Annual Report 1998
The Narragansett Electric Company
A Subsidiary of
New England Electric System
[LOGO] Narragansett Electric
A NEES Company
The Narragansett Electric Company
280 Melrose Street
Providence, Rhode Island 02901
Directors
(As of January 1, 1999)
Richard W. Frost
Vice President of the Company and of certain affiliates
Cheryl A. LaFleur
Senior Vice President, General Counsel, and Secretary of New
England Electric System
Robert L. McCabe
Chairman of the Company and of certain affiliates
Lawrence J. Reilly
President and Chief Executive Officer of the Company and of
certain affiliates
Michael F. Ryan
Vice President of the Company
Richard P. Sergel
President and Chief Executive Officer of New England Electric
System
Ronald L. Thomas
Manager of Labor Relations of the Company and of certain
affiliates
Officers
(As of January 1, 1999)
Robert L. McCabe
Chairman of the Company and of certain affiliates
Lawrence J. Reilly
President and Chief Executive Officer of the Company and of
certain affiliates
Lydia M. Pastuszek
Senior Vice President of the Company and of certain affiliates
Christopher E. Root
Senior Vice President of the Company and of certain affiliates
Richard W. Frost
Vice President of the Company and of certain affiliates
Michael E. Jesanis
Vice President of the Company and of certain affiliates, and
Senior Vice President and Chief Financial Officer of New England
Electric System
Richard Nadeau
Vice President of the Company
Michael F. Ryan
Vice President of the Company
Peter T. Zschokke
Vice President of the Company
Ronald T. Gerwatowski
Secretary and General Counsel of the Company
John G. Cochrane
Treasurer of the Company and of certain affiliates, Vice
President of an affiliate, Assistant Treasurer of an affiliate
and Treasurer of New England Electric System
Robert King Wulff
Assistant Secretary of the Company and Clerk, Assistant Clerk or
Secretary of certain affiliates
Howard W. McDowell
Assistant Treasurer and Controller of the Company and of certain
affiliates, Senior Vice President of an affiliate, Treasurer or
Controller of certain affiliates and Assistant Secretary of an
affiliate
Transfer Agent, Dividend Paying Agent, and Registrar of Preferred
Stock, State Street Bank and Trust Company, Boston, Massachusetts
This report is not to be considered an offer to sell or buy or
solicitation of an offer to sell or buy any security.
The Narragansett Electric Company
The Narragansett Electric Company (the Company) is a wholly
owned subsidiary of New England Electric System (NEES) operating
in Rhode Island. The Company's business is the distribution of
electricity at retail. Electric service is provided to
approximately 335,000 customers in 27 cities and towns having a
population of approximately 725,000 (1990 Census). The Company's
service area, which includes urban, suburban, and rural areas,
covers approximately 80 percent of Rhode Island, and includes the
cities of Providence, East Providence, Cranston, and Warwick.
The diversified economy of the Company's service area produces
fabricated metal products, electrical and industrial machinery,
transportation equipment, textiles, silverware, and chemical
products. In addition, a broad range of professional, banking,
medical, and educational institutions is served. As described in
the "Industry Restructuring" section of Financial Review, all
customers gained the right to choose their power supplier
effective January 1, 1998.
The properties of the Company include an integrated system of
transmission and distribution lines and substations.
In September 1998, NEES completed the divestiture of
substantially all of its nonnuclear generating business,
including the Company's 10 percent share of the Manchester Street
generating station. For further information on industry
restructuring and the divestiture of NEES' nonnuclear generating
business, refer to the "Industry Restructuring" section of
Financial Review.
In December 1998, NEES agreed to a merger with The National
Grid Group plc, whose principal subsidiary operates the
transmission system in England and Wales.
In February 1999, NEES entered into an agreement to acquire
Eastern Utilities Associates, a utility holding company serving
approximately 300,000 customers in Massachusetts and Rhode
Island. For further information on these proposed mergers, refer
to the "Merger Agreements" sections of Financial Review.
Report of Independent Accountants
The Narragansett Electric Company, Providence, Rhode Island:
In our opinion, the accompanying balance sheets and the
related statements of income, of retained earnings, and of cash
flows present fairly, in all material respects, the financial
position of The Narragansett Electric Company (the Company), a
wholly owned subsidiary of New England Electric System, at
December 31, 1998 and 1997, and the results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted
accounting principles. 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 of these statements in accordance
with generally accepted auditing standards which 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, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed
above.
Boston, Massachusetts PricewaterhouseCoopers LLP
February 23, 1999
The Narragansett Electric Company
Financial Review
Merger Agreement with The National Grid Group plc
On December 11, 1998, New England Electric System (NEES), The
National Grid Group plc (National Grid), and NGG Holdings LLC
(Holdings), a directly and indirectly wholly owned subsidiary of
National Grid, entered into an Agreement and Plan of Merger
(Merger Agreement). Pursuant to the Merger Agreement, Holdings
will merge with and into NEES (the Merger), with NEES becoming a
wholly owned subsidiary of National Grid. The Narragansett
Electric Company (the Company) will remain a wholly owned
subsidiary of NEES.
The Merger is subject to approval by a majority vote of NEES
shareholders as well as National Grid shareholder approval. In
addition, the Merger is subject to a number of regulatory and
other approvals and consents, including approvals by the
Securities and Exchange Commission (SEC), under the Public
Utility Holding Company Act of 1935 (1935 Act), Federal Energy
Regulatory Commission (FERC), and Nuclear Regulatory Commission
(NRC), support or approval from the states in which NEES
subsidiaries operate, and clearance under both the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
and the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988. National Grid has obtained
governmental clearance in the United Kingdom for the Merger. The
Merger is expected to be completed by early 2000.
Merger Agreement with Eastern Utilities Associates
On February 1, 1999, NEES, Eastern Utilities Associates (EUA),
and Research Drive LLC (Research Drive), a directly and
indirectly wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA
Agreement, Research Drive will merge with and into EUA, with EUA
becoming a wholly owned subsidiary of NEES.
The acquisition of EUA is subject to approval by a two-thirds
vote of EUA shareholders. In addition, the acquisition is subject
to a number of regulatory and other approvals and consents,
including approvals by the SEC, under the 1935 Act, FERC, and
NRC, support or approval from the states in which EUA
subsidiaries operate, and clearance under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. The EUA
acquisition is expected to be completed by early 2000. Following
the acquisition of EUA, the subsidiaries of NEES and EUA whose
operations are similar are expected to be consolidated.
Industry Restructuring
Pursuant to legislation enacted in Rhode Island and settlement
agreements approved by state and federal regulators, all
customers were provided the right to purchase electricity from
the power supplier of their choice effective January 1, 1998.
Customers who do not choose a power supplier are able, for a
period of time, to continue to purchase their electricity from
the Company at a transition rate ("standard offer generation
service") which, when combined with delivery charges, results in
a total rate reduction of 8 percent compared with the rates that
had been in effect prior to the introduction of customer choice.
Pursuant to the Rhode Island statute, the total rate for
customers who do not choose a power supplier is capped through
2009 at a level equal to the 1996 rate adjusted upward for 80
percent of inflation and for other factors beyond the control of
the Company.
On September 1, 1998, the Company and New England Power
Company (NEP) (collectively, the Sellers) completed the sale of
substantially all of their nonnuclear generating business, all of
which had a book value of approximately $1.1 billion, to USGen
New England Inc. (USGen), an indirect wholly owned subsidiary of
PG&E Corporation. Included in the sale was the Company's 10
percent share of Manchester Street Station. The Sellers received
$1.59 billion for the sale, of which the Company received
approximately $40 million equal to the net book value of its
assets included in the sale. Effective September 1, 1998, USGen
and TransCanada Power Marketing, Ltd. (TCPM) became the Company's
principal suppliers for meeting standard offer generation service
obligations. However, NEP remained obligated for standard offer
service for new customer load in Rhode Island.
The Rhode Island Settlement also provides that the costs of
NEP's generating investments and related contractual commitments
that were not recovered from the divestiture of those investments
("stranded costs") (the Company's share is 22 percent) are to be
recovered from distribution customers through contract
termination charges (CTC), which will be collected by the
Company. Under the Rhode Island Settlement, the recovery of NEP's
stranded costs is divided into several categories. Unrecovered
costs associated with generating plants (nuclear and nonnuclear)
and most regulatory assets will be fully recovered through the
CTC by the end of 2000 and would earn a return on equity of 11
percent. NEP's obligation relating to the above-market cost of
purchased power contracts and nuclear decommissioning costs are
recovered through the CTC over a longer period of time, as such
costs are actually incurred. NEP's CTC rate was originally set at
2.8 cents per kilowatthour (kWh), and subsequently reduced to
approximately 1.5 cents or less per kWh upon completion of the
sale of NEP's nonnuclear generating business as described above.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of these
charges because they are expected to be included in future
customer charges. At December 31, 1998, the Company had
approximately $16 million in net regulatory assets.
The Company believes the Rhode Island Settlement and statute
will enable the Company to recover through rates its specific
costs of providing ongoing distribution services and stranded
costs billed to it by NEP. The Company believes these factors
will allow it to continue to apply FAS 71.
Currently, there is much regulatory and other movement toward
establishing performance-based rates. It is possible that the
adoption of performance-based rates, future regulatory rules, or
other circumstances could cause the application of FAS 71 to be
discontinued. This discontinuation would result in a noncash
write-off of previously established regulatory assets. In
addition, reserves for depreciation may also have to be increased
to comply with unregulated accounting practices.
Impact of Restructuring on Distribution Business
Under the Rhode Island statute, the Company increased
distribution rates by approximately $7 million and $11 million in
1998 and 1997, respectively. The statute does not limit
Narragansett Electric's ability to seek approval from state
regulators to increase rates in the future.
Overview of Financial Results
Net income in 1998 and 1997 increased $4 million and $5
million, respectively, from the prior year. Both increases were
primarily due to the previously mentioned distribution rate
increases which went into effect in January of each year and
increases in kWh deliveries. The increase in 1998 earnings was
partially offset by an underrecovery of transmission wheeling
costs of approximately $4 million.
Operating Revenue
Operating revenue decreased $44 million in 1998 compared with
1997, reflecting lower purchased power related rates pursuant to
Rhode Island legislation, a change in true-up mechanisms and a
decrease in postretirement benefits other than pensions (PBOPs).
Rates were reduced by 8 percent effective January 1998. The
revenues that the Company is billing related to purchased power
costs both prior to and subsequent to the September 1 sale are
subject to fully reconciling true-up mechanisms, as are CTC
charges from NEP. However, transmission wheeling costs are not
subject to a true-up mechanism until 1999, and the Company
incurred an underrecovery of such costs in 1998. The decrease in
PBOPs is due to lower costs being incurred as well as refunds
made by the Company in January 1998 of past overrecoveries of
PBOP costs, for which reserves had previously been established.
The decrease in 1998 operating revenue was partially offset by
the $7 million distribution rate increase mentioned above and a
2.9 percent increase in kWh deliveries. The increase in kWh
deliveries reflects a strong economy. For the year as a whole,
weather had a negative impact on 1998 deliveries when compared to
1997.
Operating revenue increased $17 million in 1997 compared with
1996, reflecting an $11 million increase in base rates effective
January 1, 1997, increased fuel recovery (see 1997 fuel costs
discussion in the "Operating Expenses" section), and a 1.3
percent increase in kWh deliveries.
The Company received approval from the Rhode Island Public
Utilities Commission (RIPUC) to recover demand-side management
(DSM) program expenditures in rates on a current basis through
1998. These expenditures were $11 million, $10 million, and $10
million in 1998, 1997, and 1996, respectively. The Company has
also received approval from the RIPUC to recover its 1999 DSM
program expenditures. Since 1990, the Company has been allowed to
earn incentives based on the results of its DSM programs and has
recorded before-tax incentives of $0.3 million, $0.3 million, and
$0.2 million in 1998, 1997, and 1996, respectively.
Operating Expenses
Operating expenses for 1998 decreased $47 million compared
with 1997 primarily due to reduced purchased electric energy
expenses, partially offset by increased operation and maintenance
costs. The decrease in purchased electric energy is principally
due to reduced rates billed to the Company by suppliers.
Historically, the Company purchased all of its electrical
requirements from NEP under the provisions of an all-requirements
contract at NEP's standard resale rate. Effective January 1,
1998, the contract was amended, terminating the all-requirements
provision of the contract. The Company's customers also gained
the right to choose their power supplier. NEP continued to
supply power to the Company, at lower rates, for customers that
continued to take power from the Company, until September 1,
1998, when USGen and TCPM became the Company's principal
wholesale power suppliers. This decrease in purchased electric
energy was partially offset by a reduction in the level of
reimbursements received from NEP for costs associated with the
Company's 10 percent ownership of the Manchester Street
generating station as a result of the sale of this facility in
September 1998. All of the output of this generating unit had
been previously supplied to NEP.
The increase in other operation and maintenance expenses in
1998 is primarily due to increased transmission costs of
approximately $23 million which, as of January 1, 1998 are billed
separately and recorded as operation and maintenance expense
instead of as a component of purchased power expense. The
Company also experienced increased costs associated with year
2000 (Y2K) computer readiness. The increases were partially
offset by decreased charges related to postretirement benefits
other than pensions and the effect of workforce reductions during
the year.
Operating expenses for 1997 increased $13 million compared
with 1996 primarily due to increased purchased electric energy
expenses and increased other operation and maintenance expenses.
The increase in purchased electric energy expenses was due to
increased replacement power fuel costs due to reduced generation
from NEP's partially owned nuclear units and reduced
reimbursements received from NEP for dismantlement costs
associated with the previously retired South Street generating
facility. These replacement power costs were passed on to the
Company through NEP's fuel clause. The increase in other
operation and maintenance expenses was primarily due to increased
customer accounts expenses, transmission and distribution system
related expenses, and increased general and administrative
expenses.
Hazardous Waste
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. The Company has been named as a
potentially responsible party by either federal or state
environmental regulatory agencies for three sites at which
hazardous waste is alleged to have been disposed. The Company is
currently aware of other sites, and may in the future become
aware of additional sites, that it may be held responsible for
remediating. The Company is aware of approximately five sites on
which gas was manufactured or manufactured gas was stored that
were owned either by the Company or by its predecessor companies.
A more detailed discussion of potential hazardous waste
liabilities is contained in Note D-2 of the Notes to the
Financial Statements. Predicting the potential costs to
investigate and remediate hazardous waste sites continues to be
difficult. The Company believes that hazardous waste liabilities
for all sites of which it is aware are not material to its
financial position.
Year 2000 Readiness Disclosure
Over the next year, most companies will face a potentially
serious information systems (computer) problem because many
software applications and operational programs written in the
past may not properly recognize calendar dates associated with
Y2K. This could cause computers to either shut down or lead to
incorrect calculations.
During 1996, the NEES companies began the process of
identifying the changes required to their computer software and
hardware to mitigate Y2K issues. The NEES companies established a
Y2K Project team to manage these issues, which has consisted of
as many as 70 full-time equivalent staff at some points in time,
primarily external consultants being overseen by an internal Y2K
management team. To facilitate the Y2K Project, NEES entered
into contracts with Keane, Inc. and International Business
Machines Corporation to provide personnel support to the Y2K
Project. Through December 31, 1998, the NEES companies have
spent approximately $14 million with these vendors, which is
included in the cost figures disclosed below. The Y2K Project
team reports project progress to a Y2K Executive Oversight
Committee each month. The team also makes regular reports to
NEES' Board of Directors and its Audit Committee. The NEES
companies have separated their Y2K Project into four parts as
shown below, along with the estimated completion dates for each
part.
Substantial Contingency Testing
Completion Documentation,
of Critical and Clean
Category Specific Example Systems Management
- -------- ---------------- ----------- -------------------
Mainframe/Midrange Accounting/Customer Completed Throughout 1999
systems service integrated
systems
Desktop systems Personal computers/ June 30, 1999 Throughout 1999
Department software/
Networks
Operational/ Dispatching systems/ June 30, 1999 Throughout 1999
Embedded Transmission and
systems Distribution systems/
Telephone systems
External issues Electronic Data June 30, 1999 Throughout 1999
Interchange/Vendor
communications
The NEES companies are using a three-phase approach in
coordinating their Y2K Project for system-related issues: (I)
Assessment and Inventory, (II) Pilot Testing, and (III)
Renovation, Conversion, or Replacement of Application and
Operating Software Packages and Testing. Phase I, which was an
initial assessment of all systems and devices for potential Y2K
defects, was completed in mid-1997. These assessments included,
but were not limited to, the review of program code for mainframe
and midrange systems, analysis of personal computer hardware and
network equipment for desktop systems, reaching consensus with
key "data exchange" partners regarding the approach and execution
of plans to address Y2K-related issues, and coordination with
other New England Power Pool (NEPOOL) member utilities related to
operational systems, such as transmission systems. Phase II,
which consisted of renovation pilots for a cross-section of
systems in order to facilitate the establishment of templates for
Phase III work, was completed in late 1997. Phase III, which is
currently ongoing, requires the renovation, conversion, or
replacement of the remaining applications and operating software
packages.
Critical systems include major operational and informational
systems such as the NEES companies' financial-related and
customer information systems. These mission critical systems
were first addressed at an individual component level, and then,
upon satisfactory completion of that testing, reviewed at an
integrated level, during which the Y2K Project team tested for
Y2K problems which could be caused by various system interfaces.
Additionally, contingency plans are being formulated for mission
critical systems, as described below.
The overall Y2K Project has also been designed such that Y2K-
related work performed by external consultants is reviewed by
NEES employees, and vice-versa. The Y2K Project team management
periodically benchmarks its progress against the recommended
progress schedule documented by the North American Electric
Reliability Council (NERC), and is currently ahead of the
recommended schedule.
The NEES companies have also implemented a formalized
communication process with third parties to give and receive
information related to their progress in remediating their own
Y2K issues, and to communicate the NEES companies' progress in
addressing the Y2K issue. These third parties include major
customers, suppliers, and significant businesses with which the
NEES companies have data links (such as banks). The NEES
companies have identified standard offer generation service
providers, telecommunications companies, and the Independent
System Operator-New England (ISO New England) as critical to
business operations. The NEES companies have been in contact
with all of these parties regarding the progress of their Y2K
remediation efforts, and will continue to monitor their ongoing
remediation efforts through continued communications. The NEES
companies cannot predict the outcome of other companies'
remediation efforts. Therefore, contingency plans are being
developed, as described below.
The NEES companies believe total costs associated with making
the necessary modifications to all centralized and noncentralized
systems will be approximately $28 million. These costs include
the replacement of approximately one thousand desktop computers.
In addition, the NEES companies are spending $4 million related
to the replacement of the human resources and payroll system, in
part due to the Y2K issue. To date, total Y2K-related costs of
$25 million have been incurred, of which $3 million has been
capitalized. The NEES companies continually review their cost
estimates based upon the overall Y2K Project status, and update
these estimates as warranted.
The NEES companies are in the process of developing Y2K
contingency plans to allow for critical information and operating
systems to function from January 1, 2000 forward. If required,
these plans are intended to address both internal risks as well
as potential external risks related to suppliers and customers.
Part of the contingency planning for accounting and desktop
systems will include taking extensive data back-ups prior to
year-end closing. For operational systems, the NEES companies
have in place an overall disaster recovery program, which already
includes periodic disaster simulation training (for outages due
to severe weather, for instance). As part of Y2K contingency
planning, the NEES companies will review their disaster recovery
plans, modifying them for Y2K-specific issues, such as a
potential loss of telecommunication services. The NEES companies
expect that these contingency plans will be in place by the third
quarter of 1999.
Interregional and regional contingency plans are being
formulated that address emergency scenarios due to the
interconnection of utility systems throughout the United States.
At a regional level, the NEES companies are participating and
cooperating with NEPOOL and the Independent System Operator of
the NEPOOL area (ISO New England). Overall regional activities,
including those of NEPOOL and ISO New England, will be
coordinated by the Northeast Power Coordinating Council, whose
activities will be incorporated into the interregional
coordinating effort by NERC. The target for the completion of
this planning process is mid-1999. The NEES companies have noted
that the Y2K coordination efforts by ISO New England began in May
1998, resulting in a demanding and difficult schedule to attain
regional and interregional target dates.
The NEES companies believe the worst case scenario with a
reasonable chance of occurring is temporary disruptions of
electric service. This scenario could result from a failure to
adequately remediate Y2K problems at NEES company facilities or
could be caused by the inability of entities, such as ISO New
England, to maintain the short-term reliability of various
generators and/or transmission lines on a regional or
interregional basis. The NEES companies believe that the
contingency plans being developed both internally and on a
regional level, as described above, should substantially mitigate
the risks of this potential scenario. In the event that a
short-term disruption in service occurs, NEES does not expect
that it would have a material impact on its financial position
and results of operations.
While the NEES companies believe that their overall Y2K
program will satisfactorily address all critical operational and
system-related issues, significant risks remain. These risks
include, but are not limited to, the Y2K readiness of third
parties, including other utilities and power suppliers, cost and
timeline estimates of remaining Y2K mitigation efforts, and the
overall accuracy of assumptions made related to future events in
the development of the Y2K mitigation effort.
New Accounting Standards
In 1997, the Financial Accounting Standards Board (FASB)
released Statement of Financial Accounting Standards No. 130,
Reporting of Comprehensive Income (FAS 130), which was adopted by
the Company in the first quarter of 1998. FAS 130 establishes
standards for reporting comprehensive income and its components.
Comprehensive income for the period is equal to net income plus
"other comprehensive income," which for the Company, consists of
the change in unrealized holding gains on available-for-sale
securities during the period. Other comprehensive income was
immaterial for the Company for the year ended December 31, 1998.
Also in 1997, the FASB released Statement of Financial
Accounting Standards No. 131, Disclosure about Segments of an
Enterprise and Related Information (FAS 131), which went into
effect in 1998. FAS 131 requires the reporting in financial
statements of certain new additional information about operating
segments of a business. FAS 131 does not currently impact the
Company's reporting requirements.
In February 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits (FAS 132), which
revises disclosure requirements for pension and other
postretirement benefits. The Company has adopted FAS 132 in its
financial statements for the year ended December 31, 1998.
The adoption of FAS 130, FAS 131, and FAS 132 had no impact on
the Company's operating results, financial position, or cash
flows.
In June 1998, the FASB issued Statement of Financial
Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (FAS 133), which establishes
accounting and reporting standards for such instruments. FAS 133
is effective for fiscal years beginning after June 15, 1999.
Currently, the Company has no such derivative holdings.
Risk Management
The Company's major financial market risk exposure is changing
interest rates. Changing interest rates will affect the fair
value of fixed rate debt. The table below presents the average
rate on the Company's long-term debt at December 31, 1998, the
amounts maturing during each of the next five years, and the fair
value of the Company's debt at December 31, 1998.
Fixed Long-Term
---------------
Weighted Average Rates 7.67%
Maturities (millions of dollars)
1999 $ 8
2000 15
2001 -
2002 15
2003 18
Cumulative thereafter 122
----
Total $178
----
Fair Value $195
----
Utility Plant Expenditures and Financing
Cash expenditures for utility plant totaled $22 million in
1998. The funds necessary for utility plant expenditures during
1998 were primarily provided by increased short-term debt and
proceeds from the sale of the nonnuclear generating business.
Cash expenditures for utility plant for 1999 are estimated to
be approximately $25 million. Internally generated funds are
expected to fully meet capital expenditure requirements in 1999.
In 1998, the Company retired $12 million of long-term debt.
In 1998, the Company repurchased preferred stock with an
aggregate par value of $5.6 million. Total premiums paid of $1.2
million in connection with the preferred stock redemption were
charged to retained earnings.
At December 31, 1998, the Company had $27 million of short-
term debt outstanding representing borrowings from affiliates.
The Company's ability to issue short-term debt is limited by the
need to obtain regulatory approval from the SEC under the 1935
Act. Approval has been granted for up to $100 million. As of
December 31, 1998, the Company had lines of credit with banks
totaling $41 million. There were no borrowings under these lines
of credit at December 31, 1998.
The Narragansett Electric Company
Statements of Income
Year ended December 31, (In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Operating revenue $475,654 $520,038 $503,585
-------- -------- --------
Operating expenses:
Fuel for generation and purchased
electric energy (Note A):
Contract termination charges from New
England Power Company, an affiliate 117,756 - -
Other 122,351 309,430 297,060
Other operation 95,792 74,375 71,625
Maintenance 11,997 12,447 13,009
Depreciation 22,759 22,957 27,899
Taxes, other than federal income taxes 38,915 39,366 38,530
Federal income taxes 16,177 14,247 11,951
-------- -------- --------
Total operating expenses 425,747 472,822 460,074
-------- -------- --------
Operating income 49,907 47,216 43,511
-------- -------- --------
Other income:
Other income (expense), net 801 (750) (732)
-------- -------- --------
Operating and other income 50,708 46,466 42,779
-------- -------- --------
Interest:
Interest on long-term debt 14,925 16,179 17,205
Other interest 3,615 2,475 2,883
Allowance for borrowed funds used
during construction credit (85) (120) (263)
-------- -------- --------
Total interest 18,455 18,534 19,825
-------- -------- --------
Net income $ 32,253 $ 27,932 $ 22,954
======== ======== ========
Statements of Retained Earnings
Year ended December 31, (In thousands) 1998 1997 1996
- -----------------------------------------------------------------------------
Retained earnings at beginning of year $129,567 $119,978 $108,227
Net income 32,253 27,932 22,954
Dividends declared on cumulative
preferred stock (567) (1,955) (2,143)
Dividends declared on common stock,
$65.00, $13.00, and $8.00 per share,
respectively (73,612) (14,722) (9,060)
Premium on redemption of preferred stock (1,176) (1,666) -
-------- -------- --------
Retained earnings at end of year $ 86,465 $129,567 $119,978
======== ======== ========
The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company
Balance Sheets
At December 31, (In thousands) 1998 1997
- -----------------------------------------------------------------------------
Assets
Utility plant, at original cost $732,077 $760,923
Less accumulated provisions for depreciation 209,155 198,551
-------- --------
522,922 562,372
Construction work in progress 2,566 5,739
-------- --------
Net utility plant 525,488 568,111
-------- --------
Current assets:
Cash 2,957 3,122
Accounts receivable:
From electric energy services 53,727 54,109
Other (including $4,444 and $1,112
from affiliates) 5,575 2,571
Less reserves for doubtful accounts 4,240 4,707
-------- --------
55,062 51,973
Unbilled revenues (Note A-3) 20,752 15,997
Fuel, materials, and supplies, at average cost 3,494 4,165
Prepaid and other current assets 739 14,202
-------- --------
Total current assets 83,004 89,459
-------- --------
Deferred charges and other assets (Note C) 55,628 55,285
-------- --------
$664,120 $712,855
======== ========
Capitalization and Liabilities
Capitalization:
Common stock, par value $50 per share, authorized
and outstanding 1,132,487 shares $ 56,624 $ 56,624
Premium on preferred stock 81 36
Other paid-in capital 105,713 105,500
Retained earnings 86,465 129,567
Unrealized gain on securities, net 237 112
-------- --------
Total common equity 249,120 291,839
Cumulative preferred stock,
par value $50 per share (Note H) 7,238 12,800
Long-term debt 168,702 183,545
-------- --------
Total capitalization 425,060 488,184
-------- --------
Current liabilities:
Long-term debt due in one year 8,000 5,000
Short-term debt - (including $26,675 and
$4,425 to affiliates) 26,675 16,350
Accounts payable (including $1,929 and
$50,751 to affiliates) 28,260 56,048
Accrued liabilities:
Taxes 10,031 4,314
Interest 4,553 4,810
Other accrued expenses (Note G) 34,734 21,519
Customer deposits 6,116 5,982
Dividends payable 4,058 3,587
-------- --------
Total current liabilities 122,427 117,610
-------- --------
Deferred federal income taxes 81,045 82,871
Unamortized investment tax credits 6,533 7,023
Other reserves and deferred credits 29,055 17,167
Commitments and contingencies (Note D)
-------- --------
$664,120 $712,855
======== ========
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) 1998 1997 1996
- -----------------------------------------------------------------------------
Operating activities:
Net income $ 32,253 $ 27,932 $ 22,954
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 22,759 22,957 27,899
Deferred federal income taxes and
investment tax credits, net (2,701) (415) 4,177
Allowance for funds used during construction (85) (120) (263)
Decrease (increase) in accounts receivable,
net and unbilled revenues (7,844) 22 12,082
Decrease (increase) in fuel, materials, and
supplies 671 135 1,945
Decrease (increase) in prepaid and other
current assets 13,463 1,717 (32)
Increase (decrease) in accounts payable (27,788) 10,827 (1,026)
Increase (decrease) in other current
liabilities 18,809 9,484 (10,335)
Other, net 14,666 1,181 8,236
-------- -------- --------
Net cash provided by
operating activities $ 64,203 $ 73,720 $ 65,637
-------- -------- --------
Investing activities:
Plant expenditures, excluding allowance for
funds used during construction $(22,196) $(30,965) $(52,574)
Other investing activities (35) (294) (181)
Proceeds from sale of generating assets 39,724 - -
-------- -------- --------
Net cash provided by (used in)
investing activities $ 17,493 $(31,259) $(52,755)
-------- -------- --------
Financing activities:
Capital contributions from parent $ 214 $ 25,500 $ -
Dividends paid on common stock (73,045) (13,590) (7,361)
Dividends paid on preferred stock (662) (2,301) (2,143)
Changes in short-term debt 10,325 (2,675) (3,650)
Long-term debt issues - 10,000 2,000
Long-term debt retirements (12,000) (32,500) (2,000)
Preferred stock - retirements (5,517) (23,834) -
Premium on reacquisition of preferred stock (1,176) (1,666) -
-------- -------- --------
Net cash used in financing activities $(81,861) $(41,066) $(13,154)
-------- -------- --------
Net increase (decrease) in cash and
cash equivalents $ (165) $ 1,395 $ (272)
Cash and cash equivalents at
beginning of year 3,122 1,727 1,999
-------- -------- --------
Cash and cash equivalents at end of year $ 2,957 $ 3,122 $ 1,727
======== ======== ========
Supplementary Information:
Interest paid less amounts capitalized $ 17,079 $ 17,911 $ 18,620
-------- -------- --------
Federal income taxes paid $ 13,180 $ 13,825 $ 8,873
======== ======== ========
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 Narragansett Electric Company (the Company) is a wholly
owned subsidiary of New England Electric System (NEES) operating
in Rhode Island. The Company's business is the distribution of
electricity at retail. Electric service is provided to
approximately 335,000 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. Under an all-requirements
contract with its transmission affiliate, New England Power
Company (NEP), the Company had previously purchased its electric
energy requirements from NEP. The contract with NEP has been
amended to terminate the all-requirements provision of the
contract and allow NEP to recover its above-market generation
commitments through a contract termination charge (CTC), which
the Company collects from its customers. See Note C for a
discussion of industry restructuring and the Company's and NEP's
divestiture of their nonnuclear generating business.
2. System of Accounts:
The accounts of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by regulatory bodies
having jurisdiction.
In preparing the financial statements, management is required
to make estimates that affect the reported amounts of assets and
liabilities and disclosures of asset recovery and contingent
liabilities as of the date of the balance sheets and revenues and
expenses for the period. These estimates may differ from actual
amounts if future circumstances cause a change in the assumptions
used to calculate these estimates.
3. Electric Utility Revenue:
The Company accrues revenues for electricity delivered but not
yet billed (unbilled revenues). Accrued revenues are also
recorded in accordance with rate adjustment mechanisms.
4. Allowance for Funds Used During Construction (AFDC):
The Company capitalizes AFDC as part of construction costs.
AFDC represents the composite interest costs of capital funds
used to finance that portion of construction costs not yet
eligible for inclusion in rate base. AFDC is capitalized in
"Utility plant" with offsetting noncash credits to "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.
5. Depreciation:
Depreciation is provided annually on a straight-line basis.
The provision for depreciation as a percentage of weighted
average transmission and distribution depreciable property was
3.1 percent in each of the years 1998, 1997, and 1996.
6. Cash:
The Company classifies short-term investments with a maturity
of 90 days or less at time of purchase as cash.
7. New Accounting Standards:
In 1997, the Financial Accounting Standards Board (FASB)
released Statement of Financial Accounting Standards No. 130,
Reporting of Comprehensive Income (FAS 130), which was adopted by
the Company in the first quarter of 1998. FAS 130 establishes
standards for reporting comprehensive income and its components.
Comprehensive income for the period is equal to net income plus
"other comprehensive income," which for the Company, consists of
the change in unrealized holding gains on available-for-sale
securities during the period. Other comprehensive income was
immaterial for the Company for the year ended December 31, 1998.
Also in 1997, the FASB released Statement of Financial
Accounting Standards No. 131, Disclosure about Segments of an
Enterprise and Related Information (FAS 131), which went into
effect in 1998. FAS 131 requires the reporting in financial
statements of certain new additional information about operating
segments of a business. FAS 131 does not currently impact the
Company's reporting requirements.
In February 1998, the FASB issued Statement of Financial
Accounting Standards No. 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits (FAS 132), which
revises disclosure requirements for pension and other
postretirement benefits. The Company has adopted FAS 132 in its
financial statements for the year ended December 31, 1998.
The adoption of FAS 130, FAS 131, and FAS 132 had no impact on
the Company's operating results, financial position, or cash
flows.
In June 1998, the FASB issued Statement of Financial
Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (FAS 133), which establishes
accounting and reporting standards for such instruments. FAS 133
is effective for fiscal years beginning after June 15, 1999.
Currently, the Company has no such derivative holdings.
Note B - Merger Agreements
Merger Agreement with The National Grid Group plc
On December 11, 1998, NEES, The National Grid Group plc
(National Grid), and NGG Holdings LLC (Holdings), a directly and
indirectly wholly owned subsidiary of National Grid, entered into
an Agreement and Plan of Merger (Merger Agreement). Pursuant to
the Merger Agreement, Holdings will merge with and into NEES (the
Merger), with NEES becoming a wholly owned subsidiary of National
Grid. The Company will remain a wholly owned subsidiary of NEES.
The Merger is subject to approval by a majority vote of NEES
shareholders as well as National Grid shareholder approval. In
addition, the Merger is subject to a number of regulatory and
other approvals and consents, including approvals by the
Securities and Exchange Commission (SEC), under the Public
Utility Holding Company Act of 1935 (1935 Act), Federal Energy
Regulatory Commission (FERC), and Nuclear Regulatory Commission
(NRC), support or approval from the states in which NEES
subsidiaries operate, and clearance under both the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended,
and the Exon-Florio Provisions of the Omnibus Trade and
Competitiveness Act of 1988. National Grid has obtained
governmental clearance in the United Kingdom for the Merger. The
Merger is expected to be completed by early 2000.
Merger Agreement with Eastern Utilities Associates
On February 1, 1999, NEES, Eastern Utilities Associates (EUA),
and Research Drive LLC (Research Drive), a directly and
indirectly wholly owned subsidiary of NEES, entered into an
Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA
Agreement, Research Drive will merge with and into EUA, with EUA
becoming a wholly owned subsidiary of NEES.
The acquisition of EUA is subject to approval by a two-thirds
vote of EUA shareholders. In addition, the acquisition is subject
to a number of regulatory and other approvals and consents,
including approvals by the SEC, under the 1935 Act, FERC, and
NRC, support or approval from the states in which EUA
subsidiaries operate, and clearance under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. The EUA
acquisition is expected to be completed by early 2000. Following
the acquisition of EUA, the subsidiaries of NEES and EUA whose
operations are similar are expected to be consolidated.
Note C - Industry Restructuring
Pursuant to legislation enacted in Rhode Island and settlement
agreements approved by state and federal regulators, all
customers were provided the right to purchase electricity from
the power supplier of their choice effective January 1, 1998.
Customers who do not choose a power supplier are able, for a
period of time, to continue to purchase their electricity from
the Company at a transition rate ("standard offer generation
service") which, when combined with delivery charges, results in
a total rate reduction of 8 percent compared with the rates that
had been in effect prior to the introduction of customer choice.
Pursuant to the Rhode Island statute, the total rate for
customers who do not choose a power supplier is capped through
2009 at a level equal to the 1996 rate adjusted upward for 80
percent of inflation and for other factors beyond the control of
the Company.
On September 1, 1998, the Company and NEP, (collectively, the
Sellers) completed the sale of substantially all of their
nonnuclear generating business, all of which had a book value of
approximately $1.1 billion, to USGen New England, Inc. (USGen),
an indirect wholly owned subsidiary of PG&E Corporation. Included
in the sale was the Company's 10 percent share of Manchester
Street Station. The Sellers received $1.59 billion for the sale,
of which the Company received approximately $40 million equal to
the net book value of its assets included in the sale. Effective
September 1, 1998, USGen and TransCanada Power Marketing, Ltd.
became the Company's principal suppliers for meeting standard
offer generation service obligations. However, NEP remained
obligated for standard offer service for new customer load in
Rhode Island.
The Rhode Island Settlement also provides that the costs of
NEP's generating investments and related contractual commitments
that were not recovered from the divestiture of those investments
("stranded costs") (the Company's share is 22 percent) are to be
recovered from distribution customers through CTCs, which will be
collected by the Company. Under the Rhode Island Settlement, the
recovery of NEP's stranded costs is divided into several
categories. Unrecovered costs associated with generating plants
(nuclear and nonnuclear) and most regulatory assets will be fully
recovered through the CTC by the end of 2000 and would earn a
return on equity of 11 percent. NEP's obligation relating to the
above-market cost of purchased power contracts and nuclear
decommissioning costs are recovered through the CTC over a longer
period of time, as such costs are actually incurred. NEP's CTC
rate was originally set at 2.8 cents per kilowatthour (kWh), and
subsequently reduced to approximately 1.5 cents or less per kWh
upon completion of the sale of NEP's nonnuclear generating
business as described above.
Accounting Implications
Historically, electric utility rates have been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of
Certain Types of Regulation (FAS 71), requires regulated
entities, in appropriate circumstances, to establish regulatory
assets, and thereby defer the income statement impact of these
charges because they are expected to be included in future
customer charges.
The Company believes the Rhode Island Settlement and statute
will enable the Company to recover through rates its specific
costs of providing ongoing distribution services and stranded
costs billed to it by NEP. The Company believes these factors
will allow it to continue to apply FAS 71.
Currently, there is much regulatory and other movement toward
establishing performance-based rates. It is possible that the
adoption of performance-based rates, future regulatory rules, or
other circumstances could cause the application of FAS 71 to be
discontinued. This discontinuation would result in a noncash
write-off of previously established regulatory assets. In
addition, reserves for depreciation may also have to be increased
to comply with unregulated accounting practices.
The components of regulatory assets are as follows:
At December 31, (In thousands) 1998 1997
- ------------------------------------------------------------------------------
Regulatory assets (liabilities) included
in current assets and liabilities:
Rate adjustment mechanisms $(29,144) $ (9,794)
-------- --------
Regulatory assets (liabilities) included
in deferred charges and other reserves
and deferred credits:
Deferred FAS No. 109 costs 31,430 31,291
Unamortized losses on reacquired debt 10,963 12,438
Storm fund (4,477) (3,586)
Other 7,331 5,225
-------- --------
45,247 45,368
-------- --------
$ 16,103 $ 35,574
======== ========
Note D - Commitments and Contingencies
1. Plant expenditures:
The Company's utility plant expenditures are estimated to be
$25 million in 1999. At December 31, 1998, 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. A number of states, including Massachusetts, have
enacted similar laws.
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. NEES subsidiaries currently have in
place an internal environmental audit program and an external
waste disposal vendor audit and qualification program intended to
enhance compliance with existing federal, state, and local
requirements regarding the handling of potentially hazardous
products and by-products.
The Company has been named as a potentially responsible party
(PRP) by either the United States Environmental Protection Agency
or the Massachusetts Department of Environmental Protection for
three sites (two of which are located in Massachusetts) at which
hazardous waste is alleged to have been disposed. The Company is
currently aware of other sites, and may in the future become
aware of additional sites, that it may be held responsible for
remediating.
Gas was manufactured from coal in Rhode Island in the past.
The Company is aware of five sites on which gas was manufactured
or manufactured gas was stored that were owned either by the
Company or by its predecessor companies. It is not known to what
extent the Company would be held liable for hazardous wastes, if
any, left at these manufactured gas locations.
Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult. There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by the Company. a
preliminary review by a consultant hired by the NEES companies of
the potential cost of investigating and, if necessary,
remediating Rhode Island manufactured gas sites resulted in costs
per site ranging from less than $1 million to $11 million. An
informal survey of other utilities conducted on behalf of NEES
and its subsidiaries indicated costs in a similar range. The
NEES companies have recovered amounts from certain insurers, and,
where appropriate, the Company intends to seek recovery from
other 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. Absent unusual circumstances, 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 1998, 1997, and 1996 included the following components:
- -----------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------------------------------------
Service cost - benefits earned during the period $ 2,020$ 2,092 $ 2,007
Plus (less):
Interest cost on projected benefit obligation 9,135 9,027 8,954
Return on plan assets at expected long-term rate (10,688)(10,311) (9,787)
Amortization of transition obligation (345) (351) (355)
Amortization of prior service cost 217 245 249
Amortization of net (gain)/loss 124 56 271
Curtailment (gain)/loss (860) - -
- -----------------------------------------------------------------------------------------
Benefit cost $ (397)$ 758 $ 1,339
- -----------------------------------------------------------------------------------------
Special termination benefits not included above $ 10,146$ - $ -
- -----------------------------------------------------------------------------------------
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:
- ---------------------------------------------------------------------------
(millions of dollars) 1998 1997
- ---------------------------------------------------------------------------
Benefit obligation $843 $819
Unrecognized prior service costs (6) (8)
Transition liability not yet recognized (amortized) (2) (4)
Additional minimum liability 7 4
- ---------------------------------------------------------------------------
842 811
- ---------------------------------------------------------------------------
Plan assets at fair value 837 834
Transition asset not yet recognized (amortized) (6) (8)
Net (gain)/loss not yet recognized (amortized) (92) (52)
- ---------------------------------------------------------------------------
739 774
- ---------------------------------------------------------------------------
Accrued pension/(prepaid) payments
recorded on books $103 $ 37
- ---------------------------------------------------------------------------
The following provides a reconciliation of benefit obligations
and plan assets:
- ---------------------------------------------------------------------------
(millions of dollars) 1998 1997
- ---------------------------------------------------------------------------
Changes in benefit obligation:
Benefit obligation at January 1 $819 $807
Service cost 14 15
Interest cost 55 53
Actuarial (gain)/loss (5) 59
Benefits paid from plan assets (94) (47)
Special termination benefits 64 -
Curtailment (11) -
Plan Amendments 1 -
Dispositions (Yankee Atomic) - (68)
- ---------------------------------------------------------------------------
Benefit obligation at December 31 $843 $819
- ---------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $834 $812
Actual return on plan assets during year 93 130
Company contributions 4 8
Benefits paid from plan assets (94) (47)
Dispositions (Yankee Atomic) - (69)
- ---------------------------------------------------------------------------
Fair value of plan assets at December 31 $837 $834
- ---------------------------------------------------------------------------
Year ended December 31 1999 1998 1997 1996
- ----------------------------------------------------------------------
Assumptions used to determine pension cost:
Discount rate 6.75% 6.75% 7.25% 7.25%
Average rate of increase in
future compensation level 4.13% 4.13% 4.13% 4.13%
Expected long-term rate of
return on assets 8.50% 8.50% 8.50% 8.50%
The plans' funded status at December 31, 1998 and 1997 were
calculated using the assumed rates from 1999 and 1998,
respectively, and the 1983 Group Annuity Mortality table.
Plan assets are composed primarily of corporate equity, debt
securities, and cash equivalents.
2. Postretirement Benefit Plans Other than Pensions (PBOPs):
The Company provides health care and life insurance coverage
to eligible retired employees. Eligibility is based on certain
age and length of service requirements and in some cases retirees
must contribute to the cost of their coverage.
The Company's total cost of PBOPs for 1998, 1997, and 1996
included the following components:
- -----------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1998 1997 1996
- -----------------------------------------------------------------------------------------
Service cost - benefits earned during the period $ 962 $ 990 $ 1,030
Plus (less):
Interest cost on projected benefit obligation 4,701 4,843 5,034
Return on plan assets at expected long-term rate (4,013) (3,513) (2,803)
Amortization of transition obligation 3,696 3,862 3,862
Amortization of prior service cost 12 12 12
Amortization of net (gain)/loss (1,697) (1,617) (1,135)
Curtailment (gain)/loss 7,075 - -
- -----------------------------------------------------------------------------------------
Benefit cost $10,736 $ 4,577 $ 6,000
- -----------------------------------------------------------------------------------------
Special termination benefits not included above $ 784 $ - $ -
- -----------------------------------------------------------------------------------------
The following table sets forth the Company's benefits earned
and the plans' funded status:
- -----------------------------------------------------------------------------
At December 31 (millions of dollars) 1998 1997
- -----------------------------------------------------------------------------
Benefit obligation $ 74 $ 69
Unrecognized prior service costs - -
Transition liability not yet recognized (amortized) (47) (58)
- -----------------------------------------------------------------------------
27 11
- -----------------------------------------------------------------------------
Plan assets at fair value 53 50
Net (gain)/loss not yet recognized (amortized) (32) (33)
- -----------------------------------------------------------------------------
21 17
- -----------------------------------------------------------------------------
Accrued pension/(prepaid) payments recorded on books $ 6 $ (6)
- -----------------------------------------------------------------------------
The following provides a reconciliation of benefit obligations
and plan assets:
- -----------------------------------------------------------------------------
(millions of dollars) 1998 1997
- -----------------------------------------------------------------------------
Changes in benefit obligation:
Benefit obligation at January 1 $ 69 $ 75
Service cost 1 1
Interest cost 5 5
Actuarial (gain)/loss 2 (9)
Benefits paid from plan assets (4) (3)
Special termination benefits 1 -
Curtailment - -
- -----------------------------------------------------------------------------
Benefit obligation at December 31 $ 74 $ 69
- -----------------------------------------------------------------------------
Reconciliation of change in plan assets:
Fair value of plan assets at January 1 $ 50 $ 42
Actual return on plan assets during year 7 8
Company contributions - 3
Benefits paid from plan assets (4) (3)
- -----------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 53 $ 50
- -----------------------------------------------------------------------------
Year ended December 31 1999 1998 1997 1996
- ----------------------------------------------------------------------
Assumptions used to determine postretirement benefit cost:
Discount rate 6.75% 6.75% 7.25% 7.25%
Expected long-term rate of
return on assets 8.25% 8.25% 8.25% 8.25%
Health care cost rate -
1996 to 1999 5.25% 5.25% 8.00% 8.00%
Health care cost rate -
2000 to 2004 5.25% 5.25% 6.25% 6.25%
Health care cost rate -
2005 and beyond 5.25% 5.25% 5.25% 5.25%
The plans' funded status at December 31, 1998 and 1997 were
calculated using the assumed rates in effect for 1999 and 1998,
respectively.
The assumptions used in the health care cost trends have a
significant effect on the amounts reported. A one percentage
point change in the assumed rates would increase the accumulated
postretirement benefit obligation (APBO) as of December 31, 1998
by approximately $9 million or decrease the APBO by approximately
$8 million, and change the net periodic cost for 1998 by
approximately $1 million.
The Company generally funds the annual tax-deductible
contributions. Plan assets are invested in equity and debt
securities and cash equivalents.
3. Early Retirement and Special Severance Programs:
In 1998, the Company offered a voluntary early retirement
program to all 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 to reflect the sale of the nonnuclear generating
business. The early retirement offer was accepted by 141
employees. A special severance program was also utilized in 1998
for employees affected by the organizational restructuring, but
who were not eligible for, or did not accept, the early
retirement offer. The cost of these programs is being reimbursed
by NEP.
Note F - Income Taxes
The Company and other subsidiaries participate with NEES in
filing consolidated federal income tax returns. The Company's
income tax provision is calculated on a separate return basis.
Federal income tax returns have been examined and reported on by
the Internal Revenue Service through 1993.
Total federal income taxes consist of the following
components:
Year ended December 31, (In thousands) 1998 1997 1996
---- ---- ----
Income taxes charged (credited)
to operations:
Current income taxes $19,530 $14,648 $ 7,499
Deferred income taxes (2,863) 93 4,950
Investment tax credits, net (490) (494) (498)
------- ------- -------
Total income taxes charged
to operations 16,177 14,247 11,951
------- ------- -------
Income taxes charged (credited)
to "Other income":
Current income taxes (218) (464) (581)
Deferred income taxes 652 (14) (275)
------- ------- -------
Total income taxes charged
(credited) to "Other income" 434 (478) (856)
------- ------- -------
Total federal income taxes $16,611 $13,769 $11,095
======= ======= =======
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 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) 1998 1997 1996
- ----------------------------------------------------------------
Computed tax at statutory rate $17,102 $14,595 $11,917
Increases (reductions) in tax resulting from:
Book versus tax depreciation
not normalized 707 741 778
Costs associated with utility
plant retirements deducted
for tax purposes (769) (1,046) (1,341)
Amortization of investment
tax credits (490) (494) (498)
All other differences 61 (27) 239
------- ------- -------
Total federal income taxes $16,611 $13,769 $11,095
======= ======= =======
The following table identifies the major components of total
deferred income taxes:
At December 31, (In millions) 1998 1997
---- ----
Deferred tax asset:
Plant related $ 2 $ 2
Investment tax credits 3 3
All other 17 13
----- -----
22 18
----- -----
Deferred tax liability:
Plant related (75) (72)
All other (28) (29)
----- -----
(103) (101)
----- -----
Net deferred tax liability $ (81) $ (83)
===== =====
Note G - Short-Term Borrowings and Other Current Liabilities
At December 31, 1998, the Company had $27 million of
short-term debt outstanding representing 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, 1998, the Company had lines of credit with
banks totaling $41 million. There were no borrowings under these
lines of credit at December 31, 1998. Fees are paid in lieu of
compensating balances on most lines of credit.
The components of other accrued expenses are as follows:
At December 31, (In thousands) 1998 1997
- ----------------------------------------------------------------
Rate adjustment mechanisms $30,680 $12,970
Accrued wages and benefits 3,776 8,050
Other 278 499
------- -------
$34,734 $21,519
======= =======
Note H - Cumulative Preferred Stock
A summary of cumulative preferred stock at December 31, 1998
and 1997 is as follows (in thousands of dollars except for share
data):
Shares Dividends Call
Outstanding Amount Declared Price
- ------------------------------------------------------------------------------
1998 1997 1998 1997 1998 1997
- ------------------------------------------------------------------------------
$50 Par value
4.50% Series 49,209 49,730 $2,460 $ 2,487 $111 $ 365 $55.000
4.64% Series 57,057 61,217 2,853 3,061 137 320 $52.125
6.95% Series 38,500 145,050 1,925 7,252 319 1,270 (a)
- ------------------------------------------------------------------------------
Total 144,766 255,997 $7,238 $12,800 $567 $1,955
- ------------------------------------------------------------------------------
<FN>
(a) Callable on or after August 1, 2003 at $51.74.
</FN>
The annual dividend requirement for total cumulative
preferred stock was $377,000 and $758,000 at the end of 1998 and
1997, respectively.
In 1998, the Company redeemed preferred stock with an
aggregate par value of $5.6 million. Total premiums of $1.2
million in connection with the preferred stock redemption were
charged to retained earnings.
Note I - Long-term Debt
A summary of long-term debt is as follows:
At December 31, (In thousands)
Series Rate % Maturity 1998 1997
- ----------------------------------------------------------------------------
First Mortgage Bonds:
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 20,200 22,200
T 8.875 August 1, 2021 17,000 22,000
U(93-5) 7.050 September 1, 2023 5,000 5,000
U(94-1) 7.050 February 2, 2024 5,000 5,000
V(94-1) 8.080 May 2, 2024 5,000 5,000
V(94-5) 8.160 August 9, 2024 5,000 5,000
V(95-2) 7.750 June 2, 2025 10,000 10,000
V(95-3) 7.500 October 10, 2025 7,000 7,000
W(95-1) 7.300 November 13, 2025 16,000 16,000
W(96-1) 7.240 January 19, 2026 2,000 2,000
W(97-1) 7.390 September 30, 2027 3,000 3,000
W(97-2) 7.390 October 1, 2027 7,000 7,000
Unamortized discounts and premiums (998) (1,155)
-------- --------
Total long-term debt $176,702 $188,545
======== ========
Long-term debt due in one year 8,000 5,000
-------- --------
$168,702 $183,545
======== ========
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 $8,000,000 in 1999,
$15,000,000 in 2000, $15,000,000 in 2002, $17,500,000 in 2003,
and $121,500,000 thereafter, to retire maturing mortgage bonds.
At December 31, 1998, the Company's long-term debt had a
carrying value of approximately $178,000,000 and had a fair value
of approximately $195,000,000. The fair market value of the
Company's long-term debt was estimated based on the quoted prices
for similar issues or on the current rates offered to the Company
for debt of the same remaining maturity.
Note J - Restrictions on Retained Earnings Available for
Dividends on Common Stock
As long as any preferred stock is outstanding, certain
restrictions on payment of dividends on common stock would come
into effect if the "junior stock equity" was, or by reason of
payment of such dividends became, less than 25 percent of "Total
capitalization." However, the junior stock equity at December 31,
1998 was 58 percent of total capitalization, and accordingly,
none of the Company's retained earnings at December 31, 1998 were
restricted as to dividends on common stock under the foregoing
provisions.
Note K - Regulatory Matters
a 1986 Rhode Island Supreme Court decision held that the
RIPUC's rate-making powers include the authority to order refunds
of amounts earned in excess of an allowed return. As a result,
the RIPUC monitors the Company's earnings on a regular basis.
Note L - Supplementary Income Statement Information
Advertising expenses, expenditures for research and
development, and rents were not material and there were no
royalties paid in 1998, 1997, or 1996. Taxes, other than federal
income taxes, charged to operating expenses are set forth by
class as follows:
Year ended December 31,
(In thousands) 1998 1997 1996
---- ---- ----
Municipal property taxes $19,325 $18,061 $16,546
State gross earnings tax 16,646 18,676 18,764
Federal and state payroll
and other taxes 2,944 2,629 3,220
------- ------- -------
$38,915 $39,366 $38,530
======= ======= =======
New England Power Service Company, an affiliated service
company operating pursuant to the provisions of Section 13 of the
1935 Act, furnished services to the Company at the cost of such
services. These costs amounted to $27,968,000, $23,341,000, and
$27,336,000, including capitalized construction costs of
$1,667,000, $1,946,000, and $6,426,000 for each of the years
1998, 1997, and 1996, respectively.
The Narragansett Electric Company
Selected Financial Information
Year ended December 31,
(In millions) 1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------
Operating revenue $476 $520 $504 $499 $482
Net income $ 32 $ 28 $ 23 $ 24 $ 15
Total assets $664 $713 $707 $700 $647
Capitalization:
Common equity $249 $292 $257 $245 $208
Cumulative preferred stock 7 13 36 36 37
Long-term debt 169 183 179 211 189
- ------------------------------------------------------------------------------
Total capitalization $425 $488 $472 $492 $434
Preferred dividends declared $ 1 $ 2 $ 2 $ 2 $ 2
Common dividends declared $ 74 $ 15 $ 9 $ 5 $ 3
Selected Quarterly Financial Information (Unaudited)
First Second Third Fourth
(In thousands) Quarter Quarter Quarter Quarter
- -----------------------------------------------------------------------------
1998
Operating revenue $119,976 $117,295 $128,787 $109,596
Operating income $ 14,805 $ 8,765 $ 14,101 $ 12,236
Net income $ 9,399 $ 4,335 $ 11,510 $ 7,009
1997
Operating revenue $131,466 $119,894 $141,980 $126,698
Operating income $ 13,403 $ 9,819 $ 14,238 $ 9,756
Net income $ 7,693 $ 5,085 $ 9,862 $ 5,292
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, 1998 will be available on or about April
1, 1999, at no charge by contacting: Merrill IR Edge, 33 Boston
Post Road, Suite 270, Marlborough, MA 01752, Telephone: 508-786-
1907, Fax: 508-786-1915, E-mail: iredge@merrillcorp.com.