Annual Report 1995
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 December 31, 1995)
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
President, 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 Vice President of New England Electric System
William E. Trueheart
President of Bryant College, Smithfield, Rhode Island
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 December 31, 1995)
Richard P. Sergel
Chairman of the Company and Vice President of New England Electric System
Robert L. McCabe
President and Chief Executive Officer
William Watkins, Jr.
Executive Vice President
Francis X. Beirne
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
Richard Nadeau
Vice President
Marcy L. Reed
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
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 328,000 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. There are a number of
proposals that would increase competition in the electric utility industry and
result in customers having a choice of power suppliers (see "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 a recently repowered 489 megawatt steam-electric generating
station. 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, 1995 and 1994 and the related statements
of income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1995. 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, 1995 and 1994, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1995 in conformity
with generally accepted accounting principles.
Boston, Massachusetts COOPERS & LYBRAND L.L.P.
March 1, 1996
The Narragansett Electric Company
Financial Review
Overview
Net income for 1995 increased $9 million compared with 1994. This increase
reflects the 1995 commencement of the recovery of the Company's investment in
the Manchester Street Station, which went into service in the second half of
1995, 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.
Net income increased by $300,000 in 1994. The increase was primarily due
to the inclusion of a one-time charge in 1993 associated with an early
retirement program. The increase also reflects kilowatt-hour (kWh) sales
growth in 1994, the commencement of recognition of unbilled revenues and
increased allowance for funds used during construction. These increases were
largely offset by rate discounts to large commercial and industrial customers,
increases in other operation expenses, and increased interest expense.
Competitive Conditions
The electric utility business is being subjected to rapidly increasing
competitive pressures, stemming from a combination 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. To date, this competition has been most prominent in the
bulk power market, in which non-utility generators have significantly
increased their market share. Electric utilities have had exclusive
franchises for the retail sale of electricity in specified service
territories. As a result, competition in the retail market has been limited
to (i) competition with alternative fuel suppliers, primarily for heating and
cooling, (ii) competition with customer-owned generation, and (iii) direct
competition among electric utilities to attract major new facilities to their
service territories. These competitive pressures have led the Company and
other utilities to offer, from time to time, special discounts or service
packages to certain large customers.
In states across the country, including Rhode Island, there have been an
increasing number of 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"). If electric customers were allowed to choose their
electricity supplier, the Company's role would change and it would provide
only distribution services. Power would be provided by power generators and
marketers, which could be either affiliated or non-affiliated companies. In
these competitive circumstances, utilities across the country that operate
generation plants, such as the Company's affiliate, New England Power Company
(NEP), would face the risk that market prices may not be sufficient to recover
the costs of the commitments incurred to supply customers under a regulated
industry structure. The amount by which costs exceed market prices is
commonly referred to as "stranded costs."
The Company purchases electricity on behalf of its customers under a
wholesale all-requirements contract with NEP. NEP derives approximately 20
percent of its electric sales revenues from sales to the Company.
Choice: New England
In October 1995, the New England Electric System (NEES) companies announced
a plan to allow all customers of electric utilities in Massachusetts, Rhode
Island, and New Hampshire to choose their power supplier beginning in 1998.
The plan, Choice: New England, was developed in response to 1995 decisions by
the Rhode Island Public Utilities Commission (RIPUC) and the Massachusetts
Department of Public Utilities that approved a set of principles for industry
restructuring. These principles include allowing utilities the opportunity to
recover stranded costs. In March 1995, the RIPUC ordered all utilities in
Rhode Island to file restructuring plans by April 12, 1996. In response to a
RIPUC order, the Company plans to file a similar version of Choice: New
England with the RIPUC in April 1996.
Under Choice: New England, the Company would no longer sell electricity to
its customers. Instead, customers would purchase electricity from a supplier
of their choice, with the Company remaining responsible for providing
distribution services to customers under regulated rates. Transmission
services would be provided by a new affiliate of the Company, which would be
formed by NEES to provide comparable service across the NEES companies'
transmission system. Initially, the new affiliate would have operational
control of the Company's transmission facilities, but may, at a later date,
acquire those facilities from the Company. The net book value of the
Company's transmission system is approximately $80 million.
Under Choice: New England, the pricing of generation would be deregulated.
However, customers would have the right to receive service under a "standard
offer" from the incumbent utility or its affiliate, the pricing of which would
be approved in advance by legislators or regulators. Customers electing the
standard offer would be eligible to choose an alternative power supplier at
any time, but would not be allowed to return to the standard offer.
Under Choice: New England, the Company's wholesale contract with NEP would
be terminated. In return, Choice: New England proposes that the cost of NEP's
past generation commitments be recovered from the Company and its retail
affiliates through a contract termination charge. The Company would, in turn,
seek to recover the payments to NEP through a wires access or transition
charge to retail customers. Those commitments primarily consist of (i)
generating plant commitments, (ii) regulatory assets, (iii) purchased power
contracts, and (iv) the operating cost of nuclear plants which cannot be
mitigated by shutting down the plants (otherwise referred to as "nuclear costs
independent of operation"). The portion of these commitments incurred by NEP
to serve the Company's customers is currently estimated at approximately $1
billion on a present value basis. Sunk costs associated with utility
generating plants, such as past capital investments, and regulatory assets
would be recovered over ten years. Purchased power contract costs and nuclear
costs independent of operation would be recovered as incurred over the life of
those obligations, a period expected to extend beyond ten years. The access
charge would be set at three cents per kWh for the first three years.
Thereafter, the access charge would vary, but is expected to decline. The
provisions of Choice: New England, including the proposed access charge, are
subject to state approval and Federal Energy Regulatory Commission (FERC)
approval.
Rhode Island Legislation
In February 1996, the Speaker and Majority Leader of the House of
Representatives of the Rhode Island Legislature announced the filing of
legislation which would allow electric consumers in Rhode Island to choose
their power supplier. Under the proposed legislation, large manufacturing
customers and new large non-manufacturing customers would gain access to
alternative power suppliers over a two-year period beginning in 1998. These
customers represent approximately 14 percent of the Company's retail kWh
sales. The balance of Rhode Island customers would gain access over a
two-year period beginning in the year 2000, or earlier if consumers of 50
percent of the electricity in New England gain similar rights to choose their
power supplier. The NEES companies have announced their support for the
proposed legislation.
A key provision of the legislation authorizes utilities to recover the cost
of past generation commitments through a transition access charge on utility
distribution wires. The legislation divides those past commitments in the
same manner as Choice: New England. The legislation proposes a 12-year
recovery period for utility generation commitments and
regulatory assets. The legislation would require the Company to transfer its
10 percent share of the Manchester Street Station and its transmission
facilities to separate affiliates at net book value. (See "Repowering of
Manchester Street Station" section.)
The legislation also establishes performance-based rates for distribution
utilities, such as the Company. Under the legislation, the Company would be
entitled to increase its distribution rates by approximately $10 million
annually, for the period 1997 through 1999, less any increases in wholesale
base rates from NEP passed on by the Company to customers. For those three
years, the Company's return on equity would be subject to a floor of 6 percent
and a ceiling of 11 percent. Earnings over the ceiling would be shared
equally between customers and shareholders up to an absolute cap on return on
equity of 12.5 percent. To the extent that earnings fall below the floor, the
Company would be authorized to surcharge customers for the shortfall.
Consideration by the Rhode Island Legislature of the proposed legislation is
expected to be completed by the summer of 1996.
Previously, in 1995, the Rhode Island Legislature passed legislation that
would have allowed certain industrial customers to buy power from alternative
suppliers, rather than through the local electric utility. The Company urged
the Governor of Rhode Island to veto the legislation because the Company
believed it would result in piecemeal deregulation that would not be fair to
customers or shareholders. The Governor vetoed the proposed legislation, in
part because of commitments by the Company to provide a two-year rate discount
to manufacturing customers (see "Rate Activity" section) and to submit a
specific and detailed proposal to the RIPUC addressing the issues associated
with providing large customers with access to the Company's distribution
system for the purpose of choosing an alternative power supplier.
Other Regulatory Initiatives
In March 1995, the FERC issued a Notice of Proposed Rulemaking in which it
stated that it is appropriate that legitimate and verifiable stranded costs be
recovered from departing customers as a result of wholesale competition. The
FERC also indicated that costs stranded as a result of retail competition
would be subject to state commission review if the necessary statutory
authority exists and subject to FERC review if the state commission does not
have such authority. A final decision is expected during 1996.
Risk Factors
The major risk factors affecting the Company relate to the possibility of
adverse regulatory decisions or legislation which limit the level of revenues
the Company is allowed to charge for its services. The Company's
all-requirements purchased power contract with NEP requires either party to
give seven years notice prior to terminating the contract. Termination of the
contract would create stranded costs at NEP that NEP would seek to recover
from the Company pursuant to the contract. In that event, the Company would
seek recovery of such stranded costs from its customers. However, there is no
assurance that the final restructuring plans ordered by state regulatory
bodies or state legislatures will include provisions that allow the Company to
fully recover any stranded costs passed on to the Company by NEP. In such an
event, the Company could be faced with a significant amount of costs being
billed to it by NEP that the Company could not fully recover from retail
customers, for which the Company would seek a remedy in the courts.
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 liabilities, and thereby
defer the income statement impact of certain costs that are expected to be
recovered in future rates. The effects of regulatory, legislative, or utility
initiatives could, in the near future, cause all or a portion of the Company's
operations to cease meeting the criteria of FAS 71. In that event, the
application of FAS 71 to such operations would be discontinued and a non-cash
write-off of previously established regulatory assets and liabilities related
to such operations would be required. At December 31, 1995, the Company had
pre-tax regulatory assets (net of regulatory liabilities) of approximately $48
million. If competitive or regulatory change should cause a substantial
revenue loss or lead to the permanent shutdown of any generating facilities, a
write-down of plant assets could be required pursuant to Financial Accounting
Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of (FAS 121). In addition, FAS 121 requires
that all regulatory assets, which must have a high probability of recovery to
be initially established, must continue to meet that high probability standard
to avoid being written off. FAS 121, which is effective for the Company in
January 1996, is not expected to have a material adverse impact on the
financial condition or results of operations upon adoption, based on the
current regulatory environment in which the Company operates. However, the
impact in the future may change as competitive factors and potential
restructuring influence the electric utility industry. For a further
discussion, see Note B.
Rate Activity
The RIPUC approved a settlement agreement that provides for a $15 million
increase to base rates for the Company effective December 1, 1995. The RIPUC
also approved $3 million of new discounts for manufacturing customers, the
costs of which are not being recovered from other customers.
In February 1995, the FERC approved a rate agreement, effective in January
1995, for NEP. This rate agreement, among other things, increased the credits
the Company receives from NEP for the costs of owning and operating its
generation and transmission facilities by $14 million on an annual basis. The
Company supplies all of the output of its generating facilities to NEP. The
increase in the credits reflects the Company's 10 percent investment in the
Manchester Street Station, which entered commercial operation in the second
half of 1995, and the transmission facilities associated with the station,
which were placed in service in September 1994. An additional increase in
these credits of approximately $2 million took effect in January 1996.
In 1994, the RIPUC approved a rate agreement between the Company and the
Rhode Island Division of Public Utilities and Carriers that provided for the
Company to recognize, for accounting purposes, $14 million of unbilled
revenues over a 21 month period which ended in December 1995. The agreement
further provided for rate discounts for large commercial and industrial
customers who signed agreements to give a five-year notice to the Company
before they purchase power from another supplier or generate any additional
power themselves. In addition, commencing in 1995 the cost of these discounts
is being passed on to NEP as a result of the NEP rate settlement referred to
above.
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. 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 (DSM)
The Company has received approval from the RIPUC to recover DSM program
expenditures in rates on a current basis. These expenditures were $9 million,
$10 million, and $12 million in 1995, 1994, and 1993, 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 $0.5 million,
$0.6 million, and $0.5 million in 1995, 1994, and 1993, respectively.
Operating Revenue
The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
(In Millions) 1995 1994
---- ----
Sales growth $2 $5
Fuel recovery 11 (7)
Rate changes/service extension discounts (SEDs) 1
Unbilled revenues recognized under rate agreements 2 5
Purchased power cost adjustment (PPCA) mechanism 1 (2)
DSM recovery (1) (2)
Other 1
---- ----
$17 $(1)
==== ====
In 1995, kWh sales to ultimate customers increased 0.3 percent over 1994.
A warmer summer in 1995 and a return to more normal weather in the fourth
quarter of 1995 was largely offset by unusually mild weather in the first
quarter of 1995.
In 1994, kWh sales to ultimate customers increased by 0.6 percent over 1993
reflecting an improved regional economy, partially offset by a loss of sales
attributable to the May 1994 plant closing of one of the Company's largest
customers.
In the third quarter of 1994, the Company began recognizing electricity
delivered but not yet billed (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.
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.
Operating Expenses
The following table summarizes the changes in operating expenses:
Increase (Decrease) in Operating Expenses
(In Millions) 1995 1994
---- ----
Purchased electric energy:
Fuel costs $11 $(7)
Integrated facilities credit from NEP (19) (6)
SED reimbursements (2)
Purchases and demand charges and other 2 3
Other operation and maintenance (1) (1)
Depreciation 7 7
Taxes 7 1
---- ----
$5 $(3)
==== ====
The 1995 increase in fuel costs from NEP reflects decreased nuclear
generation due to overhauls and decreased hydro production resulting from low
water levels. The decrease in the fuel cost component of purchased power in
1994 includes a decrease 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 Company owns a 10 percent share of the Manchester Street Station and
also owns the seven mile underground transmission line associated with this
facility as well as other transmission facilities in Rhode Island. The
Company's share of the electricity generated by this plant is made available
to NEP which owns the remaining 90 percent of the station. The Company
receives a credit on its purchased power bill from NEP reflecting rate
recovery of its investment in the station and the transmission line, and for
its fuel costs and other generation and transmission costs. The increase in
the integrated facilities credits from NEP is primarily due to the recovery of
the Company's investment in the repowered Manchester Street Station that went
into service in the second half of 1995 and the related transmission line
which was placed in service in September 1994. The increased credits in both
1995 and 1994 also reflect the reimbursement of increased dismantlement costs
being incurred on the Company's previously retired South Street generating
station. These increased costs for dismantlement are reflected in the
increases in depreciation in the above table.
The reduction in other operation and maintenance expenses in 1995 reflects
decreased distribution related expenses, partially offset by increased
postretirement benefit expenses.
The increase in operation and maintenance expenses in 1994 reflects
increased computer system development costs, postretirement benefit expenses
and general increases in other areas, partially offset by a one-time charge of
$5 million in 1993 associated with an early retirement program.
The increase in taxes in 1995 is primarily due to increased income.
Allowance for Funds Used During Construction (AFDC)
AFDC decreased in 1995 due to the completion in 1994 of transmission
facilities related to the Manchester Street Station repowering project,
partially offset by additional spending in 1995 on the generating station
itself. AFDC increased in 1994 due to increased construction work in progress
associated with the Manchester Street Station and related transmission
facilities (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 a range
of potentially hazardous products and by-products in its operations. NEES
subsidiaries currently have an environmental audit program in place 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 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.
Electric and Magnetic Fields (EMF)
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.
Utility Plant Expenditures and Financings
Cash expenditures for utility plant totaled $73 million in 1995, including
$13 million related to the Manchester Street Station repowering project
discussed below. The funds necessary for utility plant expenditures during
1995 were primarily provided by net cash from operating activities, after the
payment of dividends, long-term debt issues, and capital contributions from
NEES. Cash expenditures for utility plant for 1996 are estimated to be
approximately $50 million. Internally generated funds are estimated to
provide 95 percent of these needs in 1996. Cash expenditures for utility
plant are also expected to be funded through the issuance of long-term debt.
In 1995, the Company issued $38 million of first mortgage bonds bearing
interest rates ranging from 7.30 percent to 7.81 percent. In November 1995,
the Company retired $16 million of first mortgage bonds prior to maturity and
incurred premiums of $1.9 million. The Company has refinanced $2 million of
long-term debt to date in 1996 at an interest rate of 7.24 percent and plans
to issue an additional $10 million of long-term debt later in 1996.
At December 31, 1995, the Company had $23 million of short-term debt
outstanding including $22 million of commercial paper borrowings and $1
million of borrowings from affiliates. As of December 31, 1995, the Company
had lines of credit with banks totaling $41 million. There were no borrowings
under these lines of credit at December 31, 1995.
Repowering of Manchester Street Station
In the second half of 1995, NEP and the Company completed the 489 megawatt
repowering of the Manchester Street Station. NEP owns a 90 percent interest
and the Company owns a 10 percent interest in the Manchester Street Station.
The total cost for the generating station will be approximately $450 million
including AFDC, of which the Company's share will be approximately $40
million. In addition, related transmission improvements were placed in
service in September 1994 at a cost of approximately $60 million, of which the
Company's share was $45 million.
March 25, 1996
The Narragansett Electric Company
Statements of Income
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Operating revenue $499,113 $481,669 $483,028
-------- -------- --------
Operating expenses:
Purchased electric energy, principally
from New England Power Company,
an affiliate 293,272 300,678 310,895
Other operation 73,194 73,082 73,723
Maintenance 11,174 12,281 12,179
Depreciation 31,533 24,813 17,645
Taxes, other than federal income taxes 36,627 35,818 35,846
Federal income taxes 10,888 4,883 4,175
-------- -------- --------
Total operating expenses 456,688 451,555 454,463
-------- -------- --------
Operating income 42,425 30,114 28,565
-------- -------- --------
Other income:
Allowance for equity funds used
during construction 106 1,028 543
Other income (expense), net (192) (856) (634)
-------- -------- --------
Operating and other income 42,339 30,286 28,474
-------- -------- --------
Interest:
Interest on long-term debt 16,627 14,334 12,715
Other interest 3,663 2,897 2,074
Allowance for borrowed funds used during
construction credit (1,861) (1,534) (589)
-------- -------- --------
Total interest 18,429 15,697 14,200
-------- -------- --------
Net income $23,910 $14,589 $14,274
======== ======== ========
Statements of Retained Earnings
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Retained earnings at beginning of year $91,556 $81,659 $74,207
Net income 23,910 14,589 14,274
Dividends declared on cumulative
preferred stock (2,143) (2,143) (1,931)
Dividends declared on common stock,
$4.50, $2.25, and $4.00 per share,
respectively (5,096) (2,549) (4,530)
Premium on redemption of preferred stock (361)
-------- -------- --------
Retained earnings at end of year $108,227 $91,556 $81,659
======== ======== ========
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Balance Sheets
At December 31, (In Thousands) 1995 1994
---- ----
Assets
Utility plant, at original cost $699,906 $617,498
Less accumulated provisions for depreciation 173,391 161,557
-------- --------
526,515 455,941
Construction work in progress 8,733 35,974
-------- --------
Net utility plant 535,248 491,915
-------- --------
Current assets:
Cash 1,999 713
Accounts receivable:
From sales of electric energy 59,760 51,278
Other (including $1,464 and $9,306 from affiliates) 9,330 17,953
Less reserves for doubtful accounts 5,516 4,472
-------- --------
63,574 64,759
Unbilled revenues (Note A-3) 16,500 13,100
Fuel, materials, and supplies, at average cost 6,245 5,170
Prepaid and other current assets 15,887 13,993
-------- --------
Total current assets 104,205 97,735
-------- --------
Deferred charges and other assets (Note B) 60,168 57,727
-------- --------
$699,621 $647,377
======== ========
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 60,000
Retained earnings 108,227 91,556
-------- --------
Total common equity 245,021 208,350
Cumulative preferred stock, par value $50 per share 36,500 36,500
Long-term debt 210,892 188,862
-------- --------
Total capitalization 492,413 433,712
-------- --------
Current liabilities:
Short-term debt (including $1,000 to
affiliates in 1995) 22,675 29,800
Accounts payable (including $38,510 and
$47,900 to affiliates) 46,247 56,139
Accrued liabilities:
Taxes 6,380 143
Interest 5,847 5,615
Other accrued expenses (Note F) 19,558 25,346
Customer deposits 5,691 5,261
Dividends payable 1,102 819
-------- --------
Total current liabilities 107,500 123,123
-------- --------
Deferred federal income taxes 76,017 70,253
Unamortized investment tax credits 8,016 8,518
Other reserves and deferred credits 15,675 11,771
Commitments and contingencies (Note D)
-------- --------
$699,621 $647,377
======== ========
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) 1995 1994 1993
---- ---- ----
Operating activities:
Net income $23,910 $14,589 $14,274
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation 31,533 24,813 17,645
Deferred federal income taxes and
investment tax credits, net 3,009 3,422 1,690
Allowance for funds used during
construction (1,967) (2,562) (1,132)
Amortization of unbilled revenues (8,209) (6,158)
Early retirement program 2,705
Decrease (increase) in accounts receivable,
net and unbilled revenues (2,215) (14,163) (2,183)
Decrease (increase) in fuel, materials,
and supplies (1,075) (598) 429
Decrease (increase) in prepaid and
other current assets (1,894) (2,478) 2,359
Increase (decrease) in accounts payable (9,892) 5,134 (3,180)
Increase (decrease) in other
current liabilities 9,320 12,312 2,287
Other, net 5,931 5,877 (2,180)
--------- --------- ---------
Net cash provided by operating
activities $48,451 $40,188 $32,714
--------- --------- ---------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(72,897) $(92,503) $(62,897)
Other investing activities (251) (911)
--------- --------- ---------
Net cash used in investing activities $(73,148) $(93,414) $(62,897)
--------- --------- ---------
Financing activities:
Capital contributions from NEES $20,000 $15,000
Dividends paid on common stock (4,813) (2,831) $(5,663)
Dividends paid on preferred stock (2,143) (2,143) (1,783)
Changes in short-term debt (7,125) 10,075 16,050
Long-term debt issues 38,000 33,000 27,500
Long-term debt retirements (16,000) (14,900)
Preferred stock issues 20,000
Preferred stock retirements (10,000)
Premium on reacquisition of long-term debt (1,936) (652)
Premium on redemption of preferred stock (361)
--------- --------- ---------
Net cash provided by
financing activities $25,983 $53,101 $30,191
--------- --------- ---------
Net increase (decrease) in cash and
cash equivalents $1,286 $(125) $8
Cash and cash equivalents at
beginning of year 713 838 830
--------- --------- ---------
Cash and cash equivalents at end of year $1,999 $713 $838
========= ========= =========
Supplementary Information:
Interest paid less amounts capitalized $17,050 $14,015 $12,623
--------- --------- ---------
Federal income taxes paid $1,084 $2,982 $2,352
--------- --------- ---------
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
328,000 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 a recently repowered 489 megawatt steam-electric generating station.
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 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.
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, pursuant to its 1994 rate agreement, began accruing revenues for
electricity delivered but not yet billed (unbilled revenues). Unbilled
revenues at December 31, 1995 and 1994 were $17 million and $13 million,
respectively, of which $12 million and $5 million were recognized in income in
the respective years. Included in these income amounts are $8 million in 1995
and $6 million in 1994 which represent amortization of the initial effect of
recording unbilled revenues in accordance with the rate agreement. Other
accrued revenues are 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 eligible for inclusion in rate base. In
1995, an average of $4 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 6.2 percent, 6.8 percent, and 6.9 percent in 1995,
1994, and 1993, 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 5.0
percent, 4.5 percent, and 3.5 percent in 1995, 1994, and 1993, respectively.
The increase in the depreciation rates in 1995 and 1994 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 - Competitive Conditions
The electric utility business is being subjected to rapidly increasing
competitive pressures and increasing demands for customer choice. Accordingly,
the companies within the NEES system have developed a plan, Choice: New
England, which would allow all customers of electric utilities in the states
the NEES companies serve to choose their power supplier beginning in 1998. The
Company plans to file a similar version of Choice: New England with the Rhode
Island Public Utilities Commission (RIPUC) in April 1996. Under Choice: New
England, pricing of generation would be deregulated while transmission and
distribution rates would remain regulated. Choice: New England proposes that
the cost of past commitments to serve customers be recovered through a wires
access or transition charge. Those past commitments include generating plant
commitments, regulatory assets, purchased power contracts, and nuclear costs
independent of operation.
In addition, legislation has been introduced in the Rhode Island House of
Representatives by the House leadership that would allow customers to choose
their power supplier on a phased-in basis beginning in 1998. It also provides
that past commitments be recovered through a wires access or transition
charge.
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 liabilities, and thereby
defer the income statement impact of certain costs that are expected to be
recovered in future rates. The effects of regulatory, legislative, or utility
initiatives could, in the near future, cause all or a portion of the Company's
operations to cease meeting the criteria of FAS 71. In that event, the
application of FAS 71 to such operations would be discontinued and a non-cash
write-off of previously established regulatory assets and liabilities related
to such operations would be required. In March 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of (FAS 121). This standard clarifies when and how to recognize
an impairment of long-lived assets. If competitive or regulatory change should
cause a substantial revenue loss or lead to the permanent shutdown of any
generating facilities, a write-down of plant assets could be required pursuant
to FAS 121. In addition, FAS 121 requires that all regulatory assets, which
must have a high probability of recovery to be initially established, must
continue to meet that high probability standard to avoid being written off.
However, if written off, a regulatory asset can be restored if it again has a
high probability of recovery. FAS 121, which is effective for the Company in
January 1996, is not expected to have a material adverse impact on the
financial condition or results of operations upon adoption, based on the
current regulatory environment in which the Company operates. However, the
impact in the future may change as competitive factors and potential
restructuring influence the electric utility industry.
The components of regulatory assets are as follows:
At December 31, (In Thousands) 1995 1994
---- ----
Regulatory assets (liabilities) included in current assets
and liabilities:
Rate adjustment mechanisms $(7,661) $(8,382)
Unamortized unbilled revenues (see Note A-3) (8,209)
-------- --------
(7,661) (16,591)
-------- --------
Regulatory assets included in deferred charges:
Deferred SFAS No. 109 costs (see Note C) 29,251 26,999
Unamortized losses on reacquired debt 13,918 12,538
Deferred SFAS No. 106 costs (see Note E 2) 4,894 5,539
Deferred storm costs 3,676 4,277
Other 3,900 3,751
-------- --------
55,639 53,104
-------- --------
$47,978 $36,513
======== ========
Amounts included in "Deferred charges and other assets" on the Company's
balance sheets that do not represent regulatory assets totaled $4,529,000 and
$4,623,000 at December 31, 1995 and 1994, 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) 1995 1994 1993
---- ---- ----
Income taxes charged to operations:
Current income taxes $7,560 $1,511 $2,537
Deferred income taxes 3,831 3,880 2,146
Investment tax credits, net (503) (508) (508)
------- ------- -------
Total income taxes charged to operations 10,888 4,883 4,175
------- ------- -------
Income taxes charged (credited) to "Other income":
Current income taxes (348) (491) (354)
Deferred income taxes (319) 50 53
------- ------- -------
Total income taxes charged (credited) to
"Other income" (667) (441) (301)
------- ------- -------
Total federal income taxes $10,221 $4,442 $3,874
======= ======= =======
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) 1995 1994 1993
---- ---- ----
Computed tax at statutory rate $11,946 $6,661 $6,352
Increases (reductions) in
tax resulting from:
Book versus tax depreciation not normalized 529 653 496
Costs associated with utility
plant retirements deducted
for tax purposes (1,768) (1,872) (1,756)
Allowance for equity funds used
during construction (37) (360) (190)
Amortization of investment tax credits (503) (508) (508)
Adjustment of prior year tax accruals (47) (150) (473)
All other differences 101 18 (47)
------- ------- -------
Total federal income taxes $10,221 $4,442 $3,874
======= ======= =======
The following table identifies the major components of total deferred income
taxes:
At December 31, (In Millions) 1995 1994
---- ----
Deferred tax asset:
Plant related $2 $2
Investment tax credits 3 3
All other 13 13
----- -----
18 18
===== =====
Deferred tax liability:
Plant related (62) (57)
All other (32) (31)
----- -----
(94) (88)
----- -----
Net deferred tax liability $(76) $(70)
===== =====
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 $50
million in 1996. At December 31, 1995, 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 a range of
potentially hazardous products and by-products in its operations. NEES
subsidiaries currently have an environmental audit program in place 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 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.
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 1995, 1994, and 1993 included the following components:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Service cost benefits earned
during the period $1,963 $1,877 $1,557
Plus (less):
Interest cost on projected
benefit obligation 9,327 8,629 8,737
Return on plan assets at expected
long-term rate (9,567) (9,024) (8,739)
Amortization 67 567 (101)
------- ------- -------
Net pension cost $1,790 $2,049 $1,454
------- ------- -------
Actual return on plan assets $25,192 $809 $13,545
======= ======= =======
1996 1995 1994 1993
---- ---- ---- ----
Assumptions used to determine
pension cost:
Discount rate 7.25% 8.25% 7.25% 8.25%
Average rate of increase in
future compensation levels 4.13% 4.63% 4.35% 5.35%
Expected long-term rate of
return on assets 8.50% 8.75% 8.75% 8.75%
Service cost for 1993 does not reflect $5 million of costs incurred in
connection with an early retirement and special severance program offered by
the Company in that year.
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) 1995 1994
---- ----
Union Non-Union Union Non-Union
Employee Employee Employee Employee
Plans Plans Plans Plans
------ ------ ------ ------
Benefits earned
Actuarial present value of
accumulated benefit liability:
Vested $293 $343 $251 $308
Non-vested 8 10 8 9
---- ---- ---- ----
Total $301 $353 $259 $317
==== ==== ==== ====
Reconciliation of funded status
Actuarial present value of
projected benefit liability $346 $402 $303 $355
Unrecognized prior service costs (7) (4) (8) (4)
Unrecognized transition liability (1) (1)
Unrecognized net loss (1) (23) (13) (33)
---- ---- ---- ----
338 374 282 317
---- ---- ---- ----
Pension fund assets at fair value 349 392 293 323
Unrecognized transition asset (11) (13)
---- ---- ---- ----
338 392 280 323
---- ---- ---- ----
Accrued pension/(prepaid)
payments recorded on books $ - $(18) $ 2 $ (6)
The plans' funded status at December 31, 1995 and 1994 were calculated using
the assumed rates from 1996 and 1995, respectively, and the 1983 Group Annuity
Mortality table.
Plan assets are composed primarily of corporate equity, guaranteed investment
contracts, 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 1995, 1994, and 1993 included the following
components:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Service cost - benefits earned during
the period $1,072 $1,252 $1,161
Plus (less):
Interest cost on accumulated
benefit obligation 6,006 5,630 6,330
Return on plan assets at expected
long-term rate (2,080) (1,640) (1,031)
Amortization 3,539 3,716 3,864
------- ------- -------
Net postretirement benefit cost $8,537 $8,958 $10,324
======= ======= =======
Actual return (loss) on plan assets $6,161 $(23) $1,047
======= ======= =======
1996 1995 1994 1993
---- ---- ---- ----
Assumptions used to determine
postretirement benefit cost:
Discount rate 7.25% 8.25% 7.25% 8.25%
Expected long-term rate of return
on assets 8.25% 8.50% 8.50% 8.50%
Health care cost rate 1994 and 1993 11.00% 12.00%
Health care cost rate 1995 to 1999 8.00% 8.50% 8.50% 9.50%
Health care cost rate 2000 to 2004 6.25% 8.50% 8.50% 9.50%
Health care cost rate 2005 and beyond 5.25% 6.25% 6.25% 7.25%
The following table sets forth benefits earned and the plans' funded status:
At December 31, (In Millions) 1995 1994
---- ----
Accumulated postretirement benefit obligation:
Retirees $50 $50
Fully eligible active plan participants 6 10
Other active plan participants 20 14
---- ----
Total benefits earned 76 74
Unrecognized transition obligation (66) (70)
Unrecognized net gain 16 10
---- ----
26 14
Plan assets at fair value 34 22
---- ----
Prepaid postretirement benefit costs recorded on books $8 $8
==== ====
The plans' funded status at December 31, 1995 and 1994 were calculated using
the assumed rates in effect for 1996 and 1995, 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, 1995 by
approximately $10 million and the net periodic cost for the year 1995 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, 1995, the Company had $23 million of short-term debt
outstanding including $22 million in commercial paper borrowings and $1
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, 1995, the Company had lines of credit with banks totaling $41
million. There were no borrowings under these lines of credit at December 31,
1995. 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, 1995. 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) 1995 1994
---- ----
Rate adjustment mechanisms $14,075 $12,102
Deferred unbilled revenues 8,209
Accrued wages and benefits 5,483 4,999
Other 36
------- -------
$19,558 $25,346
======= =======
Note G - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1995 and 1994 is as follows (in
thousands of dollars except for share data):
Shares
Authorized Dividends Call
and Outstanding Amount Declared Price
--------------- ------ ------------ -----
1995 1994 1995 1994 1995 1994
---- ---- ---- ---- ---- ---- -----
$50 Par value
4.50% Series 180,000 180,000 $9,000 $9,000 $405 $405
4.64% Series 150,000 150,000 7,500 7,500 348 348
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
======= ============== ======= ====== ======
(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
1995 and 1994.
Note H - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In Thousands)
Series Rate % Maturity 1995 1994
- -----------------------------------------------------------------------------
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
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 24,000 40,000
U(93-5) 7.050 September 1, 2023 5,000 5,000
U(94-1) 7.050 February 2, 2024 5,000 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
V(95-3) 7.500 October 10, 2025 7,000
W(95-1) 7.300 November 13, 2025 16,000
Unamortized discounts and premiums (1,308) (1,338)
-------- --------
Total long-term debt $210,892 $188,862
======== ========
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 1996.
To date in 1996, the Company has refinanced $2 million of long-term debt at
7.24 percent.
At December 31, 1995, the Company's long-term debt had a carrying value of
approximately $211,000,000 and had a fair value of approximately $229,000,000.
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, 1995 was 50 percent of total capitalization and, accordingly,
none of the Company's retained earnings at December 31, 1995 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 1995, 1994, or 1993.
Taxes, other than federal income taxes, charged to operating expenses are set
forth by classes as follows:
Year Ended December 31, (In Thousands) 1995 1994 1993
---- ---- ----
Municipal property taxes $15,172 $13,944 $13,798
State gross earnings tax 18,617 19,270 19,281
Federal and state payroll and other taxes 2,838 2,604 2,767
------- ------- -------
$36,627 $35,818 $35,846
======= ======= =======
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 $28,502,000, $32,445,000, and $30,133,000, including
capitalized construction costs of $6,268,000, $7,756,000, and $6,602,000, for
each of the years 1995, 1994, and 1993, respectively.
The Narragansett Electric Company
Operating Statistics (Unaudited)
Year Ended December 31, 1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Sources of Energy (Thousands of kWh)
Net generation for New England
Power Company 64,035 5,781 4,506 83,753 162,844
Purchased energy:
From New England Power
Company, an affiliate
(net of generation) 4,955,575 5,001,843 4,982,254 4,729,733 4,699,509
From others 2,080 2,909 2,343 2,249 2,243
--------------------------------------------------
Total generated and
purchased 5,021,690 5,010,533 4,989,103 4,815,735 4,864,596
Losses, company use, etc. (260,960) (263,234) (270,373) (229,106) (277,383)
--------------------------------------------------
Total sources of energy 4,760,730 4,747,299 4,718,730 4,586,629 4,587,213
==================================================
Sales of Energy (Thousands of kWh)
Residential 1,835,085 1,843,970 1,817,675 1,783,754 1,784,156
Commercial 2,031,541 1,983,508 1,931,377 1,877,738 1,867,225
Industrial 843,635 868,092 917,305 869,062 878,142
Other 49,881 51,138 51,821 55,476 57,106
--------------------------------------------------
Total sales to
ultimate customers 4,760,142 4,746,708 4,718,178 4,586,030 4,586,629
Sales for resale 588 591 552 599 584
--------------------------------------------------
Total sales of energy 4,760,730 4,747,299 4,718,730 4,586,629 4,587,213
==================================================
Annual Maximum Demand
(kW one hour peak) 1,031,000 1,005,000 939,000 919,000 961,000
Average Annual Use per
Residential Customer (kWh) 6,305 6,397 6,337 6,265 6,308
Number of Customers at December 31
Residential 292,659 289,317 287,876 286,228 284,275
Commercial 32,412 32,195 31,948 31,534 31,417
Industrial 1,792 1,825 1,869 1,914 1,944
Other 873 875 878 941 934
--------------------------------------------------
Total ultimate customers 327,736 324,212 322,571 320,617 318,570
Other electric companies
(for resale) 2 2 1 3 4
--------------------------------------------------
Total customers 327,738 324,214 322,572 320,620 318,574
==================================================
Operating Revenue (In Thousands)
Residential $205,649 $200,778 $202,522 $196,983 $192,688
Commercial 198,429 189,059 190,185 183,702 178,616
Industrial 72,071 72,136 78,088 76,275 76,299
Other 7,236 6,883 6,778 6,587 6,197
--------------------------------------------------
Total revenue from
ultimate customers 483,385 468,856 477,573 463,547 453,800
Amortization of unbilled
revenues 8,209 6,158
Sales for resale 70 68 64 68 65
--------------------------------------------------
Total revenue from
electric sales 491,664 475,082 477,637 463,615 453,865
Other operating revenue 7,449 6,587 5,391 4,637 3,645
--------------------------------------------------
Total operating revenue $499,113 $481,669 $483,028 $468,252 $457,510
==================================================
The Narragansett Electric Company
Selected Financial Information
Year Ended December 31, (In Millions) 1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Operating revenue:
Electric sales
(excluding fuel cost recovery) $361 $356 $351 $342 $340
Fuel cost recovery 131 120 127 121 114
Other 7 6 5 5 4
------ ------ ------ ------ ------
Total operating revenue $499 $482 $483 $468 $458
Net income $24 $15 $14 $21 $17
Total assets $700 $647 $556 $479 $445
Capitalization:
Common equity $245 $208 $183 $176 $151
Cumulative preferred stock 36 37 37 27 27
Long-term debt 211 189 156 143 118
------ ------ ------ ------ ------
Total capitalization $492 $434 $376 $346 $296
Preferred dividends declared $2 $2 $2 $2 $2
Common dividends declared $5 $3 $5 $5 $5
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In Thousands) Quarter Quarter Quarter Quarter
------- ------- ------- -------
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
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
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, 1995
will be available on or about April 1, 1996, without charge, upon written
request to The Narragansett Electric Company, Shareholder Services Department,
280 Melrose Street, Providence, Rhode Island 02901.