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, 1997
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)
Incorporated in Vermont 03-0111290
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)
802-773-2711
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last
report)
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
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date. As of October
31, 1997 there were outstanding 11,423,401 shares of Common Stock, $6 Par
Value.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q
Table of Contents
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statement of Income and Retained
Earnings for the three and nine months ended
September 30, 1997 and 1996 3
Consolidated Balance Sheet as of September 30, 1997 and
December 31, 1996 4
Consolidated Statement of Cash Flows for the nine
months ended September 30, 1997 and 1996 5
Notes to Consolidated Financial Statements 6-9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 10-23
PART II. OTHER INFORMATION 24
SIGNATURES 25
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<TABLE>
<CAPTION>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
1997 1996 1997 1996
<S> <C> <C> <C> <C>
Operating Revenues $67,990 $63,833 $221,926 $209,469
Operating Expenses
Operation
Purchased power 40,114 37,063 121,415 110,774
Production and
transmission 6,134 5,615 17,421 15,307
Other operation 9,762 10,030 30,445 27,650
Maintenance 4,187 4,203 10,913 10,620
Depreciation 4,135 4,511 12,824 13,391
Other taxes, principally
property taxes 2,394 2,657 8,100 8,123
Taxes on income 86 (520) 6,375 7,698
_______ _______ _______ _______
Total operating expenses 66,812 63,559 207,493 193,563
_______ _______ _______ _______
Operating Income 1,178 274 14,433 15,906
_______ _______ _______ _______
Other Income and Deductions
Equity in earnings of
affiliates 790 807 2,467 2,460
Allowance for equity funds
during construction 9 31 53 79
Other income, net 3,633 658 7,007 2,345
Benefit (provision) for income
taxes (1,126) (80) (2,157) 88
_______ _______ _______ _______
Total other income and
deductions, net 3,306 1,416 7,370 4,972
_______ _______ _______ _______
Total Operating and Other
Income 4,484 1,690 21,803 20,878
_______ _______ _______ _______
Net Interest Expense 2,419 2,475 7,274 7,352
_______ _______ _______ _______
Net Income (Loss) 2,065 (785) 14,529 13,526
Retained Earnings at Beginning
of Period 77,983 72,553 74,137 66,422
_______ _______ _______ _______
80,048 71,768 88,666 79,948
Cash Dividends Declared
Preferred stock 507 507 1,521 1,521
Common stock (21) - 7,583 7,166
_______ _______ _______ _______
Total dividends declared 486 507 9,104 8,687
_______ _______ _______ _______
Retained Earnings at End
of Period $79,562 $71,261 $ 79,562 $ 71,261
======== ======= ======== ========
Earnings (Losses) Available
for Common Stock $ 1,558 $(1,292) $13,008 $12,005
Average Shares of Common
Stock Outstanding 11,423,401 11,519,748 11,470,643 11,552,140
Earnings (Losses) Per Share
of Common Stock $ .14 $(.11) $1.13 $1.04
Dividends Paid Per Share
of Common Stock $ .22 $ .22 $ .66 $ .62
</TABLE>
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<TABLE>
<CAPTION>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
(Unaudited)
September 30 December 31
1997 1996
<S> <C> <C>
Assets
Utility Plant, at original cost $465,467 $461,231
Less accumulated depreciation 156,650 146,539
________ ________
308,817 314,692
Construction work in progress 13,243 9,302
Nuclear fuel, net 965 947
________ ________
Net utility plant 323,025 324,941
________ ________
Investments and Other Assets
Investments in affiliates, at equity 26,741 26,630
Non-utility investments 30,271 27,823
Non-utility property, less accumulated
depreciation 2,872 4,498
________ ________
Total investments and other assets 59,884 58,951
________ ________
Current Assets
Cash and cash equivalents 23,716 6,365
Special deposits 3,381 5,633
Accounts receivable 13,132 21,878
Unbilled revenues 6,272 11,673
Materials and supplies, at average cost 3,689 3,690
Prepayments 2,607 2,423
Other current assets 3,994 3,840
________ ________
Total current assets 56,791 55,502
________ ________
Regulatory Assets and Other Deferred Charges 71,898 63,574
________ ________
Total Assets $511,598 $502,968
======== ========
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized
19,000,000 shares;
outstanding 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,290 45,273
Treasury stock (362,447 shares
and 266,100 shares,
respectively, at cost) (4,728) (3,656)
Retained earnings 79,562 74,137
________ ________
Total common stock equity 190,839 186,469
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund
requirements 20,000 20,000
Long-term debt 117,374 117,374
Long-term lease arrangements 17,493 18,304
________ ________
Total capitalization 353,760 350,201
________ ________
Current Liabilities
Short-term debt - 5,750
Current portion of long-term debt 3,001 3,015
Accounts payable 3,699 4,432
Accounts payable - affiliates 10,627 12,109
Accrued income taxes 1,148 2,552
Dividends declared 507 507
Other current liabilities 27,422 24,184
________ ________
Total current liabilities 46,404 52,549
________ ________
Deferred Credits
Deferred income taxes 56,871 57,463
Deferred investment tax credits 7,319 7,612
Other deferred credits 47,244 35,143
________ ________
Total deferred credits 111,434 100,218
________ ________
Total Capitalization and Liabilities $511,598 $502,968
======== ========
</TABLE>
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<TABLE>
<CAPTION>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Nine Months Ended
September 30
1997 1996
<S> <C> <C>
Cash Flows Provided (Used) By
Operating Activities
Net income $14,529 $13,526
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation 12,824 13,391
Deferred income taxes and investment
tax credits (691) 554
Allowance for equity funds during
construction (53) (79)
Net deferral and amortization of nuclear
refueling replacement energy and
maintenance costs 4,045 (1,393)
Amortization of conservation and
load management costs 5,264 3,896
Gain on sale of investment (2,891) -
Gain on sale of property (2,095) (700)
Decrease in accounts receivable 12,207 11,999
Increase(decrease) in accounts payable (2,043) 2,878
Decrease in accrued income taxes (1,316) (2,117)
Change in other working capital items 5,311 3,408
Other, net (4,684) (2,833)
________ ________
Net cash provided by operating activities 40,407 42,530
________ ________
Investing Activities
Construction and plant expenditures (10,742) (14,813)
Deferred conservation and load management
expenditures (1,065) (1,158)
Investments in affiliates (11) (99)
Proceeds from sale of investment 3,750 -
Proceeds from sale of property 2,624 775
Non-utility investments (1,747) (1,079)
Other investments, net 74 (158)
________ ________
Net cash used for investing activities (7,117) (16,532)
________ ________
Financing Activities
Repurchase of common stock (1,072) (1,042)
Sale of treasury stock - 14
Short-term debt, net (5,764) (13,490)
Long-term debt, net - 1,236
Common and preferred dividends paid (9,103) (8,686)
________ ________
Net cash used for financing activities (15,939) (21,968)
________ ________
Net Increase in Cash and Cash Equivalents 17,351 4,030
Cash and Cash Equivalents at Beginning of Period 6,365 11,962
________ ________
Cash and Cash Equivalents at end of Period $23,716 $15,992
======== ========
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 5,017 $ 5,011
Income taxes (net of refunds) $10,398 $ 7,999
</TABLE>
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1997
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note 1 of
Notes to Consolidated Financial Statements included in its 1996 Annual Report
on Form 10-K filed with the Securities and Exchange Commission. For interim
reporting purposes, the Company follows these same basic accounting policies
but considers each interim period as an integral part of an annual period.
The financial information included herein is unaudited; however, such
information reflects all adjustments (consisting of normal recurring
accruals) which are, in the opinion of management, necessary for a fair
statement of results for the interim periods.
Note 2 - Environmental
The Company is engaged in various operations and activities which
subject it to inspection and supervision by both Federal and state regulatory
authorities including the United States Environmental Protection Agency
(EPA). It is Company policy to comply with all environmental laws. The
Company has implemented various procedures and internal controls to assess
and assure compliance. If non-compliance is discovered, corrective action is
taken. Based on these efforts and the oversight of those regulatory agencies
having jurisdiction, the Company believes it is in compliance, in all
material respects, with all pertinent environmental laws and regulations.
Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture of a
pole mounted transformer, or a broken hydraulic line. Whenever the Company
learns of such a release, the Company responds in a timely fashion and in a
manner that complies with all Federal and state requirements. Except as
discussed in the following paragraphs, the Company is not aware of any
instances where it has caused, permitted or suffered a release or spill on or
about its properties or otherwise which will likely result in any material
environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies.
Those companies engaged in various operations and activities prior to being
merged into the Company. At least two of these companies were involved in
the production of gas from coal to sell and distribute to retail customers at
three different locations. These activities were discontinued by the Company
in the late 1940's or early 1950's. The coal gas manufacturers, other
predecessor companies, and the Company itself may have engaged in waste
disposal activities which, while legal and consistent with commercially
accepted practices at the time, may not meet modern standards and thus
represent potential liability.
The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these historic
activities. The Company's policy is to accrue a liability for those sites
where costs for remediation, monitoring and other future activities are
probable and can be reasonably estimated. As part of that process, the
Company also researches the possibility of insurance coverage that could
defray any such remediation expenses. For related information see Legal
Proceedings below.
CLEVELAND AVENUE PROPERTY One such site is the Company's Cleveland Avenue
property located in the City of Rutland, Vermont, a site where one of its
predecessors operated a coal-gasification facility and later the Company
sited various operations functions. Due to the presence of coal tar deposits
and Polychlorinated Biphenyl (PCB) contamination and uncertainties as to
potential off-site migration of those contaminants, the Company conducted
studies in the late 1980's and early 1990's to determine the magnitude and
extent of the contamination. After completing its preliminary investigation,
the Company engaged a consultant to assist in evaluating clean-up
methodologies and provide cost estimates. Those studies indicated the cost
to remediate the site would be approximately $5 million. This was charged to
expense in the fourth quarter of 1992. Site investigation continued over the
next several years.
In January of 1995, the Company was formally contacted by the EPA asking
for written consent to conduct a site evaluation of the Cleveland Avenue
property. That evaluation has been completed. The Company does not believe
the EPA's evaluation changes its potential liability so long as the State
remains satisfied that reasonable progress continues to be made in
remediating the site and retains oversight of the process.
In 1995, as part of that process, the Company's consultant completed its
risk assessment report and submitted it to the State of Vermont for review.
The State generally agreed with that assessment but expressed a number of
concerns and directed the Company to collect some additional data. The
Company has addressed almost all of the concerns expressed by the State and
continues to work with the State in a joint effort to develop a mutually
acceptable solution.
The Company selected a consulting/engineering firm to collect the
additional data requested by the State and develop and implement a
remediation plan for the site. That firm has begun work at the site. It has
collected the additional data requested by the State and will use all the
data gathered to date to formulate a comprehensive remediation plan. The
additional data gathered to date has not caused the Company to alter its
original estimate of the likely cost of remediating the site.
PCB, INC. In August 1995, the Company received an Information Request from
the EPA pursuant to a Superfund investigation of two related sites, one in
Kansas and the other in Missouri (the Sites). During the mid-1980's, these
Sites received materials containing PCBs from hundreds of sources, including
the Company. According to the EPA, more than 1,200 parties have been
identified as Potential Responsible Parties (PRPs). The Company has complied
with the information request and will monitor EPA activities at the Sites.
In December 1996, the Company received an invitation to join a PRP
steering committee. The Company has not yet decided whether joining that
committee would be in its best interest. That committee has estimated the
Company's pro rata share of the waste sent to the Sites to be .42%. The
committee estimates that the Sites' remediation will cost between $5 million
and $40 million. Based on this information, the Company does not believe
that the Sites represent the potential for a material adverse effect on its
financial condition or results of operations.
The Company also faces potential liability arising from the alleged
disposal of hazardous materials at two former municipal landfills: the Parker
Landfill and the Trafton-Hoisington Landfill.
PARKER AND TRAFTON-HOISINGTON LANDFILLS There have been no further
developments involving the Company at these sites. The Company's
investigations at the time it was originally contacted indicated that it
contributed little if any hazardous substances to the sites. The Company has
not been contacted by the EPA, the state or any of the PRPs since 1994.
Therefore, the Company believes that the likelihood that these sites will
cause the Company to accrue significant liability has significantly
diminished. For historical information pertaining to these sites, refer to
the Company's 1995 Form 10-K.
At this time, the Company does not believe these landfill sites
represent the potential for a material adverse effect on its financial
condition or results of operations but it will continue to monitor activities
at the sites. The Company is not subject to any pending or threatened
litigation with respect to any other sites that have the potential for
causing the Company to incur material remediation expenses, nor has the EPA
or other Federal or state agency sought contribution from the Company for the
study or remediation of any such sites.
In 1996, the Company filed a Federal lawsuit against several insurance
companies. In its complaint, the Company alleges that general liability
policies issued by the insurers provide coverage for all expenses incurred or
to be incurred by the Company in conjunction with, among others, the
Cleveland Avenue Property and the Bennington Landfill sites. A settlement
has been reached with six of the thirteen defendants. Due to the
uncertainties associated with the total outcome of this lawsuit, no
receivables have been recorded.
Note 3 - Accounts Receivable
At September 30, 1997 and December 31, 1996, a total of $12 million of
accounts receivable and unbilled revenues were sold under an accounts
receivable facility.
Accounts receivable and unbilled revenues that have been sold were
transferred with limited recourse. A pool of assets, varying between 3% to
5% of the accounts receivable and unbilled revenues sold, are set aside for
this potential recourse liability. Accounts receivable and unbilled
revenues are reflected net of sales of $6.6 million and $5.4 million,
respectively, at September 30, 1997 and $4.8 million and $7.2 million,
respectively, at December 31, 1996.
Accounts receivable are also reflected net of an allowance for
uncollectible accounts of $1.1 million at September 30, 1997 and December 31,
1996.
Note 4 - Income Taxes
The Company received an accounting order (Order) from the Vermont Public
Service Board (PSB) dated September 30, 1997. The Order authorizes the
Company to defer and amortize over a 20-year period beginning January 1,
1998, approximately $2.0 million to reflect the revenue requirement level of
additional deferred income tax expense resulting from the recently enacted
Vermont Corporate income tax increase from 8.25% to 9.75%, subject to a
determination that these costs may be recovered in rates in the Company's
current rate proceedings.
Note 5 - Voluntary Retirement and Severance Programs
In the third quarter of 1997, the Company offered voluntary retirement
and severance programs to employees. The estimated benefit obligation for
the retirement program as of September 30, 1997 is approximately $4.8
million. This amount consists of pension benefits and post-retirement
medical benefits of $2.4 million and $2.4 million, respectively. The
estimated benefit obligation for the severance program, which includes
termination pay as well as other costs, is about $1.8 million. These
obligations will be recorded in the fourth quarter of 1997. The Company
received an Accounting Order from the PSB dated September 30, 1997,
authorizing the Company to defer all of these program costs and amortize them
over a five-year period beginning January 1, 1998 through December 31, 2002,
subject to a determination that these costs may be recovered in rates in the
Company's current rate proceeding.
Note 6 - Maine Yankee
On August 6, 1997, the Maine Yankee's Board of Directors decided to
prematurely retire the Maine Yankee Plant from commercial operation and
decommission the facility. The decision to shut down the Plant was based on
an economic analysis of the costs of operating it compared to the cost of
closing it and incurring replacement power costs over the remaining period of
the Plant's operating license. The Plant had been off-line since December
1996.
The Company relied on Maine Yankee for less than 5% of its required
system capacity. Presently, costs billed to the Company by Maine Yankee,
including a provision for ultimate decommissioning of the unit, are being
collected from the Company's customers through existing retail and wholesale
rate tariffs. Maine Yankee has preliminarily estimated as of September 1,
1997, the sum, in 1997 dollars, of future payments for the closing,
decommissioning and recovery of the remaining investment in Maine Yankee to
be approximately $929.9 million including a decommissioning obligation of
$398.8 million. The Company's total share is approximately $18.6 million of
which $3.9 million has been funded through September 30, 1997. This amount
is subject to ongoing review and revision and is reflected in the
accompanying balance sheet both as regulatory asset and deferred power
contract obligation (current and non-current).
Note 7 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Abbreviated financial information for Vermont Yankee is as
follows (dollars in thousands):
Three Months Ended Nine Months Ended
September 30 September 30
1997 1996 1997 1996
Operating revenues $41,967 $55,068 $126,771 $138,106
Operating income $ 3,526 $ 3,547 $ 10,816 $ 10,983
Net income $ 1,721 $ 1,735 $ 5,244 $ 5,035
Company's equity in net income $ 548 $ 540 $ 1,649 $ 1,575
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
September 30, 1997
Earnings Overview
Earnings available for common stock and earnings per share of common
stock for the three months ended September 30, 1997 were $1.6 million and
$.14, respectively, compared to losses available for common stock of $1.3
million or $.11 per share of common stock during the same period last year.
Due to seasonal pricing, the Company normally experiences losses in the
second and third quarter when sales are lower and rates are reduced.
For the nine months ended September 30, 1997, earnings available for
common stock were $13.0 million compared to $12.0 million in 1996. Earnings
per share of common stock for these respective periods were $1.13 and $1.04.
The improved earnings result primarily from an after tax gain of
approximately $1.8 million or $.16 per share of common stock from the sale by
Catamount Energy Corporation, a wholly owned non-utility subsidiary of the
Company, of its 8.1% partnership's interest in the NW Energy Williams Lake L.
P. Project. Other factors affecting results for 1997 are described in
Results of Operations below.
The Company filed for a 6.6% or $15.4 million general rate increase on
September 22, 1997 to become effective June 6, 1998, to offset the increasing
cost of providing service as more fully discussed below.
RESULTS OF OPERATIONS
The major elements of the Consolidated Statement of Income are discussed
below.
Operating Revenues and MWH Sales
A summary of MWH sales and operating revenues for the three and nine months
ended September 30, 1997 and 1996 (and the related percentage changes from
1996) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended September 30
Percentage Percentage
MWH Increase Revenues (000's) Increase
1997 1996 (Decrease) 1997 1996 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Residential 213,402 211,344 1.0 $24,744 $22,053 12.2
Commercial 234,354 229,016 2.3 23,913 21,897 9.2
Industrial 99,945 93,710 6.7 6,997 6,597 6.1
Other retail 1,816 1,842 (1.4) 496 478 3.8
_______ _______ ______ ______
Total retail sales 549,517 535,912 2.5 56,150 51,025 10.0
_______ _______ ______ ______
Resale sales:
Firm 258 370 (30.3) 11 21 47.6
Entitlement 91,983 116,752 (21.2) 4,458 6,826 (34.7)
Other 217,214 162,032 34.1 6,018 3,938 52.8
_______ _______ ______ ______
Total resale sales 309,455 279,154 10.9 10,487 10,785 (2.8)
_______ _______ ______ ______
Other revenues - - - 1,353 2,023 (33.1)
_______ _______ ______ ______
Total sales 858,972 815,066 5.4 $67,990 $63,833 6.5
======= ======= ======= =======
Nine Months Ended September 30
Percentage Percentage
MWH Increase Revenues (000's) Increase
1997 1996 (Decrease) 1997 1996 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Residential 705,862 711,815 (.8) $ 85,032 $ 78,253 8.7
Commercial 680,489 669,365 1.7 76,451 70,053 9.1
Industrial 314,501 291,415 7.9 24,805 22,735 9.1
Other retail 5,365 5,448 (1.5) 1,455 1,383 5.2
_________ _________ _______ _______
Total retail sales 1,706,217 1,678,043 1.7 187,743 172,424 8.9
_________ _________ _______ _______
Resale sales:
Firm 755 1,166 (35.2) 34 60 (43.3)
Entitlement 287,469 386,632 (25.6) 14,025 19,716 (28.9)
Other 599,792 547,491 9.6 15,795 13,148 20.1
_________ _________ _______ _______
Total resale sales 888,016 935,289 (5.1) 29,854 32,924 (9.3)
_________ _________ _______ _______
Other revenues - - - 4,329 4,121 5.0
_________ _________ _______ _______
Total sales 2,594,233 2,613,332 (.7) $221,926 $209,469 5.9
========= ========= ======== ========
</TABLE>
Retail MWH sales for the third quarter ended September 30, 1997
increased 2.5% reflecting the improving Vermont economy. However, retail
revenues increased $5.1 million or 10.0% over last year due to a $4.0 million
increase in price resulting from a 2% retail rate increase effective in
January 1997 and $1.1 million associated with the 2.5% increase in retail MWH
sales. The revenue increase was also impacted by a reduction in the
company's seasonal rate differential effective April 1, 1997. The seasonal
rate adjustment while increasing off-peak revenues will result in lower peak
revenues.
For the nine months ended September 30, 1997, retail MWH sales increased
1.7% while retail revenues increased $15.3 million or 8.9% compared to last
year. The revenue increase results from a $13.0 million increase in price
resulting from a 2-phase retail rate increase effective in June 1996 and
January 1997 and $2.3 million associated with the 1.7% increase in retail MWH
sales. MWH sales for the residential category decreased .8%, reflecting
moderate temperatures during the 1997 winter months. The commercial category
MWH sales increased 1.7% while the industrial sector MWH sales increased 7.9%
primarily due to increased megawatt-hour requirements for snow making by ski
area customers.
Primarily due to the scheduled termination of several sales agreements
in late 1996, entitlement MWH sales and revenues decreased for the three and
nine months ended September 30, 1997 compared to the same periods in 1996.
Resale sales and revenues increased for the third quarter due to
increased off-system sales, short-term system capacity sales and sales to
Nepool. The increase for the nine-month period resulted from increased
off-system sales and
sales to Nepool partially offset by a decrease in unit and
short-term system capacity sales.
The decrease in other revenues for the third quarter resulted primarily
from higher 1996 transmission revenues related to a transmission
interconnection service agreement recorded in the third quarter of 1996.
For the nine months ended September 30, 1997, other revenues increased
due to an increase in transmission revenues related to various transmission
interconnection agreements.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three and nine months ended September 30, 1997 and 1996 are as follows
(dollars in thousands):
<TABLE>
<CAPTION>
Three Months Ended September 30
1997 1996
Units Amount Units Amount
Purchased and produced:
Capacity (MW) 536 $23,703 537 $21,650
Energy (MWH) 862,357 16,411 821,899 15,413
_______ _______
Total purchased power costs 40,114 37,063
Production fuel (MWH) 42,799 518 47,354 485
_______ _______
Total purchased power and
production fuel costs 40,632 37,548
Entitlement and other resale sales (MWH) 309,197 10,476 278,784 10,764
_______ _______
Net purchased power and production
fuel costs $30,156 $26,784
======= =======
Nine Months Ended September 30
1997 1996
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 571 $68,161 519 $62,828
Energy (MWH) 2,567,333 53,254 2,568,318 47,946
_______ _______
Total purchased power costs 121,415 110,774
Production fuel (MWH) 174,855 1,209 224,980 1,259
_______ _______
Total purchased power and
production fuel costs 122,624 112,033
Entitlement and other resale sales (MWH) 887,261 29,820 934,123 32,864
_______ _______
Net purchased power and production
fuel costs $92,804 $79,169
======= =======
</TABLE>
As a result of higher capacity and energy costs and lower entitlement
and other resale revenues, net power costs increased $3.4 million, or 12.6%
for the third quarter and $13.6 million, or 17.2% for the nine months ended
September 30 1997 compared to the same periods last year.
These increases in net power costs resulted mostly from incremental
replacement power costs associated with Millstone Unit #3, Connecticut Yankee
and Maine Yankee nuclear power plants discussed below and an unscheduled
12-day outage at
the Vermont Yankee nuclear power plant.
Pursuant to a PSB Accounting Order, during the first half of 1997, the
Company reduced energy costs by approximately $5.8 million related to the
Hydro-Quebec agreement for which a payment of $5.8 million was received from
Hydro-Quebec on June 30, 1997.
Entitlement and other resale sales decreased for the 1997 periods for
reasons discussed above.
The Company owns and operates 20 hydroelectric generating units and two
gas turbines and one diesel peaking unit with a combined capability of
73.7 MW. The Company has equity ownership interests in four nuclear
generating companies: Vermont Yankee, Maine Yankee, Connecticut Yankee and
Yankee Atomic. In addition, the Company maintains joint-ownership interests
in Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit; Wyman #4, a 619 MW
oil-fired unit; and Millstone Unit #3, an 1154 MW nuclear unit.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in the
Millstone Unit #3 of the Millstone Nuclear Power Station and owns a 2% equity
interest in Connecticut Yankee. These two plants are operated by Northeast
Utilities (NU). The Company also owns 2%, 3.5% and 31.3% equity interest in
Maine Yankee, Yankee Atomic and Vermont Yankee, respectively.
Millstone Unit #3
Millstone Unit #3 (Unit #3) has been out of service since March 30,
1996, due to numerous technical and non-technical problems and is on the
Nuclear Regulatory Commission's (NRC) watch list. NU is currently
implementing comprehensive plans to be "physically ready to restart" by the
end of 1997 and the Company is advised that NU anticipates asking the NRC in
late January 1998 for permission to restart Unit #3. NU currently estimates
that its total 1997 incremental operations and maintenance costs for Unit #3
will be approximately $54.7 million. The Company's share is about $.9
million. In addition, the Company estimates that while Unit #3 is out of
service it will incur in 1997 incremental replacement power costs estimated
at $1.6 million. These incremental costs are recorded as incurred.
The remaining work and inspections of Unit #3 include the Independent
Corrective Action Verification Program which began on May 27, 1997, and two
major upcoming NRC inspections which must occur prior to restart. For
additional information regarding Unit #3, refer to the Company's 1996 Annual
Report on Form 10-K.
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various
activities to monitor and evaluate NU and Northeast Utilities Service Co.'s
efforts relating to Unit #3. On August 7, 1997, the Company and eight other
non-operating owners of Unit #3 filed a demand for arbitration with
Connecticut Light and Power Company and Western Massachussets Electric
Company and lawsuits against NU and its trustees. The arbitration and
lawsuits seek to recover costs associated with replacement power, operation
and maintenance costs and other costs resulting from the shutdown of Unit #3.
The non-operating owners claim that NU and two of its wholly owned
subsidiaries failed to comply with NRC's regulations, failed to operate the
facility in accordance with good operating practice and attempted to conceal
their activities from the non-operating owners and the NRC.
Maine Yankee
On August 6, 1997, the Maine Yankee's Board of Directors decided to
prematurely retire the Maine Yankee Plant from commercial operation and
decommission the facility. The decision to shut down the Plant was based on
an economic analysis of the costs of operating it compared to the cost of
closing it and incurring replacement power costs over the remaining period of
the Plant's operating license. The Plant has been off-line since December
1996. For additional information regarding the permanent shutdown of the
Plant, see Note 6 to the Consolidated Financial Statements in this Form 10-Q.
On September 2, 1997, the Maine Public Utilities Commission (MPUC)
released a report of a consultant it had retained to perform a management
audit of Maine Yankee for the period January 1, 1994 to June 30, 1997. The
report concluded that Maine Yankee's decision in December 1996 to proceed
with the steps necessary to restart its nuclear generating plant at
Wiscasset, Maine (Plant) was "imprudent"; and that Maine Yankee's May 27,
1997 decision to reduce restart expenses while exploring a possible sale of
the Plant was "inappropriate." The consultant's report concludes that a more
objective and comprehensive competitive analysis at that time "might have
indicated a benefit for restarting" the Plant. Those decisions resulted in
Maine Yankee incurring $95.9 million in "unreasonable" costs. The Company
has charged its 2% share of the Maine Yankee expenses to income.
Connecticut Yankee
On December 4, 1996, the Board of Directors of Connecticut Yankee
decided to prematurely retire the Plant and decommission the facility. The
decision was based on an economic analysis of the costs of operating it
compared to the costs of closing it and incurring replacement power costs
over the remaining period of the plant's operating license.
The Company relied on Connecticut Yankee for less than 3% of its
required system capacity. Presently, costs billed to the Company by
Connecticut Yankee, including a provision for ultimate decommissioning of the
unit, are being collected from the Company's customers via existing retail
and wholesale rate tariffs. Connecticut Yankee has estimated as of December
31, 1996, the sum of future payments for the closing, decommissioning and
recovery of the remaining investment in Connecticut Yankee in 1996 dollars to
be approximately $762.8 million subject to ongoing review and revision. The
Company's share of remaining costs with respect to Connecticut Yankee's
decision to discontinue operation is approximately $13.4 million at September
30, 1997 and is reflected in the accompanying balance sheet both as a
regulatory asset and deferred power contract obligation (current and
non-current).
On June 17, 1997 testimony was filed with the FERC by the Connecticut
Department of Public Utility Control and the Connecticut Attorney General's
Office in regard to Connecticut Yankee's current decommissioning obligation.
Regulators are asking the FERC to prevent the collection of approximately
$220 million for the decommissioning of the Connecticut Yankee Nuclear plant.
They claim that the current decommissioning costs are excessive and include
estimated costs for removal of highly contaminated soil that only became
necessary because of "careless and sloppy work habits" by the plant operator.
Regulators also argue that the plant closed because its management had been
imprudent which led to additional costs that should have been avoided. The
Company has denied these allegations. FERC's decision on this matter is
pending.
Yankee Atomic
In 1992, the Board of Directors of Yankee Atomic decided to permanently
discontinue operation of their plant, and to decommission the facility.
The Company relied on Yankee Atomic for less than 1.5% of its system
capacity. Presently, costs billed to the Company by Yankee Atomic, which
include a provision for ultimate decommissioning of the unit, are being
collected from the Company's customers via existing retail rate tariffs.
The Company's share of remaining costs with respect to Yankee Atomic's
decision to discontinue operation is approximately $4.7 million at
September 30, 1997. This amount is reflected in the accompanying balance
sheet both as a regulatory asset and deferred power contract obligation
(current and non-current).
The Company believes that based on the current regulatory process, its
proportionate share of Connecticut Yankee, Yankee Atomic and Maine Yankee
decommissioning costs will be recovered through the regulatory process and,
therefore, the ultimate resolution of the premature retirement of the three
plants has not and will not have a material adverse effect on the Company's
financial position, results of operations and cash flows.
Although the estimated costs of decommissioning and premature
retirements of nuclear power plants are subject to change due to changing
technologies and regulations, the Company expects that its liability,
including any future change in such costs related to these nuclear power
plants will be recovered in its current and future rates.
Vermont Yankee
The Design Basis Documentation project (Project) initiated by Vermont
Yankee during 1996 is expected to be completed by the end of 1999. The
Company's 35% share of the total cost for this Project is expected to be
about $6.3 million. Such costs will be deferred by Vermont Yankee and
amortized over the remaining license life of the plant.
Production and Transmission
Due to increased production costs, primarily related to Unit #3 and
higher transmission costs, production and transmission expenses were $.5
million and $2.1 million higher for the three and nine months ended September
30, 1997 compared to the comparable periods last year.
Other Operation
Other operating expenses increased $2.8 million for the nine months
ended September 30, 1997 principally due to amortization of Conservation and
Load Management (C&LM) costs which are recovered in rates.
Other Taxes, Principally Property Taxes
Due to a property tax refund, other taxes decreased for the third
quarter of 1997.
Income Taxes
Federal and state income taxes fluctuate with the level of pre-tax
earnings. The increase in total income tax expense for the three and nine
months ended September 30, 1997 results primarily from an increase in pre-tax
earnings for the periods and an increase in the Vermont Corporate income tax
rate from 8.25% to 9.75% effective January 1, 1997.
The Company believes that these additional Vermont Corporate income
taxes will be recovered through the regulatory process. The timing and
recoverability of these costs will be determined into the company's current
rate proceedings. See Note 4 to the consolidated financial statements.
Other Income, Net
The increase in other income, net for the three months ended September
30, 1997 results principally from a gain on sale of non-utility investment
discussed below and higher non-utility subsidiaries' earnings. The increase
for the nine months ended September 30, 1997 results primarily from gains on
sale of property and investment partially offset by $1.3 million of insurance
proceeds recorded in March 1996.
Cash Dividends Declared
Common
The year to date increase in common dividends declared resulted from a
10% increase in the quarterly common dividend paid (from $.20 to $.22 per
share) effective for the quarterly common dividend paid on August 15, 1996.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity is primarily affected by the level of cash
generated from operations and the funding requirements of its ongoing
construction and C&LM programs. Net cash provided by operating activities
was $40.4 million and $42.5 million for the nine months ended September 30,
1997 and 1996, respectively.
The Company ended the first nine months of 1997 with cash and cash
equivalents of $23.7 million, an increase of $17.4 million from the beginning
of the year. The increase in cash for the first nine months of 1997 was the
result of $40.4 million provided by operating activities, $7.1 million used
for investing activities and $15.9 million used for financing activities.
Operating Activities - Net income, depreciation and deferred income
taxes and investment tax credits provided $26.7 million. Fluctuations in
working capital provided $14.1 million; $4.6 million was provided by
deferral/amortization of nuclear refueling replacement energy and maintenance
costs, amortization of C&LM costs and other, net; and reduced by $2.1 million
and $2.9 million gain from sale of property and investment, respectively.
Investing Activities - Construction and plant expenditures consumed
$10.7 million, $1.1 million was used for C&LM programs and $1.7 million was
used for non-utility investments. Proceeds of $2.6 million and $3.8 million
were generated from the sale of property and investment, respectively.
Financing Activities - Dividends paid on common stock were $7.6 million,
while preferred stock dividends were $1.5 million. Short-term obligations
repaid totaled $5.7 million and $1.1 million was used to reacquire common
stock.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from cost of service and return on equity based rates
to one with more market based rates. Many states, including Vermont and New
Hampshire, where the Company does business, are exploring new mechanisms to
bring greater competition, customer choice and market influence to the
industry while retaining the public benefits associated with the current
regulatory system.
Vermont
On December 31, 1996, the PSB issued a Report and Order (the Report)
outlining a restructuring plan (Plan), subject to legislative approval, for
the Vermont electric utility industry. The Plan, which is a recommendation
to the Vermont Legislature, consists of the following nine components:
* Provide customer choice. Enable all customers to demand and purchase the
products and service they need and want. It provides for additional market
opportunities for low-usage customers.
* Require Vermont's largest investor-owned utilities to divide their
generation and distribution functions into separate corporate subsidiaries.
The PSB does not propose full corporate divestiture at this time but requires
this "functional separation" of the companies into wholly owned subsidiaries.
* Provide for equitable treatment of stranded costs. It promotes aggressive
actions to reduce utilities' current and future costs and provides utilities
with the opportunity to recover their legitimate, remaining stranded costs.
* Address the unique attributes of municipal, cooperative, and small
investor-owned utilities. The Plan requires that these utilities provide
open access to competitive providers, but does not require functional
separation of activities.
* Assure consumer protection. Preserves the wide range of consumer
protections currently provided by the franchise system. It proposes new
initiatives to assist low-income customers.
* Deliver cost-effective energy efficiency programs to all customers. It
proposes several complimentary approaches to delivering energy efficiency to
Vermont's electric consumers.
* Promote the continued use and development of renewable energy resources.
Requires all retail companies selling electricity in Vermont to secure a
minimum percentage of the sales from renewable resources.
* Promote national and regional policies that assure environmental quality.
The Plan supports proposals in neighboring states to impose environmental
comparability on older generation sources and the creation of an inter-
regional emissions trading
program.
* Establish a regional independent system operator (ISO) and power exchange.
The Plan proposes the establishment of a regional power exchange to provide
a short-term spot market for energy services and other services necessary to
support system reliability by the ISO.
If adopted by the Vermont Legislature, the Plan would allow for the
recovery of stranded costs through a non-bypassable, non-discriminatory wires
charge on electric consumption, after mitigation of costs. It would also
authorize the use of incentive-and performance-based regulation for
distribution companies presently subject to price regulation.
The Report promotes aggressive actions to reduce utilities' current and
future power costs including "innovative financing renegotiation of above-
market contractual
commitments, and asset sales." If adopted by the Vermont
Legislature, the PSB would take into account the circumstances under which
stranded costs were incurred and the companies' efforts to mitigate them.
The multiple step process outlined by the PSB would involve 1) an estimation
of stranded costs including an estimation of future power costs and a
determination of the extent to which stranded costs can be mitigated, 2) an
adjustment of stranded costs and 3) a stranded cost reconciliation
proceeding.
The largest component of the Company's stranded costs are future costs
under long-term purchased power contracts. If the PSB's recommendation is
approved by the Vermont Legislature, the Company will be able to recover its
unmitigatable stranded costs through a non-bypassable, non-discriminatory
wires charge on electric consumption. The Report suggests that if utilities
satisfy a multi-factor analysis, Vermont should "create the opportunity for
full recovery of stranded costs provided they are legitimate, verifiable,
otherwise recoverable, prudently incurred and non-mitigatable." Such
recovery is, however, "explicitly tied to successful mitigation." At this
time, the Company cannot give assurance that it will be successful in
realizing mitigation of these costs to the extent that will satisfy the broad
standards identified by the PSB or that it will be able to achieve full or
substantial recovery of these costs, should Vermont's utility industry be
restructured.
The PSB Report "strongly encourage[s] the participants in this docket to
continue to work together to forge comprehensive solutions on a consensus
basis wherever possible." The Company continues to work to achieve a
restructured industry in Vermont which meets the consensus principles for
industry restructuring endorsed by the PSB and protects the interests of the
Company and the stakeholders who financed the system under the regulatory
bargain.
Due to uncertainty surrounding legislative schedules, the PSB, on April
18, 1997, issued an Order which suspended, pending further legislative action
or future PSB Orders, certain filing deadlines for reports and plans to be
completed in connection with the Plan.
In an effort to achieve a negotiated resolution to the issues
surrounding the restructuring of the Vermont electric utility industry, the
Company, Green Mountain Power Corporation, the DPS and representatives of the
Governor of Vermont developed a Memorandum of Understanding (MOU) in February
1997 establishing a plan for implementing restructuring in Vermont. Although
concepts of the MOU are still under consideration, no action has been taken
on the MOU.
On April 3, 1997, Senate bill 62 (S-62), an act relating to electric
industry restructuring was passed by the Vermont Senate. Pursuant to S-62,
electric utility customers would be entitled to purchase electricity in a
competitive market place and could choose their electricity supplier.
Incumbent investor-owned electric utilities, including the Company, would be
required to separate their regulated distribution and transmission operations
into affiliate entities that are functionally separate from competitive
generation and retail operations. S-62 provides for the recovery of a
portion of investor-owned utility's "above market costs" which may be
stranded on account of the introduction of competition within their service
area. When considering the recovery of such amounts, S-62 would require that
the PSB weigh the goal of sharing net prudently incurred, discretionary
above-market costs "evenly" between utilities and customers against other
goals including preserving the continuing financial integrity of the existing
utility and respecting the just interests of investors. S-62 also creates an
incentive for the Company to take steps to close the Vermont Yankee Nuclear
Power Station by conditioning the recovery of certain plant related stranded
costs on the decision of its owners to cease operations in 1998, unless the
PSB agrees to allow the plant to run for up to two more refuelings to avoid
power shortages or for other public interest reasons. To become law, S-62
would have to be passed by the Vermont House of Representatives in its next
session beginning in January 1998 and signed by the Governor of the State
of Vermont.
At this time, the Vermont House of Representatives is not considering
S-62 but instead has
convened a special committee of the Vermont House of
Representatives to study matters relating to the reform of Vermont's electric
utility system with the goal of issuing recommendations prior to the 1998
legislation sessions. The House Committee has for now tabled the idea of
competition in the electric utility industry. Therefore, at this time, it
cannot be determined whether future restructuring legislation will be enacted
in 1998 that would conform to the concepts developed by the Report, the MOU
or S-62.
New Hampshire
In New Hampshire, the New Hampshire Public Utilities Commission (NHPUC),
directed by the New Hampshire legislature, has established a Pilot Program
(Pilot) to determine the implications of retail competition in the electric
utility industry. The Pilot is for a two-year period beginning in May 1996
and is open to all electric utilities and to 3% of all classes of customers
in New Hampshire. The Company competed as a competitive supplier to acquire
additional load currently served by other New Hampshire utilities and to
retain load currently served by Connecticut Valley Electric Company Inc.
(Connecticut Valley), the Company's wholly owned New Hampshire subsidiary.
The Company acquired new customers with combined annual electric use totaling
approximately 20,000 megawatt hours.
On February 28, 1997 the NHPUC released its Final Plan to restructure
the electric utility industry in New Hampshire pursuant to legislation
enacted in New Hampshire during 1996. Concurrently, supplemental utility-
specific orders to
establish interim stranded cost charges were issued. The
legislation requires each utility to file comprehensive plans no later than
June 30, 1997, which comply with the Final Plan and the supplemental orders.
By a later Order, dated May 22, 1997, the NHPUC modified the scope of the
June 30, 1997 filing and only required the filing of open access tariffs for
informational purposes. The 1996 legislation also states that utilities
shall not be required to implement their compliance filings unless compliance
filings representing at least 70% of New Hampshire retail kilowatt hour
sales, on an annual basis, have been or are being implemented. The 1997
legislature amended this requirement to the extent that a utility having less
than 50% of statewide retail electric distribution sales (measured in
kilowatt hours per year) may seek a ruling by the NHPUC that it is in the
public interest that implementation of such utility's compliance filing be
deferred until compliance filings representing 70% of retail electric sales
have been or are being implemented.
In its Final Plan, the NHPUC announced a departure from cost-based
ratemaking and instead adopted a market-priced approach to stranded cost
recovery. The Company believes that if the NHPUC adopted the Final Plan in
its present form, Connecticut Valley, as well as, the Company's wholesale
power business with Connecticut Valley, would no longer be able to apply
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting For
The Effects of Certain Types of Regulation," and the Company may have to
remove from its balance sheet substantially all of its regulatory assets
associated with New Hampshire business estimated at approximately
$3.0 million as of December 31, 1997, on a pre-tax basis. In addition, the
supplemental order specific to Connecticut Valley denies stranded cost
recovery related to its Federal Energy Regulatory Commission (FERC) approved
power contract with the Company and further ordered Connecticut Valley to
terminate the contract. The net revenue loss associated with costs
potentially disallowed under the power contract are estimated by the Company
to total over $80.0 million (pre-tax) over a twenty-eight year period on a
nominal dollar basis. The Company intends to vigorously pursue the recovery
of these costs and will continue to assess the likelihood of recovery. If it
is determined that it is probable that FERC will not permit recovery of these
costs, the Company would have to assess the likelihood and magnitude of
losses incurred under both SFAS No. 5, "Accounting for Contingencies" and
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for
Long Lived Assets to be Disposed Of."
On April 7, 1997, the NHPUC issued an Order addressing certain threshold
procedural matters raised in the motion for rehearing and/or clarification
filed by various parties, including Connecticut Valley, relative to the
Final Plan and interim stranded cost orders. The Order suspends and stays
those aspects of the Final Plan that are the subject of rehearing or
clarification requests in order to thoroughly review and evaluate the issues
raised in such motions and also suspends and stays the interim stranded cost
orders for the various parties, including Connecticut Valley. The suspension
and stay of these orders will remain in effect until two weeks following the
issuance of any order concerning outstanding requests for rehearing and
clarification.
On May 9, 1997, Public Service Company of New Hampshire (PSNH) filed a
Motion For Suspension of the electric utility restructuring proceeding to
allow mediation with the State of New Hampshire to proceed. On May 22, 1997,
NHPUC issued an Order granting PSNH's Motion For Suspension until July 2,
1997. On July 2, 1997, PSNH filed another Motion For Continued Suspension of
the proceedings. On July 21, 1997, NHPUC issued an Order extending the
suspension of the rehearing schedule until August 5, 1997. On August 1,
1997, PSNH filed another Motion For Continued Suspension of the proceedings.
On August 12, 1997, the NHPUC issued Order No. 22,681 denying PSNH's Motion
For Suspension and establishing a schedule of rehearing of PSNH specific
issues regarding rate-making and the Rate Agreement. The NHPUC adopted a
procedural schedule to rehear these PSNH specific issues so as not to
interfere with the ongoing mediation which continued until September 2,
1997.
The Final Plan and supplemental order also contain rulings on numerous
issues that may have a substantial effect on the operations of the
Company. Included among these rulings is the requirement that Connecticut
Valley divest within two years all of its wholesale power purchase contracts;
a prohibition on the remaining distribution company and its affiliates from
engaging in retail marketing or load aggregation services; and a mandate for
the filing of tariffs with the FERC for the provision of unbundled retail
transmission service. Connecticut Valley's utility specific supplemental
order did approve the recovery through interim stranded cost charges of the
projected above market power costs associated with purchases from Qualifying
Facilities that were previously approved by the NHPUC.
PSNH and various PSNH affiliates, including Northeast Utilities, have
filed an action for injunctive and declaratory relief in the New Hampshire
Federal District Court (Court) with respect to the NHPUC's Final Plan and the
supplemental order pertaining to PSNH. The Court has rendered, and later
amended, a temporary restraining order in favor of PSNH. The Court has also
rendered an order declining to abstain, except, at present, with respect to
certain limited issues regarding ratemaking and regarding a Rate Agreement
between PSNH and the State of New Hampshire. The Company and Connecticut
Valley have filed claims for intervention (seeking declaratory relief with
respect to the NHPUC's Final Plan and pertinent supplemental order) and have
moved to intervene in PSNH's federal action.
Intervention status was granted to the Company and Connecticut Valley by
the Federal Court. On September 2, 1997, the mediator appointed by the Court
to mediate PSNH's claims reported that the mediation effort had failed. PSNH
was the only New Hampshire utility involved in that attempt to resolve the
dispute.
On September 15, 1997 the US District Court of Rhode Island reported
that it no longer had jurisdiction over the matter because the Circuit Court
of Appeals had docketed several appeals to District Court's earlier orders.
The Circuit Court of Appeals has scheduled a hearing on December 5, 1997.
Those appeals pertain to motions for intervention status previously denied to
non-utility parties the standards for granting injunctive relief and the
jurisdiction of the court over the matters.
On September 29, 1997, a Legal and Policy Memorandum was filed by the
New Hampshire Governor with the NHPUC that had as its stated purpose "...to
moot the federal case and bring the restructuring effort back to New
Hampshire, where it belongs." Among other things, the Governor proposed the
NHPUC abandon its proposed benchmark approach to ratemaking and return to a
cost-based, ratemaking method. The Governor and other parties have proposed
numerous cost-based methodologies. The NHPUC has scheduled hearings from
November 20 through November 26, 1997 for the PSNH rehearing issues. Other
rehearing issues will be addressed subsequently.
As stated above, the NHPUC in its supplemental order specific to
Connecticut Valley denies stranded cost recovery related to its FERC approved
power contract with the Company and further ordered Connecticut Valley to
terminate the contract. However, FERC, in its Order No. 888, established
that it would determine stranded cost recovery and make such recoveries a
component of charges for transmission service in cases of wholesale
termination. Accordingly, on June 25, 1997, the Company petitioned the FERC
to assert its jurisdiction over the recovery of stranded costs resulting from
the NHPUC's Final Plan and allow recovery rejected by the New Hampshire
Regulators. Various interests have sought party status before the FERC in
this matter. A notice scheduling a pre-hearing conference by the FERC has
not yet been scheduled.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. The Company cannot predict whether the ultimate outcome of this
matter would have a material adverse effect on the Company's results of
operations, cash flows, and ability to obtain capital at competitive rates.
Connecticut Valley constitutes approximately 7% of the Company's total
retail MWH sales.
Competition-Risk Factors
If retail competition is implemented in Vermont or New Hampshire, the
Company is unable to predict the impact of this competition on its revenues,
the Company's ability to retain existing customers and attract new customers
or the margins that will be realized on retail sales of electricity.
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.
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation,"
requires regulated entities, in appropriate circumstances, to establish
regulatory assets and liabilities, and thereby defer the income statement
impact of certain costs and revenues that are expected to be realized in
future rates.
As described in Note 1 of Notes to Consolidated Financial Statements,
included in the Company's 1996 Annual Report on Form 10-K, the Company
complies with the provisions of SFAS No. 71. In the event the Company
determines that it no longer meets the criteria for following SFAS No. 71,
the accounting impact would be an extraordinary, non-cash charge to
operations of an amount that could be material. Criteria that give rise to
the discontinuance of SFAS No. 71 include (1) increasing competition that
restricts the Company's ability to establish prices to recover specific
costs and (2) a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation.
The Securities and Exchange Commission has questioned the ability of
certain utility companies continuing the application of SFAS No. 71 where
legislation provided for the transition to retail competition. The issue of
when and how to discontinue the application of SFAS No. 71 by utilities
during transition to competition has been referred to the Financial
Accounting Standards Board's Emerging Issues Task Force (EITF).
The EITF has reached a tentative consensus that regulatory assets should
be assigned to separable portions of the company's business based on the
source of the cash flows that will recover those regulatory assets.
Therefore, if the source of the cash flows is from a separable portion of the
company's business that meets the criteria to apply SFAS No. 71, those
regulatory assets should not be written off under SFAS No. 101, "Accounting
for the Discontinuation of Application of SFAS No. 71," but should be
assessed under paragraph 9 of SFAS No. 71 for realizability. The Company's
Management believes that SFAS No. 71 continues to apply to its regulated
operations.
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and
for Long-Lived Assets to Be Disposed Of," which was implemented by the
Company on January 1, 1996, requires that any assets, including regulatory
assets, that are no longer probable of recovery through future revenues, be
revalued based upon future cash flows. SFAS No. 121 requires that a rate-
regulated enterprise
recognize an impairment loss for the amount of costs
excluded from recovery. As of September 30, 1997, based upon the regulatory
environment within which the Company currently operates, SFAS No. 121 did not
have an impact on the Company's financial position or results of operations.
Competitive influences or regulatory developments may impact this status in
the future.
The Company believes that the provisions of both the Report and MOU, if
ultimately approved by the PSB and Vermont General Assembly, would meet the
criteria for continuing application of SFAS Nos. 71 and 121. Conversely, the
Company believes that the unmodified provisions of S-62 and the NHPUC Final
Plan would not meet the criteria for continuing application of SFAS No. 71
and 121. Because the Company is unable to predict what form possible future
legislation will take, it cannot predict if or to what extent SFAS Nos. 71
and 121 will continue to be applicable in the future. In addition, if the
Company is unable to mitigate or otherwise recover stranded costs that could
arise under S-62 or the NHPUC Final Plan, the Company would have to assess
the likelihood and magnitude of losses incurred under SFAS No. 5.
As such, the Company cannot predict whether the Report, the MOU
and restructuring legislation enacted in Vermont or the issuance of a final
restructuring Plan in New Hampshire would have a material adverse effect on
the Company's operations, financial condition or credit ratings. However,
the Company's failure to recover a significant portion of its purchased
power costs, would likely have a material adverse effect on the Company's
results of operations, cash flows and ability to obtain capital at
competitive rates. It is possible that stranded cost exposure, including the
potential impact of write-offs associated with SFAS Nos. 5, 71, and 121,
before mitigation could exceed the Company's current total common stock
equity.
FINANCING AND CAPITALIZATION
Utility
The level of short-term borrowings fluctuates based on seasonal
corporate needs, the timing of long-term financings and market
conditions. Short-term borrowings are supported by committed and
uncommitted lines of credit with several banks totaling $36.0 million.
On November 7, 1997, the Company implemented a 364 day Revolving Credit
and Competitive Advance Facility (Credit Facility) providing for up to $50
million of Credit Facility which upon PSB regulatory approval will become a
Three Year Revolving Credit Facility. This Credit Facility will be used for
general corporate purposes and to replace $36 million of the committed and
uncommitted lines of credit.
The Company's capital structure ratios as of September 30, 1997
(including amounts of long-term debt and preferred stock due within one
year), consisted of 53.5% common equity, 7.9% preferred stock and 38.6%
long-term debt including capital lease obligations.
At September 30, 1997, the Company's mandatory sinking fund requirements
for long-term debt and preferred stock due within the next twelve-month
period is approximately $3.0 million and $1.0 million, respectively.
Current credit ratings for the Company's outstanding mortgage debt,
Standard & Poor's corporate credit rating and preferred stock are as follows:
Duff & Standard
Phelps & Poor's
First Mortgage Bonds BBB A-
Corporate Credit Rating BBB
Preferred Stock BBB- BBB-
Non-Utility
Catamount Energy Corporation (Catamount), a wholly owned subsidiary of
the Company, implemented a credit facility in July 1996 which provides for up
to $8 million of letters of credit and working capital loans. Currently, a
$1.2 million letter of credit is outstanding to support certain of
Catamount's obligations in connection with a debt reserve requirement in the
Appomattox Cogeneration project.
SmartEnergy, also a wholly owned subsidiary of the Company, currently
maintains $.5 million revolving line of credit with a bank to provide working
capital and financing assistance for investment purposes. There are no
outstanding borrowings under this facility.
Financial obligations of the Company's non-utility wholly owned
subsidiaries are non-recourse to the Company.
C&LM Programs
The primary purpose of these programs is to offset the need for long-
term power supply and
delivery resources that are more expensive to purchase
or develop than customer-efficiency programs. Total C&LM expenditures in
1996 were $3.5 million, and based on an agreement between the Company and the
DPS and approved by the PSB, total 1997 C&LM expenditures are not to exceed
$4.5 million.
Diversification
Catamount was formed for the purpose of investing in non-regulated power
plant projects. Currently, Catamount, through its wholly owned subsidiaries,
has interests in five operating independent power projects located in Glenns
Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont and Hopewell,
Virginia. In addition, Catamount has interests in projects under construction
in Thetford, England, and under development in Summersville, West Virginia.
Catamount's net income was $2.6 million and $3.6 million for the three and
nine months ended September 30, 1997. For the three and nine months ended
September 30, 1996, Catamount incurred a net loss of $114,000 and net income
of $144,000, respectively. Included in results of operation for the nine
months ended September 30, 1997 and 1996 were $.4 million and $1.8 million,
respectively, of pre-tax costs related to the Gauley River project in
Summersville, West Virginia. These expenses would be reimbursed and taken
into income if this pending project reaches financial closing.
On August 5, 1997, Catamount sold its 8.1% partnership's interest in the
NW Energy Williams Lake L.P. project. The sale resulted in a $1.8 million
after-tax gain or approximately $.16 per share of common stock during the
third quarter of 1997.
For the three and nine months ended September 30, 1997, SmartEnergy
incurred a net loss of $202,000 and $164,000, respectively compared to
earnings of $84,000 and $271,000 for the three and nine months ended
September 30, 1996.
RATES AND REGULATION
The Company recognizes adequate and timely rate relief is necessary if
the Company is to maintain its financial strength, particularly since Vermont
regulatory rules do not allow for changes in purchased power and fuel costs
to be passed on to consumers through automatic rate adjustment clauses. The
Company's practice of reviewing costs periodically will continue and rate
increases will be requested when warranted. The Company filed for a 6.6% or
$15.4 million general rate increase on September 22, 1997 to become effective
June 6, 1998 to offset increasing cost of providing service. Approximately
$14.3 million or 92.9% of the rate increase request is to recover contractual
increases in the cost of power the Company purchases from Hydro-Quebec.
At the same time, the Company also filed a request to eliminate the
winter-summer rate differential and price electricity the same year-round.
The change would be revenue-neutral within classes of customers and overall.
Over time, customers would see a leveling off of rates so they would pay the
same per kilowatt-hour during the winter and summer months.
During proceedings related to the April 30, 1996 Order described in the
Company's 1996 Annual Report on Form 10-K, certain intervening parties
petitioned the PSB for a management audit of the Company. In an Order dated
April 10, 1996, the PSB severed the management audit issue from the rate
proceeding. The PSB held a status conference on May 6, 1996 to address
whether there should be such an audit as well as other related issues.
Hearings for the management audit issue were held on July 16, 1996 and August
29, 1996.
On April 17, 1997, the PSB issued an Order which rejects the idea of a
traditional management audit of the Company and instead ordered an
independent forward-looking analysis of three of the Company's management
policies and practices focusing on three areas: 1) Transmission of
information to the Board of Directors by management. 2) Cost benefit
analyses for major corporate decisions. 3) Implementation of the Company's
ethics and conflict of interest policy.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1996, the FASB issued SFAS No. 125, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities,"
effective for transfers and servicing of financial assets and extinguishments
of liabilities occuring after December 31, 1996. Earlier or retroactive
application is not permitted. Subsequently, in December 1996, the FASB
issued SFAS No. 127, "Deferral of the Effective Date of Certain Provisions of
SFAS No. 125." This statement defers for one year the effective date of
certain provisions of SFAS No. 125. The Company anticipates that the
adoption of SFAS No. 125 will not have a material impact on the Company's
financial position or results of operations.
In February 1997, the Financial Accounting Standards Board issued SFAS
No. 128, "Earnings per Share," effective for both interim and annual
periods ending after December 15, 1997. Earlier application is not
permitted. SFAS No. 128 establishes standards for computing and
presenting earnings per share(EPS) and applies to entities with publicly
held common stock or potential common stock. The Company anticipates that
the adoption of SFAS No. 128 will not have an impact on the Company's
computation and presentation of basic EPS. The Company does not have any
potential common stock that would result in the dilution of EPS.
YEAR-2000 COMPLIANCY
The Company is in process of assessing the scope, magnitude and costs of
making its computer systems and applications year-2000 compliant. The
assessment is expected to be completed by the end of the fourth quarter of
1997. Although final costs cannot be determined at this time, the Company
does not believe that these costs represent the potential for a material
adverse effect on its financial position or results of operations.
FORWARD LOOKING STATEMENTS
Statements in this report relating to future financial conditions are
forward looking statements. Such forward-looking statements are not
guarantees of future performance and involve known and unknown risks,
uncertainties and other factors, which may cause the actual results,
performance or achievements to differ materially from the future forward-
looking statements.
Such factors include general economic and business
conditions, changes in industry regulation, weather and other factors which
are described in further detail in the Company's filings with the Securities
and Exchange Commission.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On July 29, 1996, the Company filed a Declaratory Judgment action
pertaining to remediation in the United States District Court for the
District of Vermont. The Complaint names as defendants a number of insurance
companies that issued insurance policies to the Company dating from the mid
1940s to the late 1980s. The Company asserts that insurance policies issued
by defendants provide coverage for all defense and remediation costs
associated with the Cleveland Avenue property, the Bennington Landfill site
and the North Clarendon site. With the exception of the North Clarendon site
where no further remediation is anticipated, see Note 2 to the Consolidated
Financial Statements for related disclosures.
Items 2, 3, and 4.
None.
Item 5. Other Information
(a) Frederic H. Bertrand was elected Chairman of the Board of Directors
on September 2, 1997 to replace F. Ray Keyser Jr., who retired as Chairman at
the end of September 1997 and plans to retire as Director on December 31,
1997
(b) On June 27, 1997, NU's management temporarily suspended all
nucleartraining programs at Millstone to address programmatic deficiencies
identified by NU's subsidiary, Northeast Nuclear Energy Company and the NRC
inspectors during reviews of NU system's licensed operator training programs
at NU system's four Connecticut nuclear units. Currently, Training Restart
Plan has been established and various training programs have been restarted
including the licensed operator training programs for Millstone. NU's
management continues to believe that the suspension will not affect the
current schedule to restart Unit #3.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
EXHIBIT INDEX
27. Financial Data Schedule.
(b) There were no reports on Form 8-K for the quarter ended
September 30, 1997.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
(Registrant)
By Francis J. Boyle
___________________________________________
Francis J. Boyle, Senior Vice President,
Finance and Administration and
Principal Financial Officer
By James M. Pennington
___________________________________________
James M. Pennington, Vice President,
Controller and Principal Accounting
Officer
Dated November 13, 1997
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This Financial Data Schedule contains summary financial information extracted
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