Annual Report 1997
The Narragansett Electric Company
A Subsidiary of
New England Electric System
[LOGO] Narragansett Electric
A NEES Company
The Narragansett Electric Company
280 Melrose Street
Providence, Rhode Island 02901
Directors
(As of March 18, 1998)
Richard W. Frost
Vice President of the Company and of certain affiliates
Cheryl A. LaFleur
Senior Vice President, General Counsel, and Secretary of New
England Electric System
Robert L. McCabe
Chairman of the Company and of certain affiliates
Lawrence J. Reilly
President and Chief Executive Officer of the Company and of
certain affiliates
Michael F. Ryan
Vice President of the Company
Richard P. Sergel
President and Chief Executive Officer of New England Electric
System
Ronald L. Thomas
Manager of Labor Relations of the Company and of certain
affiliates
Officers
(As of March 18, 1998)
Robert L. McCabe
Chairman of the Company and of certain affiliates
Lawrence J. Reilly
President and Chief Executive Officer of the Company and of
certain affiliates
Lydia M. Pastuszek
Senior Vice President of the Company and of certain affiliates
Christopher E. Root
Senior Vice President of the Company and of certain affiliates
Richard W. Frost
Vice President of the Company and of certain affiliates
Michael E. Jesanis
Vice President of the Company and Senior Vice President and
Chief Financial Officer of New England Electric System
Shannon M. Larson
Vice President of the Company
Richard Nadeau
Vice President of the Company
Michael F. Ryan
Vice President of the Company
Peter T. Zschokke*
Vice President of the Company
Ronald T. Gerwatowski
Secretary and General Counsel of the Company
John G. Cochrane
Treasurer of the Company and of certain affiliates, Vice
President of an affiliate, Assistant Treasurer of an affiliate
and Treasurer of New England Electric System
Robert King Wulff
Assistant Secretary of the Company and Clerk, Assistant Clerk or
Secretary of certain affiliates
Howard W. McDowell
Assistant Treasurer and Controller of the Company and of certain
affiliates, Treasurer or Controller of certain affiliates and
Assistant Secretary of an affiliate
* Effective April 1, 1998.
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, Fleet National Bank, Providence, Rhode Island
This report is not to be considered an offer to sell or buy or
solicitation of an offer to sell or buy any security.
The Narragansett Electric Company
The Narragansett Electric Company (the Company) is a wholly
owned subsidiary of New England Electric System (NEES) operating
in Rhode Island. The Company's business is the distribution of
electricity at retail. Electric service is provided to
approximately 330,000 customers in 27 cities and towns having a
population of approximately 725,000 (1990 Census). The Company's
service area, which includes urban, suburban, and rural areas,
covers approximately 80 percent of Rhode Island, and includes the
cities of Providence, East Providence, Cranston, and Warwick.
The diversified economy of the Company's service area produces
fabricated metal products, electrical and industrial machinery,
transportation equipment, textiles, silverware, and chemical
products. In addition, a broad range of professional, banking,
medical, and educational institutions is served. In 1996,
legislation was enacted in the state of Rhode Island which
provided certain customers with choice of power supplier as early
as July 1, 1997. The balance of customers gained such choice on
January 1, 1998.
The properties of the Company include an integrated system of
transmission and distribution lines and substations. In
addition, the Company owns a 10 percent share of the 489 megawatt
Manchester Street generating station. The entire output of this
plant is made available to New England Power Company (NEP), the
Company's generation and transmission affiliate, as part of the
integrated NEES system. Under an all-requirements contract with
NEP, the Company purchased its electric energy requirements from
NEP. This contract has been amended to terminate the all-
requirements provision of the contract and allow NEP to recover
its above-market generation commitments through a transition
access charge, which the Company will collect from its customers.
For further information, refer to the "Industry Restructuring"
section of Financial Review.
In August 1997, the Company and NEP agreed to sell their
nonnuclear generating business, which includes Manchester Street,
to an independent third party. See the "Divestiture of
Generating Business" section of Financial Review.
Report of Independent Accountants
The Narragansett Electric Company, Providence, Rhode Island:
We have audited the accompanying balance sheets of The
Narragansett Electric Company (the Company), a wholly owned
subsidiary of New England Electric System, as of December 31,
1997 and 1996 and the related statements of income, retained
earnings, and cash flows for each of the three years in the
period ended December 31, 1997. These financial statements are
the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of the Company as of December 31, 1997 and 1996, and the results
of its operations and its cash flows for each of the three years
in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
March 2, 1998
The Narragansett Electric Company
Financial Review
Industry Restructuring
Historically, electric utilities have provided their customers
bundled electric service within exclusive service territories.
As a result of a number of trends, including a disparity in
electric rates among regions of the country and new regulations
and legislation intended to foster competition, distribution
customers are being allowed to choose their power supplier, with
incumbent utilities required to deliver that electricity over
their transmission and distribution systems.
When customers are allowed to choose their power supplier,
utilities face the risk that market prices may not be sufficient
to recover the costs of the commitments (generation related)
incurred to supply customers under a regulated structure. The
amounts by which such costs exceed market prices are commonly
referred to as "stranded costs."
In August 1996, the state of Rhode Island enacted legislation
that allows customers in that state the opportunity to choose
their power supplier. Under the Rhode Island statute, state
accounts, certain new customers, and the largest manufacturing
customers were able to choose their power supplier beginning on
July 1, 1997. The balance of Rhode Island customers gained the
ability to choose their power supplier on January 1, 1998. The
statute also provides a mechanism for the recovery of stranded
costs resulting from the introduction of customer choice of power
supplier.
As part of the implementation of the statute, the Company and
its affiliate, New England Power Company (NEP), reached a
settlement agreement with the Rhode Island Public Utilities
Commission (RIPUC), the Rhode Island Division of Public Utilities
and Carriers, and other parties representing all of its
distribution customers (the Rhode Island Settlement). The Rhode
Island Settlement provides for the recovery of stranded costs.
In November 1997, the Federal Energy Regulatory Commission (FERC)
conditionally approved the Rhode Island Settlement, subject to a
compliance filing to clarify the impact of the settlement on
nonsettling parties.
The Rhode Island Settlement requires NEP to sell power to the
Company at specified prices for resale to distribution customers
who do not choose a power supplier ("standard offer generation
service"). The total rates for customers purchasing this interim
power service from the Company are approximately 7 percent below
the total rates that were in effect during 1997. Pursuant to the
Rhode Island statute, the total rate for customers who do not
choose a power supplier is capped through 2009 at a level equal
to the 1996 rate adjusted upward for 80 percent of inflation and
for other factors beyond the control of the Company. The statute
also provided for the Company to increase distribution rates by
approximately $11 million in January 1997 and another $7 million
in January 1998. The statute also provides that the Company may
request increased distribution rates which would take effect no
earlier than 1999.
In accordance with the Rhode Island Settlement, NEP's
wholesale contract with the Company has been amended effective
January 1, 1998. The Rhode Island statute provides that NEP's
stranded costs (the Company's share is 22 percent) will be
recovered from distribution customers through a transition access
charge, which will be collected by the Company. Under the Rhode
Island Settlement, the recovery of NEP's stranded costs is
divided into several categories. Unrecovered costs associated
with generating plants and regulatory assets would be recovered
over 12 years and would earn a return on equity of 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 kilowatthour (kWh) and would be reduced upon
completion of the sale of NEP's generating business, as described
below.
In addition to addressing customer choice and the recovery of
stranded costs, the Rhode Island Settlement also required the
NEES companies to divest their nonnuclear generating business.
In August 1997, the Company and NEP entered into an agreement to
sell substantially all of their nonnuclear generating business to
USGen New England, Inc. (USGen), an indirect wholly owned
subsidiary of PG&E Corporation (PG&E). See "Divestiture of
Generating Business" below. The net proceeds from the sale of
the nonnuclear generating business to USGen will be used to
reduce the transition access charge from 2.8 cents per kWh to
approximately 1.5 cents per kWh. In addition, the FERC accepted
the NEES companies' proposal in conjunction with their
divestiture filing that the recovery of the remaining above-
market nuclear generating plant investment and regulatory assets
be completed by the end of the year 2000.
Divestiture of Generating Business
As described above, in August 1997, the Company and NEP
(collectively, the Sellers) reached an agreement to sell their
nonnuclear generating business to USGen. The nonnuclear
generating business includes three fossil-fueled and 15
hydroelectric generating stations, totaling approximately 4,000
megawatts (MW) of capacity, as well as NEES' 100 percent interest
in Narragansett Energy Resources Company, a 20 percent general
partner in the Ocean State Power project, all of which has a book
value of $1.1 billion. USGen will pay the Sellers $1.59 billion
in cash, of which $225 million will be contingent upon the
introduction of customer choice of power supplier in
Massachusetts. Based on the enactment of the Massachusetts
statute, the NEES companies believe that the conditions for
payment of the full purchase price have been met. NEP will remit
to the Company a portion of the proceeds from the sale equal to
the Company's net book value of the Manchester Street plant.
USGen will also reimburse the NEES companies for $85 million of
costs associated with early retirement and special severance
programs for employees affected by industry restructuring. USGen
will assume responsibility for environmental conditions at the
Sellers' nonnuclear generating stations. USGen will also assume
the Sellers' obligations under long-term fuel and fuel
transportation contracts and certain collective bargaining
agreements.
In addition to the purchase of the nonnuclear generating
stations, USGen will purchase NEP's entitlement to approximately
1,100 MW of power procured under long-term contracts. NEP will
make a monthly fixed contribution towards the above-market cost
of the purchased power of between $12.5 million and $14.2 million
per month from closing through January 2008. USGen will be
responsible for the balance of the costs under the purchased
power contracts.
The sale is subject to approval by various state and federal
regulatory agencies. Several parties have objected to the sale
on various grounds, including allegations that following the
sale, USGen would be able to exercise unlawful levels of market
power. On February 25, 1998, the FERC issued an order that
rejected the market power allegations, approved the sale, and
conditionally approved most supporting filings. While the timing
of receipt of final regulatory approvals is uncertain, receipt of
all approvals is unlikely before mid-1998. Closing is contingent
upon all regulatory approvals being obtained by February 1999.
Upon completion of the divestiture of the nonnuclear
generating business, the Company's share of NEP's stranded costs
which will be recovered from the Company's customers through the
transition access charge will be reduced from approximately $1
billion to $0.5 billion.
Workforce Reduction
The NEES companies expect to implement substantial workforce
reductions beginning in 1998 as a result of industry
restructuring and the sale of the nonnuclear generating business.
The NEES companies are in the process of offering early
retirement programs to their union and non-union employees,
contingent upon the closing of the sale of the nonnuclear
generating business to USGen. In addition, the NEES companies
intend to offer enhanced severance benefits to affected
employees. As previously described, the costs of the early
retirement and severance programs for all NEES companies are
expected to be substantially recovered from the proceeds of the
sale of the nonnuclear generating business. Since the early
retirement program is contingent upon the divestiture, its cost
will not be accrued until that time.
Risk Factors
This annual report contains statements that may be considered
forward looking statements as defined under the securities laws.
Actual results may differ materially for the reasons discussed in
this Financial Review. While the Company believes that the
previously described settlement and legislation and the sale
agreement with USGen and other developments constitute
substantial progress in reducing the impacts associated with
industry restructuring, significant risks remain. These include,
but are not limited to: (i) the potential that ultimately the
Rhode Island Settlement will not be implemented in the manner
anticipated by the Company, (ii) the possibility of federal
legislation that would increase the risks above those contained
in the Rhode Island Settlement and statute, and (iii) the failure
to complete the sale of the nonnuclear generating business to
USGen. The major risk factors affecting the Company relate to
the possibility of adverse regulatory or judicial decisions or
legislation which limit the level of revenues the Company is
allowed to charge for its services or affect the costs the
Company incurs.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of certain
items of income and expense expected to be reflected in future
rates. At December 31, 1997, the Company had approximately $35
million in net regulatory assets in compliance with FAS 71.
The Company believes the Rhode Island Settlement and statute
will enable the Company to recover through rates its specific
costs of providing ongoing distribution services and stranded
costs billed to it by NEP. The Company believes these factors
will allow it to continue to apply FAS 71.
Despite the progress made to date, it is possible that future
regulatory rules or other circumstances could cause the
application of FAS 71 to be discontinued, which would result in a
noncash write-off of previously established regulatory assets
related to the affected operations.
Overview of Financial Results
Net income for 1997 increased $5 million compared with 1996.
The increase was primarily due a rate increase in base
distribution rates which became effective January 1, 1997, and an
increase in kWh deliveries.
Net income in 1996 decreased by $1 million. This decrease was
primarily due to (i) the completion of the amortization, in
accordance with a rate agreement, of the initial effect of
recording unbilled revenues, as well as (ii) a decrease in
allowance for funds used during construction (AFDC) primarily due
to the completion in the second half of 1995 of the Manchester
Street Station. These decreases were partially offset by the
effects of a rate increase that went into effect in late 1995.
Operating Revenue
The following table summarizes the changes in operating
revenue:
Increase (Decrease) in Operating Revenue
(In Millions) 1997 1996
---- ----
Sales and deliveries growth $ 2 $ 1
Fuel recovery 7 3
Rate changes 11 11
Unbilled revenues recognized
under rate agreements - (8)
Purchased power cost adjustment
(PPCA) mechanism (3) (4)
Other - 1
--- ---
$17 $ 4
=== ===
KWh deliveries increased by 1.3 percent in 1997 and less than
1 percent in 1996.
The Company's rates previously contained a fuel clause and a
PPCA provision. These mechanisms were designed to allow the
Company to pass on to its customers changes in purchased energy
costs. Rates in effect during the first five months of 1998
include a reconciliation mechanism that will allow the Company to
recover its purchased energy costs. Rates have not yet been
established for the period beyond May 1998.
For a discussion of fuel recovery, see the fuel costs
discussion in the "Operating Expenses" section.
The increase in revenues due to rate changes in 1997 reflects
an $11 million increase in base rates, approved by the RIPUC,
effective January 1, 1997, in accordance with the Utility
Restructuring Act of 1996. In 1996, the increase in revenues due
to rate changes represents a $12 million general rate increase
that went into effect in December 1995.
The Company has received approval from the RIPUC to recover
demand-side management (DSM) program expenditures in rates on a
current basis through 1997. These expenditures were $10 million,
$10 million, and $9 million in 1997, 1996 and 1995, respectively.
The Company has received approval from the RIPUC to recover its
1998 DSM program expenditures. Since 1990, the Company has been
allowed to earn incentives based upon the results of its DSM
programs. The Company recorded before-tax incentives of $0.3
million, $0.2 million, and $0.5 million in 1997, 1996 and 1995,
respectively.
Operating Expenses
The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
(In millions) 1997 1996
---- ----
Fuel for generation and electric energy:
Fuel costs $ 7 $ 3
Integrated facilities credit from NEP 5 3
Purchases and demand charges and other - (4)
Other operation and maintenance:
DSM - 1
Other 3 1
Depreciation (5) (4)
Taxes, other than income taxes 1 2
Income taxes 2 1
--- ---
$13 $ 3
=== ===
The increase in fuel costs is due to increased replacement
power fuel purchases by NEP due to the reduced generation from
partially owned nuclear units. These costs were passed on to the
Company through NEP's fuel clause. The Company, in turn, passed
these costs on to its customers. Effective January 1, 1998, the
Company terminated its power purchases under NEP's fuel clause.
The Company's rates in effect for sales on or after January 1,
1998 no longer include a fuel clause.
The entire output of the Company's generating capacity is made
available to NEP. The Company is compensated by NEP for its fuel
costs and other generation and transmission related costs. The
reduction in this compensation in 1997 and 1996, and the
associated reduction in depreciation expenses, reflects a
reduction in dismantlement costs associated with the previously
retired South Street generating facility.
The increase in other operation and maintenance expenses is
primarily due to increased customer accounts expenses,
transmission and distribution system related expenses and
increased general and administrative expense.
Allowance for Funds Used During Construction (AFDC)
The decrease in AFDC in 1996 is due to the completion of the
Manchester Street plant repowering project.
Hazardous Waste
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. The Company has been named as a
potentially responsible party by either federal or state
environmental regulatory agencies for three sites at which
hazardous waste is alleged to have been disposed. 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. The Company is aware of approximately five sites on
which gas was manufactured or manufactured gas was stored that
were owned either by the Company or by its predecessor companies.
A more detailed discussion of potential hazardous waste
liabilities is contained in Note D-2 of the Notes to the
Financial Statements. Predicting the potential costs to
investigate and remediate hazardous waste sites continues to be
difficult. The Company believes that hazardous waste liabilities
for all sites of which it is aware are not material to its
financial position.
Year 2000 Computer Issues
In the next two years, most large companies will face a
potentially serious information systems (computer) problem
because most software applications and operational programs
written in the past will not properly recognize calendar dates
beginning in the year 2000. This could force computers to either
shut down or lead to incorrect calculations. The NEES companies
began the process of identifying the changes required to their
computer programs and hardware during 1996. The necessary
modifications to the NEES companies' centralized financial,
customer, and operational information systems are expected to be
completed by the end of 1998. Noncentralized systems are also
being reviewed for Year 2000 problems. The NEES companies
believe total costs associated with making the necessary
modifications to all centralized and noncentralized systems will
be approximately $25 million, of which approximately $8 million
has been incurred as of December 31, 1997. Most of the remaining
costs are expected to be incurred prior to December 31, 1998.
The Company's share of the total costs is expected to be
approximately $5 million.
New Accounting Standards
In 1997, the Financial Accounting Standards Board released two
new Statements of Financial Accounting Standards (FAS), FAS 130
and FAS 131, both of which will go into effect in 1998. FAS 130,
Reporting Comprehensive Income, requires the reporting in
financial statements of a new additional item called
comprehensive income, which will incorporate amounts not
previously included in reported net income. FAS 131, Disclosure
about Segments of an Enterprise and Related Information, requires
the reporting in financial statements of certain new additional
information about operating segments of a business. The Company
does not believe these new accounting standards will have a
significant impact on its future reporting requirements.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $31 million in
1997. The funds necessary for utility plant expenditures during
1997 were primarily provided by net cash from operating
activities, after the payment of dividends. Cash expenditures
for utility plant for 1998 are estimated to be approximately $35
million. Internally generated funds and the Company's share of
proceeds from the divestiture of the nonnuclear generating
business are expected to fully meet capital expenditures in 1998.
In 1997, the Company retired $33 million of maturing long-term
debt and issued $10 million of first mortgage bonds bearing an
interest rate of 7.39 percent to finance capital expenditures.
The Company plans to issue $5 million of long-term debt in 1998
to retire maturing debt.
In 1997, the Company retired preferred stock with an aggregate
par value of $24 million. Total premiums paid of $1.7 million in
connection with the preferred stock retirement were charged to
retained earnings.
At December 31, 1997, the Company had $16 million of short-
term debt outstanding including $12 million of commercial paper
borrowings and $4 million of borrowings from affiliates. As of
December 31, 1997, the Company had lines of credit with banks
totaling $31 million. There were no borrowings under these lines
of credit at December 31, 1997.
The Narragansett Electric Company
Statements of Income
Year Ended December 31, (In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Operating revenue $520,038 $503,585 $499,113
-------- -------- --------
Operating expenses:
Fuel for generation and purchased electric
energy, (principally from New England
Power Company, an affiliate) 309,430 297,060 294,652
Other operation 74,375 71,625 71,814
Maintenance 12,447 13,009 11,174
Depreciation 22,957 27,899 31,533
Taxes, other than federal income taxes 39,366 38,530 36,627
Federal income taxes 14,247 11,951 10,888
-------- -------- --------
Total operating expenses 472,822 460,074 456,688
-------- -------- --------
Operating income 47,216 43,511 42,425
-------- -------- --------
Other income:
Allowance for equity funds used
during construction - - 106
Other income (expense), net (750) (732) (192)
-------- -------- --------
Operating and other income 46,466 42,779 42,339
-------- -------- --------
Interest:
Interest on long-term debt 16,179 17,205 16,627
Other interest 2,475 2,883 3,663
Allowance for borrowed funds used
during construction credit (120) (263) (1,861)
-------- -------- --------
Total interest 18,534 19,825 18,429
-------- -------- --------
Net income $ 27,932 $ 22,954 $ 23,910
======== ======== ========
Statements of Retained Earnings
Year Ended December 31, (In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Retained earnings at beginning of year $119,978 $108,227 $ 91,556
Net income 27,932 22,954 23,910
Dividends declared on cumulative
preferred stock (1,955) (2,143) (2,143)
Dividends declared on common stock,
$13.00, $8.00, and $4.50 per share,
respectively (14,722) (9,060) (5,096)
Premium on redemption of preferred stock (1,666) - -
-------- -------- --------
Retained earnings at end of year $129,567 $119,978 $108,227
======== ======== ========
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Balance Sheets
At December 31, (In thousands) 1997 1996
- -----------------------------------------------------------------------------
Assets
Utility plant, at original cost $760,923 $742,481
Less accumulated provisions for depreciation 198,551 187,690
-------- --------
562,372 554,791
Construction work in progress 5,739 5,392
-------- --------
Net utility plant 568,111 560,183
-------- --------
Current assets:
Cash 3,122 1,727
Accounts receivable:
From sales of electric energy 54,109 54,426
Other (including $1,112 and $1,253
from affiliates) 2,571 3,415
Less reserves for doubtful accounts 4,707 5,149
-------- --------
51,973 52,692
Unbilled revenues (Note A-3) 15,997 15,300
Fuel, materials, and supplies, at average cost 4,165 4,300
Prepaid and other current assets 14,202 15,919
-------- --------
Total current assets 89,459 89,938
-------- --------
Deferred charges and other assets (Note B) 55,285 56,881
-------- --------
$712,855 $707,002
======== ========
Capitalization and Liabilities
Capitalization:
Common stock, par value $50 per share, authorized
and outstanding 1,132,487 shares $ 56,624 $ 56,624
Premium on preferred stock 36 170
Other paid-in capital 105,500 80,000
Retained earnings 129,567 119,978
Unrealized gain on securities, net 112
-------- --------
Total common equity 291,839 256,772
Cumulative preferred stock,
par value $50 per share 12,800 36,500
Long-term debt 183,545 178,517
-------- --------
Total capitalization 488,184 471,789
-------- --------
Current liabilities:
Long-term debt due in one year 5,000 32,500
Short-term debt (including $4,425 and $5,300
to affiliates) 16,350 19,025
Accounts payable (including $50,751 and $40,425
to affiliates) 56,048 45,221
Accrued liabilities:
Taxes 4,314 3,877
Interest 4,810 5,677
Other accrued expenses (Note G) 21,519 11,949
Customer deposits 5,982 5,638
Dividends payable 3,587 2,801
-------- --------
Total current liabilities 117,610 126,688
-------- --------
Deferred federal income taxes 82,871 81,880
Unamortized investment tax credits 7,023 7,517
Other reserves and deferred credits 17,167 19,128
Commitments and contingencies (Note D)
-------- --------
$712,855 $707,002
======== ========
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Statements of Cash Flows
Year Ended December 31, (In thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
Operating activities:
Net income $ 27,932 $ 22,954 $ 23,910
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 22,957 27,899 31,533
Deferred federal income taxes and
investment tax credits, net (415) 4,177 3,009
Allowance for funds used during construction (120) (263) (1,967)
Amortization of unbilled revenues - - (8,209)
Decrease (increase) in accounts receivable,
net and unbilled revenues 22 12,082 (2,215)
Decrease (increase) in fuel, materials, and
supplies 135 1,945 (1,075)
Decrease (increase) in prepaid and other
current assets 1,717 (32) (1,894)
Increase (decrease) in accounts payable 10,827 (1,026) (9,892)
Increase (decrease) in other current
liabilities 9,484 (10,335) 9,320
Other, net 1,181 8,236 5,931
------- ------- -------
Net cash provided by
operating activities $73,720 $65,637 $48,451
------- ------- -------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(30,965) $(52,574) $(72,897)
Other investing activities (294) (181) (251)
-------- -------- --------
Net cash used in investing activities $(31,259) $(52,755) $(73,148)
-------- -------- --------
Financing activities:
Capital contributions from parent $ 25,500 $ - $ 20,000
Dividends paid on common stock (13,590) (7,361) (4,813)
Dividends paid on preferred stock (2,301) (2,143) (2,143)
Changes in short-term debt (2,675) (3,650) (7,125)
Long-term debt issues 10,000 2,000 38,000
Long-term debt retirements (32,500) (2,000) (16,000)
Preferred stock - retirements (23,834) - -
Premium on reacquisition of preferred stock (1,666) - -
Premium of reacquisition of long-term debt - - (1,936)
-------- -------- --------
Net cash provided by (used in)
financing activities $(41,066) $(13,154) $ 25,983
-------- -------- --------
Net increase (decrease) in cash and
cash equivalents $ 1,395 $ (272) $ 1,286
Cash and cash equivalents at
beginning of year 1,727 1,999 713
-------- -------- --------
Cash and cash equivalents at end of year $ 3,122 $ 1,727 $ 1,999
======== ======== ========
Supplementary Information:
Interest paid less amounts capitalized $ 17,911 $ 18,620 $ 17,050
-------- -------- --------
Federal income taxes paid $ 13,825 $ 8,873 $ 1,084
======== ======== ========
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Notes to Financial Statements
Note A - Significant Accounting Policies
1. Nature of Operations:
The Company is a wholly owned subsidiary of New England
Electric System (NEES) operating in Rhode Island. The Company's
business is the distribution of electricity at retail. Electric
service is provided to approximately 330,000 customers in 27
cities and towns having a population of approximately 725,000
(1990 Census). The Company's service area, which includes urban,
suburban, and rural areas, covers approximately 80 percent of
Rhode Island. The properties of the Company include an
integrated system of transmission and distribution lines and
substations. In addition, the Company owns a 10 percent share of
the 489 megawatt (MW) Manchester Street generating station. The
entire output of this plant is made available to New England
Power Company (NEP), the Company's generation and transmission
affiliate, as part of the integrated NEES system. Under an all-
requirements contract with NEP, the Company purchased its
electric energy requirements from NEP. This contract has been
amended to terminate the all-requirements provision of the
contract and allow NEP to recover its above-market generation
commitments through a transition access charge, which the Company
will collect from its customers. See Note B for a discussion of
industry restructuring and Note C for a discussion of the
Company's and NEP's planned divestiture of their nonnuclear
generating business.
2. System of Accounts:
The accounts of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by regulatory bodies
having jurisdiction.
In preparing the financial statements, management is required
to make estimates that affect the reported amounts of assets and
liabilities and disclosures of asset recovery and contingent
liabilities as of the date of the balance sheets and revenues and
expenses for the period. These estimates may differ from actual
amounts if future circumstances cause a change in the assumptions
used to calculate these estimates.
3. Electric Sales Revenue:
The Company accrues revenues for electricity delivered but not
yet billed (unbilled revenues). Included in income is $8 million
in 1995, which represents the amortization over 21 months of the
initial effect of recording unbilled revenues, in accordance with
a rate agreement. Accrued revenues are also recorded in
accordance with rate adjustment mechanisms.
4. 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
5.7 percent, 5.3 percent, and 6.2 percent in 1997, 1996, and
1995, respectively.
5. Depreciation:
Depreciation is provided annually on a straight-line basis.
The provision for depreciation as a percentage of weighted
average depreciable property was 3.2 percent, 4.0 percent, and
5.0 percent in 1997, 1996, and 1995, respectively. The change in
the depreciation rates is primarily due to the recognition
through depreciation expense of dismantlement costs for a retired
generating facility.
6. Cash:
The Company classifies short-term investments with a maturity
of 90 days or less at time of purchase as cash.
7. New Accounting Standards:
In 1997, the Financial Accounting Standards Board released two
new Statements of Financial Accounting Standards (FAS), FAS 130
and FAS 131, both of which will go into effect in 1998. FAS 130,
Reporting Comprehensive Income, requires the reporting in
financial statements of a new additional item called
comprehensive income, which will incorporate amounts not
previously included in reported net income. FAS 131, Disclosure
about Segments of an Enterprise and Related Information, requires
the reporting in financial statements of certain new additional
information about operating segments of a business. The Company
does not believe these new accounting standards will have a
significant impact on its future reporting requirements.
Note B - Industry Restructuring
Historically, electric utilities have provided their customers
bundled electric service within exclusive service territories.
As a result of a number of trends, including a disparity in
electric rates among regions of the country and new regulations
and legislation intended to foster competition, distribution
customers are being allowed to choose their power supplier, with
incumbent utilities required to deliver that electricity over
their transmission and distribution systems.
When customers are allowed to choose their power supplier,
utilities face the risk that market prices may not be sufficient
to recover the costs of the commitments (generation related)
incurred to supply customers under a regulated structure. The
amounts by which such costs exceed market prices are commonly
referred to as "stranded costs."
In August 1996, the state of Rhode Island enacted legislation
that allows customers in that state the opportunity to choose
their power supplier. Under the Rhode Island statute, state
accounts, certain new customers, and the largest manufacturing
customers were able to choose their power supplier beginning on
July 1, 1997. The balance of Rhode Island customers gained the
ability to choose their power supplier on January 1, 1998. The
statute also provides a mechanism for the recovery of stranded
costs resulting from the introduction of customer choice of power
supplier.
As part of the implementation of the statute, the Company and
NEP reached a settlement agreement with the Rhode Island Public
Utilities Commission (RIPUC), the Rhode Island Division of Public
Utilities and Carriers, and other parties representing all of its
distribution customers (the Rhode Island Settlement). The Rhode
Island Settlement provides for the recovery of stranded costs.
In November 1997, the Federal Energy Regulatory Commission (FERC)
conditionally approved the Rhode Island settlement, subject to a
compliance filing to clarify the impact of the settlement on
nonsettling parties.
The Rhode Island Settlement requires NEP to sell power to the
Company at specified prices for resale to distribution customers
who do not choose a power supplier ("standard offer generation
service"). The total rates for customers purchasing this interim
power service from the Company are approximately 7 percent below
the total rates that were in effect during 1997. Pursuant to the
Rhode Island statute, the total rate for customers who do not
choose a power supplier is capped through 2009 at a level equal
to the 1996 rate adjusted upward for 80 percent of inflation and
for other factors beyond the control of the Company. The statute
also provided for the Company to increase distribution rates by
approximately $11 million in January 1997 and another $7 million
in January 1998. The statute also provides that the Company may
request increased distribution rates which would take effect no
earlier than 1999.
In accordance with the Rhode Island Settlement, NEP's
wholesale contract with the Company has been amended effective
January 1, 1998. The Rhode Island statute provides that NEP's
stranded costs (the Company's share is 22 percent) will be
recovered from distribution customers through a transition access
charge, which will be collected by the Company. Under the Rhode
Island Settlement, the recovery of NEP's stranded costs is
divided into several categories. Unrecovered costs associated
with generating plants and regulatory assets would be recovered
over 12 years and would earn a return on equity of 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 kilowatthour (kWh) and would be reduced upon
completion of the sale of NEP's generating business, as described
below.
In addition to addressing customer choice and the recovery of
stranded costs, the Rhode Island Settlement also required the
NEES companies to divest their nonnuclear generating business.
In August 1997, the Company and NEP entered into an agreement to
sell substantially all of their nonnuclear generating business to
USGen New England, Inc. (USGen), an indirect wholly owned
subsidiary of PG&E Corporation (PG&E). See "Divestiture of
Generating Business" below. The net proceeds from the sale of
the nonnuclear generating business to USGen will be used to
reduce the transition access charge from 2.8 cents per kWh to
approximately 1.5 cents per kWh. In addition, the FERC accepted
the NEES companies' proposal in conjunction with their
divestiture filing that the recovery of the remaining
above-market nuclear generating plant investment and regulatory
assets be completed by the end of the year 2000.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of certain
items of income and expense expected to be reflected in future
rates. At December 31, 1997, the Company had approximately $35
million in net regulatory assets in compliance with FAS 71.
The Company believes the Rhode Island Settlement and statute
will enable the Company to recover through rates its specific
costs of providing ongoing distribution services and stranded
costs billed to it by NEP. The Company believes these factors
will allow it to continue to apply FAS 71.
Despite the progress made to date, it is possible that future
regulatory rules or other circumstances could cause the
application of FAS 71 to be discontinued, which would result in a
noncash write-off of previously established regulatory assets
related to the affected operations.
The components of regulatory assets are as follows:
At December 31, (In thousands) 1997 1996
- ----------------------------------------------------------------
Regulatory assets (liabilities) included
in current assets and liabilities:
Rate adjustment mechanisms
(see Note G) $(9,794) $(2,870)
------- -------
Regulatory assets included in deferred charges
and other reserves and deferred credits:
Deferred FAS No. 109 costs (see Note F) 31,291 30,439
Unamortized losses on reacquired debt 12,438 13,287
Storm fund (3,586) (4,691)
Deferred FAS No. 106 costs (see Note E-2) (795) 2,487
Other 6,020 5,656
------- -------
45,368 47,178
------- -------
$35,574 $44,308
======= =======
Note C - Divestiture of Generating Business
As described above, in August 1997, the Company and NEP
(collectively, the Sellers) reached an agreement to sell their
nonnuclear generating business to USGen. The nonnuclear
generating business includes three fossil-fueled and 15
hydroelectric generating stations, totaling approximately 4,000
MW of capacity, as well as NEES' 100 percent interest in
Narragansett Energy Resources Company, a 20 percent general
partner in the Ocean State Power project, all of which has a book
value of $1.1 billion. USGen will pay the Sellers $1.59 billion
in cash, of which $225 million will be contingent upon the
introduction of customer choice of power supplier in
Massachusetts. Based on the enactment of the Massachusetts
statute, the NEES companies believe that the conditions for
payment of the full purchase price have been met. NEP will remit
to the Company a portion of the proceeds from the sale equal to
the Company's net book value of the Manchester Street plant.
USGen will also reimburse the NEES companies for $85 million of
costs associated with early retirement and special severance
programs for employees affected by industry restructuring. USGen
will assume responsibility for environmental conditions at the
Sellers' nonnuclear generating stations. USGen will also assume
the Sellers' obligations under long-term fuel and fuel
transportation contracts and certain collective bargaining
agreements.
In addition to the purchase of the nonnuclear generating
stations, USGen will purchase NEP's entitlement to approximately
1,100 MW of power procured under long-term contracts. NEP will
make a monthly fixed contribution towards the above-market cost
of the purchased power of between $12.5 million and $14.2 million
per month from closing through January 2008. USGen will be
responsible for the balance of the costs under the purchased
power contracts.
The sale is subject to approval by various state and federal
regulatory agencies. Several parties have objected to the sale
on various grounds, including allegations that following the
sale, USGen would be able to exercise unlawful levels of market
power. On February 25, 1998, the FERC issued an order that
rejected the market power allegations, approved the sale, and
conditionally approved most supporting filings. While the timing
of receipt of final regulatory approvals is uncertain, receipt of
all approvals is unlikely before mid-1998. Closing is contingent
upon all regulatory approvals being obtained by February 1999.
Note D - Commitments and Contingencies
1. Plant Expenditures:
The Company's utility plant expenditures are estimated to be
approximately $35 million in 1998. At December 31, 1997,
substantial commitments had been made relative to future planned
expenditures.
2. 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.
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
three sites (two of which are located in Massachusetts) at which
hazardous waste is alleged to have been disposed. 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.
Gas was manufactured from coal in Rhode Island in the past.
The Company is aware of five sites on which gas was manufactured
or manufactured gas was stored that were owned either by the
Company or by its predecessor companies. It is not known to what
extent the Company would be held liable for hazardous wastes, if
any, left at these manufactured gas locations.
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. A
preliminary review by a consultant hired by the NEES companies of
the potential cost of investigating and, if necessary,
remediating Rhode Island manufactured gas sites resulted in costs
per site ranging from less than $1 million to $11 million. An
informal survey of other utilities conducted on behalf of NEES
and its subsidiaries indicated costs in a similar range. The
NEES companies have recovered amounts from certain insurers, and,
where appropriate, the Company intends to seek recovery from its
insurers and from other PRPs, but it is uncertain whether, and to
what extent, such efforts will be successful. The Company
believes that hazardous waste liabilities for all sites of which
it is aware are not material to its financial position.
In October 1996, the American Institute of Certified Public
Accountants issued new accounting rules for Environmental
Remediation Liabilities which became effective in 1997. These
new rules did not have a material effect on the Company's
financial position or results of operations.
Note E - Employee Benefits
1. Pension Plans:
The Company participates with other subsidiaries of NEES in
noncontributory, defined-benefit plans covering substantially all
employees of the Company. The plans provide pension benefits
based on the employee's compensation during the five years prior
to retirement. The Company's funding policy is to contribute
each year the net periodic pension cost for that year. However,
the contribution for any year will not be less than the minimum
contribution required by federal law or greater than the maximum
tax deductible amount.
The Company's net pension cost for 1997, 1996, and 1995
included the following components:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Service cost benefits earned
during the period $ 2,092 $ 2,007 $ 1,963
Plus (less):
Interest cost on projected
benefit obligation 9,027 8,954 9,327
Return on plan assets at
expected long-term rate (10,311) (9,787) (9,567)
Amortization (50) 165 67
-------- ------- -------
Net pension cost $ 758 $ 1,339 $ 1,790
======== ======= =======
Actual return on plan assets $ 23,999 $17,228 $25,192
======== ======= =======
Year ended December 31, 1998 1997 1996 1995
- ----------------------------------------------------------------
Assumptions used to
determine pension cost:
Discount rate 6.75% 7.25% 7.25% 8.25%
Average rate of increase in
future compensation levels 4.13% 4.13% 4.13% 4.63%
Expected long-term rate
of return on assets 8.50% 8.50% 8.50% 8.75%
The funded status of the plans cannot be presented separately
for the Company as the Company participates in the plans with
other NEES subsidiaries. The following table sets forth the
funded status of the NEES companies' plans at December 31:
Retirement Plans, (In millions) 1997 1996
- ----------------------------------------------------------------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $647 $640
Nonvested 18 19
---- ----
Total $665 $659
==== ====
Reconciliation of funded status
Actuarial present value of
projected benefit liability $757 $753
Unrecognized prior service costs (8) (9)
FAS No. 87 transition liability
not yet recognized (amortized) (1) (1)
Net gain (loss) not yet recognized (amortized) 61 40
---- ----
809 783
---- ----
Pension fund assets at fair value 834 812
FAS No. 87 transition asset not
yet recognized (amortized) (8) (10)
---- ----
826 802
---- ----
Accrued pension/(prepaid)
payments recorded on books $(17) $(19)
==== ====
The plans' funded status at December 31, 1997 and 1996 were
calculated using the assumed rates from 1998 and 1997,
respectively, and the 1983 Group Annuity Mortality table.
Plan assets are composed primarily of corporate equity, debt
securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions (PBOPs)
The Company provides health care and life insurance coverage
to eligible retired employees. Eligibility is based on certain
age and length of service requirements and in some cases retirees
must contribute to the cost of their coverage.
The Company's total cost of PBOPs for 1997, 1996, and 1995
included the following components:
Year ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Service cost - benefits earned
during the period $ 990 $ 1,030 $ 1,072
Plus (less):
Interest cost on accumulated
benefit obligation 4,843 5,034 6,006
Return on plan assets at
expected long-term rate (3,513) (2,803) (2,080)
Amortization 2,257 2,739 3,539
------- ------- -------
Net postretirement benefit cost $ 4,577 $ 6,000 $ 8,537
======= ======= =======
Actual return (loss) on
plan assets $ 8,195 $ 5,469 $ 6,161
======= ======= =======
Year ended December 31, 1998 1997 1996 1995
- ----------------------------------------------------------------
Assumptions used to determine
postretirement benefit cost:
Discount rate 6.75% 7.25% 7.25% 8.25%
Expected long-term rate of
return on assets 8.25% 8.25% 8.25% 8.50%
Health care cost rate
1995 to 1999 5.25% 8.00% 8.00% 8.50%
Health care cost rate
2000 to 2004 5.25% 6.25% 6.25% 8.50%
Health care cost rate
2005 and beyond 5.25% 5.25% 5.25% 6.25%
The following table sets forth the Company's benefits earned and
the plans' funded status:
At December 31, (In millions) 1997 1996
- ----------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 46 $ 51
Fully eligible active plan participants 6 5
Other active plan participants 17 19
---- ----
Total benefits earned 69 75
Unrecognized transition obligation (58) (62)
Net gain not yet recognized 33 22
---- ----
44 35
---- ----
Plan assets at fair value 50 42
---- ----
Prepaid postretirement benefit costs
recorded on books $ 6 $ 7
==== ====
The plans' funded status at December 31, 1997 and 1996 were
calculated using the assumed rates in effect for 1998 and 1997,
respectively.
The assumptions used in the health care cost trends have a
significant effect on the amounts reported. Increasing the
assumed rates by 1 percent in each year would increase the
accumulated postretirement benefit obligation as of December 31,
1997 by approximately $8 million and the net periodic cost for
1997 by approximately $0.8 million.
The Company funds the annual tax-deductible contributions.
Plan assets are invested in equity and debt securities and cash
equivalents.
Note F - Federal Income Taxes
The Company and other subsidiaries participate with NEES in
filing consolidated federal income tax returns. The Company's
income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by
the Internal Revenue Service through 1993.
Total federal income taxes consist of the following components:
Year Ended December 31, (In thousands) 1997 1996 1995
---- ---- ----
Income taxes charged (credited)
to operations:
Current income taxes $14,648 $ 7,499 $ 7,560
Deferred income taxes 93 4,950 3,831
Investment tax credits, net (494) (498) (503)
------- ------- -------
Total income taxes charged
to operations 14,247 11,951 10,888
------- ------- -------
Income taxes charged (credited)
to "Other income":
Current income taxes (464) (581) (348)
Deferred income taxes (14) (275) (319)
------- ------- -------
Total income taxes charged
(credited) to "Other income" (478) (856) (667)
------- ------- -------
Total federal income taxes $13,769 $11,095 $10,221
======= ======= =======
Investment tax credits have been deferred and are being
amortized over the estimated lives of the property giving rise to
the credits.
Consistent with rate-making policies of the RIPUC, the Company
has adopted comprehensive interperiod tax allocation
(normalization) for most temporary book/tax differences.
Total federal income taxes differ from the amounts computed by
applying the federal statutory tax rates to income before taxes.
The reasons for the differences are as follows:
Year Ended December 31, (In thousands) 1997 1996 1995
- ----------------------------------------------------------------
Computed tax at statutory rate $14,595 $11,917 $11,946
Increases (reductions) in tax resulting from:
Book versus tax depreciation
not normalized 741 778 529
Costs associated with utility
plant retirements deducted
for tax purposes (1,046) (1,341) (1,768)
Allowance for equity funds used
during construction - - (37)
Amortization of investment
tax credits (494) (498) (503)
All other differences (27) 239 54
------- ------- -------
Total federal income taxes $13,769 $11,095 $10,221
======= ======= =======
The following table identifies the major components of total
deferred income taxes:
At December 31, (In millions) 1997 1996
---- ----
Deferred tax asset:
Plant related $ 2 $ 2
Investment tax credits 3 3
All other 13 13
----- -----
18 18
----- -----
Deferred tax liability:
Plant related (72) (67)
All other (29) (33)
----- -----
(101) (100)
----- -----
Net deferred tax liability $ (83) $ (82)
===== =====
Note G - Short-term Borrowings and Other Accrued Expenses
At December 31, 1997, the Company had $16 million of
short-term debt outstanding including $12 million in commercial
paper borrowings and $4 million of borrowings from affiliates.
NEES and certain subsidiaries, including the Company, with
regulatory approval, operate a money pool to more effectively
utilize cash resources and to reduce outside short-term
borrowings. Short-term borrowing needs are met first by
available funds of the money pool participants. Borrowing
companies pay interest at a rate designed to approximate the cost
of outside short-term borrowings. Companies which invest in the
pool share the interest earned on a basis proportionate to their
average monthly investment in the money pool. Funds may be
withdrawn from or repaid to the pool at any time without prior
notice.
At December 31, 1997, the Company had lines of credit with
banks totaling $31 million. There were no borrowings under these
lines of credit at December 31, 1997. Fees are paid in lieu of
compensating balances on most lines of credit.
The weighted average rate on outstanding short-term borrowings
was 5.7 percent at December 31, 1997. The fair value of the
Company's short-term debt equals carrying value.
The components of other accrued expenses are as follows:
At December 31, (In thousands) 1997 1996
- ----------------------------------------------------------------
Rate adjustment mechanisms $12,970 $ 4,632
Accrued wages and benefits 8,050 7,259
Other 499 58
------- -------
$21,519 $11,949
======= =======
Note H - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1997
and 1996 is as follows (in thousands of dollars except for share
data):
Shares
Authorized Dividends Call
and Outstanding Amount Declared Price
- ------------------------------------------------------------------------------
1997 1996 1997 1996 1997 1996
- ------------------------------------------------------------------------------
$50 Par value
4.50% Series 49,730 180,000 $ 2,487 $ 9,000 $ 365 $ 405 $55.000
4.64% Series 61,217 150,000 3,061 7,500 320 348 $52.125
6.95% Series 145,050 400,000 7,252 20,000 1,270 1,390 (a)
- ------------------------------------------------------------------------------
Total 255,997 730,000 $12,800 $36,500 $1,955 $2,143
- ------------------------------------------------------------------------------
<FN>
(a) Callable on or after August 1, 2003 at $51.74.
</FN>
The annual dividend requirement for total cumulative
preferred stock was $758,000 for 1997 and $2,143,000 for 1996.
In 1997, the Company retired preferred stock with an
aggregate par value of $24 million. Total premiums of $1.7
million in connection with the preferred stock retirement were
charged to retained earnings.
Note I - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In thousands)
Series Rate % Maturity 1997 1996
- ----------------------------------------------------------------
First Mortgage Bonds:
U(92-1) 7.230 June 3, 1997 $10,000
U(92-2) 7.210 June 3, 1997 5,000
U(92-3) 7.000 June 16, 1997 10,000
U(92-7) 5.700 September 16, 1997 7,500
V(95-1) 7.810 February 16, 1998 $ 5,000 5,000
V(94-2) 6.960 May 3, 1999 2,000 2,000
V(94-3) 6.910 May 4, 1999 1,000 1,000
U(92-6) 6.630 August 12, 1999 5,000 5,000
U(92-5) 6.980 July 17, 2000 5,000 5,000
U(92-8) 6.340 September 18, 2000 10,000 10,000
U(92-4) 7.830 June 17, 2002 15,000 15,000
U(93-1) 7.080 January 13, 2003 7,500 7,500
U(93-2) 6.560 April 15, 2003 5,000 5,000
U(93-4) 6.350 July 1, 2003 5,000 5,000
V(94-4) 7.420 June 15, 2004 5,000 5,000
V(94-6) 8.330 November 8, 2004 10,000 10,000
U(93-3) 6.650 June 30, 2008 5,000 5,000
S 9.125 May 1, 2021 22,200 22,200
T 8.875 August 1, 2021 22,000 22,000
U(93-5) 7.050 September 1, 2023 5,000 5,000
U(94-1) 7.050 February 2, 2024 5,000 5,000
V(94-1) 8.080 May 2, 2024 5,000 5,000
V(94-5) 8.160 August 9, 2024 5,000 5,000
V(95-2) 7.750 June 2, 2025 10,000 10,000
V(95-3) 7.500 October 10, 2025 7,000 7,000
W(95-1) 7.300 November 13, 2025 16,000 16,000
W(96-1) 7.240 January 19, 2026 2,000 2,000
W(97-1) 7.390 September 30, 2027 3,000
W(97-2) 7.390 October 1, 2027 7,000
Unamortized discounts and premiums (1,155) (1,183)
-------- --------
Total long-term debt $188,545 $211,017
======== ========
Long-term debt due in one year 5,000 32,500
-------- --------
$183,545 $178,517
======== ========
Substantially all of the properties and franchises of the
Company are subject to the lien of mortgage indentures under
which the first mortgage bonds have been issued.
The Company will make cash payments of $5,000,000 in 1998,
$8,000,000 in 1999, $15,000,000 in 2000, and $15,000,000 in 2002
to retire maturing mortgage bonds. There are no cash payments
required in 2001.
At December 31, 1997, the Company's long-term debt had a
carrying value of approximately $190,000,000 and had a fair value
of approximately $201,000,000. The fair market value of the
Company's long-term debt was estimated based on the quoted prices
for similar issues or on the current rates offered to the Company
for debt of the same remaining maturity.
Note J - Restrictions on Retained Earnings Available for
Dividends on Common Stock
As long as any preferred stock is outstanding, certain
restrictions on payment of dividends on common stock would come
into effect if the "junior stock equity" was, or by reason of
payment of such dividends became, less than 25 percent of "Total
capitalization." However, the junior stock equity at December 31,
1997 was 59 percent of total capitalization and, accordingly,
none of the Company's retained earnings at December 31, 1997 were
restricted as to dividends on common stock under the foregoing
provisions.
Note K - Regulatory Matters
A 1986 Rhode Island Supreme Court decision held that the
RIPUC's rate-making powers include the authority to order refunds
of amounts earned in excess of an allowed return. As a result,
the RIPUC monitors the Company's earnings on a regular basis.
Note L - Supplementary Income Statement Information
Advertising expenses, expenditures for research and
development, and rents were not material and there were no
royalties paid in 1997, 1996, or 1995. Taxes, other than federal
income taxes, charged to operating expenses are set forth by
class as follows
Year Ended December 31,
(In thousands) 1997 1996 1995
---- ---- ----
Municipal property taxes $18,061 $16,546 $15,172
State gross earnings tax 18,676 18,764 18,617
Federal and state payroll
and other taxes 2,629 3,220 2,838
------- ------- -------
$39,366 $38,530 $36,627
======= ======= =======
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 $23,341,012, $27,336,438, and $29,094,719, including
capitalized construction costs of $1,946,000, $6,426,000, and
$6,268,000 for each of the years 1997, 1996, and 1995,
respectively.
The Narragansett Electric Company
Selected Financial Information
Year Ended December 31,
(In millions) 1997 1996 1995 1994 1993
- ------------------------------------------------------------------------------
Operating revenue:
Electric sales
(excluding fuel cost recovery) $369 $361 $361 $356 $351
Fuel cost recovery 142 134 131 120 127
Other 9 9 7 6 5
- ------------------------------------------------------------------------------
Total operating revenue $520 $504 $499 $482 $483
Net income $ 28 $ 23 $ 24 $ 15 $ 14
Total assets $713 $707 $700 $647 $556
Capitalization:
Common equity $292 $257 $245 $208 $183
Cumulative preferred stock 13 36 36 37 37
Long-term debt 183 179 211 189 156
- ------------------------------------------------------------------------------
Total capitalization $488 $472 $492 $434 $376
Preferred dividends declared $ 2 $ 2 $ 2 $ 2 $ 2
Common dividends declared $ 15 $ 9 $ 5 $ 3 $ 5
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In thousands) Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
1997
Operating revenue $131,466 $119,894 $141,980 $126,698
Operating income $ 13,403 $ 9,819 $ 14,238 $ 9,756
Net income $ 7,693 $ 5,085 $ 9,862 $ 5,292
1996
Operating revenue $127,285 $116,470 $140,481 $119,349
Operating income $ 12,286 $ 8,245 $ 13,419 $ 9,561
Net income $ 6,290 $ 3,117 $ 8,169 $ 5,378
Per share data is not relevant because the Company's common
stock is wholly owned by New England Electric System.
A copy of The Narragansett Electric Company's Annual Report on
Form 10-K to the Securities and Exchange Commission for the year
ended December 31, 1997 will be available on or about April 1,
1998, without charge, upon written request to The Narragansett
Electric Company, Shareholder Services Department, 280 Melrose
Street, Providence, Rhode Island 02901.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24
<SEQUENCE>33
<DESCRIPTION>NARRA POWER OF ATTORNEY
<TEXT>
EXHIBIT (24)
POWER OF ATTORNEY
-----------------
Each of the undersigned directors of The Narragansett Electric
Company (the "Company"), individually as a director of the Company, hereby
constitutes and appoints John G. Cochrane, Robert K. Wulff, and Geraldine
M. Zipser, individually, as attorney-in-fact to execute on behalf of the
undersigned the Company's annual report on Form 10-K for the year ended
December 31, 1997, to be filed with the Securities and Exchange
Commission, and to execute any appropriate amendment or amendments
thereto as may be required by law.
Dated this 18th day of March, 1998.
s/Michael F. Ryan
_________________________ _________________________
Richard W. Frost Michael F. Ryan
s/Cheryl A. LaFleur s/Richard P. Sergel
_________________________ _________________________
Cheryl A. LaFleur Richard P. Sergel
s/Robert L. McCabe s/Ronald L. Thomas
_________________________ _________________________
Robert L. McCabe Ronald L. Thomas
s/Lawrence J. Reilly
_________________________
Lawrence J. Reilly