Annual Report 1994
The Narragansett Electric Company
A Subsidiary of
New England Electric System
(Logo) Narragansett Electric
A New England Electric System company
The Narragansett Electric Company
280 Melrose Street
Providence, Rhode Island 02901
Directors
(As of December 31, 1994)
Joan T. Bok John W. Rowe
Chairman of the Board of New England President and Chief Executive
Electric System Officer of New England Electric
System
Stephen A. Cardi
Treasurer, Cardi Corporation Richard P. Sergel
(Construction), Warwick, Rhode Island Chairman of the Company and Vice
President of New England Electric
Frances H. Gammell System
Treasurer and Secretary, Original
Bradford Soap Works, Inc., West Warwick, William E. Trueheart
Rhode Island President of Bryant College,
Smithfield, Rhode Island
Joseph J. Kirby
President, Washington Trust Bancorp, John A. Wilson, Jr.
Inc., Westerly, Rhode Island Consultant to and former President of
Wanskuck Company (Cable reel
Robert L. McCabe manufacturer), Providence, Rhode
President and Chief Executive Officer Island and Consultant to Hinkley,
of the Company Allen, Tobin and Silverstein
Officers
(As of December 31, 1994)
Richard P. Sergel James V. Mahoney
Chairman of the Company and Vice Vice President
President of New England Electric
System Richard Nadeau
Vice President
Robert L. McCabe
President and Chief Executive Officer Michael F. Ryan
Vice President
William Watkins, Jr.
Executive Vice President Thomas G. Robinson
Secretary
Francis X. Beirne
Vice President John G. Cochrane
Assistant Treasurer of the Company
Richard W. Frost and of an affiliate
Vice President
David J. Saggau
Alfred D. Houston Assistant Secretary
Vice President and Treasurer of the
Company and Executive Vice President Howard W. McDowell
and Chief Financial Officer of New Controller of the Company and of
England Electric System 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 324,000 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 about
839 square miles or 80 percent of Rhode Island, and includes the cities of
Providence, East Providence, Cranston, and Warwick. The diversified economy
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.
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 a steam-electric generating station which
is in the process of being repowered. The repowering will more than triple
the power generating capacity of the station to 489 megawatts. The entire
output of this plant is made available to New England Power Company (NEP),
an affiliate, as part of the integrated NEES system. Under a 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. The Company and NEP are members of
the New England Power Pool, which provides for the coordination of the
planning and operation of the generation and transmission facilities in New
England, and the region-wide central dispatch of generation.
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, 1994 and 1993 and the related statements
of income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1994. 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, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
February 27, 1995
The Narragansett Electric Company
Financial Review
Overview
Net income for 1994 increased by $300,000 compared with 1993. The
increase was primarily due to the inclusion in 1993 of a one-time charge
associated with an early retirement program. The increase also reflects
kilowatthour (KWH) sales growth in 1994, the commencement of recognition of
revenues for electricity delivered but not yet billed (unbilled revenues)
pursuant to a 1994 rate agreement, and increased allowance for funds used
during construction. These increases were largely offset by rate discounts
to large commercial and industrial customers also implemented as part of this
rate agreement, increases in other operation expenses, and increased interest
expense due to additional debt outstanding.
Net income decreased by $7 million in 1993. This decrease was primarily
due to increased operation and maintenance expenses as well as a reduction
in incentives recorded on the Company's demand-side management (DSM)
programs. This increase in operation and maintenance expense included the
effects of an early retirement program discussed above. The decrease in
income was partially offset by an increase in KWH sales to ultimate
customers.
Rate Activity
On March 1, 1995, the Company filed with the Rhode Island Public
Utilities Commission (RIPUC) a request to increase its base rates by $30.5
million to be effective December 1995. As an alterative to the December 1995
effective date, the Company proposed to phase its requested rate increase in
two steps--the first step in June 1995 ($13 million) and the second step in
June 1996. As part of its filing, the Company proposed a special rate
discount of 8 percent of base rates, for manufacturing customers that agree
to give the Company a five-year notice before they purchase power from
another supplier or generate any additional power themselves.
In July 1994, the RIPUC approved a rate agreement between the Company
and the Rhode Island Division of Public Utilities and Carriers that provides
for a 5 percent base rate discount, excluding fuel costs, for the Company's
large commercial and industrial customers who sign an agreement to give a
five-year notice to the Company before they purchase power from another
supplier or generate any additional power themselves. The notice provision
may be reduced from five to three years under certain conditions. The
aggregate amount of the Company's discounts was $1.5 million in 1994 and is
expected to be approximately $3 million per year thereafter. Customers
representing over 64 percent of revenues from large commercial and industrial
customers have signed these agreements. In addition, commencing in 1995 the
cost of these discounts is being passed on to New England Power Company
(NEP), the Company's affiliated wholesale power supplier. This is the result
of a NEP rate settlement that was approved by the Federal Energy Regulatory
Commission (FERC) in early 1995. The agreement also provides for the Company
to recognize, for accounting purposes, $14 million of unbilled revenues over
a 21 month period beginning April 1994 through December 1995.
Effective March 1993, the RIPUC approved a new purchased power cost
adjustment (PPCA) mechanism for the recovery of all of the Company's
purchased power costs, excluding fuel charges which continue to be
Rate Activity (continued)
recovered through a separate adjustment mechanism. Under the new mechanism
any over or under-collections of purchased power expense will ultimately be
passed on to customers including the effects of peak-demand billing
fluctuations. The Company accrues the effects of this new mechanism on its
books on a current basis. In August 1994, the RIPUC gave notice that it
intends to open a proceeding to consider the effect of fuel adjustment
clauses on utility incentives to reduce costs.
Effective January 1993, the RIPUC approved a $1.5 million increase in
rates for the Company, representing the first step of a three year phase-in
of the Company's recovery of costs associated with postretirement benefits
other than pensions (PBOPs). The second and third $1.5 million increases
took effect in January 1994 and 1995, respectively.
A 1986 Rhode Island Supreme Court decision held that the RIPUC's
rate-making power includes 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.
Demand-Side Management
The Company regularly files its demand-side management (DSM) programs
with the RIPUC and has received approval to recover DSM program expenditures
in rates on a current basis. These expenditures were $10 million, $12
million, and $12 million in 1994, 1993, and 1992, respectively. Since 1990,
the Company has been allowed to earn incentives based on the results of its
DSM programs. The Company must be able to demonstrate the electricity
savings produced by its DSM programs to the RIPUC before incentives are
recorded. The Company recorded before-tax incentives of $0.6 million, $0.5
million, and $1.3 million in 1994, 1993, and 1992, respectively. The Company
has received regulatory orders that will give it the opportunity to continue
to earn incentives based on 1995 DSM program results.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
- -----------------------------------------------------------------------
(In Millions) 1994 1993
- -----------------------------------------------------------------------
Sales growth $ 5 $ 6
General rate changes - 2
Unbilled revenues 5 -
PPCA mechanism (2) 2
DSM recovery (2) -
Fuel recovery (7) 5
---------------------
$(1) $15
=====================
KWH sales billed to ultimate customers in 1994 increased by 0.6 percent
over 1993. The increase in KWH sales reflects an improved economy partially
offset by a loss of sales attributable to the May 1994 plant closing of one
Operating Revenue (continued)
of the Company's largest customers. Revenues from this customer, excluding
fuel and purchased power costs, were approximately $1.4 million on an annual
basis. KWH sales in 1993 increased 2.9 percent over 1992 sales, reflecting
more normal weather conditions in 1993 compared with 1992, partially offset
by the fact that 1992 included an extra day for leap year.
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 resulting from rate increases or decreases
by NEP, the Company's affiliated wholesale power supplier.
In the third quarter of 1994, the Company began recognizing unbilled
revenues according to its rate agreement filed in July 1994 with the RIPUC.
For a further discussion of unbilled revenues, see "Rate Activity" section.
Operating Expenses
The following table summarizes the changes in total operating expenses
discussed below:
Increase (Decrease) in Operating Expenses
- -------------------------------------------------------------------------
(In Millions) 1994 1993
- -------------------------------------------------------------------------
Fuel for generation $ - $(3)
Purchased electric energy:
Fuel costs (7) 5
NEP refunds 1 2
Purchases and demand charges from NEP 2 4
Integrated facilities credit from NEP (6) 13
Other operation and maintenance:
DSM (2) -
Thermal generation - (6)
Other 1 13
Depreciation 7 (2)
Taxes 1 (4)
---------------
$(3) $22
===============
The entire output of the Company's generating capacity is made available
to NEP. The Company receives a credit on its purchased power bill from NEP
for its fuel costs and other generation and transmission costs. The change
in the integrated facilities credit from NEP for 1994 shown in the above
table reflects increased credits for dismantlement costs being incurred on
the Company's previously retired South Street generating station. These
increased costs for dismantlement are reflected in the increase in
depreciation shown above.
The change in the integrated facilities credit from NEP for 1993
reflects decreased credits is attributable to the Company's mid-1992 sale of
90 percent of the Manchester Street Station to NEP as part of the Manchester
Street repowering project. The decreases in fuel for generation and thermal
generation-related operation and maintenance costs in 1993 are also due to
this sale (see "Repowering of Manchester Street Station" section).
Operating Expenses (continued)
The changes in the fuel cost component of purchased power in 1994 and
1993 reflect changes in the amount of New England Energy Incorporated's
(NEEI) costs passed through by NEP. NEEI is an affiliated company involved
in oil and gas exploration and development. The 1994 decrease also reflects
a reduction in the fuel component of NEP's purchased electric energy costs.
In addition, the increase in fuel costs in 1993 reflects increased KWH
purchases.
The change in other operation and maintenance expense in both 1993 and
1994 reflects the one-time charge of $5 million in 1993 associated with an
early retirement program. The increase in both periods also reflects
increased computer system development costs and postretirement benefit costs
as well as general increases in other areas.
Allowance for Funds Used During Construction (AFDC)
AFDC increased in 1994 and 1993 due to increased construction work in
progress associated with the repowering of the Manchester Street Station (see
"Repowering of Manchester Street Station" section).
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. New
England Electric System (NEES) subsidiaries currently have in place an
environmental audit 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 U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for two sites (one of which is 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
Hazardous Waste (continued)
ranging from less than $1 million to $8 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 would be successful. The Company believes that
hazardous waste liabilities for all sites of which it is aware will not be
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. Some of the studies have suggested associations between certain
EMF and health effects, including various types of cancer, while other
studies have not substantiated such associations. 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.
Many utilities, including the NEES companies, have been contacted by
customers regarding a potential relationship between EMF and adverse health
effects. To date, no court in the United States has ruled that EMF from
electrical facilities cause adverse health effects and no utility has been
found liable for personal injuries alleged to have been caused by EMF. In
any event, the Company believes that it currently has adequate insurance
coverage for personal injury claims.
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.
Bills have been introduced unsuccessfully in the past in the Rhode
Island legislature to require that transmission lines be placed underground.
Competitive Conditions
The electric utility business is being subjected to increasing
competitive pressures, stemming from a combination of trends, including
increasing electric rates, improved technologies, and new regulations and
legislation intended to foster competition. To date, this competition has
been most prominent in the bulk power market in which non-utility generating
sources have noticeably increased their market share. For example, since
non-utilities were allowed to enter the wholesale generation market,
two-thirds of NEP's new generating capability has come from independent
generating sources and Hydro-Quebec.
Competitive Conditions (continued)
Electric utilities are also facing increased competition in the retail
market. Currently, retail competition includes competition with alternative
fuel suppliers (including natural gas companies) for heating and cooling,
competition with customer-owned generation to displace purchases from
electric utilities, and direct competition among electric utilities to
attract major new facilities to their service territories. Electric
utilities, including the Company, are under increasing pressure from large
commercial and industrial customers to discount rates or face the possibility
that such customers might relocate or seek alternate suppliers. Across the
country, including Rhode Island and the other states in which the Company's
affiliates operate, there have been an increasing number of proposals to
allow retail customers to choose their electricity supplier, with utilities
required to deliver that electricity over their transmission and distribution
systems. In Rhode Island, the RIPUC has convened a task force of utilities,
commercial and industrial customers, regulators, and other interested parties
to prepare a report by May 1995 regarding restructuring the industry. The
Massachusetts Division of Energy Resources (DOER) proposed in January 1995
that the Massachusetts Department of Public Utilities (MDPU) modify its
regulations to allow retail utility customers to choose a supplier and bid
for access to the local utility's transmission and distribution systems in
situations where new generating capacity is needed. The NEES companies have
indicated their support for the DOER proposal. The Company's Massachusetts
retail affiliate has announced plans to propose a limited bidding experiment
consistent with the DOER proposal. Also in Massachusetts, the MDPU initiated
a proceeding in February 1995 regarding electric industry regulation and
structure. In New Hampshire, the New Hampshire Public Utilities Commission
is considering the proposal of a new company to sell electricity at retail
to large customers in New Hampshire.
The impact of increased customer choice on the financial condition of
utilities is uncertain. In recent years, substantial surplus generating
capacity in the Northeast has resulted in the sale of bulk power by utilities
to other utilities at prices substantially below the total costs of owning
and operating, or contracting for, such generating capacity. Should retail
customers gain access to the bulk power market, particularly while surplus
capacity exists, it is unlikely that utilities would be able to charge power
prices which fully cover their costs. Such unrecovered costs, which could
be substantial, have been referred to by the industry as stranded costs.
Whether and to what extent utilities should be able to recover stranded
costs resulting from increased customer choice has been the subject of much
debate. In 1994, the FERC issued a notice of proposed rule-making on the
recovery of stranded costs. The NEES companies and other utilities have
taken the position that when a regulatory body changes policies which govern
customer choice and the resultant rates paid by customers, utilities must be
compensated for commitments made under the former policies. Furthermore, the
utility industry believes that recovery of stranded costs is necessary to
promote efficient competition among market participants. Previously, the
FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a
utility may recover such stranded costs from a departing wholesale
requirements customer. On appeal, the United States Court of Appeals for the
District of Columbia Circuit has questioned whether allowing utilities to
recover stranded costs is anti-competitive and the Court remanded the case
back to the FERC for further proceedings and development of the competitive
issues.
Competitive Conditions (continued)
In addition to the arguments described above, the NEES companies have
taken the position that, because utility transmission and distribution assets
have a replacement value in excess of their historic costs (on which utility
rates are set), utilities should have the ability to recover stranded
generation-related costs by realizing the higher value of transmission and
distribution assets. The NEES companies have stated their willingness, in
order to assure stranded cost recovery and promote increased competition, to
consider divesting their transmission system, either through sale or spinoff.
The NEES companies are actively responding to current and anticipated
competitive pressures in a variety of ways, including cost control and a 1993
corporate reorganization into separate retail and wholesale business units.
The retail business unit, which includes the Company, is responding to
competition through the development of an EnergyFIT program, which offers
comprehensive value-added services for large business customers, intensified
business development efforts, including economic development rates and
service packages to encourage businesses to locate in the Company's service
territory, and development of new pricing and service options for customers.
Additionally, more than 75 percent of the Company's large commercial and
industrial customers (representing 64 percent of eligible revenues) have
signed service extension discount contracts providing for discounts in
exchange for agreements requiring three to five years notice before they may
change electricity suppliers (see "Rate Activity" section). As part of their
long-term planning process, the NEES companies are from time to time
evaluating other strategies, such as business combinations and other forms
of restructuring, to better respond to the changing competitive environment.
Since the largest component of the Company's costs is represented by the
cost of power purchased from NEP, its competitive position is affected by
NEP's ability to control costs. NEP is controlling costs and positioning
itself for increased competition by freezing base rates until at least 1997
(wholesale base rates were last raised in March 1992), terminating certain
purchased power and gas pipeline contracts, shutting down uneconomic
generating stations, and accelerating the recovery of uneconomic assets and
other deferred costs. In addition, NEP's wholesale tariff requires its
wholesale customers, including the Company and NEES's other retail
subsidiaries, to provide seven years notice before they may terminate the
tariff.
Electric utility rates are generally 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. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in future
rates. The effects of competition could ultimately cause the operations of
the Company, or a portion thereof, to cease meeting the criteria for
application of these accounting rules. In such an event, accounting
standards applicable to enterprises in general would apply and immediate
write-off of any previously deferred costs (regulatory assets) would be
necessary in the year in which these criteria were no longer applicable. In
addition, if, because of competition, utilities are unable to recover all of
their costs in rates, it may be necessary to write off those costs that are
not recoverable.
Utility Plant Expenditures and Financings
Cash expenditures for utility plant totaled $93 million in 1994,
including $33 million related to the Manchester Street Station repowering
project discussed below. The funds necessary for utility plant expenditures
were primarily provided by net cash from operating activities, after the
payment of dividends, the issuance of long-term and short-term debt, and a
capital contribution from NEES. Cash expenditures for utility plant for 1995
are estimated to be $55 million (including approximately $16 million related
to the repowering of Manchester Street Station). Internally generated funds
are estimated to provide 50 percent of these needs in 1995. Cash
expenditures for utility plant are also expected to be funded through the
issuance of long-term and short-term debt.
In 1994, the Company issued $33 million of first mortgage bonds bearing
interest rates ranging from 6.91 percent to 8.33 percent. The Company has
issued $5 million of long-term debt to date in 1995 at an interest rate of
7.81 percent and plans to issue an additional $20 million of long-term debt
later in 1995 to reduce short-term debt and fund capital expenditures.
At December 31, 1994, the Company had $30 million of short-term debt
outstanding in the form of commercial paper borrowings. As of December 31,
1994, the Company had lines of credit with banks totaling $41 million. There
were no borrowings under these lines of credit at December 31, 1994.
Repowering of Manchester Street Station
The Company's major construction project is the repowering of Manchester
Street Station, a 140 megawatt electric generating station in Providence,
Rhode Island. Repowering will more than triple the power generation capacity
of Manchester Street Station and substantially increase the plant's thermal
efficiency. To facilitate financing this project, the Company sold a 90
percent interest in the existing station to NEP effective July 1, 1992. The
total cost for the generating station, scheduled to be placed in service in
late 1995, is estimated to be approximately $520 million including AFDC. At
December 31, 1994, $298 million, including AFDC, had been spent on the
generating station (including $28 million by the Company). In addition,
related transmission improvements were placed in service in September 1994
at a cost of approximately $60 million (including approximately $45 million
by the Company).
The Narragansett Electric Company
Statements of Income
- -----------------------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
- -----------------------------------------------------------------------------------------
Operating revenue $481,669 $483,028 $468,252
Operating expenses:
Purchased electric energy, principally
from New England Power Company, an affiliate 300,678 310,895 286,483
Other operation 73,082 73,723 69,602
Maintenance 12,281 12,179 12,286
Depreciation 24,813 17,645 19,826
Taxes, other than federal income taxes 35,818 35,846 35,172
Federal income taxes 4,883 4,175 8,984
----------------------------------
Total operating expenses 451,555 454,463 432,353
----------------------------------
Operating income 30,114 28,565 35,899
Other income:
Allowance for equity funds used during construction 1,028 543 10
Other income (expense) - net, including related taxes (856) (634) (639)
----------------------------------
Operating and other income 30,286 28,474 35,270
----------------------------------
Interest:
Interest on long-term debt 14,334 12,715 13,290
Other interest 2,897 2,074 1,277
Allowance for borrowed funds used during
construction - credit (1,534) (589) (349)
----------------------------------
Total interest 15,697 14,200 14,218
----------------------------------
Net income $ 14,589 $ 14,274 $ 21,052
==================================
Statements of Retained Earnings
- -----------------------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
- -----------------------------------------------------------------------------------------
Retained earnings at beginning of year $81,659 $74,207 $59,804
Net income 14,589 14,274 21,052
Dividends declared on cumulative preferred stock (2,143) (1,931) (1,553)
Dividends declared on common stock, $2.25, $4.00,
and $4.50 per share, respectively (2,549) (4,530) (5,096)
Premium on redemption of preferred stock (361)
----------------------------------
Retained earnings at end of year $91,556 $81,659 $74,207
==================================
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Balance Sheets
- -----------------------------------------------------------------------------------------
At December 31, (In Thousands) 1994 1993
- -----------------------------------------------------------------------------------------
Assets
Utility plant, at original cost $617,498 $534,569
Less accumulated provisions for depreciation 161,557 156,652
---------------------
455,941 377,917
Construction work in progress 35,974 43,660
---------------------
Net utility plant 491,915 421,577
---------------------
Current assets:
Cash 713 838
Accounts receivable:
From sales of electric energy 51,278 55,795
Other (including $9,306,000 and $1,087,000 from affiliates) 17,953 11,701
Less reserves for doubtful accounts 4,472 3,800
---------------------
64,759 63,696
Unbilled revenues (Note A-2) 13,100
Fuel, materials, and supplies, at average cost 5,170 4,572
Prepaid and other current assets 13,993 11,515
---------------------
Total current assets 97,735 80,621
---------------------
Deferred charges and other assets (Note A-6) 57,727 53,709
---------------------
$647,377 $555,907
=====================
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 60,000 45,000
Retained earnings 91,556 81,659
---------------------
Total common equity 208,350 183,453
Cumulative preferred stock, par value $50 per share 36,500 36,500
Long-term debt 188,862 155,972
---------------------
Total capitalization 433,712 375,925
---------------------
Current liabilities:
Short-term debt (including $19,725,000 to affiliates in 1993) 29,800 19,725
Accounts payable (including $47,900,000 and $43,468,000
to affiliates) 56,139 51,005
Accrued liabilities:
Taxes 143 1,712
Interest 5,615 4,921
Other accrued expenses (Note A-2) 25,346 11,798
Customer deposits 5,261 5,622
Dividends payable 819 1,102
---------------------
Total current liabilities 123,123 95,885
---------------------
Deferred federal income taxes 70,253 63,494
Unamortized investment tax credits 8,518 9,026
Other reserves and deferred credits 11,771 11,577
Commitments and contingencies (Note C)
---------------------
$647,377 $555,907
=====================
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) 1994 1993 1992
- ------------------------------------------------------------------------------------------
Operating activities:
Net income $ 14,589 $ 14,274 $ 21,052
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation 24,813 17,645 19,826
Deferred federal income taxes and
investment tax credits - net 3,422 1,690 4,053
Allowance for funds used during construction (2,562) (1,132) (359)
Amortization of unbilled revenues (6,158)
Early retirement program 2,705
Decrease (increase) in accounts receivable, net
and unbilled revenues (14,163) (2,183) (5,935)
Decrease (increase) in fuel, materials, and (598) 429 3,281
supplies
Decrease (increase) in prepaid and other current
assets (2,478) 2,359 (12,786)
Increase (decrease) in accounts payable 5,134 (3,180) 2,214
Increase (decrease) in other current liabilities 12,312 2,287 8,879
Other, net 5,877 (2,180) 404
----------------------------------
Net cash provided by operating activities $ 40,188 $ 32,714 $ 40,629
----------------------------------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(92,503) $(62,897) $(39,624)
Other investing activities (911)
Purchase of 90 percent interest in Manchester
Street Station from affiliate 3,249
----------------------------------
Net cash used in investing activities $(93,414) $(62,897) $(36,375)
----------------------------------
Financing activities:
Capital contributions from NEES $ 15,000 $ 10,000
Dividends paid on common stock (2,831) $ (5,663) (4,530)
Dividends paid on preferred stock (2,143) (1,783) (1,553)
Changes in short-term debt 10,075 16,050 (11,850)
Long-term debt - issues 33,000 27,500 67,500
Long-term debt - retirements (14,900) (62,200)
Preferred stock - issues 20,000
Preferred stock - retirements (10,000)
Premium on reacquisition of long-term debt (652) (1,645)
Premium on redemption of preferred stock (361)
Net cash provided by (used in) ----------------------------------
financing activities $ 53,101 $ 30,191 $ (4,278)
----------------------------------
Net increase (decrease) in cash and cash
equivalents $ (125) $ 8 $ (24)
Cash and cash equivalents at beginning of year 838 830 854
----------------------------------
Cash and cash equivalents at end of year $ 713 $ 838 $ 830
==================================
Supplementary Information:
Interest paid less amounts capitalized $ 14,015 $ 12,623 $ 12,365
----------------------------------
Federal income taxes paid $ 2,982 $ 2,352 $ 4,005
----------------------------------
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. System of Accounts:
The accounts of the Company are maintained in accordance with the Uniform
System of Accounts prescribed by regulatory bodies having jurisdiction.
2. Revenue:
The Company, pursuant to its 1994 rate agreement, began accruing revenues
for electricity delivered but not yet billed (unbilled revenues).
Unbilled revenues at December 31, 1994 were $13 million, of which $5
million were recognized in income monthly in 1994. The remainder of $8
million at December 31, 1994 has been deferred for recognition monthly
through December 1995 and appears on the balance sheet under the caption
"Other accrued expenses". Accrued revenues are also recorded in
accordance with rate adjustment mechanisms.
3. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs. AFDC
represents the composite interest and equity costs of capital funds used
to finance that portion of construction costs not eligible for inclusion
in rate base. In 1994, an average of $5 million of construction work in
progress was included in rate base, all of which was attributable to the
Manchester Street Station repowering project. AFDC is capitalized in
"Utility plant" with offsetting non-cash 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 6.8 percent, 6.9 percent, and 5.0 percent, in 1994, 1993, and 1992,
respectively.
4. Depreciation:
Depreciation is provided annually on a straight-line basis. The
provisions for depreciation as a percentage of weighted average
depreciable property were 4.5 percent, 3.5 percent, and 3.8 percent in
1994, 1993, and 1992, respectively. The increase in the depreciation rate
in 1994 is primarily due to the recognition through depreciation expense
of dismantlement costs for a retired generating facility.
5. Cash:
The Company classifies short-term investments with a remaining maturity
of 90 days or less as cash. Current banking arrangements do not require
outstanding checks to be funded until actually presented for payment.
Outstanding checks are therefore recorded in accounts payable until such
time as the banks present them for payment.
Note A - Significant Accounting Policies (continued)
- ----------------------------------------
6. Deferred Charges and Other Assets:
The components of deferred charges and other assets are as follows:
--------------------------------------------------------------------
At December 31, (In Thousands) 1994 1993
--------------------------------------------------------------------
Regulatory assets:
Deferred SFAS No. 109 costs (see Note B) $26,999 $24,170
Unamortized losses on reacquired debt 12,538 13,383
Deferred SFAS No. 106 costs (see Note D-2) 5,539 4,053
Deferred storm costs 4,277 5,122
Other 3,751 3,750
--------------------
53,104 50,478
Other deferred charges and other assets 4,623 3,231
--------------------
$57,727 $53,709
====================
Electric utility rates are generally 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. These
accounting rules require regulated entities, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the income
statement impact of certain costs that are expected to be recovered in
future rates. The effects of competition could ultimately cause the
operations of the Company, or a portion thereof, to cease meeting the
criteria for application of these accounting rules. In such an event,
accounting standards applicable to enterprises in general would apply and
immediate write-off of any previously deferred costs (regulatory assets)
would be necessary in the year in which these criteria were no longer
applicable. Approximately $20 million of the regulatory assets at
December 31, 1994 listed above are expected to be recovered within 10
years. All of the remainder will be fully recovered within the next 20
years with the exception of the Deferred SFAS No. 109 costs which will
take longer to recover.
Note B - Federal Income Taxes
- -----------------------------
The Company and other subsidiaries participate with New England Electric
System (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 1991.
Note B - Federal Income Taxes (continued)
- -----------------------------
Federal income taxes consist of the following components:
-------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
-------------------------------------------------------------------------
Income taxes charged to operations:
Current income taxes $1,511 $2,537 $4,998
Deferred income taxes 3,880 2,146 4,493
Investment tax credits--net (508) (508) (507)
----------------------------
Total income taxes charged to operations 4,883 4,175 8,984
----------------------------
Income taxes charged (credited)
to "Other income":
Current income taxes (491) (354) (390)
Deferred income taxes 50 53 67
----------------------------
Total income taxes charged (credited) to
"Other income" (441) (301) (323)
----------------------------
Total federal income taxes $4,442 $3,874 $8,661
============================
Investment tax credits are deferred and amortized over the estimated lives
of the property giving rise to the credits. Since the Tax Reform Act of
1986 generally eliminated investment tax credits, the amounts shown above
principally reflect the amortization of investment tax credits generated
in prior years.
Consistent with rate-making policies of the Rhode Island Public Utilities
Commission (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) 1994 1993 1992
--------------------------------------------------------------------------
Computed tax at statutory rate $ 6,661 $ 6,352 $10,102
Increases (reductions) in tax resulting from:
Book versus tax depreciation not normalized 653 496 749
Costs associated with utility plant
retirements deducted for tax purposes (1,872) (1,756) (1,257)
Allowance for equity funds used during
construction (360) (190) (3)
Amortization of investment tax credits (508) (508) (508)
Adjustment of prior year tax accruals (150) (473)
All other differences 18 (47) (422)
----------------------------
Total federal income taxes $ 4,442 $ 3,874 $ 8,661
============================
Effective federal income tax rate 23.3% 21.3% 29.1%
============================
Note B - Federal Income Taxes (continued)
- -----------------------------
The Financial Accounting Standards Board established Statement of
Financial Accounting Standards (SFAS) No. 109, "Accounting for Income
Taxes" which became effective in 1993. The application of this new
standard did not have a significant impact on 1993 or 1994 net income.
The following table identifies the major components of total deferred
income taxes:
--------------------------------------------------------------------
At December 31, (In Millions) 1994 1993
--------------------------------------------------------------------
Deferred tax asset:
Plant related $ 2 $ 2
Investment tax credits 3 3
All other 13 13
------------------
18 18
------------------
Deferred tax liability:
Plant related (57) (53)
All other (31) (28)
------------------
(88) (81)
------------------
Net deferred tax liability $(70) $ (63)
==================
There were no valuation allowances for deferred tax assets deemed
necessary.
The deferred taxes resulting from timing differences which appeared on the
income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993)
primarily included deferred income taxes of $3 million in connection with
postretirement benefits other than pensions and $2 million related to
utility plant, partially offset by deferred tax credits of $1 million
associated with rate adjustment mechanisms.
Note C - Commitments and Contingencies
- --------------------------------------
1. Plant Expenditures:
The Company's utility plant expenditures are estimated to be $55 million
in 1995. At December 31, 1994, 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 environmental audit 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 U.S. Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for two sites (one of which is
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 $8 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 would be
successful. The Company believes that hazardous waste liabilities for all
sites of which it is aware will not be material to its financial position.
3. 1991 Rhode Island Filled Land Legislation:
The Company's title to properties which may be situated on filled lands
(including substations) has been called into question by a 1991 Rhode
Island Supreme Court case dealing with title to filled land. The
Company's title to the land on which the Manchester Street Station
property is located was cleared by legislation in July 1992, by the Rhode
Island legislature. The Company is challenging the 1991 ruling with
respect to another parcel of property.
Note D - 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 before 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 required contribution under federal law or
greater than the maximum tax deductible amount.
Net pension cost for 1994, 1993, and 1992 included the following
components:
-------------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
-------------------------------------------------------------------------
Service cost-benefits earned during the
period $ 1,877 $ 1,557 $ 1,558
Plus (less):
Interest cost on projected benefit
obligation 8,629 8,737 8,261
Return on plan assets at expected long-term
rate (9,024) (8,739) (8,572)
Amortization 567 (101) (125)
----------------------------
Net pension cost $ 2,049 $ 1,454 $ 1,122
============================
Assumptions used to determine pension cost:
Discount rate 7.25% 8.25% 8.50%
Average rate of increase in future
compensation levels 4.35% 5.35% 6.70%
Expected long-term rate of return on assets 8.75% 8.75% 9.00%
----------------------------
Actual return on plan assets $ 809 $13,545 $ 7,570
============================
Service cost for 1993 does not reflect costs incurred in connection with
an early retirement program offered by the Company in that year (see Note
D-3).
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:
Note D - Employee Benefits (continued)
- --------------------------
-------------------------------------------------------------------------
Retirement Plans (In Millions) 1994 1993
---------------------------------------------------------------------------
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
----------------------------------------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $251 $308 $251 $333
Non-vested 8 9 20 6
--------------------------------------
Total $259 $317 $271 $339
======================================
Reconciliation of funded status
Actuarial present value of
projected benefit liability $303 $355 $310 $383
Unrecognized prior service costs (8) (4) (8) (6)
SFAS No. 87 transition liability
not yet recognized (amortized) - (1) - (1)
Net loss not yet recognized
(amortized) (13) (33) (11) (45)
Additional minimum liability
recognized - - - 8
--------------------------------------
282 317 291 339
--------------------------------------
Pension fund assets at fair value 293 323 302 318
SFAS No. 87 transition asset not
yet recognized (amortized) (13) - (14) -
--------------------------------------
280 323 288 318
--------------------------------------
Accrued pension/(prepaid)
payments recorded on books $ 2 $ (6) $ 3 $ 21
======================================
The assumed discount rate and the assumed average rate of increase in
future compensation levels used to calculate pension cost changed
effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively.
The expected long-term rate of return on assets used to calculate pension
cost was not changed from the level shown in the table above. The plans'
funded status at December 31, 1994 was calculated using these revised
rates.
Plan assets are composed primarily of corporate equity, guaranteed
investment contracts, debt securities, and cash equivalents.
2. Postretirement Benefit Plans Other Than Pensions and Postemployment
Benefits:
In 1993, SFAS No. 106, "Employer's Accounting for Postretirement Benefits
Other Than Pensions" (PBOPs) went into effect. The Company provides
health care and life insurance coverage to eligible retired employees.
Note D - Employee Benefits (continued)
- --------------------------
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 1994 and 1993 included the following
components:
--------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993
--------------------------------------------------------------------
Service cost--benefits earned during
the period $ 1,252 $ 1,161
Plus (less):
Interest cost on the accumulated
benefit obligation 5,630 6,330
Return on plan assets at expected
long-term rate (1,640) (1,031)
Amortization 3,716 3,864
---------------------
Net postretirement benefit cost $ 8,958 $10,324
=====================
Actual return (loss) on plan assets $ (23) $ 1,047
=====================
The following table sets forth benefits earned and the plans' funded status:
-----------------------------------------------------------------------
At December 31, (In Millions) 1994 1993
-----------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 50 $ 54
Fully eligible active plan participants 10 7
Other active plan participants 14 22
------------------
Total benefits earned 74 83
Unrecognized transition obligation (70) (74)
Net gain (loss) not yet recognized 10 (1)
------------------
14 8
Plan assets at fair value 22 17
------------------
Prepaid postretirement benefit costs
recorded on books $ 8 $ 9
==================
----------------------------------------------------------------------
1995 1994 1993
----------------------------------------------------------------------
Assumptions used to determine
postretirement benefit cost:
Discount rate 8.25% 7.25% 8.25%
Expected long-term rate of return
on assets 8.50% 8.50% 8.50%
Health care cost rate - 1994 and 1993 - 11.00% 12.00%
Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50%
Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25%
Note D - Employee Benefits (continued)
- --------------------------
The plans' funded status at December 31,1994 and 1993 presented above was
calculated using the assumed rates in effect for 1995 and 1994,
respectively.
The health care cost trend rate assumption has 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, 1994 by approximately $11 million and the net periodic cost
for the year 1994 by approximately $1.2 million.
The Company funds the annual tax deductible contributions. Plan assets
are invested in equity and debt securities and cash equivalents.
Prior to 1993, the Company recorded the cost of PBOPs when paid. These
costs amounted to approximately $3.0 million in 1992. The Company has
been permitted by the RIPUC to phase-in over a three year period that
commenced January 1, 1993, a level of rate recovery that is expected to
equal or exceed the amount of PBOP costs calculated in accordance with
SFAS No. 106. At December 31, 1994, the Company had deferred for recovery
over a seven year period commencing January 1, 1996, $6 million,
representing that portion of increased PBOP costs not being recovered
during this phase-in period. Therefore, adoption of this new accounting
standard did not have a significant impact on net income.
In the fourth quarter of 1993, the Company recorded a $1 million charge
to earnings reflecting the cumulative effect of adopting a new accounting
standard for postemployment benefits.
3. 1993 Early Retirement and Special Severance Programs:
In February 1993, the Company offered a voluntary early retirement program
to non-union employees who were at least 55 years old with 10 years of
service. This program was part of an organizational review with the goal
of streamlining operations and reducing the work force. The early
retirement offer was accepted by 46 employees. A special severance
program was also announced in February 1993 for employees affected by the
organizational review, but who were not eligible for, or did not accept,
the early retirement offer. The Company recorded in the first quarter of
1993 a one-time charge to earnings of approximately $3 million, after tax
($5 million, before tax), to reflect the cost of the early retirement and
special severance programs which consisted principally of pension
benefits. This total includes the Company's portion of its affiliated
service company's cost of these programs.
Note E - Short-term Borrowing Arrangements
- ------------------------------------------
At December 31, 1994, the Company had $30 million of short-term debt
outstanding in the form of commercial paper borrowings. At December 31,
1994, the Company had lines of credit with banks totaling $41 million.
There were no borrowings under these lines of credit at December 31, 1994.
Fees are paid in lieu of compensating balances on most lines of credit.
The weighted average rate on outstanding short-term borrowings was 6.1
percent at December 31, 1994.
Note F - Intercompany Lending Arrangement
- -----------------------------------------
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.
Note G - Cumulative Preferred Stock
- -----------------------------------
A summary of cumulative preferred stock at December 31, 1994 and 1993 is
as follows (in thousands of dollars except for share data):
Shares
Authorized
and Dividends Call
Outstanding Amount Declared Price
-------------------------------------------------------------------------
1994 1993 1994 1993 1994 1993
-------------------------------------------------------------------------
$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 1,390 710 (a)
8.00% Series 468
--------------------------------------------------
Total 730,000 730,000 $36,500 $36,500 $2,143 $1,931
==================================================
(a) Callable on or after August 1, 2003 at $51.74.
The annual dividend requirement for total cumulative preferred stock was
$2,143,000 for 1994 and 1993.
During 1993, all of the Company's 8.00 percent Series of cumulative
preferred stock were redeemed. Total premiums of $361,000 in connection
with this redemption were charged to retained earnings in 1993. There are
no mandatory redemption provisions on the Company's cumulative preferred
stock.
Note H - Long-term Debt
- -----------------------
A summary of long-term debt is as follows:
At December 31, (In Thousands)
-------------------------------------------------------------
Series Rate % Maturity 1994 1993
-------------------------------------------------------------
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 (94-2) 6.960 May 3, 1999 2,000
V (94-3) 6.910 May 4, 1999 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
V (94-6) 8.330 November 8, 2004 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 40,000 40,000
U (93-5) 7.050 September 1, 2023 5,000 5,000
U (94-1) 7.050 February 2, 2024 5,000
V (94-1) 8.080 May 2, 2024 5,000
V (94-5) 8.160 August 9, 2024 5,000
Unamortized discounts and premiums (1,338) (1,228)
-------------------
Total long-term debt $188,862 $155,972
===================
Substantially all of the properties and franchises of the Company are
subject to the lien of the mortgage indentures under which first mortgage
bonds have been issued.
The Company will make cash payments of $32,500,000 in 1997 and $8,000,000
in 1999 to retire maturing mortgage bonds. There are no cash payments
required in 1995, 1996, and 1998.
Note I - Fair Value of Financial Instruments
- --------------------------------------------
At December 31, 1994, the Company's long-term debt had a carrying value
of approximately $189,000,000 and had a fair value of approximately
$183,000,000. 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. The
fair value of the Company's short-term debt equals carrying value.
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, 1994 was 48 percent of total capitalization and,
accordingly, none of the Company's retained earnings at December 31, 1994
were restricted as to dividends on common stock under the foregoing
restrictions.
Under restrictions contained in the indentures relating to first mortgage
bonds, none of the Company's retained earnings at December 31, 1994 were
restricted as to dividends on common stock.
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. Taxes, other than
federal income taxes, charged to operating expenses are set forth by
classes as follows:
-----------------------------------------------------------------------
Year Ended December 31, (In Thousands) 1994 1993 1992
-----------------------------------------------------------------------
Municipal property taxes $13,944 $13,798 $13,509
State gross earnings tax 19,270 19,281 18,730
Federal and state payroll and other taxes 2,604 2,767 2,933
----------------------------
$35,818 $35,846 $35,172
============================
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 $32,445,000, $30,133,000, and
$23,543,000 including capitalized construction costs of $7,756,000,
$6,602,000, and $5,436,000 for each of the years 1994, 1993, and 1992,
respectively.
The Narragansett Electric Company
Operating Statistics (Unaudited)
- ------------------------------------------------------------------------------------------
Year Ended December 31, 1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------
Sources of Energy (Thousands of KWH)
Net generation for New England
Power Company 5,781 4,506 83,753 162,844 583,413
Purchased energy:
From New England Power
Company, an affiliate
(net of generation) 5,001,843 4,982,254 4,729,733 4,699,509 4,272,537
From others 2,909 2,343 2,249 2,243 1,556
--------------------------------------------------------
Total generated and purchased 5,010,533 4,989,103 4,815,735 4,864,596 4,857,506
Losses, company use, etc. (263,234) (270,373) (229,106) (277,383) (265,328)
--------------------------------------------------------
Total sources of energy 4,747,299 4,718,730 4,586,629 4,587,213 4,592,178
========================================================
Sales of Energy (Thousands of KWH)
Residential 1,843,970 1,817,675 1,783,754 1,784,156 1,794,215
Commercial 1,983,508 1,931,377 1,877,738 1,867,225 1,879,587
Industrial 868,092 917,305 869,062 878,142 858,675
Other 51,138 51,821 55,476 57,106 59,099
--------------------------------------------------------
Total sales to
ultimate customers 4,746,708 4,718,178 4,586,030 4,586,629 4,591,576
Sales for resale 591 552 599 584 602
--------------------------------------------------------
Total sales of energy 4,747,299 4,718,730 4,586,629 4,587,213 4,592,178
========================================================
Annual Maximum Demand
(Kw - one hour peak) 1,005,000 939,000 919,000 961,000 940,000
Average Annual Use per
Residential Customer (KWH) 6,397 6,337 6,265 6,308 6,387
Number of Customers at
December 31
Residential 289,317 287,876 286,228 284,275 282,314
Commercial 32,195 31,948 31,534 31,417 31,591
Industrial 1,825 1,869 1,914 1,944 1,983
Other 875 878 941 934 906
--------------------------------------------------------
Total ultimate customers 324,212 322,571 320,617 318,570 316,794
Other electric companies
(for resale) 2 1 3 4 3
--------------------------------------------------------
Total customers 324,214 322,572 320,620 318,574 316,797
========================================================
Operating Revenue (In Thousands)
Residential $201,221 $202,522 $196,983 $192,688 $172,804
Commercial 189,633 190,185 183,702 178,616 162,013
Industrial 72,364 78,088 76,275 76,299 68,644
Other 6,905 6,778 6,587 6,197 5,500
--------------------------------------------------------
Total revenue from
ultimate customers 470,123 477,573 463,547 453,800 408,961
Unbilled revenues 4,891
Sales for resale 68 64 68 65 62
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Total revenue from
electric sales 475,082 477,637 463,615 453,865 409,023
Other operating revenue 6,587 5,391 4,637 3,645 3,250
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Total operating revenue $481,669 $483,028 $468,252 $457,510 $412,273
========================================================
The Narragansett Electric Company
Selected Financial Information
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Year Ended December 31, (In Millions) 1994 1993 1992 1991 1990
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Operating revenue:
Electric sales
(excluding fuel cost recovery) $356 $351 $342 $340 $308
Fuel cost recovery 120 127 121 114 101
Other 6 5 5 4 3
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Total operating revenue $482 $483 $468 $458 $412
Net income $ 15 $ 14 $ 21 $ 17 $ 18
Total assets $647 $556 $479 $445 $421
Capitalization:
Common equity $208 $183 $176 $151 $136
Cumulative preferred stock 37 37 27 27 27
Long-term debt 189 156 143 118 112
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Total capitalization $434 $376 $346 $296 $275
Preferred dividends declared $ 2 $ 2 $ 2 $ 2 $ 2
Common dividends declared $ 3 $ 5 $ 5 $ 5 $ 8
Selected Quarterly Financial Information (Unaudited)
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First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
- ---------------------------------------------------------------------------------------
1994
Operating revenue $125,461 $103,800 $137,014 $115,394
Operating income $ 10,407 $ 2,714 $ 10,937 $ 6,056
Net income (loss) $ 6,314 $ (1,013) $ 7,230 $ 2,058
1993
Operating revenue $124,147 $107,529 $136,174 $115,178
Operating income $ 8,220 $ 3,937 $ 9,761 $ 6,647
Net income $ 3,800 $ 493 $ 6,435 $ 3,546
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, 1994, will be available on or
about April 1, 1995, without charge, upon written request to The Narragansett Electric
Company, Shareholder Services Department, 280 Melrose Street, Providence, Rhode Island
02901.