SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-7471
(LOGO) THE NARRAGANSETT ELECTRIC COMPANY
(Exact name of registrant as specified in charter)
Rhode Island 05-0187805
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
280 Melrose Street, Providence, R.I. 02901
(Address of principal executive offices)
Registrant's telephone number, including area code
(401-784-7000)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes (X) No ( )
Common stock, par value $50 per share, authorized and outstanding: 1,132,487
shares at September 30, 1999.
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
- ----------------------------
THE NARRAGANSETT ELECTRIC COMPANY
Statements of Income
Periods Ended September 30
(Unaudited)
Quarter Nine Months
------- -----------
1999 1998 1999 1998
---- ---- ---- ----
(In Thousands)
Operating revenue $117,849 $128,787 $346,456 $366,058
-------- -------- -------- --------
Operating expenses:
Fuel for generation and purchased electric
energy:
Non-affiliates 41,205 12,651 113,484 12,863
New England Power Company, an affiliate 4,659 21,506
10,943 76,943
Contract termination charges from New
England Power Company 16,742 32,517 66,354 99,115
Other operation 14,826 22,722 50,779 68,849
Maintenance 3,709 2,755 9,563 8,706
Depreciation 5,623 5,762 16,868 17,685
Taxes, other than federal income taxes 9,807 10,799
29,186 31,201
Federal income taxes 5,593 5,974 11,618 13,025
-------- -------- -------- --------
Total operating expenses 102,164 114,686
308,795 328,387
-------- -------- -------- --------
Operating income 15,685 14,101 37,661 37,671
Other income:
Other income (expense), net 12 2,028 (1,316) 1,294
-------- -------- -------- --------
Operating and other income 15,697 16,129 36,345
38,965
-------- -------- -------- --------
Interest:
Interest on long-term debt 3,513 3,707 10,730 11,318
Other interest 951 924 2,568 2,475
Allowance for borrowed funds used during
construction (11) (12) (37) (72)
-------- -------- -------- --------
Total interest 4,453 4,619 13,261 13,721
-------- -------- -------- --------
Net income $ 11,244 $ 11,510 $ 23,084 $ 25,244
======== ======== ======== ========
Statements of Retained Earnings
(In Thousands)
Retained earnings at beginning of period $ 98,132 $105,550 $
86,465 $129,567
Net income 11,244 11,510 23,084 25,244
Dividends declared on cumulative
preferred stock (94) (99) (282) (478)
Dividends declared on common stock - (32,276) - (69,648)
Premium on redemption of preferred stock - (1,160) 15 (1,160)
-------- -------- -------- --------
Retained earnings at end of period $109,282 $ 83,525 $109,282
$ 83,525
======== ======== ======== ========
The accompanying notes are an integral part of these financial statements.
Per share data is not relevant because the Company's common stock is wholly
owned by New England Electric System.
THE NARRAGANSETT ELECTRIC COMPANY
Statements of Income
Twelve Months Ended September 30
(Unaudited)
1999 1998
---- ----
(In Thousands)
Operating revenue $456,052 $492,756
-------- --------
Operating expenses:
Fuel for generation and purchased electric energy:
Non-affiliates 150,197 12,882
New England Power Company, an affiliate 6,775 151,450
Contract termination charges from New England
Power Company 84,995 99,115
Other operation 77,722 90,273
Maintenance 12,854 12,031
Depreciation 21,942 23,048
Taxes, other than federal income taxes 36,900 40,685
Federal income taxes 14,770 15,845
-------- --------
Total operating expenses 406,155 445,329
-------- --------
Operating income 49,897 47,427
Other income:
Other income (expense), net (1,809) 1,617
-------- --------
Operating and other income 48,088 49,044
-------- --------
Interest:
Interest on long-term debt 14,337 15,196
Other interest 3,708 3,440
Allowance for borrowed funds used during
construction (50) (128)
-------- --------
Total interest 17,995 18,508
-------- --------
Net income $ 30,093 $ 30,536
======== ========
Statements of Retained Earnings
(In Thousands)
Retained earnings at beginning of period $ 83,525 $129,686
Net income 30,093 30,536
Dividends declared on cumulative preferred stock (371) (826)
Dividends declared on common stock (3,964) (73,045)
Premium on redemption of preferred stock (1) (2,826)
-------- --------
Retained earnings at end of period $109,282 $ 83,525
======== ========
The accompanying notes are an integral part of these financial statements.
Per share data is not relevant because the Company's common stock is wholly
owned by New England Electric System.
THE NARRAGANSETT ELECTRIC COMPANY
Balance Sheets
(Unaudited)
September 30, December 31,
ASSETS 1999 1998
- ------ ---- ----
(In Thousands)
Utility plant, at original cost $746,158 $732,077
Less accumulated provisions for depreciation 222,437 209,155
-------- --------
523,721 522,922
Construction work in progress 3,126 2,566
-------- --------
Net utility plant 526,847 525,488
-------- --------
Current assets:
Cash 2,381 2,957
Accounts receivable:
From electric energy services 44,542 53,727
Other (including $10,630,000 and $4,444,000
from affiliates) 11,802 5,575
Less reserves for doubtful accounts 4,748 4,240
-------- --------
51,596 55,062
Unbilled revenues 17,213 20,752
Fuel, materials, and supplies, at average cost 3,527 3,494
Prepaid and other current assets 17,453 739
-------- --------
Total current assets 92,170 83,004
-------- --------
Deferred charges and other assets 54,391 55,628
-------- --------
$673,408 $664,120
======== ========
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 81
Other paid-in capital 105,713 105,713
Retained earnings 109,282 86,465
Unrealized gain on securities, net 225 237
-------- --------
Total common equity 271,925 249,120
Cumulative preferred stock, par value $50 per share 7,238 7,238
Long-term debt 153,764 168,702
-------- --------
Total capitalization 432,927 425,060
-------- --------
Current liabilities:
Long-term debt due within one year 15,000 8,000
Short-term debt to affiliates 43,175 26,675
Accounts payable (including $13,356,000 and $1,929,000
to affiliates) 40,534 28,260
Accrued liabilities:
Taxes - 10,031
Interest 2,984 4,553
Other accrued expenses 16,712 34,734
Customer deposits 3,353 6,116
Dividends payable 94 4,058
-------- --------
Total current liabilities 121,852 122,427
-------- --------
Deferred federal income taxes 88,324 81,045
Unamortized investment tax credits 6,170 6,533
Other reserves and deferred credits 24,135 29,055
-------- --------
$673,408 $664,120
======== ========
The accompanying notes are an integral part of these financial statements.
THE NARRAGANSETT ELECTRIC COMPANY
Statements of Cash Flows
Nine Months Ended September 30
(Unaudited)
1999 1998
---- ----
(In Thousands)
Operating Activities:
Net income $ 23,084 $ 25,244
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation 16,868 17,685
Deferred federal income taxes and investment
tax credit, net 6,677 1,690
Allowance for funds used during construction (37) (72)
Decrease (increase) in accounts receivable, net
and unbilled revenue 7,005 (20,153)
Decrease (increase) in fuel, materials, and supplies (33)
601
Decrease (increase) in prepaid and other current assets
(16,714) 4,191
Increase (decrease) in accounts payable 12,274 (3,714)
Increase (decrease) in other current liabilities (32,385)
13,963
Other, net (3,174) 1,119
-------- --------
Net cash provided by operating activities $ 13,565
$ 40,554
-------- --------
Investing Activities:
Plant expenditures, excluding allowance for
funds used during construction $(18,223) $(14,860)
Other investing activities (172) (19)
Proceeds from sale of generating assets - 39,723
-------- --------
Net cash provided by (used in) investing activities
$(18,395) $ 24,844
-------- --------
Financing Activities:
Capital contributions from parent $ - $ 214
Dividends paid on common stock (3,964) (73,045)
Dividends paid on preferred stock (282) (568)
Long-term debt - retirements (8,000) (10,000)
Changes in short-term debt 16,500 24,400
Preferred stock - retirements - (5,153)
Premium on reacquisition of preferred stock - (1,160)
-------- --------
Net cash provided by (used in) financing activities $
4,254 $(65,312)
-------- --------
Net increase (decrease) in cash and cash equivalents $ (576) $
86
Cash and cash equivalents at beginning of period 2,957 3,122
-------- --------
Cash and cash equivalents at end of period $ 2,381 $ 3,208
======== ========
The accompanying notes are an integral part of these financial statements.
THE NARRAGANSETT ELECTRIC COMPANY
Notes to Unaudited Financial Statements
Note A - 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. The
Narragansett Electric Company (the Company) currently has 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 several 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 New England
Electric System (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 B
- ------
In the opinion of the Company, these financial statements reflect all
adjustments (which include normal recurring adjustments) necessary for a fair
statement of the results of its operations for the periods presented and
should be considered in conjunction with the notes to the financial statements
in the Company's 1998 Annual Report.
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
- -----------------------------------------------------------------
This section contains management's assessment of The Narragansett Electric
Company's (the Company) financial condition and the principal factors having
an impact on the results of operations. This discussion should be read in
conjunction with the Company's financial statements and footnotes and the 1998
Annual Report on Form 10-K.
Merger Agreements
- -----------------
For a full discussion of New England Electric System's (NEES) merger
agreements with The National Grid Group plc (National Grid) and Eastern
Utilities Associates (EUA), see the Merger Agreements sections of the
Company's Form 10-K for 1998 and the Company's 1998 Annual Report.
Update of Merger Agreements with National Grid and EUA
The NEES/National Grid merger has received approval or clearance from
shareholders of both National Grid and NEES, the Federal Trade Commission
(FTC), the Committee on Foreign Investment in the United States, the Federal
Energy Regulatory Commission (FERC), the Vermont Public Service Board (VPSB),
the Connecticut Department of Public Utility Control (CDPUC), and the New
Hampshire Public Utilities Commission (NHPUC).
On November 3, 1999, the Office of the Consumer Advocate for New
Hampshire filed a motion seeking rehearing or reconsideration of the merger
approval by the NHPUC with respect to the treatment of the acquisition premium
and stranded costs. NEES and National Grid have opposed the motion for
rehearing.
NEES and National Grid have also filed for merger approval with the
Securities and Exchange Commission (SEC), under the Public Utility Holding
Company Act of 1935 (1935 Act). In connection with the SEC application, the
Massachusetts Department of Telecommunications and Energy (MDTE) and the Rhode
Island Public Utilities Commission (RIPUC) certified to the SEC that the
merger would not interfere with their authority or ability to protect
customers of NEES' distribution subsidiaries in Massachusetts and Rhode
Island, respectively.
In addition, NEES and National Grid have also filed for merger approval
with the Nuclear Regulatory Commission (NRC) to transfer ownership licenses
for its minority ownership interests in regional nuclear plants. In July
1999, three subsidiaries of Northeast Utilities (NU) filed a request for
hearing with the NRC with respect to financial qualifications and issues of
foreign ownership. In October 1999, the NRC issued an order granting the
request for hearing and directed NEES, National Grid, and the NU subsidiaries
to promptly determine whether the proceeding could be settled without a
hearing. In November 1999, NEES, National Grid, and the NU subsidiaries
executed an agreement with respect to these issues. As part of this
agreement, the NU subsidiaries agreed to withdraw their intervention and
request for hearing. Assuming the NRC grants the motion to withdraw, NEES and
National Grid anticipate that the remaining required regulatory approvals from
the SEC, under the 1935 Act, and the NRC will be obtained in a time frame that
will allow the merger to be completed by early 2000.
The NEES acquisition of EUA has received approval or clearance from EUA
shareholders, the FTC, the CDPUC, and the FERC. NEES and EUA have also made
appropriate filings with the SEC, under the 1935 Act, NRC, MDTE, VPSB, and the
RIPUC. The acquisition of EUA is expected to be completed by early 2000.
Impact of Mergers on Distribution Rates
- ---------------------------------------
In May 1999, the Company, along with Blackstone Valley Electric Company
(Blackstone Valley) and Newport Electric Corporation (Newport Electric),
wholly owned subsidiaries of EUA, filed a rate consolidation plan with the
RIPUC, reflecting the acquisition of EUA by NEES and the merger of Blackstone
Valley and Newport Electric into the Company. In the filing, the companies
proposed that effective within 120 days after the closing of the NEES
acquisition of EUA or on April 1, 2000, whichever is later, most distribution
rates for customers of Blackstone Valley and Newport Electric would be reduced
by approximately $5 million per year. The filing calls for a distribution
rate freeze through December 31, 2002. The freeze would be extended an
additional two years upon completion of the NEES/National Grid merger.
Industry Restructuring
- ----------------------
For a full discussion of industry restructuring activities in Rhode
Island, the NEES companies' divestiture of its nonnuclear generating business
(the divestiture), stranded cost recovery, and the impact of restructuring on
the distribution business, see the "Industry Restructuring" and "Impact of
Restructuring on Distribution Business" sections of the Company's Form 10-K
for 1998 and the Company's 1998 Annual Report.
Regulatory Asset Recovery
- -------------------------
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 September 30, 1999, the Company had
net regulatory assets of approximately $32 million.
Under existing ratemaking practices and provisions of industry
restructuring settlement agreements approved by state and federal regulators,
the Company has the ability to recover through rates its specific costs of
providing ongoing distribution services and stranded costs billed to it by New
England Power Company (NEP). To date, the Company believes these factors
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. Absent the circumstances
described in the next paragraph, 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.
In May 1999, the Company filed a rate plan which, if approved, may cause the
application of FAS 71 to be discontinued upon consummation of the
NEES/National Grid merger. Because the discontinuation of FAS 71 would be
coincident with the completion of the NEES/National Grid merger, the NEES
companies believe the appropriate accounting treatment would be that the
regulatory assets would not be written off but instead reclassified to either
an intangible asset account or a goodwill account.
Year 2000 Readiness Disclosure
- ------------------------------
Over the course of this year, most companies have faced and will continue
to 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 the year 2000 (Y2K).
This could cause computers to either shut down or lead to incorrect
calculations.
The NEES companies believe that their mission critical systems used to
deliver electricity are ready for date changes associated with Y2K, in
accordance with the criteria specified by the North American Electric
Reliability Council (NERC). Recognizing that neither the NEES companies nor
any other organization can make guarantees about something as complex as Y2K,
the NEES companies have also developed and implemented the contingency plans
described below (including contingency plans in the event of temporary
disruptions of electric service) to address potential problems caused by Y2K.
In the event that a short-term disruption in service occurs, NEES does not
expect that such a disruption would have a material impact on its financial
position or results of operation.
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 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 IBM to provide personnel support to the Y2K
Project. Through September 30, 1999, the NEES companies have spent
approximately $18 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 separated their Y2K Project into four parts as shown on the
following page.
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/ Completed Throughout 1999
Department software/
Networks
Operational/ Dispatching systems/ Completed Throughout 1999
Embedded Transmission and
systems Distribution systems/
Telephone systems
External issues Electronic Data Completed Throughout 1999
Interchange/Vendor
communications
The NEES companies used 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 was completed on June 30,
1999, required 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 have been implemented for mission critical systems, as described below.
The overall Y2K Project was designed such that Y2K-related work performed
by external consultants was reviewed by NEES employees, and vice-versa. The
Y2K Project team management continuously benchmarked its progress against the
recommended progress schedule documented by NERC, and has met all recommended
schedules, including the issuance of its Year 2000 Readiness Letter to NERC on
June 30, 1999.
The NEES companies 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 (transition service) 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
have been implemented, 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, including the replacement of approximately one
thousand desktop computers. In addition, the NEES companies have spent $7
million (of which approximately $6 million has been capitalized) related to
the replacement of the human resources and payroll system, in part due to the
Y2K issue. As of September 30, 1999, substantially all Y2K-related costs have
been incurred. The NEES companies continually review their cost estimates
based upon the overall Y2K Project status, and update these estimates as
warranted.
The NEES companies developed and implemented Y2K contingency plans to
allow for critical information and operating systems to function from January
1, 2000, forward. These plans are intended to address both internal risks as
well as potential external risks related to suppliers and customers. Part of
the contingency plan implementation 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 the Y2K
contingency plan implementation, the NEES companies have reviewed their
disaster recovery plans and modified them for Y2K-specific issues, such as a
potential loss of telecommunication services. The NEES companies conducted
contingency plan drills on September 8, and 9, 1999.
Interregional and regional contingency plans have been finalized for
utility systems throughout the United States. At a regional level, the NEES
companies have participated and cooperated with NEPOOL and ISO New England.
Overall regional activities, including those of NEPOOL and ISO New England,
are being coordinated by the Northeast Power Coordinating Council, whose
activities have been incorporated into the interregional coordinating effort
by NERC. Drills of these interregional and regional contingency plans were
also conducted on September 8 and 9, 1999.
Earnings
- --------
Net income decreased less than $1 million during the third quarter of
1999 and $2 million for the first nine months of 1999, compared with the
corresponding periods in 1998. The decrease is due principally to the loss of
income associated with the Company's former 10 percent ownership of the
Manchester Street generating station (Manchester Street) as a result of the
divestiture, partially offset by increased kilowatthour (kWh) deliveries,
reduced operation and maintenance expenses on a combined basis, and reduced
property taxes. The
decrease for the third quarter is also due to the effect of a 1998
reimbursement by NEP to the Company for premiums on the reacquisition of
preferred stock. These premiums were charged to retained earnings.
Operating Revenue
- -----------------
Operating revenue decreased $11 million and $20 million in the third
quarter and first nine months of 1999, respectively, compared with the
corresponding periods in 1998, due primarily to a transition access charge
rate reduction effective January 1, 1999. The decrease is partially offset by
increased standard offer revenues and increased kWh deliveries of 5.7 percent
and 4.5 percent in the third quarter and year-to-date period, respectively, as
a result of significantly warmer weather and the effect of a strong economy.
The decrease for the year-to-date period is also partially offset by the
recovery of increased demand-side management (DSM) spending, an increase in
transmission rates associated with an increase in transmission costs, and the
impact of a refund made in January 1998 of past overrecoveries of
postretirement benefits other than pension (PBOP) costs.
Operating Expenses
- ------------------
Operating expenses for the third quarter and first nine months of 1999
decreased $13 million and $20 million, respectively, compared with the
corresponding periods in 1998. The decrease is due primarily to reduced
transition access charge billings from NEP, decreased operation and
maintenance expenses on a combined basis, and reduced property taxes. These
decreases are partially offset by reduced reimbursements associated with the
Company's former 10 percent ownership of Manchester Street.
Fuel and purchased electric energy costs decreased $4 million in the
third quarter but increased $2 million for the year-to-date period. Access
charge billings from NEP decreased $16 million and $33 million, respectively,
in the third quarter and first nine months of 1999. Reimbursement credits from
NEP in connection with the Company's ownership of transmission facilities and
former ownership of generation facilities decreased $9 million and $30
million, respectively, in the third quarter and year-to-date period. However,
$6 million and $19 million, respectively, of this reduction represents a
reclassification of the transmission portion of such credits from purchased
power expense to operation and maintenance expense in 1999. In addition, the
Company experienced increased standard offer purchased power costs of
approximately $2 million and $4 million for the third quarter and year-to-date
period, respectively, reflecting increased sales.
Operation and maintenance expenses decreased $7 million and $17 million
on a combined basis for the third quarter and first nine months of 1999,
respectively. These decreases are primarily due to the reclassification of
reimbursement credits from NEP described in the previous paragraph, as well as
reduced administrative costs resulting from workforce reductions. Partially
offsetting these decreases are increased transmission wheeling costs and
increased distribution maintenance costs as a result of severe weather in the
third quarter of 1999. For the year-to-date period, operation and maintenance
expenses also decreased due to the divestiture and the effect of a second
quarter 1998 accounting write-off of approximately $2 million of certain
previously capitalized plant items, partially offset by increased DSM spending
and the impact of a first quarter 1998 refund of past overrecoveries of PBOP
costs.
The decrease in taxes other than income taxes for the third quarter and
first nine months of 1999 is primarily the result of reduced property tax
expense, a portion of which is due to the Company's sale of Manchester Street.
Other Income
- ------------
The decrease in other income for the third quarter and year-to-date
period is primarily due to a third quarter 1998 reimbursement by NEP to the
Company for premiums incurred on the reacquisition of preferred stock in
connection with the divestiture.
Utility Plant Expenditures and Financing
- ----------------------------------------
Cash expenditures for utility plant totaled $18 million for the first
nine months of 1999. The funds necessary for utility plant expenditures during
the period were provided by net cash from operating activities, after the
payment of dividends, plus increased short-term debt.
In the first nine months of 1999, the Company retired $8 million of
mortgage bonds.
At September 30, 1999, the Company had $43 million of short-term debt
outstanding to affiliates. The Company has received regulatory approval from
the SEC, under the 1935 Act, to issue up to $100 million of short-term debt.
As of September 30, 1999, the Company had lines of credit with banks totaling
$41 million. There were no borrowings under these lines of credit at September
30, 1999.
For the twelve-month period ending September 30, 1999, the ratio of
earnings to fixed charges was 3.51.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
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Information concerning a rate consolidation plan filed by the Company
with the Rhode Island Public Utilities Commission on May 20, 1999, discussed
in Part I of this report in Management's Discussion and Analysis of Financial
Condition and Results of Operations is incorporated herein by reference and
made a part hereof.
Item 6. Exhibits and Reports on Form 8-K
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The Company is filing the following revised exhibit for incorporation by
reference into its registration statement on Form S-3, Commission File No. 33-
61131.
12 Statement re computation of ratios
The Company is filing Financial Data Schedules.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report on Form 10-Q for the quarter ended
September 30, 1999 to be signed on its behalf by the undersigned thereunto
duly authorized.
THE NARRAGANSETT ELECTRIC COMPANY
s/ John G. Cochrane
John G. Cochrane,
Treasurer, Authorized Officer, and
Principal Financial Officer
Date: November 10, 1999