was reached in
Massachusetts which, when all regulatory approvals are in place,
would allow recovery of the Company's above-market commitments to
retail customers in those states, which make up 95 percent of the
Company's all-requirements sales. In return for that recovery,
the NEES companies have agreed to provide lower rates to
customers, as well as sell their generating business. Efforts are
ongoing with New Hampshire and unaffiliated customers to secure
recovery of the balance of the Company's above-market
commitments.
Massachusetts Settlement Agreement
On February 26, 1997, the Massachusetts Department of Public
Utilities (MDPU) approved a settlement among the Company, its
Massachusetts distribution affiliates Massachusetts Electric and
Nantucket, the Massachusetts Attorney General, the Massachusetts
Division of Energy Resources, and 12 other parties, which
provides for retail choice by Massachusetts customers and the
recovery of the Company's above-market commitments to serve those
customers.
The settlement provides for the commencement of retail choice
on January 1, 1998 (contingent on choice being available to the
customers of all Massachusetts investor-owned utilities).
Customers who do not choose an alternative supplier would receive
"standard offer" service, which would be priced to guarantee
customers at least a 10 percent savings in 1998 compared with
September 1996 bundled electricity prices.
In accordance with the settlement, the Company's wholesale
contracts with Massachusetts Electric and Nantucket have been
amended to allow for early termination of all-requirements
service under those contracts. The amendment, which is subject
to regulatory approval, provides that upon early termination,
Massachusetts Electric's and Nantucket's share of the cost of the
Company's above-market generation commitments will be recovered
through a contract termination charge. This charge will, in
turn, be paid by the Company's affiliates' distribution
facilities. Those commitments consist of (i) the above-market
portion of generating plant commitments, (ii) regulatory assets,
(iii) the above-market portion of purchased power contracts, and
(iv) the operating cost of nuclear plants that cannot be avoided
by shutting down the plants, including nuclear decommissioning
costs.
The above-market portion of 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. As the
transition access charge declines, the Company would earn
mitigation incentives that would supplement its return on equity.
The incentives are structured such that the Company believes,
based on its expectations of the level of mitigation it can
achieve through divestiture and other means, that it could earn a
cumulative return on equity on unrecovered costs of approximately
11 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
would be set at 2.8 cents per kilowatt-hour (kWh) through
December 31, 2000, and is expected to decline thereafter. The
initial transition access charge assumes that the generating
plants have no market value. To measure their actual market
value, the NEES companies, including the Company, agreed to sell
their generating business. The net proceeds from the sale will
be used to reduce the transition access charge.
The settlement is subject to approval by the Federal Energy
Regulatory Commission (FERC). The FERC accepted the filing to
become effective February 1, 1997, subject to refund, and ordered
hearings.
The Utility Workers Union of America and the Massachusetts
Alliance of Utility Unions, who intervened in the MDPU proceeding
on the settlement, have indicated they intend to appeal the
MDPU's order approving the settlement to the Massachusetts
Supreme Judicial Court. If an appeal is brought, the NEES
companies will oppose it.
Several bills are pending before the Massachusetts legislature
on electric industry restructuring, including comprehensive
legislation introduced by Governor William F. Weld and by the
legislature's Joint Committee on Electric Restructuring. These
bills cover many of the topics addressed in the settlement and
could impact the implementation of the settlement.
Among the issues being considered by the legislature is
securitization, whereby a utility would assign to a trust all or
a portion of its rights to receive access charges in exchange for
a lump sum reimbursement of stranded costs.
Rhode Island Legislation
In August 1996, the state of Rhode Island enacted pioneering
legislation that allows customers in the state the opportunity to
choose their electricity supplier. Under the Rhode Island
statute, state accounts, certain new customers, and the largest
manufacturing customers will be able to choose their supplier
beginning on July 1, 1997. These customers represent
approximately 2 percent of NEES's retail customer kWh sales. The
balance of Rhode Island customers will be able to choose their
supplier in 1998.
The statute calls for the Company's contract with NEES's Rhode
Island distribution subsidiary, Narragansett, to be amended to
permit a gradual, early termination of all-requirements service
under this contract. The amendment provides that, in return,
Narragansett's 22 percent share of the cost of the Company's
above-market generation commitments would be recovered through a
transition access charge on Narragansett's distribution
facilities. The specifics of the transition access charge are
similar to, and were a model for, those contained in the
Massachusetts settlement. One difference is the statute's return
on equity, which will be set at 11 percent as long as the NEES
companies complete the divestiture or other market valuation of
their generating business; otherwise, the return will be equal to
9.2 percent.
The Company and Narragansett filed with the FERC an amendment
to their all-requirements contract in order to implement the
statute. The FERC has set down the amendment, along with the
Massachusetts settlement, for hearing. Narragansett has
indicated it is willing to make certain changes to its plan in
Rhode Island to parallel provisions in the Massachusetts
settlement. Implementation of other aspects of the statute is
subject to approval of the Rhode Island Public Utilities
Commission (RIPUC).
New Hampshire Proceeding and Settlement Agreement
On February 28, 1997, the New Hampshire Public Utilities
Commission (NHPUC) issued its plan to implement a New Hampshire
law calling for retail access by 1998. Under the plan, utilities
such as Granite State whose rates are below the regional average
would be allowed full recovery of stranded costs as calculated by
the NHPUC. However, the NHPUC indicated that its methodology and
proposed timing of recovery would yield both initial access
charges and total recovery less than that requested by Granite
State although the NHPUC indicated that its decision would not
result in savings for Granite State's customers.
The largest utility in New Hampshire is Public Service Company
of New Hampshire (PSNH). PSNH has appealed the NHPUC's decision
to the courts and has included in its appeal certain arguments
which could have an impact on Granite State. Granite State has
therefore petitioned to intervene in this appeal to protect its
interest on those issues.
Prior to the issuance of the NHPUC order, Granite State
reached an interim settlement with several customers and other
stakeholders that would set initial access charges at 2.8 cents
per kWh for two years, and in other respects would mirror the
Massachusetts settlement described previously. Stranded costs to
be recovered after the two-year initial period would be subject
to future regulatory determination. Unlike the NHPUC order, the
interim settlement agreement would provide all customers with a
rate reduction of approximately 10 percent. This interim
settlement is still pending before the NHPUC.
Federal Activity
In April 1996, the FERC issued Order No. 888 requiring
utilities that own transmission facilities to file open access
tariffs to make available transmission service to affiliates and
nonaffiliates at fair, nondiscriminatory rates. Order No. 888
also stated that public utilities will be allowed to seek
recovery of legitimate and verifiable stranded costs from
departing customers as a result of wholesale competition. The
FERC indicated that it will provide for the recovery of retail
stranded costs only if state regulators lack the legal authority
to address those costs at the time retail wheeling is required.
The FERC also stated that it would permit stranded cost recovery
under wholesale all-requirements contracts, such as the contracts
between the Company and its retail affiliates. On February 26,
1997, the FERC announced Order No. 888-A, reaffirming the
principles of Order No. 888, including stranded cost recovery.
Because of the Massachusetts settlement and the Rhode Island
statute, the Company does not expect it will rely exclusively on
Order No. 888 to recover stranded costs from its affiliates in
Massachusetts and Rhode Island. The Company cannot predict at
this time whether an Order No. 888 filing will be necessary to
fully recover stranded costs from Granite State or from seven
unaffiliated wholesale customers should any of those customers
choose to terminate service under their contract with the
Company. Granite State and these seven unaffiliated customers
are responsible for approximately 3 percent and 2 percent of the
Company's sales, respectively.
In July 1996, the Company, on behalf of the NEES companies,
filed a transmission tariff with the FERC pursuant to Order No.
888. The FERC accepted the filing, but ordered the Company to
refile to conform more closely with the FERC's requirements under
Order No. 888. Implementation of the tariff in mid-1996 did not
have a significant impact on the Company's revenues.
A number of proposals for federal legislation related to
industry restructuring have been brought forward for
consideration by the current Congress. The scope and aim of
these vary widely; however, the NEES companies and others will
argue that state settlements should be respected. The Company
cannot predict what federal legislation, if any, may be enacted.
Divestiture of Generation Business
Under the Massachusetts settlement and, if approved by the
FERC, automatically under the Rhode Island statute, the Company
must complete the divestiture of its generating businesses within
six months of the later of the commencement of retail choice in
Massachusetts or the receipt of all necessary regulatory
approvals. The Company is in the process of soliciting proposals
for the acquisition of its nonnuclear generating business with
the objective of reaching definitive purchase and sale agreements
by mid-1997. Closing would follow the receipt of regulatory
approvals, which are expected to take at least six to 12 months
following the execution of purchase and sale agreements. At
December 1996, nonnuclear net generating plant was approximately
$1.1 billion.
As part of the divestiture plan, the Company will endeavor to
sell, or otherwise transfer, its minority interest in four
nuclear power plants to nonaffiliates. The Company may retain
responsibility for decommissioning and related expenses, if
necessary. To the extent that the Company is unable to divest
its nuclear generating interest, the Massachusetts settlement
provides for a sharing between customers and shareholders of the
revenues associated with the nuclear interests and the costs not
otherwise reflected in the access charge, with 80 percent
allocated to customers and 20 percent to shareholders. This
sharing mechanism is not included in the Rhode Island statute
previously discussed. In addition, New England Energy
Incorporated (NEEI) is planning to sell its oil and gas
properties, the cost of which is supported by the Company through
fuel purchase contracts.
The Company has approximately $740 million of mortgage bonds
outstanding. The bond indenture restricts the sale of the trust
property in its entirety or substantially in its entirety. The
proposed sale of the Company's generating business would likely
require that the Company either amend the bond indenture or
defease or call the bonds in connection with the proposed sale.
Any defeasance of bonds would be by the deposit of cash
representing principal and interest to the maturity date or
interest, principal, and general redemption premium to an earlier
redemption date.
Risk Factors
While substantial progress has been made in resolving the
uncertainty regarding the impact on shareholders from industry
restructuring, significant risks remain. These include, but are
not limited to (i) the potential that ultimately the
Massachusetts settlement and the Rhode Island statute will not be
implemented in the manner anticipated by the Company, (ii) the
possibility of state or federal legislation that would increase
the risks to shareholders above those contained in the
Massachusetts settlement and Rhode Island statute, and (iii) the
potential for adverse stranded cost recovery decisions involving
Granite State and the Company's unaffiliated customers.
Even if these risks do not materialize, the implementation of
the Massachusetts settlement and the Rhode Island statute will
negatively impact financial results for the Company starting in
1998. The returns on equity permitted on the unrecovered
commitments in the generating business (generally 9.4 percent to
11 percent) are less than those historically earned by the
Company. Also, once the Company has divested its generating
business and completed its stranded cost recovery, it will become
solely a provider of transmission services with substantially
lower revenues and capital requirements than currently exists.
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. 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 costs expected to be
recovered in future rates. The Company has recorded
approximately $340 million in net regulatory assets in compliance
with FAS 71. In addition, the Company's affiliate, NEEI, has a
regulatory asset of approximately $150 million, which is
recoverable in its entirety from the Company.
Both the Massachusetts settlement and the Rhode Island statute
provide for full recovery of the 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 costs of these assets would be
recovered as part of a contract termination charge imposed on all
distribution customers. 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. Specifically, FERC Order No. 888 enables
transmission companies, which the Company would essentially
become, to recover their specific costs of providing transmission
service. The Company believes these factors will allow it to
continue to apply FAS 71 and that no impairment of plant assets
will exist 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). Any loss from the
divestiture of generating assets and oil and gas assets will be
recorded as a regulatory asset to be recovered through the
contract termination charge.
Although the Company believes that it will continue to meet
the criteria for continued application of FAS 71, the Company
understands that members of the SEC staff have raised questions
concerning the continued applicability of FAS 71 to certain other
electric utilities facing restructuring. In addition, despite
the progress made to date in Massachusetts and Rhode Island, it
is possible that the final restructuring plans ultimately ordered
by regulatory bodies would not reflect full recovery of stranded
costs, including a fair return on those costs as they are being
recovered. In the event that future circumstances should cause
the application of FAS 71 to be discontinued, a noncash write-off
of previously established regulatory assets and liabilities
related to the affected operations would be required. In
addition, write-downs of plant assets under FAS 121 could be
required, including a write-off of any loss from the divestiture
of the generating business.
Overview
Net income increased by $1 million in 1996. This increase
reflects 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 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. The Company also experienced reduced peak demand
charge billings in 1996.
Net income increased by $2 million in 1995 reflecting higher
sales, lower depreciation and amortization expense and lower
maintenance expense. Partially offsetting these increases were
increased purchased power costs excluding fuel, increased costs
related to postretirement benefits other than pensions (PBOPs),
increased reimbursements to affiliates for service extension
discounts (SEDs) to customers and generation and transmission
costs incurred for the benefit of the Company. In addition,
interest costs also increased in 1995.
Operating Revenue
The following table summarizes the changes in operating
revenue:
Increase (Decrease) in Operating Revenue
1996 1995
---- ----
(In Millions)
Fuel recovery $ 70 $ 27
Accrued NEEI fuel revenues (22) 4
Narragansett integrated facilities credit (9) (10)
SED reimbursements (12)
Sales growth and peak demand charges (7) 15
Other (2) 6
---- ----
$ 30 $ 30
==== ====
Accrued NEEI fuel revenues and accrued NEEI fuel costs (see
"Operating Expenses" section) reflect losses incurred by NEEI, an
affiliate of the Company, on its rate-regulated oil and gas
operations. These revenues are accrued in the year of the loss
but are billed to the Company's customers through its fuel
adjustment clause in the following year. Changes in accrued NEEI
fuel revenues and fuel costs are principally due to fluctuations
in NEEI production (see Note D-6). In addition, in December
1996, NEEI recorded a $13 million adjustment which reduced its
1996 amortization of oil and gas properties to correct amounts
recorded in the years 1990 through 1996.
The entire output of Narragansett's generating capacity is
made available to the Company. Narragansett receives a credit on
its purchased power bill from the Company for its fuel costs and
other generation and transmission-related costs. The increased
credits in 1996 relate to costs associated with the dismantlement
of the previously retired South Street generating facility and
with Narragansett's portion of the repowered Manchester Street
generating station that entered commercial operation in the
second half of 1995. The Company's 1995 rate agreement provided
for the deferral and recovery over three years of $12 million of
these credits related to the dismantlement of Narragansett's
South Street station.
Operating Expenses
The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
1996 1995
---- ----
(In Millions)
Fuel costs $ 74 $ 27
Accrued NEEI fuel costs (22) 4
Purchased energy excluding fuel (28) 22
Other operation and maintenance (22) (2)
Depreciation and amortization 1 (35)
Taxes 8 (1)
---- ----
$ 11 $ 15
==== ====
Total fuel costs represent fuel for generation and the portion
of purchased electric energy permitted to be recovered through
the Company's fuel adjustment clause. The increase in fuel costs
in 1996 is primarily 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 increase
in fuel costs also reflects increased generation as a result of
increased sales to affiliates as well as generation supplied to
other utilities. See "Operating Revenue" section for a
discussion of accrued NEEI fuel costs.
In 1996, purchased power costs, excluding fuel, decreased,
reflecting the expiration of certain purchased power contracts.
In addition, purchased power costs in the first half of 1995
included the Company's share of costs to repair steam generator
tubes at the Maine Yankee nuclear power plant in which the
Company has a 20 percent interest. The increase in 1995 also
reflected other overhaul and refueling shutdowns by partially
owned nuclear power suppliers and the commencement of
amortization over seven years of $29 million of deferred
purchased power contract termination costs, in accordance with a
1995 rate settlement.
The decrease in operation and maintenance in 1996 reflects
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. The decrease in
operation and maintenance expense in 1995 has also reflected
reduced overhaul activity partially offset by the commencement of
amortization over seven years of $19 million of deferred PBOP
costs in accordance with the 1995 rate settlement. The rate
agreement also provided for the deferral and recovery over three
years of $15 million of costs related to the replacement of a
turbine rotor at one of the Company's generating stations.
Depreciation expense increased in 1996 due to new plant
expenditures, including the Manchester Street Station which
entered service in the last half of 1995. This increase was
partially offset by the completion in mid-1995 of the
amortization of a portion of Seabrook 1 costs and Salem Harbor
coal conversion costs. Depreciation in 1995 decreased due to
reduced amortization of Seabrook 1 in accordance with the 1995
rate settlement which deferred recognition of $15 million of such
amortization from 1995 to 1996 as well as the completion of the
amortizations mentioned above. Partially offsetting these
decreases were increased depreciation rates of approximately $8
million approved in the 1995 rate agreement and increased
depreciation of new plant expenditures, including the Manchester
Street Station.
The increase in taxes in 1996 reflects municipal property
taxes. The increase in municipal property taxes is primarily as
a result of increased taxes on the Manchester Street Station.
Allowance for Funds Used During Construction (AFDC)
The changes in AFDC in 1996 and 1995 are due to the Manchester
Street Station repowering project which began commercial
operation in the second half of 1995.
Investments in Nuclear Units
The Company owns minority interests in six nuclear generating
units, two of which, Yankee Atomic and Connecticut Yankee, have
been shut down permanently. Two others, Millstone 3 and Maine
Yankee, are currently shut down and have been placed on the
Nuclear Regulatory Commission's (NRC) "Watch List," signifying
that their safety performance exhibits sufficient weakness to
warrant increased NRC attention. Neither may restart without NRC
approval. At present, the Vermont Yankee and Seabrook 1 nuclear
generating units appear to be operating routinely without major
problems.
On October 9, 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, Maine Yankee, and Vermont Yankee nuclear power
plants responded to the NRC letters in February 1997.
Uncertainties regarding the future of nuclear generating
stations, particularly older units such as Maine Yankee and
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.
Connecticut Yankee
The Company has a 15 percent equity ownership interest in
Connecticut Yankee. As a result of an economic analysis, the
Connecticut Yankee board of directors voted in December 1996 to
permanently shut down and decommission the plant.
In December 1996, Connecticut Yankee filed with the FERC to
recover all of its approximately $246 million undepreciated
investment in the plant and other costs over the period extending
through June 2007, when the plant's NRC operating license would
have expired. In a 1993 decision, the FERC allowed Yankee Atomic
to recover its undepreciated investment in its permanently shut
down nuclear plant, in part on the grounds that owners should not
be discouraged from closing uneconomic plants. Several parties
have intervened in opposition to Connecticut Yankee's filing. The
Company believes that the FERC will allow the Company to recover
from its customers all costs that the FERC allows Connecticut
Yankee to recover from the Company.
The Company has recorded the estimated future payment
obligation to Connecticut Yankee of $114 million, as a liability
and as an offsetting regulatory asset, reflecting the Company's
expected future rate recovery of such costs. The NRC has
identified numerous apparent violations of its regulations, which
may result in the assessment of civil penalties.
Millstone 3
The Company is a 12 percent joint owner of 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 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 action taken at the unit,
an NRC assessment concluding a culture change has occurred,
public hearings, and a vote of the NRC Commissioners. NU
announced in December 1996 that it expects Millstone 3 to be
ready for restart around the end of 1997, subject to review by
the NRC Commissioners. The Company cannot predict when Millstone
3 will be allowed by the NRC to restart, but believes that the
unit will remain shut down for a very protracted period.
The Company incurred $10 million of actual costs in 1996
related to corrective actions associated with the outage. The
Company has also accrued a liability of approximately $3 million
for its share of future corrective action costs. Additional costs
may be incurred. During the outage, the Company is also
incurring approximately $1.6 million per month in incremental
replacement power costs, which it has been recovering from
customers through its fuel clause.
Several criminal investigations related to Millstone 3 are
ongoing. The NRC has identified numerous apparent violations of
its regulations which may result in the assessment of civil
penalties. The Company and other minority owners of Millstone 3
are assessing their legal rights with respect to NU's operation
of Millstone 3.
Maine Yankee
The Company has a 20 percent equity ownership interest in
Maine Yankee. Over the past few years, the Maine Yankee nuclear
generating plant has experienced numerous technical and
nontechnical problems. In 1995, the plant had been shut down for
much of the year due to the discovery of cracks in its steam
generator tubes. The plant is currently shut down due to a cable
routing problem. In addition, due to leaking nuclear fuel rods,
68 fuel assemblies will be replaced. As a result, Maine Yankee
management does not expect the unit to restart until summer of
1997.
In late 1995, allegations were made to the NRC that inadequate
analyses of the plant's emergency core cooling system had been
performed. As a result of the allegations, the NRC limited the
plant's operation to 90 percent of full capacity. In September
1996, the NRC asked the Department of Justice (DOJ) to review,
for potential criminal violations, an NRC investigatory report on
the allegations. The DOJ is not limited in its investigation to
the matters covered in that report.
During 1996, the NRC conducted an independent safety
assessment (ISA) and identified a number of weaknesses,
deficiencies, and apparent violations which could result in
fines. Yankee Atomic performed professional services for Maine
Yankee associated with the matters being investigated. In
response to the ISA results, Maine Yankee has indicated that it
will spend more than $50 million in 1997 on operational
improvements. Additionally, in February 1997, Entergy
Corporation, an operator of five nuclear units, commenced
providing management services.
Under a confirmatory action letter issued by the NRC on
December 18, 1996, and supplemented on January 30, 1997, Maine
Yankee must fulfill certain commitments before its plant will be
allowed by the NRC staff to return to service. Because of
regulatory and other uncertainties faced by Maine Yankee, the
Company cannot predict whether or when Maine Yankee will return
to service.
During the outage, the Company is incurring approximately $1.8
million per month in incremental replacement power costs, which
it has been recovering from customers through its fuel clause.
Brayton Point
In October 1996, the Environmental Protection Agency (EPA)
announced it was beginning a process to determine whether to
modify or revoke the Company's water discharge permit for its
Brayton Point 1,576 megawatt 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) that action be
taken on the Brayton Point permit prior to its 1998 renewal,
based on concerns raised in a final RIDEM report issued in
October 1996. The 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-1980's.
In February 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 is in lieu of any immediate action on the permit, but
will cover only the months of February and March 1997. During
this time, the parties will continue to work toward a longer-term
solution. 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 as well as require significant capital expenditures of
tens of millions of dollars to construct equipment to address the
concerns raised by the environmental agencies.
Electric and Magnetic Fields (EMF)
In recent years, concerns have been raised about whether EMF,
which occur near transmission and distribution lines as well as
near household wiring and appliances, cause or contribute to
adverse health effects. Numerous studies on the effects of these
fields, some of them sponsored by electric utilities (including
NEES companies), have been conducted and are continuing. In
October 1996, the National Research Council of the National
Academy of Sciences released a report stating no conclusive and
consistent evidence demonstrates that exposures to residential
EMF produce adverse health effects. It is impossible to predict
the ultimate impact on the Company and the electric utility
industry if further investigations were to demonstrate that the
present electricity delivery system is contributing to increased
risk of cancer or other health problems.
Several state courts have recognized a cause of action for
damage to property values in transmission line condemnation cases
based on the fear that power lines cause cancer. It is difficult
to predict what the impact on the Company would be if this cause
of action is recognized in the states in which the Company
operates and in contexts other than condemnation cases.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $66 million for
1996. 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 1997 are estimated to be $70 million. Internally
generated funds are expected to fully cover the Company's 1997
capital expenditures in 1997.
In 1996, the Company refinanced $48 million of variable rate
mortgage bonds. In addition, in 1996, the Company retired $10
million of mortgage bonds.
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.
At December 31, 1996, the Company had $94 million of
short-term debt outstanding including $89 million of commercial
paper borrowings and $5 million of borrowings from affiliates.
At December 31, 1996, the Company had lines of credit and bond
purchase facilities with banks totaling $530 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, 1996.
New England Power Company
Statements of Income
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Operating revenue, principally from
affiliates $1,600,309 $1,570,539 $1,540,757
---------- ---------- ----------
Operating expenses:
Fuel for generation 342,545 279,849 260,540
Purchased electric energy 508,910 547,926 513,583
Other operation 203,456 211,872 196,610
Maintenance 79,118 92,954 110,528
Depreciation and amortization 104,209 102,758 137,979
Taxes, other than income taxes 66,416 58,716 54,400
Income taxes 91,894 91,051 96,596
---------- ---------- ----------
Total operating expenses 1,396,548 1,385,126 1,370,236
---------- ---------- ----------
Operating income 203,761 185,413 170,521
Other income:
Allowance for equity funds used during
construction 7,746 9,142
Equity in income of nuclear power
companies 5,159 5,721 4,816
Other income (expense), net (1,851) (1,610) (293)
---------- ---------- ----------
Operating and other income 207,069 197,270 184,186
---------- ---------- ----------
Interest:
Interest on long-term debt 45,111 46,797 38,711
Other interest 10,066 10,525 1,956
Allowance for borrowed funds used
during construction - credit (591) (11,479) (5,854)
---------- ---------- ----------
Total interest 54,586 45,843 34,813
---------- ---------- ----------
Net income $ 152,483 $ 151,427 $ 149,373
========== ========== ==========
Statements of Retained Earnings
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Retained earnings at beginning of year $ 385,309 $ 372,763 $ 346,153
Net income 152,483 151,427 149,373
Dividends declared on cumulative
preferred stock (2,574) (3,433) (3,440)
Dividends declared on common stock,
$20.80, $21.00, and $18.50 per share,
respectively (134,158) (135,448) (119,323)
Premium on redemption of preferred stock (450)
--------- --------- ---------
Retained earnings at end of year $ 400,610 $ 385,309 $ 372,763
========= ========= =========
The accompanying notes are an integral part of these financial statements.
New England Power Company
Balance Sheets
At December 31, (In Thousands) 1996 1995
Assets ---- ----
Utility plant, at original cost $2,991,797 $2,941,469
Less accumulated provisions for
depreciation and amortization 1,118,340 1,047,982
---------- ----------
1,873,457 1,893,487
Net investment in Seabrook 1 under rate
settlement (Note D-2) 15,210
Construction work in progress 36,836 41,566
---------- ----------
Net utility plant 1,910,293 1,950,263
---------- ----------
Investments:
Nuclear power companies, at equity (Note D-1) 47,902 47,055
Non-utility property and other investments 30,591 26,627
---------- ----------
Total investments 78,493 73,682
---------- ----------
Current assets:
Cash 3,046 2,607
Accounts receivable:
Affiliated companies 201,370 204,314
Accrued NEEI revenues (Note D-6) 21,648 43,731
Others 23,219 17,821
Fuel, materials, and supplies, at average cost 58,709 54,664
Prepaid and other current assets 25,050 27,986
---------- ----------
Total current assets 333,042 351,123
---------- ----------
Deferred charges and other assets (Note B) 325,887 273,275
---------- ----------
$2,647,715 $2,648,343
========== ==========
Capitalization and Liabilities
Capitalization:
Common stock, par value $20 per share,
authorized and outstanding 6,449,896 shares $ 128,998 $ 128,998
Premiums on capital stocks 86,779 86,829
Other paid-in capital 289,818 288,000
Retained earnings 400,610 385,309
---------- ----------
Total common equity 906,205 889,136
Cumulative preferred stock, par value $100
per share (Note G) 39,666 60,516
Long-term debt 733,006 735,440
---------- ----------
Total capitalization 1,678,877 1,685,092
---------- ----------
Current liabilities:
Long-term debt due in one year 3,000 10,000
Short-term debt (including $5,275 and
$1,025 to affiliates) 93,600 125,150
Accounts payable (including $25,301 and
$50,760 to affiliates) 127,226 163,791
Accrued liabilities:
Taxes 8,158 3,447
Interest 9,668 10,482
Other accrued expenses (Note F) 16,577 10,834
Dividends payable 27,412 32,249
---------- ----------
Total current liabilities 285,641 355,953
---------- ----------
Deferred federal and state income taxes 382,164 390,197
Unamortized investment tax credits 55,486 57,509
Other reserves and deferred credits 245,547 159,592
Commitments and contingencies (Note D)
---------- ----------
$2,647,715 $2,648,343
========== ==========
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) 1996 1995 1994
Operating activities: ---- ---- ----
Net income $ 152,483 $ 151,427 $ 149,373
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 108,338 108,384 142,764
Deferred income taxes and
investment tax credits, net (7,458) 25,683 23,051
Allowance for funds used during
construction (591) (19,225) (14,996)
Decrease (increase) in accounts
receivable 19,629 1,321 (6,932)
Decrease (increase) in fuel, materials,
and supplies (4,045) 18,697 (17,406)
Decrease (increase) in prepaid and
other current assets 2,936 5,743 (7,275)
Increase (decrease) in accounts payable (36,565) (15,970) 35,661
Increase (decrease) in other current
liabilities 9,640 (2,150) (30,823)
Other, net 28,582 (28,244) (26,845)
--------- --------- ---------
Net cash provided by operating
activities $ 272,949 $ 245,666 $ 246,572
--------- --------- ---------
Investing activities:
Plant expenditures, excluding allowance
for funds used during construction $ (65,981) $(162,766) $(229,015)
Other investing activities (3,878) (3,614) (3,053)
--------- --------- ---------
Net cash used in investing activities $ (69,859) $(166,380) $(232,068)
--------- --------- ---------
Financing activities:
Dividends paid on common stock $(138,995) $(103,198) $(133,835)
Dividends paid on preferred stock (2,574) (3,433) (3,440)
Changes in short-term debt (31,550) (20,425) 95,050
Long-term debt - issues 47,850 60,000 28,000
Long-term debt - retirements (57,850) (10,000)
Preferred stock - retirements (20,900) (512)
Gain on redemption of preferred stock 1,368
--------- --------- ---------
Net cash used in financing activities $(202,651) $ (77,056) $ (14,737)
--------- --------- ---------
Net increase (decrease) in cash and cash
equivalents $ 439 $ 2,230 $ (233)
Cash and cash equivalents at beginning of
year 2,607 377 610
--------- --------- ---------
Cash and cash equivalents at end of year $ 3,046 $ 2,607 $ 377
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $ 51,212 $ 41,557 $ 32,510
--------- --------- ---------
Federal and state income taxes paid $ 96,006 $ 57,948 $ 83,455
--------- --------- ---------
Dividends received from investments
at equity $ 4,313 $ 5,014 $ 4,809
--------- --------- ---------
The accompanying notes are an integral part of these financial statements.
New England Power Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of operations:
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, 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),
Massachusetts Electric Company (Massachusetts Electric),
Nantucket Electric Company (Nantucket), and The Narragansett
Electric Company. (See Note B for a discussion of industry
restructuring and the Company's proposed divestiture of its
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 5.8 percent, 7.5
percent, and 7.8 percent, in 1996, 1995, and 1994, 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) 1996 1995 1994
---- ---- ----
Depreciation $ 78,187 $ 66,309 $ 52,834
Nuclear decommissioning
costs (Note D-3) 2,629 2,629 1,951
Amortization:
Investment in Seabrook 1 under
rate settlement (Note D-2) 15,210 23,074 65,061
Oil Conservation Adjustment (OCA) 4,467 11,854
Property losses 6,279 6,279 6,279
Millstone 3 additional amortization,
under rate settlement 1,904
-------- -------- --------
Total depreciation and
amortization expense $104,209 $102,758 $137,979
======== ======== ========
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 1996, 2.7 percent in
1995, and 2.4 percent in 1994. The OCA was designed to recover
expenditures for coal conversion facilities at the Company's
Salem Harbor Station. These costs were fully amortized at
December 31, 1995. In addition, pre-1988 Seabrook 1 costs under
the rate settlement were fully amortized at December 31, 1996.
5. Cash:
The Company classifies short-term investments with a maturity of
90 days or less at time of purchase as cash.
Note B - Industry Restructuring
The electric utility business is rapidly progressing toward the
unbundling of what is now a fully-regulated, bundled product into
separate generation, transmission, and distribution components
and creating competition in the generation component. Under the
current regulatory framework, electric utilities have incurred
costs related to commitments to supply electricity to customers
that may not be economical in a competitive environment. The
amounts by which such costs exceed market prices are commonly
referred to as "stranded costs." As described below, a variety
of new rules, laws, or proposals have been enacted, or are in
process, in the jurisdictions that the NEES subsidiaries operate,
to provide for competition in a deregulated generation
environment, and allow for stranded cost recovery. See also the
"Industry Restructuring" section of Financial Review for a more
in-depth discussion of current developments in this area.
Massachusetts and Rhode Island
On February 26, 1997, the Massachusetts Department of Public
Utilities approved an industry restructuring settlement agreement
among the Company, its Massachusetts distribution affiliates,
Massachusetts Electric and Nantucket, the Massachusetts Attorney
General, and other parties. In August 1996, the state of Rhode
Island enacted industry restructuring legislation.
The Massachusetts settlement and the Rhode Island statute have
many similarities. Both plans:
- - provide for complete retail choice by customers of their power
supplier. In Rhode Island, this would begin in July 1997 for
certain customers. All customers in Rhode Island and
Massachusetts would have choice in 1998. In Massachusetts,
choice is contingent on open access being available to all
customers of Massachusetts investor-owned utilities;
- - provide for recovery of their allocated share of the Company's
stranded costs;
- - provide customers who do not choose an alternative supplier
with service called "standard offer" service;
- - require an adjustment of stranded cost recovery to reflect the
market value of fossil and hydroelectric generating assets with
the Massachusetts settlement requiring actual divestiture of such
assets;
- - propose amendments to the New England Power Company-
distribution companies' wholesale all-requirements contracts
which have been filed with and accepted by the FERC, set down for
hearing, and made effective, subject to refund.
The stranded costs to be recovered in both Massachusetts and
Rhode Island include (i) the above-market portion of generating
plant commitments and regulatory assets to be recovered over 12
years in Massachusetts and 12.5 years in Rhode Island and (ii)
the above-market portion of purchased power contracts and the
operating cost of nuclear plants, that cannot be avoided by
shutting down the plants, including nuclear decommissioning
costs. These latter costs would be recovered as incurred over
the life of these obligations, a period expected to extend beyond
12 years. The Company estimates that at December 31, 1996, its
above-market commitments are approximately $4.5 billion on a
present-value basis before application of the proceeds from the
sale of its generating business.
Under the Massachusetts settlement, the Company must complete the
divestiture of its generating business within six months of the
later of the commencement of retail choice in Massachusetts or
the receipt of all necessary regulatory approvals. As part of
the divestiture plan, the Company will endeavor to sell, or
otherwise transfer, its minority interest in four nuclear power
plants to nonaffiliates. To the extent the Company is unable to
divest its nuclear generating interests, the Massachusetts
settlement provides for a sharing between customers and
shareholders of the nuclear-related revenues and costs not
otherwise reflected in the stranded costs recovery, with 80
percent allocated to customers and 20 percent to shareholders.
In addition, New England Energy Incorporated is planning to sell
its oil and gas properties, the cost of which is supported by the
Company through fuel purchased contracts.
The Utility Workers Union of America and the Massachusetts
Alliance of Utility Unions, who intervened in the MDPU proceeding
on the settlement, have indicated they intend to appeal the
MDPU's order approving the settlement to the Massachusetts
Supreme Judicial Court. If an appeal is brought, the NEES
companies will oppose it.
New Hampshire and federal activity
On February 28, 1997, the New Hampshire Public Utilities
Commission (NHPUC) issued its plan to implement a New Hampshire
law calling for retail access by 1998. Under the plan, utilities
such as Granite State whose rates are below the regional average
would be allowed full recovery of stranded costs as calculated by
the NHPUC. However, the NHPUC indicated that its methodology and
proposed timing of recovery would yield both initial access
charges and total recovery less than that requested by Granite
State. Further, the NHPUC indicated that its decision would not
result in savings for Granite State's customers.
The largest utility in New Hampshire is Public Service Company of
New Hampshire (PSNH). PSNH has appealed the NHPUC's decision to
the courts and has included in its appeal certain arguments which
could have an impact on Granite State. Granite State has
therefore petitioned to intervene in this appeal to protect its
interest on those issues.
Prior to the issuance of the NHPUC order, Granite State had
reached an interim settlement with several customers and other
stakeholders that would set initial access charges at 2.8 cents
per kilowatt-hour (kWh) for two years, and in other respects
would mirror the Massachusetts settlement described above.
Stranded costs to be recovered after the two-year initial period
would be subject to future regulatory determination. Unlike the
NHPUC order, the interim settlement agreement would provide all
customers with a rate reduction of approximately 10 percent.
This interim settlement is still pending before the NHPUC.
In April 1996, the FERC issued Order No. 888 requiring utilities
that own transmission facilities to file open access tariffs to
make available transmission service to affiliates and
nonaffiliates at fair, nondiscriminatory rates. In mid-1996, the
Company filed a transmission tariff with the FERC pursuant to
this requirement. Order No. 888 also stated that public
utilities will be allowed to seek recovery of legitimate and
verifiable stranded costs from departing customers as a result of
wholesale competition. The FERC also stated that it would permit
stranded cost recovery under wholesale all-requirements
contracts, such as those between the Company and its retail
affiliates. On February 26, 1997, the FERC announced Order No.
888-A, reaffirming the principle of Order No. 888, including
stranded cost recovery.
Because of the Massachusetts settlement and the Rhode Island
statute, the Company does not expect it will rely exclusively on
Order No. 888 to recover stranded costs from its affiliates in
Massachusetts and Rhode Island. The Company cannot predict at
this time whether an Order No. 888 filing will be necessary to
fully recover stranded costs from Granite State or from seven
unaffiliated wholesale customers should any of those customers
choose to terminate service under their contracts with the
Company. Granite State and these seven unaffiliated customers
are responsible for approximately 3 percent and 2 percent of the
Company's sales, respectively.
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. 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 costs expected to be
recovered in future rates. The Company has recorded
approximately $340 million in regulatory assets in compliance
with FAS 71. In addition, the Company's affiliate, NEEI, has a
net regulatory asset of approximately $150 million, which is
recoverable in its entirety from the Company.
Both the Massachusetts settlement and the Rhode Island statute
provide for full recovery of the 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 costs of these assets would be
recovered as part of a contract termination charge imposed on all
distribution customers. 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. Specifically, FERC Order No. 888 enables
transmission companies, which the Company would essentially
become, to recover their specific costs of providing transmission
service. The Company believes these factors will allow it to
continue to apply FAS 71 and that no impairment of plant assets
will exist 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). Any loss from the
divestiture of generating assets and oil and gas assets will be
recorded as a regulatory asset to be recovered through the
contract termination charge.
Although the Company believes that it will continue to meet the
criteria for continued application of FAS 71, the Company
understands that members of the SEC staff have raised questions
concerning the continued applicability of FAS 71 to certain other
electric utilities facing restructuring. In addition, despite
the progress made to date in Massachusetts and Rhode Island, it
is possible that the final restructuring plans ultimately ordered
by regulatory bodies would not provide for full recovery of
stranded costs, including a fair return on those costs as they
are being recovered. In the event that future circumstances
should cause the application of FAS 71 to be discontinued, a
noncash write-off of previously established regulatory assets and
liabilities related to the affected operations would be required.
In addition, write-downs of plant assets under FAS 121 could be
required, including a write-off of any loss from the divestiture
of the generating business.
The components of regulatory assets are as follows:
At December 31, (In Thousands) 1996 1995
---- ----
Regulatory assets included in current
assets and liabilities:
Accrued NEEI losses (see Note D-6) $ 21,648 $43,731
Rate adjustment mechanisms (4,790)
-------- -------
16,858 43,731
Regulatory assets included in deferred charges:
Accrued Connecticut Yankee
costs (see Note D-3) 114,425
Accrued Yankee Atomic
costs (see Note D-3) 51,988 67,566
Unamortized losses on reacquired debt 31,353 32,571
Deferred SFAS No. 106 costs
(see Note E-2) 13,680 16,416
Deferred SFAS No. 109 costs
(see Note C) 27,461 30,059
Purchased power contract
termination costs 19,578 23,494
Deferred gas pipeline charges
(see Note D-9) 59,733 62,873
Unamortized property losses 253 12,044
Other 2,727 22,049
-------- --------
321,198 267,072
-------- --------
$338,056 $310,803
======== ========
Amounts included in "Deferred charges and other assets" on the
balance sheets that do not represent regulatory assets totaled
$4,689,000 and $6,203,000 at December 31, 1996 and 1995,
respectively. As previously noted, the Company's affiliate,
NEEI, has a regulatory asset of approximately $150 million, which
is recoverable in its entirety from the Company (see Note D-6).
Note C - 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 (IRS) through 1991. The returns for
1992 and 1993 are currently under examination by the IRS.
Total income taxes in the statements of income are as follows:
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Income taxes charged to operations $91,894 $91,051 $96,596
Income taxes charged (credited) to
"Other income" 555 353 (994)
------- ------- -------
Total income taxes $92,449 $91,404 $95,602
======= ======= =======
Total income taxes, as shown above, consist of the following components:
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Current income taxes $99,907 $65,721 $72,551
Deferred income taxes (5,435) 27,188 26,628
Investment tax credits, net (2,023) (1,505) (3,577)
------- ------- -------
Total income taxes $92,449 $91,404 $95,602
======= ======= =======
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) 1996 1995 1994
---- ---- ----
Federal income taxes $76,656 $74,590 $78,274
State income taxes 15,793 16,814 17,328
------- ------- -------
Total income taxes $92,449 $91,404 $95,602
======= ======= =======
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) 1996 1995 1994
---- ---- ----
Computed tax at statutory rate $85,726 $84,991 $85,741
Increases (reductions) in tax
resulting from:
Amortization of investment
tax credits (2,023) (2,227) (3,045)
State income taxes, net of federal
income tax benefit 10,265 10,929 11,263
All other differences (1,519) (2,289) 1,643
------- ------- -------
Total income taxes $92,449 $91,404 $95,602
======= ======= =======
The following table identifies the major components of total
deferred income taxes:
At December 31, (In Millions) 1996 1995
---- ----
Deferred tax asset:
Plant related $ 97 $ 92
Investment tax credits 23 24
All other 46 43
----- -----
166 159
----- -----
Deferred tax liability:
Plant related (415) (397)
Equity AFDC (45) (47)
All other (88) (105)
----- -----
(548) (549)
----- -----
Net deferred tax liability $(382) $(390)
==== =====
There were no valuation allowances for deferred tax assets deemed
necessary.
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) 1996 1995 1994
---- ---- ----
Operating revenue $ 697,054 $ 695,781 $ 631,940
=========== =========== ===========
Net income $ 27,567 $ 31,657 $ 30,345
=========== =========== ===========
Company's equity in
net income $ 5,159 $ 5,721 $ 4,816
=========== =========== ===========
Net plant 401,049 443,967 537,103
Other assets 2,031,336 1,418,681 1,458,186
Liabilities and debt (2,177,068) (1,612,843) (1,748,960)
----------- ----------- -----------
Net assets $ 255,317 $ 249,805 $ 246,329
=========== =========== ===========
Company's equity in
net assets $ 47,902 $ 47,055 $ 46,349
=========== =========== ===========
Company's purchased
electric energy $ 110,778 $ 115,647 $ 106,404
=========== =========== ===========
At December 31, 1996, $14 million of undistributed earnings of
the Yankees were included in the Company's retained earnings.
2. Jointly-owned nuclear generating units:
The Company is also a 12 percent and 10 percent joint owner,
respectively, of the Millstone 3 and Seabrook 1 nuclear
generating units, each 1,150 megawatts. The Company's net
investment in Millstone 3, included in "Net utility plant" is
approximately $379 million. The Company's pre-1988 investment in
Seabrook 1 has been fully amortized in 1996 pursuant to a
settlement agreement. The Company's net investment in Seabrook 1
since January 1, 1988, which is approximately $55 million, is
included in "Net utility plant" on the Company's balance sheet
and is being depreciated over the term of Seabrook 1's operating
license. The Company's share of expenses for these units is
included in "Operating expenses."
3. Nuclear plant decommissioning and nuclear fuel disposal:
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 Nuclear Regulatory Commission (NRC), but also
costs to dismantle the uncontaminated portion of the units. The
Company records decommissioning costs expense 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.
Connecticut Yankee
The Company has a 15 percent equity ownership interest in
Connecticut Yankee. As a result of an economic analysis, the
Connecticut Yankee board of directors voted in December 1996 to
permanently shut down and decommission the plant.
In December 1996, Connecticut Yankee filed with the FERC to
recover all of its approximately $246 million undepreciated
investment in the plant and other costs over the period extending
through June 2007, when the plant's NRC operating license would
have expired. In a 1993 decision, the FERC allowed Yankee Atomic
to recover its undepreciated investment in its permanently shut
down nuclear plant, in part on the grounds that owners should not
be discouraged from closing uneconomic plants. Several parties
have intervened in opposition to Connecticut Yankee's filing.
The Company believes that the FERC will allow the Company to
recover from its customers all costs that the FERC allows
Connecticut Yankee to recover from the Company.
The Company has recorded the estimated future payment obligation
to Connecticut Yankee of $114 million as a liability and as an
offsetting regulatory asset, reflecting the Company's expected
future rate recovery of such costs. The NRC has identified
numerous apparent violations of its regulations, which may result
in the assessment of civil penalties.
Yankee Atomic
The Company has a 30 percent ownership interest in Yankee Atomic.
In 1992, the Yankee Atomic board of directors decided to
permanently cease power operation of, and decommission, the
facility. Decommissioning is currently underway.
The Company has recorded an estimate of its total future payment
obligations for post-operating costs to Yankee Atomic as a
liability and as an offsetting regulatory asset, reflecting its
expected future rate recovery of such costs. This liability and
related regulatory asset are approximately $52 million each at
December 31, 1996.
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's
share of (millions of dollars)
-------------------------------
Estimated
The Company's Net DecommissioningDecommissioning License
Ownership Plant Cost (in 1996 $) Fund Balances* Expiration
Unit Interest(%) Assets
Maine Yankee ** 20 44 74 31 2008
Vermont Yankee 20 36 75 30 2012
Millstone 3 *** 12 379 62 16 2025
Seabrook 1 *** 10 55 45 7 2026
<FN>
* Certain additional amounts are anticipated to be available
through tax deductions.
** 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.
*** Fund balances are included in "Other investments" on the balance
sheets and approximate market value.
</FN>
There is no assurance that decommissioning costs actually
incurred by the Yankees, 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,
the funds collected for decommissioning to that point would
beinsufficient.
The Nuclear Waste Policy Act of 1982 establishes that the federal
government 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 Millstone 3 and Seabrook 1
nuclear units. The Company is recovering this fee through its
fuel clause. Similar costs are incurred by the Maine Yankee and
Vermont Yankee nuclear generating units. These costs are billed
to the Company and also recovered from customers through the
Company's fuel clause.
4. Investments in nuclear units
The Millstone 3 and Maine Yankee nuclear generating units are
currently shut down and have been placed on the NRC "Watch List,"
signifying that their safety performance exhibits sufficient
weakness to warrant increased NRC attention. Neither may restart
without NRC approval. At present, the Vermont Yankee and
Seabrook 1 nuclear generating units appear to be operating
routinely without major problems.
On October 9, 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, Maine Yankee, and Vermont Yankee nuclear power
plants responded to the NRC letters in February 1997.
Uncertainties regarding the future of nuclear generating
stations, particularly older units, such as Maine Yankee and
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.
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 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 culture change has occurred,
public hearings, and a vote of the NRC Commissioners. NU
announced in December 1996 that it expects Millstone 3 to be
ready for restart around the end of 1997, subject to review by
the NRC Commissioners. The Company cannot predict when Millstone
3 will be allowed by the NRC to restart, but believes that the
unit will remain shut down for a very protracted period.
The Company incurred $10 million of actual costs in 1996 related
to corrective actions associated with the outage. The Company has
also accrued a liability of approximately $3 million for its
share of future corrective action costs. Additional costs may be
incurred. During the outage, the Company is also incurring
approximately $1.6 million per month in incremental replacement
power costs, which it has been recovering from customers through
its fuel clause.
Several criminal investigations related to Millstone 3 are
ongoing. The NRC has identified numerous apparent violations of
its regulations which may result in the assessment of civil
penalties. The Company and other minority owners of Millstone 3
are assessing their legal rights with respect to NU's operation
of Millstone 3.
Maine Yankee
Over the past few years, the Maine Yankee nuclear generating
plant has experienced numerous technical and nontechnical
problems. In 1995, the plant had been shut down for much of the
year due to the discovery of cracks in its steam generator tubes.
The plant is currently shut down due to a cable routing problem.
In addition, due to leaking nuclear fuel rods, 68 fuel assemblies
will be replaced. As a result, Maine Yankee management does not
expect the unit to restart until summer of 1997.
In late 1995, allegations were made to the NRC that inadequate
analyses of the plant's emergency core cooling system had been
performed. As a result of the allegations, the NRC limited the
plant's operation to 90 percent of full capacity. In September
1996, the NRC asked the Department of Justice (DOJ) to review,
for potential criminal violations, an NRC investigatory report on
the allegations. The DOJ is not limited in its investigation to
the matters covered in that report.
During 1996, the NRC conducted an independent safety assessment
(ISA) and identified a number of weaknesses, deficiencies, and
apparent violations which could result in fines. Yankee Atomic
performed professional services for Maine Yankee associated with
the matters being investigated. In response to the ISA results,
Maine Yankee has indicated that it will spend more than $50
million in 1997 on operational improvements. Additionally, in
February 1997, Entergy Corporation, an operator of five nuclear
units, commenced providing management services.
Under a confirmatory action letter issued by the NRC on December
18, 1996, and supplemented on January 30, 1997, Maine Yankee must
fulfill certain commitments before its plant will be allowed by
the NRC staff to return to service. Because of regulatory and
other uncertainties faced by Maine Yankee, the Company cannot
predict whether or when Maine Yankee will return to service.
During the outage, the Company is incurring approximately $1.8
million per month in incremental replacement power costs, which
it has been recovering from customers through its fuel clause.
5. 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 and Connecticut
Yankee), Millstone 3, and Seabrook 1 would subject the Company to
a $58.0 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 is planning to
file with the NRC for a similar exemption.
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 $11 million per year.
6. Oil and gas operations:
NEEI, a subsidiary of NEES, is engaged in domestic oil and gas
exploration, development, and production. NEEI operates under an
intercompany pricing policy with the Company which has been
approved by the Securities and Exchange Commission (SEC). The
pricing policy requires the Company to purchase all fuel meeting
its specifications offered to it by NEEI. Under the pricing
policy, NEEI's oil and gas exploration program is composed of
prospects entered into through December 31, 1983 under a
rate-regulated program. NEEI has incurred operating losses since
1986, due to low oil and gas prices, and expects to incur
substantial additional losses in the future. These losses are
passed on to the Company in the year after they are incurred by
NEEI and, in turn, are being recovered from customers through the
Company's fuel clause. The Company's ability to pass these
losses on to its customers was favorably resolved in the
Company's 1988 FERC rate settlement. This settlement covered all
costs incurred by or resulting from commitments made by NEEI
through March 1, 1988. Other subsequent costs incurred by NEEI
are subject to normal regulatory review. In 1996, 1995, and
1994, the Company recorded accrued fuel expenses and accrued
revenues of $22 million, $44 million, and $40 million,
respectively, representing losses incurred by NEEI in each year.
In the absence of the pricing policy, the SEC's cost center
"ceiling test" rule requires non-rate-regulated companies to
write down capitalized costs to a level which approximates the
present value of their proved oil and gas reserves. Based on
NEEI's 1996 average oil and gas selling prices, application of
the ceiling test would have resulted in a write-down of
approximately $93 million after tax ($149 million before tax) at
December 31, 1996.
7. Plant expenditures:
The Company's utility plant expenditures are estimated to be
approximately $70 million in 1997. At December 31, 1996,
substantial commitments had been made relative to future planned
expenditures.
8. Hydro-Quebec Interconnection:
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 $69 million in utility plant at December 31, 1996.
Under the support agreements, the Company has agreed, in
conjunction with any Hydro-Quebec Phase II project debt
financing, to guarantee its share of project debt. At December
31, 1996, the Company had guaranteed approximately $27 million of
project debt.
9. Natural gas pipeline capacity:
In connection with serving the Company's gas-burning 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 approximately $57 million to $60
million per year from 1997 to 2001. Under these agreements,
remaining fixed payments from 2002 through 2014 total
approximately $525 million.
As part of a rate settlement, the Company was recovering 50
percent of the fixed pipeline capacity payments through its
current fuel clause and deferring the recovery of the remaining
50 percent until the Manchester Street repowering project was
completed. These deferrals ended in November 1995, at which time
the Company had deferred payments of approximately $63 million
which will be amortized over 25 years in accordance with rate
settlements (see Note B).
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 $50
million, $71 million, and $55 million, in 1996, 1995, and 1994,
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 Station entering
commercial operation in the second half of 1995.
10. 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. NEES subsidiaries currently have 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. 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 become effective in 1997. The
Company does not believe these new rules will have a material
effect on the Company's financial position or results of
operations.
11. 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 1997 to
2029. In conjunction with its divesture plan, the Company will
endeavor to sell these long-term contracts.
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 $186 million in
1996, $215 million in 1995, and $190 million in 1994. These
contracts, excluding contracts with Yankee Atomic and Connecticut
Yankee (see Note D-3), have minimum fixed payment requirements of
$155 million in 1997, $150 million in 1998 and 1999, $145 million
in 2000 and 2001, and approximately $1.3 billion thereafter.
Approximately 92 percent of the payments under these contracts
are to the Yankees and Ocean State Power, entities in which the
Company or its affiliates 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 $230
million in 1996, $245 million in 1995, and $210 million in 1994.
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.
Net pension cost for 1996, 1995, and 1994 included the following
components:
Year Ended December 31, (In Thousands) 1996 1995 1994
- -------------------------------------- ---- ---- ----
Service cost - benefits earned during the
period $ 2,769 $2,231 $2,202
Plus (less):
Interest cost on projected benefit obligation 6,669 6,406 6,403
Return on plan assets at expected long-term
rate (7,204) (6,488) (6,554)
Amortization 270 131 557
------- ------- -------
Net pension cost $ 2,504 $ 2,280 $ 2,608
======= ======= =======
Actual return on plan assets $12,672 $17,108 $ 608
======= ======= =======
Year Ended December 31, 1997 1996 1995 1994
- ----------------------- ---- ---- ---- ----
Assumptions used to determine pension cost:
Discount rate 7.25% 7.25% 8.25% 7.25%
Average rate of increase in future
compensation levels 4.13% 4.13% 4.63% 4.35%
Expected long-term rate of
return on assets 8.50% 8.50% 8.75% 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:
Retirement Plans, (In Millions) 1996 1995
---- ----
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
-------- --------- ------- --------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $298 $342 $293 $343
Non-vested 9 10 8 10
---- ---- ---- ----
Total $307 $352 $301 $353
==== ==== ==== ====
Reconciliation of funded status
Actuarial present value of
projected benefit liability $355 $398 $346 $402
Unrecognized prior service costs (6) (3) (7) (4)
SFAS No. 87 transition liability
not yet recognized (amortized) - (1) - (1)
Net gain (loss) not yet recognized
(amortized) 25 15 (1) (23)
---- ---- ---- ----
374 409 338 374
---- ---- ---- ----
Pension fund assets at fair value 384 428 349 392
SFAS No. 87 transition asset
not yet recognized (amortized) (10) - (11) -
---- ---- ---- ----
374 428 338 392
---- ---- ---- ----
Accrued pension/(prepaid)
payments recorded on books $ - $(19) $ - $(18)
The plans' funded status at December 31, 1996 and 1995 were
calculated using the assumed rates from 1997 and 1996,
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 total cost of PBOPs for 1996, 1995, and 1994 included the
following components:
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Service cost - benefits earned during
the period $ 1,407 $ 1,344 $ 1,628
Plus (less):
Interest cost on accumulated
benefit obligation 3,580 4,013 3,954
Return on plan assets at expected
long-term rate (1,832) (1,374) (1,111)
Amortization 1,867 2,079 2,591
------- ------- -------
Net postretirement benefit cost $ 5,022 $ 6,062 $ 7,062
======= ======= =======
Actual return on plan assets $ 3,572 $ 4,137 $ 54
1997 1996 1995 1994
---- ---- ---- ----
Assumptions used to determine
postretirement benefit cost:
Discount rate 7.25% 7.25% 8.25% 7.25%
Expected long-term rate of return
on assets 8.25% 8.25% 8.50% 8.50%
Health care cost rate - 1994 11.00%
Health care cost rate - 1995 to 1999 8.00% 8.00% 8.50% 8.50%
Health care cost rate - 2000 to 2004 6.25% 6.25% 8.50% 8.50%
Health care cost rate - 2005 and beyond 5.25% 5.25% 6.25% 6.25%
The following table sets forth benefits earned and the plans'
funded status:
At December 31, (In Millions) 1996 1995
---- ----
Accumulated postretirement benefit obligation:
Retirees $ 32 $ 30
Fully eligible active plan participants 2 1
Other active plan participants 20 20
---- ----
Total benefits earned 54 51
Unrecognized transition obligation (41) (43)
Unrecognized net gain 13 12
---- ----
26 20
---- ----
Plan assets at fair value 29 23
---- ----
Prepaid postretirement benefit costs recorded on books $ 3 $ 3
==== ====
The plans' funded status at December 31, 1996 and 1995 were
calculated using the assumed rates in effect for 1997 and 1996,
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,
1996 by approximately $6 million and the net periodic cost for
1996 by approximately $1 million.
The Company funds the annual tax-deductible contributions. Plan
assets are invested in equity and debt securities and cash
equivalents.
Note F - Short-term Borrowings and Other Accrued Expenses
At December 31, 1996, the Company had $94 million of short-term
debt outstanding including $89 million in commercial paper
borrowings and $5 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, 1996, the Company had lines of credit and standby
bond purchase facilities with banks totaling $530 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 H) and for other corporate purposes. There were no
borrowings under these lines of credit at December 31, 1996. Fees
are paid on the lines and facilities in lieu of compensating
balances.
The weighted average rate on outstanding short-term borrowings
was 5.9 percent at December 31, 1996. 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) 1996 1995
---- ----
Accrued wages and benefits $ 7,190 $ 6,258
Capital lease obligations due within one year 4,328 4,323
Rate adjustment mechanisms 4,790
Other 269 253
------- -------
$16,577 $10,834
======= =======
Note G - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1996 and 1995 is as follows (in
thousands of dollars except for share data):
Shares
Authorized Dividends Call
and Outstanding Amount Declared Price
--------------- ------ ------------ -----
1996 1995 1996 1995 1996 1995
---- ---- ---- ---- ---- ---- -----
$100 Par value
6.00% Series 75,020 75,020$ 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 41,500 100,000 4,150 10,000 328 464 102.56
6.08% Series 100,000 100,000 10,000 10,000 608 608 102.34
7.24% Series - 150,000 - 15,000 363 1,086 103.06
------- -------------- ------- ------ ------
Total 396,660 605,160$39,666 $60,516 $2,574 $3,433
<FN>
(a) Noncallable.
</FN>
The annual dividend requirement for total cumulative preferred
stock was $2,075,000 for 1996 and $3,433,000 for 1995.
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 H - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In Thousands)
Series Rate % Maturity 1996 1995
- ----------------------------------------------------------------------------
General and Refunding Mortgage Bonds:
W(93-3) 5.12 February 2, 1996 $ 5,000
W(93-8) 5.06 February 5, 1996 5,000
Y(94-3) 8.10 December 22, 1997 $ 3,000 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
L 7.80 April 1, 2016 29,850
X variable March 1, 2018 79,250 79,250
R variable November 1, 2020 135,850 117,850
S variable November 1, 2020 50,600 20,750
T variable November 1, 2020 18,000
U 8.00 August 1, 2022 170,000 170,000
V variable October 1, 2022 106,150 106,150
Y(94-1) 8.53 September 20, 2024 5,000 5,000
Unamortized discounts (2,344) (2,910)
-------- --------
Total long-term debt 736,006 745,440
======== ========
Long-term debt due in one year (3,000) (10,000)
-------- --------
$733,006 $735,440
======== ========
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 $3 million in 1997, $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 2001.
The terms of $372 million of variable rate pollution control
revenue bonds collateralized by the Company's mortgage bonds at
December 31, 1996 require the Company to reacquire the bonds
under certain limited circumstances. The Company has
approximately $740 million of mortgage bonds outstanding. The
bond indenture restricts the sale of the trust property in its
entirety or substantially in its entirety. The proposed sale of
the Company's generating business would likely require that the
Company either amend the bond indenture or defease the bonds in
connection with the proposed sale. Any defeasance of bonds would
be by the deposit of cash representing principal and interest to
the maturity date or interest, principal, and general redemption
premium to an earlier redemption date. At December 31, 1996,
interest rates on the Company's variable rate bonds ranged from
2.30 percent to 4.80 percent.
At December 31, 1996, the Company's long-term debt had a carrying
value of $736,000,000 and had a fair value of approximately
$753,000,000. 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 I - 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, 1996 was 54 percent of total capitalization,
including long-term debt due in one year, and, accordingly, none
of the Company's retained earnings at December 31, 1996 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, 1996 were restricted
as to dividends on common stock. However, a portion of the
Company's retained earnings (less than $25 million) may be
restricted due to regulatory requirements related to
hydroelectric licensed projects.
Note J - Supplementary Income Statement Information
Advertising expenses, expenditures for research and development,
and rents were not material and there were no royalties paid in
1996, 1995, or 1994. Taxes, other than income taxes, charged to
operating expenses are set forth by classes as follows:
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Municipal property taxes $58,942 $49,807 $46,506
Federal and state payroll and other taxes 7,474 8,909 7,894
------- ------- -------
$66,416 $58,716 $54,400
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
$85,124,000, $106,411,000, and $103,961,000, including
capitalized construction costs of $19,412,000, $24,671,000, and
$22,396,000, for each of the years 1996, 1995, and 1994,
respectively.
New England Power Company
Operating Statistics (Unaudited)
Year Ended December 31, 1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Sources of Energy (Thousands of kWh)
Net generation - thermal 14,445,96911,547,85610,971,31911,621,03812,087,775
Net generation - conventional
hydro 1,818,670 1,257,533 1,352,600 1,253,925 1,212,155
Generation - pumped storage 514,400 519,931 525,653 548,358 530,796
Net generation - nuclear 1,280,119 1,812,468 1,767,959 1,696,677 1,592,340
Nuclear entitlements 2,015,104 1,278,598 2,535,534 2,196,998 2,214,976
Purchased energy from
nonaffiliates (B) 6,957,693 8,857,842 8,674,191 7,800,975 7,287,856
Energy for pumping (710,155) (716,279) (723,352) (750,784) (738,364)
--------------------------------------------------
Total generated and
purchased 26,321,80024,557,94925,103,90424,367,18724,187,534
Losses, company use, etc. (507,536) (690,626) (635,695) (548,228) (632,850)
--------------------------------------------------
Total sources of energy 25,814,26423,867,32324,468,20923,818,95923,554,684
Sales of Energy (Thousands of kWh)
Resale:
Affiliated companies 22,531,78822,338,30122,182,76121,858,49121,497,993
Less - generation by
affiliated Company (A) (329,883) (64,035) (5,781) (4,506) (83,753)
--------------------------------------------------
Net sales to affiliated
companies 22,201,90522,274,26622,176,98021,853,98521,414,240
Other utilities (B) 2,802,974 947,537 1,731,225 1,528,686 1,705,591
Municipals 795,974 633,970 551,866 426,525 415,659
--------------------------------------------------
Total sales for resale 25,800,85323,855,77324,460,07123,809,19623,535,490
Ultimate customers 13,411 11,550 8,138 9,763 19,194
--------------------------------------------------
Total sales of energy 25,814,26423,867,32324,468,20923,818,95923,554,684
Operating Revenue (In Thousands)
Revenue from electric sales
Resale:
Affiliated companies $1,480,460$1,498,848$1,448,503$1,459,619$1,450,831
Less - G and T
credits (A) (59,956) (43,532) (32,346) (26,001) (38,697)
--------------------------------------------------
Net sales to affiliated
companies 1,420,504 1,455,316 1,416,157 1,433,618 1,412,134
Other utilities (B) 95,249 41,193 56,306 52,695 55,156
Municipals 43,699 37,036 32,055 27,574 26,980
--------------------------------------------------
Total revenue from
sales for resale 1,559,452 1,533,545 1,504,518 1,513,887 1,494,270
Ultimate customers 1,065 945 606 752 1,399
---------------------------------------- ---------
Total revenue from
electric sales 1,560,517 1,534,490 1,505,124 1,514,639 1,495,669
Other operating revenue 39,792 36,049 35,633 34,375 35,206
--------------------------------------------------
Total operating revenue $1,600,309$1,570,539$1,540,757$1,549,014$1,530,875
Annual Maximum Demand
(kW - one hour peak) 4,091,000 4,381,000 4,385,000 4,081,000 3,964,000
<FN>
(A) The generation and transmission facilities of affiliates are operated as an
integrated part of the Company's power supply and the affiliates receive generation
and transmission (G and T) credits against their power bills for costs of facilities
so integrated.
(B) Includes transactions with the New England Power Pool.
</FN>
New England Power Company
Selected Financial Information
Year Ended December 31, (In Millions) 1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $ 918 $ 941 $ 942 $ 939 $ 907
Fuel cost recovery 642 594 563 576 589
Other 40 36 36 34 35
------ ------ ------ ------ ------
Total operating revenue $1,600 $1,571 $1,541 $1,549 $1,531
Net income $ 152 $ 151 $ 149 $ 141 $ 134
Total assets $2,648 $2,648 $2,613 $2,441 $2,387
Capitalization:
Common equity $ 906 $ 889 $ 877 $ 850 $ 825
Cumulative preferred stock 40 61 61 61 86
Long-term debt 733 735 695 667 666
------ ------ ------ ------ ------
Total capitalization $1,679 $1,685 $1,633 $1,578 $1,577
Preferred dividends declared $ 3 $ 3 $ 3 $ 5 $ 6
Common dividends declared $ 134 $ 135 $ 119 $ 111 $ 100
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
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
1995
Operating revenue $391,118 $378,177 $421,935 $379,309
Operating income $ 40,089 $ 33,454 $ 69,669 $ 42,201
Net income $ 30,982 $ 27,689 $ 61,684 $ 31,072
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, 1996 will be available on or about April 1, 1997,
without charge, upon written request to New England Power
Company, Shareholder Services Department, 25 Research Drive,
Westborough, Massachusetts 01582.