Annual Report 1996
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 January 1, 1997)
Joan T. Bok
Chairman of the Board of New England Electric System
Stephen A. Cardi
Treasurer, Cardi Corporation (Construction), Warwick, Rhode
Island
Frances H. Gammell
Senior Vice President, Treasurer, and Secretary, Original
Bradford Soap Works, Inc., West Warwick, Rhode Island
Joseph J. Kirby
Chairman and Chief Executive Officer, Washington Trust Bancorp,
Inc., Westerly, Rhode Island
Robert L. McCabe
President and Chief Executive Officer of the Company
John W. Rowe
President and Chief Executive Officer of New England Electric
System
Richard P. Sergel
Chairman of the Company and Senior Vice President of New England
Electric System
William E. Trueheart
Visiting Scholar of Graduate School of Education, Harvard
University, Cambridge, Massachusetts
John A. Wilson, Jr.
Consultant to and former President of Wanskuck Company (Cable
reel manufacturer), Providence, Rhode Island and Consultant to
Hinkley, Allen, Tobin and Silverstein
Officers
(As of January 1, 1997)
Richard P. Sergel
Chairman of the Company and Senior Vice President of New England
Electric System
Robert L. McCabe
President and Chief Executive Officer
William Watkins, Jr.
Executive Vice President
Richard W. Frost
Vice President
Alfred D. Houston
Vice President and Treasurer of the Company and Executive Vice
President and Chief Financial Officer of New England Electric
System
Shannon M. Larson
Vice President
Richard Nadeau
Vice President
Michael F. Ryan
Vice President
Thomas G. Robinson
Secretary of the Company and General Counsel of an affiliate
John G. Cochrane
Assistant Treasurer of the Company and of certain affiliates and
Vice President of an affiliate
Craig L. Eaton
Assistant Secretary
Howard W. McDowell
Controller of the Company and of certain affiliates and Treasurer
of certain affiliates
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 is a wholly-owned subsidiary
of New England Electric System (NEES) operating in Rhode Island.
The Company's business is the distribution and sale 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, jewelry, silverware, and
chemical products. In addition, a broad range of professional,
banking, medical, and educational institutions is served. Rhode
Island legislation passed in 1996 allows utility customers in
Rhode Island to choose their power supplier. This customer
choice is being phased in over 12 months beginning July 1997.
Distribution companies, including the Company, would be required
to deliver the power to their customers (see "Industry
Restructuring" section of Financial Review).
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 wholesale generating affiliate, as part of the
integrated NEES system. Under an all-requirements contract with
NEP, the Company purchases its electric energy requirements from
NEP. The contract provides for the integration of the Company's
generating and transmission facilities with NEP's facilities in
order to achieve maximum economy and reliability. The contract
also provides for the application of credits against the
Company's power bills from NEP for costs associated with the
Company's facilities so integrated. NEP and the Company agreed
to the divestiture of their fossil and hydroelectric generating
facilities as part of industry restructuring. The Company will
be compensated by NEP for any difference between the sale price
of the Company's share of the Manchester Street Station and its
net book value. In addition, the Company's all-requirements
contract with NEP has been amended to allow for early termination
of all-requirements service. The amendment provides that upon
early termination, the Company's share of the cost of NEP's
above-market generation commitments will be recovered through a
contract termination charge. This charge will, in turn, be paid
by customers that use the Company's distribution facilities.
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,
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
The Narragansett Electric Company
Financial Review
Industry Restructuring
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 Rhode Island, 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 currently purchases electricity on behalf of its
customers under a wholesale all-requirements contract with the
Company's wholesale generating affiliate, New England Power
Company (NEP).
As described below, comprehensive legislation was enacted in
Rhode Island which, when all regulatory approvals are in place,
would allow recovery of NEP's above-market commitments to retail
customers in Rhode Island, which make up 22 percent of NEP's all-
requirements sales.
In August 1996, the state of Rhode Island enacted pioneering
legislation that allows customers in that 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 10 percent of the Company's kilowatt-hour (kWh)
sales. The balance of Rhode Island customers will be able to
choose their supplier in 1998, with an additional 10 percent of
customers load having choice on January 1 and the remainder on
July 1. All Rhode Island customers would have choice of supplier
beginning at an earlier date if retail access becomes available
to 40 percent or more of the kWh sales in New England by that
date.
The statute calls for NEP's contract with the Company to be
amended to permit a gradual, early termination of
all-requirements service. The amendment provides that, in return,
the Company's 22 percent share of the cost of NEP's above-market
generation commitments (estimated at approximately $1 billion on
a present-value basis) would be recovered through a contract
termination charge. This charge will, in turn, be paid by
customers that use the Company's distribution facilities. Those
commitments consist of (i) generating plant commitments, (ii)
regulatory assets, (iii) the above-market component of purchased
power contracts, and (iv) the operating cost of nuclear plants
which cannot be avoided by shutting down the plants, including
nuclear decommissioning.
Sunk costs associated with generating plants and regulatory
assets would be recovered over a period of 12.5 years. The
above-market component of purchased power contracts and the
nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond
12 years. The transition access charge would be reduced to
reflect the net proceeds from the sale of the New England
Electric System (NEES) companies' generating assets. (See
"Divestiture of Generation Business" section below.) The initial
transition access charge, before the application of those
proceeds, would be set at 2.8 cents per kWh through December 31,
2000, and is expected to decline thereafter.
The statute also establishes performance-based rates for
distribution utilities, such as the Company. Under the statute,
the Company increased distribution rates by approximately $11
million in 1997, and is entitled to a similar increase in 1998.
In addition, in 1997, the Company's return on equity from
distribution operations will be subject to a floor of 6 percent
and a ceiling of 11 percent. Earnings over the ceiling will be
shared equally between customers and shareholders up to a maximum
return on equity from distribution operations of 12.5 percent.
This sharing results in an effective cap on shareholder's return
on equity of 11.75 percent. To the extent that earnings fall
below the floor, the Company will be authorized to surcharge
customers for the shortfall.
NEP and the Company filed with the Federal Energy Regulatory
Commission (FERC) an amendment to their all-requirements contract
in order to implement the statute. The FERC has set down the
amendment for hearing. The Company has indicated it is willing
to make certain changes to its plan in Rhode Island to parallel
provisions in a similar Massachusetts settlement. The
Massachusetts settlement was approved by the Massachusetts
Department of Public Utilities on February 26, 1997. The
settlement provides for retail choice for Massachusetts customers
in 1998 and the recovery of NEP's above-market commitments to
serve those customers. Implementation of other aspects of the
statute is subject to approval of the Rhode Island Public
Utilities Commission (RIPUC).
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
NEP and the Company agreed to the divestiture of their fossil
and hydroelectric generating facilities as part of industry
restructuring. Such divestiture must be accomplished within six
months of the later of the commencement of retail choice in
Massachusetts, currently scheduled for January 1, 1988, or the
receipt of all necessary regulatory approvals. The Company will
be compensated by NEP for any difference between the sale price
of the Company's share of the Manchester Street Station and its
net book value. Proposals are being solicited for the
acquisition of the 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. The
Rhode Island statute also requires the Company to transfer its
transmission assets to NEP at net book value.
Risk Factors
The major risk factors affecting the Company relate to the
possibility of adverse regulatory or judicial decisions or
legislation which limits the level of revenues the Company is
allowed to charge for its services. While substantial progress
has been made in resolving the uncertainty regarding recovery by
the Company of stranded costs billed to it by NEP, significant
risks remain. These risks are primarily attributable to the
potential that ultimately the statute, referred to above, will
not be implemented in the manner anticipated by the Company
and/or the possibility of other state or federal legislation
which would increase the risks to the Company above those
contained in the statute.
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 $44 million in net regulatory assets in compliance
with FAS 71. The Company believes that the continuing rate-
making policies and practices of the RIPUC and the terms of the
Rhode Island statute will enable the Company to recover both its
specific costs of providing ongoing distribution services and
stranded costs billed to it by NEP. The Company believes that
these factors will allow it to continue to apply FAS 71. 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 would be required.
Overview
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.
Net income for 1995 increased by $9 million compared with
1994. This increase reflects the 1995 commencement of the
recovery of the Company's investment in the Manchester Street
Station, and related transmission facilities that went into
service in 1994. The increase in earnings in 1995 also reflects
the recognition of unbilled revenues over a 21-month period that
ended December 31, 1995. These increases were partially offset
by increased depreciation expense and increased interest expense.
Operating Revenue
The following table summarizes the changes in operating
revenue:
Increase (Decrease) in Operating Revenue
(In Millions) 1996 1995
---- ----
Sales growth $ 1 $ 2
Fuel recovery 3 11
Rate changes 11 1
Unbilled revenues recognized
under rate agreements (8) 2
Purchased power cost adjustment
(PPCA) mechanism (4) 1
Demand-side management (DSM) recovery - (1)
Other 1 1
--- ---
$ 4 $17
=== ===
KWh sales to ultimate customers increased less than 1 percent
in both 1996 and 1995.
The Company's rates contain a fuel clause and a PPCA
provision. These mechanisms are designed to allow the Company to
pass on to its customers changes in purchased energy costs from
NEP.
Rate changes primarily represent a $12 million general rate
increase that went into effect in December 1995. Also, in 1994,
the RIPUC approved a rate agreement for the Company that provided
for the recognition, for accounting purposes, of $14 million of
unbilled revenues over a 21-month period which ended in December
1995.
The Company has received approval from the RIPUC to recover
DSM program expenditures in rates on a current basis. These
expenditures were $10 million, $9 million, and $10 million in
1996, 1995, and 1994, respectively. Since 1990, the Company has
been allowed to earn incentives based on the results of its DSM
programs. The Company recorded before-tax incentives of $0.2
million, $0.5 million, and $0.6 million in 1996, 1995, and 1994,
respectively.
Operating Expenses
The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
(In Millions) 1996 1995
---- ----
Fuel for generation and electric energy:
Fuel costs $ 3 $11
Integrated facilities credit from NEP 3 (18)
Purchases and demand charges and other (4) -
Other operation and maintenance
DSM 1 -
Other 1 (2)
Depreciation (4) 7
Taxes, other than income taxes 2 1
Income taxes 1 6
--- ---
$ 3 $ 5
=== ===
The entire output of the Company's 10 percent share of the
Manchester Street generating station is made available to NEP,
and the Company receives a credit on its purchased power bill
from NEP for its fuel and other generation and transmission
costs. The decrease in these credits in 1996 and a portion of
the increase in 1995 reflects fluctuations in the level of
reimbursable costs being incurred in the dismantlement of the
Company's previously retired South Street generating station. In
addition, these credits increased in both 1996 and 1995 in
connection with the completion of the Manchester Street Station
in 1995. Both of these factors are also reflected in the changes
in depreciation expense in 1996 and 1995.
The reduction in other operation and maintenance expenses in
1995 reflects decreased distribution system related expenses,
partially offset by increased postretirement benefit expenses.
The increases in taxes other than income taxes in both 1996
and 1995 is due primarily to increased municipal property taxes.
The 1996 increase is primarily attributable to the Manchester
Street Station.
Allowance for Funds Used During Construction
AFDC decreased in both 1996 and 1995. The 1996 decrease is
due to the completion in 1995 of the Manchester Street Station,
and the 1995 decrease is due to the completion in 1994, of
transmission facilities related to the Manchester Street Station.
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
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.
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 Rhode Island and in contexts other
than condemnation cases.
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $53 million in
1996. The funds necessary for utility plant expenditures during
1996 were primarily provided by net cash from operating
activities, after the payment of dividends. Cash expenditures
for utility plant for 1997 are estimated to be approximately $45
million. Internally generated funds are estimated to provide
approximately 70 percent of capital expenditure requirements in
1997. Cash expenditures for utility plant are also expected to
be funded through the issuance of long-term debt.
In 1996, the Company issued $2 million of first mortgage bonds
bearing an interest rate of 7.24 percent to refinance higher rate
bonds. In November 1995, the Company retired $16 million of
first mortgage bonds prior to maturity and incurred premiums of
$1.9 million.
At December 31, 1996, the Company had $19 million of
short-term debt outstanding including $14 million of commercial
paper borrowings and $5 million of borrowings from affiliates.
As of December 31, 1996, the Company had lines of credit with
banks totaling $41 million. There were no borrowings under these
lines of credit at December 31, 1996.
The Narragansett Electric Company
Statements of Income
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Operating revenue $503,585 $499,113 $481,669
-------- -------- --------
Operating expenses:
Fuel for generation and purchased electric
energy, (principally from New England
Power Company, an affiliate) 297,060 294,652 300,888
Other operation 71,625 71,814 72,872
Maintenance 13,009 11,174 12,281
Depreciation 27,899 31,533 24,813
Taxes, other than federal income taxes 38,530 36,627 35,818
Federal income taxes 11,951 10,888 4,883
-------- -------- --------
Total operating expenses 460,074 456,688 451,555
-------- -------- --------
Operating income 43,511 42,425 30,114
-------- -------- --------
Other income:
Allowance for equity funds used
during construction 106 1,028
Other income (expense), net (732) (192) (856)
-------- -------- --------
Operating and other income 42,779 42,339 30,286
-------- -------- --------
Interest:
Interest on long-term debt 17,205 16,627 14,334
Other interest 2,883 3,663 2,897
Allowance for borrowed funds used during
construction credit (263) (1,861) (1,534)
-------- -------- --------
Total interest 19,825 18,429 15,697
-------- -------- --------
Net income $22,954 $23,910 $14,589
======== ======== ========
Statements of Retained Earnings
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Retained earnings at beginning of year $108,227 $91,556 $81,659
Net income 22,954 23,910 14,589
Dividends declared on cumulative
preferred stock (2,143) (2,143) (2,143)
Dividends declared on common stock,
$8.00, $4.50, and $2.25 per share,
respectively (9,060) (5,096) (2,549)
-------- -------- --------
Retained earnings at end of year $119,978 $108,227 $91,556
======== ======== ========
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Balance Sheets
At December 31, (In Thousands) 1996 1995
---- ----
Assets
Utility plant, at original cost $742,481 $699,906
Less accumulated provisions for depreciation 187,690 173,391
-------- --------
554,791 526,515
Construction work in progress 5,392 8,733
-------- --------
Net utility plant 560,183 535,248
-------- --------
Current assets:
Cash 1,727 1,999
Accounts receivable:
From sales of electric energy 54,426 59,760
Other (including $1,253 and $1,464 from
affiliates) 3,415 9,330
Less reserves for doubtful accounts 5,149 5,516
-------- --------
52,692 63,574
Unbilled revenues (Note A-3) 15,300 16,500
Fuel, materials, and supplies, at average cost 4,300 6,245
Prepaid and other current assets 15,919 15,887
-------- --------
Total current assets 89,938 104,205
-------- --------
Deferred charges and other assets (Note B) 56,881 60,168
-------- --------
$707,002 $699,621
======== ========
Capitalization and Liabilities
Capitalization:
Common stock, par value $50 per share,
authorized and outstanding 1,132,487 shares $56,624 $56,624
Premiums on preferred stocks 170 170
Other paid-in capital 80,000 80,000
Retained earnings 119,978 108,227
-------- --------
Total common equity 256,772 245,021
Cumulative preferred stock, par value
$50 per share 36,500 36,500
Long-term debt 178,517 210,892
-------- --------
Total capitalization 471,789 492,413
-------- --------
Current liabilities:
Long-term debt due in one year 32,500
Short-term debt (including $5,300 and $1,000
to affiliates) 19,025 22,675
Accounts payable (including $40,425 and
$38,510 to affiliates) 45,221 46,247
Accrued liabilities:
Taxes 3,877 6,380
Interest 5,677 5,847
Other accrued expenses (Note F) 11,949 19,558
Customer deposits 5,638 5,691
Dividends payable 2,801 1,102
-------- --------
Total current liabilities 126,688 107,500
-------- --------
Deferred federal income taxes 81,880 76,017
Unamortized investment tax credits 7,517 8,016
Other reserves and deferred credits 19,128 15,675
Commitments and contingencies (Note D)
-------- --------
$707,002 $699,621
======== ========
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) 1996 1995 1994
---- ---- ----
Operating activities:
Net income $22,954 $23,910 $14,589
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation 27,899 31,533 24,813
Deferred federal income taxes and
investment tax credits, net 4,177 3,009 3,422
Allowance for funds used during
construction (263) (1,967) (2,562)
Amortization of unbilled revenues (8,209) (6,158)
Decrease (increase) in accounts receivable,
net and unbilled revenues 12,082 (2,215) (14,163)
Decrease (increase) in fuel, materials,
and supplies 1,945 (1,075) (598)
Decrease (increase) in prepaid and
other current assets (32) (1,894) (2,478)
Increase (decrease) in accounts payable (1,026) (9,892) 5,134
Increase (decrease) in other
current liabilities (10,335) 9,320 12,312
Other, net 8,236 5,931 5,877
--------- --------- ---------
Net cash provided by operating
activities $65,637 $48,451 $40,188
--------- --------- ---------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(52,574) $(72,897) $(92,503)
Other investing activities (181) (251) (911)
--------- --------- ---------
Net cash used in investing activities $(52,755) $(73,148) $(93,414)
--------- --------- ---------
Financing activities:
Capital contributions from parent $20,000 $15,000
Dividends paid on common stock $(7,361) (4,813) (2,831)
Dividends paid on preferred stock (2,143) (2,143) (2,143)
Changes in short-term debt (3,650) (7,125) 10,075
Long-term debt issues 2,000 38,000 33,000
Long-term debt retirements (2,000) (16,000)
Premium on reacquisition of long-term debt (1,936)
--------- --------- ---------
Net cash provided by (used in)
financing activities $(13,154) $25,983 $53,101
--------- --------- ---------
Net increase (decrease) in cash and
cash equivalents $(272) $1,286 $(125)
Cash and cash equivalents at
beginning of year 1,999 713 838
--------- --------- ---------
Cash and cash equivalents at end of year $1,727 $1,999 $713
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $18,620 $17,050 $14,015
--------- --------- ---------
Federal income taxes paid $8,873 $1,084 $2,982
--------- --------- ---------
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 and sale 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 Manchester Street generating station. The
entire output of this plant is made available to New England
Power Company (NEP), the Company's wholesale generating
affiliate, as part of the integrated NEES system. Under a
contract with NEP, the Company purchases all of its electric
energy requirements from NEP. The contract provides for the
integration of the Company's generating and transmission
facilities with NEP's facilities in order to achieve maximum
economy and reliability. The contract also provides for the
application of credits against the Company's power bills from NEP
for costs associated with the Company's facilities so integrated.
This contract requires either party to give seven years notice
prior to terminating the contract. (See Note B for a discussion
of industry restructuring and NEP's and the Company's proposed
divestiture of their 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 were $8
million in 1995 and $6 million in 1994, which represented 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 5.3 percent, 6.2
percent, and 6.8 percent in 1996, 1995, and 1994, 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 4.0 percent, 5.0 percent, and 4.5
percent in 1996, 1995, and 1994, respectively. The change in the
depreciation rates in 1996 and 1995 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.
Note B - Industry Restructuring
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 Rhode Island, 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 currently purchases electricity on behalf of its
customers under a wholesale all-requirements contract with NEP.
As described below, comprehensive legislation was enacted in
Rhode Island which, when all regulatory approvals are in place,
would allow recovery of NEP's above-market commitments to retail
customers in Rhode Island, which make up 22 percent of NEP's all-
requirements sales.
In August 1996, the state of Rhode Island enacted pioneering
legislation that allows customers in that 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 10 percent of the Company's kilowatt-hour (kWh)
sales. The balance of Rhode Island customers will be able to
choose their supplier in 1998, with an additional 10 percent of
customers load having choice on January 1 and the remainder on
July 1. All Rhode Island customers would have choice of supplier
beginning January 1, 1998 if retail access is available to 40
percent or more of the kWh sales in New England by that date.
The statute calls for NEP's contract with the Company to be
amended to permit a gradual, early termination of
all-requirements service. The amendment provides that, in
return, the Company's 22 percent share of the cost of NEP's
above-market generation commitments (estimated at approximately
$1 billion on a present-value basis) would be recovered through a
contract termination charge. This charge will, in turn, be paid
by customers that use the Company's distribution facilities.
Those commitments consist of (i) generating plant commitments,
(ii) regulatory assets, (iii) the above-market component of
purchased power contracts, and (iv) the operating cost of nuclear
plants which cannot be avoided by shutting down the plants,
including nuclear decommissioning.
Sunk costs associated with generating plants and regulatory
assets would be recovered over a period of 12.5 years. The
above-market component of purchased power contracts and the
nuclear decommissioning costs would be recovered as incurred over
the life of those obligations, a period expected to extend beyond
12 years. The transition access charge would be reduced to
reflect the net proceeds from the sale of the NEES companies'
generating assets. (See "Divestiture of Generation Business"
section below.) The initial transition access charge, before the
application of those proceeds, would be set at 2.8 cents per kWh
through December 31, 2000, and is expected to decline thereafter.
The statute also establishes performance-based rates for
distribution utilities, such as the Company. Under the statute,
the Company increased distribution rates by approximately $11
million in 1997, and is entitled to a similar increase in 1998.
In addition, in 1997, the Company's return on equity from
distribution operations will be subject to a floor of 6 percent
and a ceiling of 11 percent. Earnings over the ceiling will be
shared equally between customers and shareholders up to a maximum
return on equity from distribution operations of 12.5 percent.
This sharing results in an effective cap on shareholder's return
on equity of 11.75 percent. To the extent that earnings fall
below the floor, the Company will be authorized to surcharge
customers for the shortfall.
NEP and the Company filed with the Federal Energy Regulatory
Commission (FERC) an amendment to their all-requirements contract
in order to implement the statute. The FERC has set down the
amendment for hearing. The Company has indicated it is willing
to make certain changes to its plan in Rhode Island to parallel
provisions in a similar Massachusetts settlement. The
Massachusetts settlement was approved by the Massachusetts
Department of Public Utilities on February 26, 1997. The
settlement provides for retail choice for Massachusetts customers
in 1998 and the recovery of NEP's above-market commitments to
serve those customers. Implementation of other aspects of the
statute is subject to approval of the Rhode Island Public
Utilities Commission (RIPUC).
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
NEP and the Company agreed to the divestiture of their fossil and
hydroelectric generating facilities as part of industry
restructuring. Such divestiture must be accomplished within six
months of the later of the commencement of retail choice in
Massachusetts, currently scheduled for January 1, 1988, or the
receipt of all necessary regulatory approvals. The Company will
be compensated by NEP for any difference between the sale price
of the Company's share of the Manchester Street Station and its
net book value. Proposals are being solicited for the
acquisition of the 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. The
Rhode Island statute also requires the Company to transfer its
transmission assets to NEP at net book value.
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 $44 million in net regulatory assets in compliance
with FAS 71. The Company believes that the continuing rate-making
policies and practices of the RIPUC and the terms of the Rhode
Island statute will enable the Company to recover both its
specific costs of providing ongoing distribution services and
stranded costs billed to it by NEP. The Company believes that
these factors will allow it to continue to apply FAS 71. 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 would be required.
The components of regulatory assets are as follows:
At December 31, (In Thousands) 1996 1995
---- ----
Regulatory assets (liabilities) included in current
assets and liabilities:
Rate adjustment mechanisms (see Note F) $(2,870) $(7,661)
-------- --------
Regulatory assets included in deferred charges:
Deferred SFAS No. 109 costs (see Note C) 30,439 29,251
Unamortized losses on reacquired debt 13,287 13,918
Deferred SFAS No. 106 costs (see Note E 2) 2,487 4,894
Deferred storm costs 3,676
Other 5,656 3,900
-------- --------
51,869 55,639
-------- --------
Regulatory liabilities reflected in other reserves and
deferred credits - storm fund (4,691) -
-------- --------
$44,308 $47,978
======== ========
Amounts included in "Deferred charges and other assets" on the Company's
balance sheets that do not represent regulatory assets totaled $5,012,000 and
$4,529,000 at December 31, 1996 and 1995, respectively.
Note C - 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 (IRS) through 1991. The returns for
1992 and 1993 are currently under examination by the IRS.
Total federal income taxes consist of the following components:
Year Ended December 31, (In Thousands) 1996 1995 1994
---- ---- ----
Income taxes charged to operations:
Current income taxes $ 7,499 $7,560 $1,511
Deferred income taxes 4,950 3,831 3,880
Investment tax credits, net (498) (503) (508)
------- ------- -------
Total income taxes charged to
operations 11,951 10,888 4,883
------- ------- -------
Income taxes charged (credited) to
"Other income":
Current income taxes (581) (348) (491)
Deferred income taxes (275) (319) 50
------- ------- -------
Total income taxes charged (credited) to
"Other income" (856) (667) (441)
------- ------- -------
Total federal income taxes $11,095 $10,221 $4,442
======= ======= =======
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) 1996 1995 1994
---- ---- ----
Computed tax at statutory rate $11,917 $11,946 $6,661
Increases (reductions) in
tax resulting from:
Book versus tax depreciation not normalized 778 529 653
Costs associated with utility
plant retirements deducted
for tax purposes (1,341) (1,768) (1,872)
Allowance for equity funds used
during construction - (37) (360)
Amortization of investment tax credits (498) (503) (508)
All other differences 239 54 (132)
------- ------- -------
Total federal income taxes $11,095 $10,221 $4,442
======= ======= =======
The following table identifies the major components of total deferred income
taxes:
At December 31, (In Millions) 1996 1995
---- ----
Deferred tax asset:
Plant related $2 $2
Investment tax credits 3 3
All other 13 13
----- -----
18 18
===== =====
Deferred tax liability:
Plant related (67) (62)
All other (33) (32)
----- -----
(100) (94)
----- -----
Net deferred tax liability $(82) $(76)
===== =====
There were no valuation allowances for deferred tax assets deemed necessary.
Note D - Commitments and Contingencies
1. Plant Expenditures:
The Company's utility plant expenditures are estimated to be
approximately $45 million in 1997. At December 31, 1996,
substantial commitments had been made relative to future planned
expenditures.
2. Hazardous Waste:
The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly know 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. 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 its 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.
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 $2,007 $1,963 $1,877
Plus (less):
Interest cost on projected
benefit obligation 8,954 9,327 8,629
Return on plan assets at expected
long-term rate (9,787) (9,567) (9,024)
Amortization 165 67 567
------- ------- -------
Net pension cost $1,339 $1,790 $2,049
------- ------- -------
Actual return on plan assets $17,228 $25,192 $809
======= ======= =======
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
Nonvested 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 $1,030 $1,072 $1,252
Plus (less):
Interest cost on accumulated
benefit obligation 5,034 6,006 5,630
Return on plan assets at expected
long-term rate (2,803) (2,080) (1,640)
Amortization 2,739 3,539 3,716
------- ------- -------
Net postretirement benefit cost $6,000 $8,537 $8,958
======= ======= =======
Actual return (loss) on plan assets $5,469 $6,161 $(23)
======= ======= =======
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 $51 $50
Fully eligible active plan participants 5 6
Other active plan participants 19 20
---- ----
Total benefits earned 75 76
Unrecognized transition obligation (62) (66)
Net gain not yet recognized 22 16
---- ----
35 26
Plan assets at fair value 42 34
---- ----
Prepaid postretirement benefit costs recorded
on books $7 $8
==== ====
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 $9 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 $19 million of short-term
debt outstanding including $14 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 with banks
totaling $41 million. There were no borrowings under these lines
of credit at December 31, 1996. Fees are paid in lieu of
compensating balances on most lines of credit.
The weighted average rate on outstanding short-term borrowings
was 6.0 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
---- ----
Rate adjustment mechanisms $4,632 $14,075
Accrued wages and benefits 7,259 5,483
Other 58 -
------- -------
$11,949 $19,558
======= =======
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
---- ---- ---- ---- ---- ----
$50 Par value
4.50% Series 180,000 180,000 $9,000 $9,000 $405 $405 55.000
4.64% Series 150,000 150,000 7,500 7,500 348 348 52.125
6.95% Series 400,000 400,000 20,000 20,000 1,390 1,390 (a)
------- ------- ------- ------- ------ ------
Total 730,000 730,000 $36,500 $36,500 $2,143 $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
$2,143,000 for 1996 and 1995.
Note H - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In Thousands)
Series Rate % Maturity 1996 1995
- -----------------------------------------------------------------------------
First Mortgage Bonds:
U(92-1) 7.230 June 3, 1997 $10,000 $10,000
U(92-2) 7.210 June 3, 1997 5,000 5,000
U(92-3) 7.000 June 16, 1997 10,000 10,000
U(92-7) 5.700 September 16, 1997 7,500 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 24,000
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 -
Unamortized discounts and premiums (1,183) (1,308)
-------- --------
Total long-term debt $211,017 $210,892
======== ========
Long-term debt due in one year 32,500 -
-------- --------
$178,517 $210,892
======== ========
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 $32,500,000 in 1997,
$5,000,000 in 1998, $8,000,000 in 1999, and $15,000,000 in 2000
to retire maturing mortgage bonds. There are no cash payments
required in 2001.
At December 31, 1996, the Company's long-term debt had a carrying
value of approximately $211,000,000 and had a fair value of
approximately $203,000,000. 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 I - 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,
1996 was 51 percent of total capitalization 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.
Note J - 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 K - 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 federal income taxes,
charged to operating expenses are set forth by class as follows:
Year Ended December 31, 1996 1995 1994
(In Thousands) ---- ---- ----
Municipal property taxes $16,546 $15,172 $13,944
State gross earnings tax 18,764 18,617 19,270
Federal and state payroll and
other taxes 3,220 2,838 2,604
------- ------- -------
$38,530 $36,627 $35,818
======= ======= =======
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
$27,336,438, $29,094,719, and $32,445,000, including capitalized
construction costs of $6,426,000, $6,268,000, and $7,756,000 for
each of the years 1996, 1995, and 1994, respectively.
The Narragansett Electric Company
Operating Statistics (Unaudited)
Year Ended December 31, 1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Sources of Energy (Thousands of kWh)
Net generation for New England
Power Company, an affiliate 329,883 64,035 5,781 4,506 83,753
Purchased energy:
From New England Power
Company (net of
generation) 4,698,017 4,955,575 5,001,843 4,982,254 4,729,733
From others 2,422 2,080 2,909 2,343 2,249
--------------------------------------------------
Total generated and
purchased 5,030,322 5,021,690 5,010,533 4,989,103 4,815,735
Losses, company use, etc. (251,709) (260,960) (263,234) (270,373) (229,106)
--------------------------------------------------
Total sources of energy 4,778,613 4,760,730 4,747,299 4,718,730 4,586,629
==================================================
Sales of Energy (Thousands of kWh)
Residential 1,847,111 1,835,085 1,843,970 1,817,675 1,783,754
Commercial 2,035,294 2,031,541 1,983,508 1,931,377 1,877,738
Industrial 847,877 843,635 868,092 917,305 869,062
Other 47,745 49,881 51,138 51,821 55,476
--------------------------------------------------
Total sales to
ultimate customers 4,778,027 4,760,142 4,746,708 4,718,178 4,586,030
Sales for resale 586 588 591 552 599
--------------------------------------------------
Total sales of energy 4,778,613 4,760,730 4,747,299 4,718,730 4,586,629
==================================================
Annual Maximum Demand
(kW one hour peak) 929,000 1,031,000 1,005,000 939,000 919,000
Average Annual Use per
Residential Customer (kWh) 6,304 6,305 6,397 6,337 6,265
Number of Customers at
December 31
Residential 294,274 292,659 289,317 287,876 286,228
Commercial 33,101 32,412 32,195 31,948 31,534
Industrial 1,778 1,792 1,825 1,869 1,914
Other 868 873 875 878 941
--------------------------------------------------
Total ultimate customers 330,021 327,736 324,212 322,571 320,617
Other electric companies
(for resale) 2 2 2 1 3
--------------------------------------------------
Total customers 330,023 327,738 324,214 322,572 320,620
==================================================
Operating Revenue (In Thousands)
Residential $216,103 $205,649 $200,778 $202,522 $196,983
Commercial 202,219 198,429 189,059 190,185 183,702
Industrial 68,447 72,071 72,136 78,088 76,275
Other 7,809 7,236 6,883 6,778 6,587
--------------------------------------------------
Total revenue from
ultimate customers 494,578 483,385 468,856 477,573 463,547
Amortization of unbilled
revenues - 8,209 6,158 - -
Sales for resale 75 70 68 64 68
--------------------------------------------------
Total revenue from
electric sales 494,653 491,664 475,082 477,637 463,615
Other operating revenue 8,932 7,449 6,587 5,391 4,637
--------------------------------------------------
Total operating revenue $503,585 $499,113 $481,669 $483,028 $468,252
==================================================
The Narragansett Electric Company
Selected Financial Information
Year Ended December 31, (In Millions) 1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $361 $361 $356 $351 $342
Fuel cost recovery 134 131 120 127 121
Other 9 7 6 5 5
------ ------ ------ ------ ------
Total operating revenue $504 $499 $482 $483 $468
Net income $23 $24 $15 $14 $21
Total assets $707 $700 $647 $556 $479
Capitalization:
Common equity $257 $245 $208 $183 $176
Cumulative preferred stock 36 36 37 37 27
Long-term debt 179 211 189 156 143
------ ------ ------ ------ ------
Total capitalization $472 $492 $434 $376 $346
Preferred dividends declared $2 $2 $2 $2 $2
Common dividends declared $9 $5 $3 $5 $5
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
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
1995
Operating revenue $125,020 $116,426 $139,217 $118,450
Operating income $12,645 $7,301 $12,699 $9,780
Net income $7,766 $3,058 $7,939 $5,147
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, 1996 will be available on or about April 1,
1997, without charge, upon written request to The Narragansett
Electric Company, Shareholder Services Department, 280 Melrose
Street, Providence, Rhode Island 02901.