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 June 30, 1996
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 July 31, 1996 there
were outstanding 11,519,748 shares of Common Stock, $6 Par Value.
<PAGE>
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 six months ended
June 30, 1996 and 1995 3
Consolidated Balance Sheet as of June 30, 1996 and
December 31, 1995 4
Consolidated Statement of Cash Flows for the six
months ended June 30, 1996 and 1995 5
Notes to Consolidated Financial Statements 6-8
Summarized income statement information for Vermont
Yankee Nuclear Power Corporation 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 10-18
PART II. OTHER INFORMATION 19-20
SIGNATURES 21
<PAGE>
<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 Six Months Ended
June 30 June 30
1996 1995 1996 1995
<S> <C> <C> <C> <C>
Operating Revenues $61,390 $62,846 $145,636 $149,709
------- ------- -------- --------
Operating Expenses
Operation
Purchased power 36,439 37,691 73,711 76,866
Production and transmission 4,842 5,205 9,692 10,358
Other operation 8,445 10,352 17,620 20,342
Maintenance 3,582 3,146 6,417 5,594
Depreciation 4,444 4,324 8,880 8,511
Other taxes, principally property taxes 2,649 2,429 5,466 5,122
Taxes on income (407) (615) 8,218 7,674
------- ------- -------- --------
Total operating expenses 59,994 62,532 130,004 134,467
------- ------- -------- --------
Operating Income (Loss) 1,396 314 15,632 15,242
------- ------- -------- --------
Other Income and Deductions
Equity in earnings of affiliates 852 783 1,653 1,620
Allowance for equity funds during construction 27 47 48 153
Other income (expenses), net (694) 142 1,687 832
Benefit (provision) for income taxes 397 201 168 (27)
------- ------- -------- --------
Total other income and deductions, net 582 1,173 3,556 2,578
------- ------- -------- --------
Total Operating and Other Income 1,978 1,487 19,188 17,820
------- ------- -------- --------
Interest Expense
Interest on long-term debt 2,365 2,373 4,718 4,790
Other interest 125 210 275 406
Allowance for borrowed funds during construction (65) (33) (116) (109)
------- ------- -------- --------
Total interest expense, net 2,425 2,550 4,877 5,087
------- ------- -------- --------
Net Income (Loss) (447) (1,063) 14,311 12,733
Retained Earnings at Beginning of Period 78,355 68,867 66,422 55,575
------- ------- -------- --------
77,908 67,804 80,733 68,308
Cash Dividends Declared
Preferred stock 507 507 1,014 1,014
Common stock 4,848 2,335 7,166 2,332
------- ------- -------- --------
Total dividends declared 5,355 2,842 8,180 3,346
------- ------- -------- --------
Retained Earnings at End of Period $72,553 $64,962 $72,553 $ 64,962
======= ======= ======= ========
Earnings (Losses) Available for Common Stock $(954) $(1,570) $13,297 $ 11,719
Average Shares of Common Stock Outstanding 11,545,763 11,676,201 11,568,256 11,694,025
Earnings (Losses) Per Share of Common Stock $(.08) $(.13) $1.15 $1.00
Dividends Paid Per Share of Common Stock $ .20 $ .20 $ .40 $ .40
</TABLE>
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
(Unaudited)
June 30 December 31
1996 1995
Assets
Utility Plant, at original cost $448,598 $453,784
Less accumulated depreciation 145,316 136,057
-------- --------
303,282 317,727
Construction work in progress 20,366 8,108
Nuclear fuel, net 943 1,167
-------- --------
Net utility plant 324,591 327,002
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 26,686 26,464
Non-utility investments 24,872 22,622
Non-utility property, less accumulated depreciation 4,590 2,896
-------- --------
Total investments and other assets 56,148 51,982
-------- --------
Current Assets
Cash and cash equivalents 24,066 11,962
Special deposits 1,072 3,868
Accounts receivable 14,050 21,374
Unbilled revenues 4,735 11,177
Materials and supplies, at average cost 3,825 4,023
Prepayments 1,688 3,607
Other current assets 3,961 4,564
-------- --------
Total current assets 53,397 60,575
-------- --------
Regulatory Assets and Other Deferred Charges 47,365 50,503
-------- --------
Total Assets $481,501 $490,062
======== ========
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 45,263 45,251
Treasury stock (266,100 shares and 195,100 shares,
respectively, at cost) (3,656) (2,628)
Retained earnings 72,553 66,422
-------- --------
Total common stock equity 184,875 179,760
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 20,000 20,000
Long-term debt 120,383 120,142
Long-term lease arrangements 18,845 19,385
-------- --------
Total capitalization 352,157 347,341
-------- --------
Current Liabilities
Short-term debt - 13,490
Current portion of long-term debt 1,015 15
Accounts payable 3,775 4,726
Accounts payable - affiliates 9,212 10,559
Accrued income taxes 2,496 1,497
Dividends declared 3,042 507
Other current liabilities 25,751 26,101
-------- --------
Total current liabilities 45,291 56,895
-------- --------
Deferred Credits
Deferred income taxes 57,654 57,191
Deferred investment tax credits 7,808 8,003
Other deferred credits 18,591 20,632
-------- --------
Total deferred credits 84,053 85,826
-------- --------
Total Capitalization and Liabilities $481,501 $490,062
======== ========
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Six Months Ended
June 30
1996 1995
Cash Flows Provided (Used) By
Operating Activities
Net income $14,311 $12,733
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation 8,880 8,511
Deferred income taxes and investment tax credits 658 3,512
Allowance for equity funds during construction (48) (153)
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs 2,345 (6,091)
Amortization of conservation & load management
costs 2,038 1,681
Amortization of restructuring costs 122 540
Decrease in accounts receivable 14,543 13,220
Increase (decrease) in accounts payable (2,720) (1,622)
Increase (decrease) in accrued income taxes 999 (1,949)
Change in other working capital items 2,480 (41)
Other, net (2,670) (782)
------- -------
Net cash provided by operating activities 40,938 29,559
------- -------
Investing Activities
Construction and plant expenditures (9,067) (10,200)
Conservation and load management expenditures (809) (2,118)
Investments in affiliates (160) (47)
Non-utility investments 244 22
Other investments, net (121) (64)
------- -------
Net cash used for investing activities (9,913) (12,407)
------- -------
Financing Activities
Repurchase of common stock (1,042) (1,053)
Sale of treasury stock 14 -
Short-term debt, net (13,490) (4,037)
Long-term debt, net 1,241 (4,237)
Common and preferred dividends paid (5,644) (6,198)
------- -------
Net cash used for financing activities (18,921) (15,525)
Net Increase in Cash and Cash Equivalents 12,104 1,627
Cash and Cash Equivalents at Beginning of Period 11,962 7,559
------- -------
Cash and Cash Equivalents at end of Period $24,066 $ 9,186
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 4,663 $ 4,961
Income taxes (net of refunds) $ 6,393 $ 6,119
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1996
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note 1 of
Notes to Consolidated Financial Statements included in its 1995 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. Certain reclassifications have been made to
the Consolidated Balance Sheet to conform with the current period's
presentation.
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. The Company has established a
process for determining whether insurance proceeds are available to offset the
costs associated with these sites.
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. 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 for review. The state
generally agreed with that assessment but expressed a number of concerns. 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 additional
data and develop and implement a remediation plan for the site. That firm has
begun work at the site. It will collect 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 the
state of Kansas and the other in the state of Missouri (the "Sites"). During
the mid-1980's, these Sites received materials containing PCBs from hundreds
of sources, including the Company. The Company has complied with the
information request and will monitor EPA activities at the Sites. At this
time, there has been no estimate of the cost to remediate the Sites.
Therefore, the Company cannot predict whether the Sites represent the
potential for a material adverse effect on its financial condition or results
of operations. However, given the fact the EPA has identified more than 1,000
Potentially Responsible Parties (PRPs), and, based on information currently
available to the Company that contamination at the Sites appears to be
somewhat contained, any resulting liability is not expected to be significant.
The Company faces potential liability arising from the alleged disposal
of hazardous materials at three former municipal landfills: the Bennington
Landfill, the Parker Landfill, and the Trafton-Hoisington Landfill.
BENNINGTON LANDFILL The Bennington Landfill is a Superfund site located in
Bennington, Vermont. An investigation by the Company suggests that it is
unlikely that it contributed a meaningful amount of hazardous substances, if
any, to the site.
In July 1994, the EPA notified the Company that it had reviewed evidence
which, in its opinion, indicated that the Company may have contributed to the
environmental contamination at the Bennington site but that a full
determination of its potential liability for the site had not been made. EPA,
at that time, designated the Company a potentially interested party (PIP).
Also in July 1994, the EPA notified the PRP Group, the Company and other PIPs
that it was proposing a response action at the site with an estimated total
present worth cost of approximately $9.5 million.
During November 1994, the Company was notified that EPA had information
indicating that the Company was a PRP with regard to the Bennington site. The
EPA letter also requested that the Company participate with other PRPs in
the response action described above and further made a demand against the
Company and other PRPs for reimbursement of an aggregate of $.85 million in
costs EPA had incurred in responding to conditions at the site.
The original PRP Group reformed into a larger group, incorporating
additional PRPs, including the Company, to undertake the remedial response,
reimburse EPA's response expenses of $3 million it spent on its Engineering
Evaluation/Cost Analysis. The Company determined its interests would be best
served by participating in the larger PRP Group while at the same time
exploring the possibility of a "De Minimis" settlement with the EPA, either
alone or as part of a group, premised on its minimal contribution to the site.
Negotiations between the PRP Group and the EPA continue. The PRP Group
and EPA recently reached a tentative agreement. Under the terms of that
agreement, and a related internal allocation, the Company's liability would be
less than $100,000. If a final settlement is not achieved, the Company will
continue to explore its settlement options, individually and as a part of a
group of "De Minimis" parties. If all efforts at settlement fail, the Company
will defend any contribution action brought by the other PRPs or the EPA.
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.
The Company recently filed a Federal Law Suit against several insurance
companies. In its complaint, the Company alleges that general liability
policies issued by the insurer 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.
Note 3 - Accounts Receivable
At June 30, 1996 and December 31, 1995, 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 $6.2 million and $5.8 million, respectively, at
June 30, 1996 and $4.4 million and $7.6 million, respectively, at December 31,
1995.
Accounts receivable are also reflected net of an allowance for
uncollectible accounts of $1.4 million and $1.6 million at June 30, 1996 and
December 31, 1995, respectively.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Summarized income statement information for Vermont Yankee Nuclear Power
Corporation follows (dollars in thousands, except per share amounts):
Three Months Ended Six Months Ended
June 30 June 30
1996 1995 1996 1995
Operating revenues $43,282 $47,043 $83,038 $98,418
Operating expenses 39,287 43,187 75,602 90,730
------- ------- ------- -------
Operating income 3,995 3,856 7,436 7,688
Other income, net 572 512 1,201 1,049
------- ------- ------- -------
Total operating and
other income 4,567 4,368 8,637 8,737
Interest expense 2,865 2,652 5,337 5,263
------- ------- ------- -------
Net income $ 1,702 $ 1,716 $ 3,300 $ 3,474
======= ======= ======= =======
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
June 30, 1996
Earnings Overview
The Company recorded losses for common stock of $1.0 million and
$1.6 million for the three months ended June 30, 1996 and 1995, respectively.
Losses per share of common stock for these respective periods were $.08 and
$.13. Due to the Company's winter sales peak and higher winter rates, the
Company normally experiences losses in the second and third quarter when sales
are lower and rates are reduced.
For the six months ended June 30, 1996 earnings available for common
stock were $13.3 million compared to $11.7 million in 1995. Earnings per
share of common stock for these respective periods were $1.15 and $1.00.
The increase in earnings for the second quarter and first half is
primarily due to the effect of the April 30, 1996 Vermont Public Service Board
(PSB) rate order, including the 5.5% retail rate increase that became
effective with bills rendered June 1, 1996, the one-time gain from life
insurance proceeds of approximately $1.3 million and other factors described
in Results of Operations 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 six
months ended June 30, 1996 and 1995 (and the related percentage changes from
1995) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended June 30
Percentage Percentage
MWH Increase Revenues (000's) Increase
1996 1995 (Decrease) 1996 1995 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Residential 215,116 213,608 0.7 $21,719 $20,522 5.8
Commercial 208,941 205,968 1.4 19,952 18,875 5.7
Industrial 93,375 91,381 2.2 6,700 6,358 5.4
Other retail 1,819 1,831 (0.7) 463 451 2.7
------- ------- ------- -------
Total retail sales 519,251 512,788 1.3 48,834 46,206 5.7
Resale sales:
Firm 191 327 (41.6) 16 14 14.3
Entitlement 132,939 305,408 (56.5) 6,201 11,780 (47.4)
Other 200,524 160,128 25.2 4,906 3,704 32.5
------- ------- ------- -------
Total resale sales 333,654 465,863 (28.4) 11,123 15,498 (28.2)
------- ------- ------- -------
Other revenues - - - 1,433 1,142 25.5
------- ------- ------- ------
Total sales 852,905 978,651 (12.8) $61,390 $62,846 (2.3)
======= ======= ======= =======
Six Months Ended June 30
Percentage Percentage
MWH Increase Revenues (000's) Increase
1996 1995 (Decrease) 1996 1995 (Decrease)
Residential 500,471 487,306 2.7 $ 56,200 $ 53,389 5.3
Commercial 440,349 424,491 3.7 48,156 46,023 4.6
Industrial 197,705 202,655 (2.4) 16,138 16,300 (1.0)
Other retail 3,606 3,724 (3.2) 905 899 .7
--------- --------- -------- --------
Total retail sales 1,142,131 1,118,176 2.1 121,399 116,611 4.1
--------- --------- -------- --------
Resale sales:
Firm 796 4,042 (80.3) 39 192 (79.7)
Entitlement 269,880 551,224 (51.0) 12,890 23,869 (46.0)
Other 385,459 293,411 31.4 9,210 6,906 33.4
--------- --------- -------- --------
Total resale sales 656,135 848,677 (22.7) 22,139 30,967 (28.5)
--------- --------- -------- --------
Other revenues - - - 2,098 2,131 (1.5)
--------- --------- -------- --------
Total sales 1,798,266 1,966,853 (8.6) $145,636 $149,709 (2.7)
</TABLE>
Retail MWH sales for the second quarter ended June 30, 1996 increased
1.3%. However, retail revenues increased $2.6 million or 5.7% over last year
due to a $2.1 million increase in price resulting from the 5.5% retail rate
increase effective with bills rendered June 1, 1996 and $.5 million associated
with the 1.3% increase in retail MWH sales. For the quarter, residential MWH
sales were about the same as last year while commercial and industrial MWH
sales increased 1.4% and 2.2%, respectively, reflecting more normal weather
than during the corresponding 1995 quarter.
For the first half of 1996, retail MWH sales increased 2.1% while retail
revenues increased $4.8 million or 4.1% compared to last year. The revenue
increase results from a $2.1 million increase in price due to the 5.5% retail
rate increase and $2.7 million associated with the 2.1% increase in retail MWH
sales. For the first half of 1996, residential and commercial MWH sales
increased 2.7% and 3.7%, respectively, reflecting the normal cold weather
experienced during the first quarter of 1996. Industrial MWH sales and
revenues decreased 2.4% and 1.0%, respectively, as a result of increased
natural snowfall during 1996 reducing ski areas' megawatt-hour requirements
for snow making.
Primarily due to the expiration in October 1995 of a five year sale of
part of the Company's interest in the output of Vermont Yankee and Merrimack
#2 and lower sellback of Hydro-Quebec power, entitlement MWH sales and
revenues decreased for the second quarter and first half of 1996 compared to
the same periods in 1995.
The increase in other resale sales and revenues for the second quarter
resulted primarily from increased short-term system capacity sales offset by a
decrease in off-system sales to other utilities in New England. The increases
for the first half are mostly due to increased short-term system capacity
sales.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three and six months ended June 30, 1996 and 1995 are as follows (dollars
in thousands):
<TABLE>
<CAPTION>
Three Months Ended June 30
1996 1995
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 547 $21,226 675 $21,071
Energy (MWH) 838,568 15,213 965,237 16,620
------- -------
Total purchased power costs 36,439 37,691
Production fuel (MWH) 72,409 235 70,859 529
------- -------
Total purchased power and
production fuel costs 36,674 38,220
Entitlement and other resale sales (MWH) 333,463 11,107 465,536 15,484
------- -------
Net purchased power and production
fuel costs $25,567 $22,736
======= =======
Six Months Ended June 30
1996 1995
Units Amount Units Amount
Purchased and produced:
Capacity (MW) 511 $41,178 632 $42,342
Energy (MWH) 1,746,419 32,533 1,913,760 34,524
------- -------
Total purchased power costs 73,711 76,866
Production fuel (MWH) 177,626 774 172,882 1,099
------- -------
Total purchased power and
production fuel costs 74,485 77,965
Entitlement and other resale sales (MWH) 655,338 22,100 844,635 30,775
------- -------
Net purchased power and production
fuel costs $52,385 $47,190
======= =======
</TABLE>
The Company's net purchased power and production fuel costs increased
$2.8 million for the second quarter compared to the same period last year.
Capacity costs were slightly higher than last year and energy costs decreased
by $1.4 million. These variances were offset by a net $4.4 million reduction
in entitlement and other resale sales described above. Although the Company
purchased 19.0% less MW during the second quarter which decreased capacity
costs $4.0 million, this was offset by a price increase of $4.2 million.
Energy costs were lower due to a 13.1% decrease in the amount of MWH purchased
amounting to $2.2 million offset by a price increase of $.8 million.
For the first half of 1996, net purchased power and production fuel costs
increased $5.2 million compared to the same period last year. Although
capacity and energy costs decreased by $1.2 million and $2.0 million
respectively, these decreases were offset by a net $8.7 million reduction in
entitlement and other resale sales. The decrease in capacity costs results
from less MW purchased amounting to $8.1 million partially offset by an
increase in price of $6.9 million. Energy costs were lower due to an 8.7%
decrease in the amount of MWH purchased amounting to $3.0 million offset by
price increases of $1.0 million.
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% and 3.5% equity interest in Maine
Yankee and Yankee Atomic, respectively.
Millstone Unit #3
On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed the
Millstone Nuclear Power Station on its "watch list" as a Category 2 facility
which have been identified by the NRC as having weaknesses that require
increased NRC attention until the licensee demonstrates a period of improved
performance.
The NRC issued a series of letters seeking assurances the Millstone Units
would be operated in accordance with the terms of their operating licenses,
their Updated Final Safety Analysis Reports and all NRC regulations before it
would allow restart of the Millstone Units.
On March 30, 1996, Millstone Unit #3 (Unit #3) was shut down by the
licensee following an engineering evaluation which determined that four
safety-related valves would not be able to perform their design function
during certain assumed events.
In a letter dated June 28, 1996, the NRC informed Northeast Utilities
Service Company (NUSCO) a subsidiary of NU, that the Millstone Nuclear Power
Station had been reclassified from a Category 2 facility to a Category 3
facility. Category 3 facilities are classified as having significant
weaknesses that require maintaining the plant in shutdown condition until it
is demonstrated that adequate programs have been established and implemented
to ensure substantial improvement. Also, the letter informed NUSCO that
Category 3 designation requires the NRC staff to obtain NRC approval by vote
prior to a plant returning to service.
On July 2, 1996, NUSCO filed an extensive document, including an
Operational Readiness Plan (ORP), with the NRC responding to a series of
letters received from the NRC concerning Unit #3. The response outlines a
revised corrective action program for the Millstone Nuclear Power Station in
response to criticism of this program contained in a June 6 letter from the
NRC. The July 2, 1996 filing identifies about 1,200 design and configuration
discrepancies at Unit #3 of which about 600 will have to be resolved before
Unit #3 can be returned to service. NUSCO believes that a small number of the
remaining items will require hardware modifications and the balance can be
resolved with additional inspections, documentation changes or additional
analysis. The ORP for Unit #3 is presently being implemented and NUSCO's
management estimates that it will be fully implemented by October 1996.
On August 6, 1996, the chairman of the NRC announced that an independent
review team would be created to review actions taken by NU prior to the
restart of Unit #3. No formal action has been taken by the NRC to date in
regard to the creation of the independent review team.
However, NUSCO's management cannot predict, at this time, the results of
the NRC's review of Unit #3 documentation, how long it will take NUSCO to
demonstrate the effectiveness of the corrective action program to the NRC or
the effect the independent review team will have on the timing of restart
Unit #3 and what additional costs, if any.
The incremental direct and replacement power costs associated with Unit
#3 outages will depend on the length of time Unit #3 remains out of service,
which is not known at this time. However, the Company estimates that while
Unit #3 is out of service it will incur incremental replacement power costs
estimated at $250,000 to $350,000 per month. In addition, the Company expects
to incur incremental operation and maintenance costs during 1996 of about
$750,000.
Connecticut Yankee
On May 17, 1996, NU received a letter from the NRC indicating that recent
inspections of the Connecticut Yankee (CY) nuclear unit revealed issues that
were similar to those previously identified at Millstone Nuclear Power
Station. Accordingly, the NRC requested that CY submit by May 30, 1996, a
comprehensive list of design and configuration deficiencies identified at CY,
together with a description of the actions taken in response to the
deficiencies. In its compliance response, on May 30, 1996, CY stated that
although several specific issues identified at CY are similar to those at
Unit #1 of the Millstone Nuclear Power Station, the findings do not reach the
same level as those identified at that facility. Also, CY stated that the
fundamental problems that exist at Millstone Unit #1 are not present at CY.
On July 22, 1996, the CY plant began an unscheduled outage as a
precautionary measure to evaluate the plant's service water system, which
provides cooling water to certain critical plant components. The shutdown
began after an analysis of a hypothetical, though unlikely, accident scenario
which demonstrates that the cooling water system might not perform its
intended function. Based on preliminary engineering studies, NU estimated
that the CY plant would return to service prior to mid-August 1996.
Additional maintenance was expected to be completed during its 60-day
scheduled refueling outage beginning September 21, 1996. On August 2, 1996,
NU received a letter from the NRC identifying other potentially significant
issues involving the "Residual Heat Removal, Service Water, and Feedwater
Systems." Therefore, in order to make necessary improvements to the safety
related systems, NU decided to begin the CY plant refueling outage on
August 8, 1996. NU cannot currently estimate whether the refueling outage
combined with the necessary improvements to the safety related systems will
extend beyond the 60-day scheduled refueling outage.
On August 9, 1996, NU received a letter from the NRC asking NU to "update
and resubmit" the basis for continued operation of the CY plant previously
submitted to the NRC. The NRC also requested NU to address the implications
of recently identified instances of degraded or non-conforming conditions at
the CY plant. NU must respond to the NRC letter within 30 days of its
issuance.
The Company cannot estimate, at this time, the length of the outage or
the additional operating and maintenance costs associated with the outage.
The Company's incremental replacement power costs while the CY plant is out of
service are estimated at about $140,000 per month.
Maine Yankee
By order of the NRC, the 880-megawatt nuclear generating plant (Plant)
located in Wiscasset, Maine is currently restricted to 90% of its approved
power level.
In response to concerns about Maine Yankee's analysis and the NRC's
review of certain computer codes used in calculating the safety of the Plant
in the event of some types of accidents, in mid-July 1996 an independent
Safety Assessment Team (Team), commissioned by the NRC, began a four-week,
on-site comprehensive review of the Plant's performance. The Team will
perform a detail review of the licensing basis and operational safety
performance of the Plant. The Team is responsible for analyzing whether the
Plant has been operating in compliance with its operating license.
On July 20, 1996, the Plant was shut down as a result of a potential
problem discovered by Maine Yankee personnel related to the containment
cooling system. The Plant is scheduled to return to service the week of
August 11, 1996. The Company's share of the incremental operating and
maintenance costs associated with the outage are minimal and the Company
estimates incremental replacement power costs of about $150,000 through the
date the Plant is expected to return to service.
Yankee Atomic
In 1992, the Board of Directors of Yankee Atomic (YA) decided to
permanently discontinue operation of their plant, and to decommission the
facility. The Company relied on YA for less than 1.5% of its system capacity.
Presently, purchased power costs billed to the Company by YA, which include a
provision for ultimate decommissioning of the unit, are being collected from
the Company's customers via existing retail tariffs. The Company's share of
remaining costs with respect to YA's decision to discontinue operation is
approximately $7.0 million. 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 its proportionate share of YA costs will be
recovered through the regulatory process and, therefore, the ultimate
resolution of the premature retirement of the YA plant has not and will not
have a material adverse effect on the Company's earnings or financial
condition.
Other Operation
The decrease in other operating expenses of $1.9 million and $2.7 million
for the second quarter and first half of 1996, respectively, was primarily the
result of accounting for the cumulative effects of certain Conservation and
Load Management (C&LM) costs. Consistent with cost recovery allowed by the
PSB in its April 30, 1996 rate order, the Company, during the second quarter,
reversed approximately $1.4 million of C&LM expenses and recorded a regulatory
asset. Lower administrative and general expenses and uncollectible accounts
also contributed to the decreases for the periods.
Maintenance
The increase in maintenance expenses of $.4 million for the second
quarter and $.8 million for the first half of 1996 compared to the same
periods in 1995 is attributable to service restoration activities after
several winter storms and maintenance of the Company's hydroelectric projects.
Nuclear maintenance expenses associated with the Company's joint-ownership
interest in Millstone Unit #3 also increased for the periods.
Other Taxes, Principally Property Taxes
The increase in other taxes for the second quarter and first half of 1996
results from higher real estate taxes.
Income Taxes
Federal and state income taxes fluctuate with the level of pre-tax
earnings. The increase in total income tax expense for the second quarter and
first half of 1996 results primarily from an increase in pre-tax earnings for
the respective periods.
Other Income (Expenses), Net
For the second quarter of 1996, other income (expenses), net decreased
primarily due to litigation settlement costs of approximately $.5 million
described in Part II - Other Information and about $.2 million of costs
incurred for the New Hampshire Pilot program described in Liquidity and
Capital Resources below.
The increase for the first half of 1996 is due to insurance proceeds of
approximately $1.3 million and interest on temporary cash investments. These
increases were partially offset by litigation costs and the New Hampshire
Pilot program costs.
Other Interest Expense
Although short-term interest rates increased during the second quarter of
1996, lower short-term debt levels resulted in a decrease in other interest
expense for the second quarter compared to the same period last year. Other
interest expense declined for the first half of 1996 due to lower average
interest rates combined with decreased short-term debt levels.
Cash Dividends Declared
Common
Early declarations account for the increase in common dividends declared.
During the first half of 1996 three common stock dividends of $.20 per share
were declared while one common stock dividend of $.20 per share was declared
during the first half of 1995. However, two quarterly common stock dividends
of $.20 per share were paid during the first half of 1996 and 1995. The June
1996 declaration reflects a 10% increase in future quarterly dividends paid on
the Company's outstanding common stock to $.22 per share from $.20 per share.
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
$40.9 million and $29.6 million for the six months ended June 30, 1996 and
1995, respectively.
The Company ended the first half of 1996 with cash and cash equivalents
of $24.1 million, an increase of $12.1 million from the beginning of the year.
The increase in cash for the first six months of 1996 was the result of
$40.9 million provided by operating activities, $9.9 million used for
investing activities and $18.9 million used for financing activities.
Operating Activities
Net income before non-cash items, depreciation and deferred income taxes
provided $23.8 million. Fluctuations in working capital provided
$15.3 million and $1.8 million was provided from other net and
deferral/amortization of nuclear replacement energy and maintenance costs.
Investing Activities
Construction and plant expenditures consumed $9.1 million and $.8 million
was used for C&LM programs.
Financing Activities
Dividends paid on common stock were $4.6 million, while preferred stock
dividends were $1.0 million. Long-term debt provided $1.2 million while
short-term obligations repaid totaled $13.5 million. $1.0 million was used to
reacquire common stock.
Competition
As described in Note 1 of Notes to Consolidated Financial Statements
included in the Company's 1995 Annual Report on Form 10-K, management believes
the Company meets the requirement of SFAS No. 71, "Accounting for the Effects
of Certain Types of Regulation," but continues to evaluate significant changes
in the regulatory and competitive environment to ensure and assess the
Company's overall consistency with the criteria of SFAS No. 71. If in the
future, 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. Although
these conditions do not currently exist, the Company anticipates future
competition will place pressure on both unit sales and the prices the Company
can charge. As a result, increased competitive pressure in the electric
utility industry may restrict the Company's ability to establish prices to
recover embedded costs and may lead to a significant change in the manner
rates are set by regulators from cost-based regulation to a different form of
regulation that approximates market conditions. Singly or together these
events may give rise to the discontinuance of SFAS No. 71 and, in addition,
could diminish the Company's ability to recover its embedded costs of
providing service.
Utility Restructuring
The electric utility industry is in a period of potential 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. Most 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.
In Vermont, the PSB by Order dated October 17, 1995, opened a process
requiring all 22 electric utilities in Vermont to file proposed restructuring
plans by mid-1996. The goal, as set forth in the Order, is to achieve
restructuring by January 1, 1998. The Company filed its electric industry
restructuring proposal with the PSB on June 19, 1996.
The Company's proposal for restructuring Vermont's electric utility
industry calls for granting customers the flexibility to choose among
competing suppliers for electricity.
The Company's proposal also provides for full recovery of utility
investments and obligations that may become stranded as a result of
restructuring in the electric utility industry. Sources of potential stranded
costs would include any then above market purchased power contracts or
generation costs, nuclear decom-missioning obligations, unrecovered regulatory
assets, as well as other unrecovered investments and commitments made as a
provider of electric utility service. Recovery of stranded costs would be
sought from customers through a mandatory distribution "wires" charge for
access to the distribution system.
The PSB is expected to issue a draft report with recommendations for the
Vermont Legislature in September 1996 and is expected to issue its final
report with recommendations around December 1996.
The extent of potential stranded costs, if any, depends upon the timing,
nature, and degree of competition that may result from future changes in
regulatory policies governing the Company's activities and prices as well as
future power costs and market prices of power. As such, it is not currently
possible to predict with any reasonable precision the level of costs that
could be considered stranded as a result of future electric utility industry
restructuring. However, it is possible that stranded cost exposure could
exceed the Company's current total common stock equity.
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 up to a two-year period beginning in May
1996 and was open to all electric utilities and to all classes of customers in
New Hampshire, although only 3% of customers were allowed to participate. The
Company successfully 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
conducted an effective retail marketing campaign in New Hampshire and acquired
new customers with combined annual electric use totaling approximately
20 million kilowatt hours. The new retail load gained was more than four
times greater than the load lost by Connecticut Valley through this Pilot.
The new customers acquired by the Company include all classes of service. In
April 1996, the New Hampshire legislature passed legislation requiring the
NHPUC to file a restructuring proposal in New Hampshire in August 1996 and for
the New Hampshire electric utilities to file restructuring plans by June 1997.
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 lines of credit and uncommitted loan
facilities with several banks totaling $37.25 million.
The Company's capital structure ratios as of June 30, 1996 (including
amounts of long-term debt due within one year), consisted of 52.4% common
equity, 7.9% preferred stock, 34.4% long-term debt and 5.3% capital lease
obligations.
Based on debt issues outstanding at June 30, 1996, the Company's
mandatory sinking fund requirements for long-term debt due within the next
twelve-month period is approximately $1.0 million. None of the Company's
preferred stock is currently subject to mandatory sinking fund requirements.
Current credit ratings for the Company's outstanding mortgage debt and
preferred stock as of August 1996 are as follows:
Duff & Standard
Phelps & Poor's
------ --------
First Mortgage Bonds BBB+ 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 (limited to
$3 million). Currently, a $1.2 million letter of credit is outstanding to
support certain of Catamount's obligations in connection with a debt reserve
obligation in the Appomattox Cogeneration project.
SmartEnergy, also a wholly owned subsidiary of the Company, currently
maintains a $1.0 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 1995
were $4.8 million, and are expected to be approximately $5.1 million in 1996.
A tentative agreement has been reached between the Company and the Vermont
Department of Public Service with regard to C&LM programs and expenditure
levels for 1997.
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 four operating independent power projects located in Rumford,
Maine; East Ryegate, Vermont; Hopewell, Virginia; and Williams Lake, British
Columbia, Canada. In addition, Catamount has interests in projects under
construction in Glenns Ferry and Rupert, Idaho; and under development in
Summersville, West Virginia.
SmartEnergy was formed for the purpose of providing reliable,
energy-efficient products and services, including the rental of electric
water heaters.
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. On April 30, 1996 the Company
received a rate order from the PSB permitting an increase in its Vermont
retail rates of 5.5% effective June 1, 1996 and an additional 2% to be
effective January 1, 1997. For additional information regarding the PSB Rate
Order, see the Company's Form 10-Q for the quarter ended March 31, 1996.
During proceedings related to the April 30, 1996 Order, 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 further proceedings are scheduled for August 29, 1996.
On July 23, 1996, Connecticut Valley filed for an 8.8% or approximately
$1.6 million base rate increase to become effective September 22, 1996. The
increase is to recover increased operating costs and costs of improvements to
the electric system. As part of the permanent rate increase, Connecticut
Valley also requested a temporary rate increase of 5.4% or approximately
$.9 million to become effective August 23, 1996.
New Accounting Pronouncements
Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," which establishes accounting standards for the impairment of
long-lived assets and requires that regulatory assets which are no longer
probable of recovery through future revenues be charged to earnings. Based
on the current regulatory rate-making process, the adoption of SFAS No. 121
did not have a material impact on the Company's financial position or results
of operations. The Company did not adopt the accounting option of SFAS
No. 123, "Accounting for Stock-Based Compensation," but adopted the required
audited pro forma disclosure. Based on the requirements of the pronouncement,
the pro forma effects on earnings and earnings per share are not expected to
be material.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On March 20, 1992, Sunnyside Cogeneration Associates filed suit in
the United States District Court for the District of Vermont against the
Company, CV Energy Resources, Inc. (CVER) and a subsidiary of CVER alleging
damages in excess of five million dollars resulting from the parties'
inability to come to agreement on the terms of CVER's proposed investment in
the plaintiff's waste coal cogeneration facility under construction in
Sunnyside, Utah. The Company filed an answer denying the allegations and both
sides had filed motions for summary judgment which were denied. The plaintiff
had also submitted its Requests for Finding of Fact, in which it claimed
damages of approximately $8.7 million. The case was settled shortly before
going to trial in early July 1996.
On December 30, 1994, a lawsuit was filed in the United States
District Court for the District of Vermont, Civil Action No. 2:94-CV386, by
Bradford E. White, Michel J. Messier and John A. Wasik, against the Company,
its present directors and certain former directors. This lawsuit (the
"Shareholder Suit"), which purports to be on behalf of a class of consumers as
well as on behalf of the Company's stockholders in enforcing the rights of the
Company, alleges, among other things, (i) that F. Ray Keyser, Jr., Chairman of
the Company's Board of Directors, violated Section 8 of the Clayton Act, 15
U.S.C. Subchapter 19, which precludes certain interlocking directorships,
(ii) that Mr. Keyser violated his fiduciary duties to the Company's
stockholders by acquiring and operating a series of businesses in competition
with the Company without offering those business opportunities to the Company,
(iii) that the remaining individual defendants violated their fiduciary duties
to the Company's stockholders by failing to analyze, or to cause management to
analyze, diversification into propane and fossil fuels, and by failing to make
the Company an effective competitor of alternative fuel companies, and (iv)
that the Company violated the applicable provision of the Vermont General
Corporation Law by failing to provide a list of the Company's stockholders.
The Shareholder Suit seeks an unspecified amount of damages (including treble
damages against Mr. Keyser), attorney's fees and costs, a list of the
Company's stockholders, and a court order to enjoin the defendants from
alleged continuing violations of the law. Each of the individual defendants
and the Company itself deny the allegations against them and intend to
vigorously defend the Shareholder Suit. The Company and its directors have
filed a Motion to Dismiss which is currently pending before the Court.
Items 2, 3 and 4.
None.
Item 5. Other Information.
(a) The National Energy Policy Act of 1992 and the Federal Energy
Regulatory Commission's (FERC) March 1995 Notice of Proposed Rule-making
(NOPR) promote wholesale competition in the electric utility industry.
On April 24, 1996, under Order No. 888, FERC issued its final open
access rule promoting competition in the electric utility industry. All
public utilities that own, control or operate facilities used for transmitting
electric energy in interstate commerce are required by Order No. 888 to file
an open access, non-discriminatory transmission tariff. Order No. 888
requires public utilities to develop and maintain a same-time information
system that will give existing and potential transmission users the same
access to transmission information that the public utility enjoys and also
requires public utilities to separate transmission from generation marketing
functions and communications. Also, Order No. 888 supports full recovery of
legitimate, prudent and verifi-able stranded costs associated with providing
open access transmission services.
On April 24, 1996, the Company filed a settlement agreement with FERC
which addressed all rate issues raised in the Company's March 1, 1995 open
access Transmission Tariff No.6. The single unresolved rate issue is set for
hearing. After evaluating Order No. 888, the Company submitted, on July 9,
1996, compliance filing modifying the terms and conditions of Transmission
Tariff No. 6 to conform to the non-rate terms and conditions of the pro forma
tariffs in Order No. 888.
(b) As ordered by the NHPUC in Connecticut Valley's 1994 C&LMPA
docket, the Company entered into negotiations with the NHPUC Staff to redesign
the RS-2 wholesale rate under which Connecticut Valley purchases power from
the Company. The redesign features marginal cost based energy and capacity
charges for all energy and capacity purchases above or below a base level.
Such negotiations concluded at the end of 1994. A summary report was filed
with the NHPUC on February 13, 1995. The NHPUC issued an order approving the
summary report in June 1995. The Company is preparing the FERC filing which
it expects to file in 1996. The redesigned rate is structured such that
Connecticut Valley's cost under the existing average cost rate structure of
wholesale power will be lower than it would have if Connecticut Valley's
growth rate exceeds that of the Company's Vermont retail operations.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
EXHIBIT INDEX
-------------
Exhibit
-------
27. Financial Data Schedule.
(b) Item 5. Other Events, dated April 30, 1996 re: Retail Rate Order
was filed on May 2, 1996.
<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, Vice President,
Finance and Administration and
Principal Financial Officer
By James M. Pennington
--------------------------------------
James M. Pennington, Controller and
Principal Accounting Officer
Dated August 13, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This Financial Data Schedule contains summary financial information extracted
from the Consolidated Financial Statements included herein and is qualified in
its entirety by reference to such financial statements (dollars in thousands,
except per share amounts).
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 324,591
<OTHER-PROPERTY-AND-INVEST> 56,148
<TOTAL-CURRENT-ASSETS> 53,397
<TOTAL-DEFERRED-CHARGES> 47,365
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 481,501
<COMMON> 67,059
<CAPITAL-SURPLUS-PAID-IN> 45,263
<RETAINED-EARNINGS> 72,553
<TOTAL-COMMON-STOCKHOLDERS-EQ> 184,875
20,000
8,054
<LONG-TERM-DEBT-NET> 120,383
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,015
0
<CAPITAL-LEASE-OBLIGATIONS> 18,845
<LEASES-CURRENT> 1,094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 127,235
<TOT-CAPITALIZATION-AND-LIAB> 481,501
<GROSS-OPERATING-REVENUE> 145,636
<INCOME-TAX-EXPENSE> 8,218
<OTHER-OPERATING-EXPENSES> 121,786
<TOTAL-OPERATING-EXPENSES> 130,004
<OPERATING-INCOME-LOSS> 15,632
<OTHER-INCOME-NET> 3,556
<INCOME-BEFORE-INTEREST-EXPEN> 19,188
<TOTAL-INTEREST-EXPENSE> 4,877
<NET-INCOME> 14,311
1,014
<EARNINGS-AVAILABLE-FOR-COMM> 13,297
<COMMON-STOCK-DIVIDENDS> 7,166
<TOTAL-INTEREST-ON-BONDS> 8,142
<CASH-FLOW-OPERATIONS> 40,938
<EPS-PRIMARY> 1.15
<EPS-DILUTED> 0
</TABLE>
