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
or
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 1-8291
GREEN MOUNTAIN POWER CORPORATION
(Exact name of registrant as specified in its charter)
Vermont 03-0127430
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
25 Green Mountain Drive
South Burlington, VT 05403
Address of principal executive offices (Zip Code)
Registrant's telephone number, including area code (802) 864-5731
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.
Class - Common Stock Outstanding September 30, 1997
$3.33 1/3 Par Value 5,150,647
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1 - Item 1
<CAPTION>
September 30 December 31
----------------------------------- ----------------
1997 1996 1996
---------------- ---------------- ----------------
(In thousands) (In thousands)
<S> <C> <C> <C>
ASSETS
Utility Plant
Utility plant, at original cost.................... $260,165 $247,067 $248,135
Less accumulated depreciation...................... 87,065 81,050 81,286
---------------- ---------------- ----------------
Net utility plant................................ 173,100 166,017 166,849
Property under capital lease....................... 9,006 9,778 9,006
Construction work in progress...................... 13,877 11,536 13,998
---------------- ---------------- ----------------
Total utility plant, net......................... 195,983 187,331 189,853
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity ................... 15,684 15,862 15,769
Other investments.................................. 5,408 4,760 4,865
---------------- ---------------- ----------------
Total other investments.......................... 21,092 20,622 20,634
---------------- ---------------- ----------------
Current Assets
Cash............................................... 186 71 238
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 15,567 13,326 17,733
Accrued utility revenues .......................... 5,424 5,264 6,662
Fuel, materials and supplies, at average cost...... 3,544 3,474 3,621
Prepayments........................................ 786 1,257 2,206
Other.............................................. 841 1,405 441
---------------- ---------------- ----------------
Total current assets............................. 26,348 24,797 30,901
---------------- ---------------- ----------------
Deferred Charges
Demand side management programs.................... 13,896 14,830 16,409
Environmental proceedings costs.................... 7,600 8,286 7,991
Purchased power costs.............................. 11,219 9,095 9,163
Other.............................................. 10,404 11,532 9,661
---------------- ---------------- ----------------
Total deferred charges........................... 43,119 43,743 43,224
---------------- ---------------- ----------------
Non-Utility
Cash and cash equivalents.......................... 442 348 511
Other current assets............................... 7,768 3,242 3,979
Property and equipment............................. 10,879 11,198 11,226
Intangible assets.................................. 2,161 2,631 2,555
Equity investment in energy related businesses..... 13,642 13,957 12,494
Other assets....................................... 12,503 7,698 9,162
---------------- ---------------- ----------------
Total non-utility assets......................... 47,395 39,074 39,927
---------------- ---------------- ----------------
Total Assets........................................... $333,937 $315,567 $324,539
================ ================ ================
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,166,503, 4,993,834 and 5,037,143)........... $17,203 $16,646 $16,790
Additional paid-in capital....................... 70,315 67,363 68,226
Retained earnings................................ 26,949 26,640 26,916
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 114,089 110,271 111,554
Redeemable cumulative preferred stock.............. 17,910 7,530 19,310
Long-term debt, less current maturities............ 93,200 80,900 94,900
---------------- ---------------- ----------------
Total capitalization........................... 225,199 198,701 225,764
---------------- ---------------- ----------------
Capital lease obligation............................... 9,006 9,778 9,006
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,700 3,034 3,034
Short-term debt.................................... 14,016 23,416 1,016
Accounts payable, trade, and accrued liabilities... 4,046 2,956 6,140
Accounts payable to associated companies........... 6,157 8,380 6,621
Dividends declared................................. 354 160 381
Customer deposits.................................. 547 573 689
Taxes accrued...................................... 832 1,620 986
Interest accrued................................... 2,066 1,817 1,382
Other.............................................. 824 312 788
---------------- ---------------- ----------------
Total current liabilities...................... 30,542 42,268 21,037
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 27,581 24,869 26,726
Unamortized investment tax credits................. 4,593 4,914 4,825
Other.............................................. 24,157 23,202 23,417
---------------- ---------------- ----------------
Total deferred credits......................... 56,331 52,985 54,968
---------------- ---------------- ----------------
Non-Utility
Current liabilities................................ 1,133 978 1,752
Other liabilities.................................. 11,726 10,857 12,012
---------------- ---------------- ----------------
Total non-utility liabilities.................. 12,859 11,835 13,764
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $333,937 $315,567 $324,539
================ ================ ================
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Income Statements
(Unaudited)
Part 1 - Item 1
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
------------------------------- -------------------------------
1997 1996 1997 1996
------------ ------------ ------------ ------------
(In thousands, except amounts per share)
<S> <C> <C> <C> <C>
Operating Revenues............................................ $43,574 $44,423 $133,460 $133,304
------------ ------------ ------------ ------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation................. 8,037 7,680 24,276 23,184
Company-owned generation................................. 1,441 985 3,486 2,557
Purchases from others.................................... 13,246 15,020 45,974 48,898
Other operating............................................. 4,323 4,313 12,565 13,959
Transmission................................................ 2,503 3,136 8,464 8,350
Maintenance................................................. 1,143 1,106 3,402 3,492
Depreciation and amortization............................... 4,015 4,179 12,407 12,102
Taxes other than income..................................... 1,915 1,644 5,523 5,030
Income taxes................................................ 2,409 1,941 5,580 4,380
------------ ------------ ------------ ------------
Total operating expenses................................. 39,032 40,004 121,677 121,952
------------ ------------ ------------ ------------
Operating Income....................................... 4,542 4,419 11,783 11,352
------------ ------------ ------------ ------------
Other Income
Equity in earnings of affiliates and non-utility operations. 449 823 579 2,603
Allowance for equity funds used during construction......... 85 2 479 92
Other income and deductions, net............................ 202 54 603 82
------------ ------------ ------------ ------------
Total other income........................................ 736 879 1,661 2,777
------------ ------------ ------------ ------------
Income before interest charges.......................... 5,278 5,298 13,444 14,129
------------ ------------ ------------ ------------
Interest Charges
Long-term debt.............................................. 1,818 1,614 5,508 5,125
Other....................................................... 208 324 369 776
Allowance for borrowed funds used during construction....... (119) (114) (348) (335)
------------ ------------ ------------ ------------
Total interest charges.................................... 1,907 1,824 5,529 5,566
------------ ------------ ------------ ------------
Net Income.................................................... 3,371 3,474 7,915 8,563
Dividends on preferred stock.................................. 349 159 1,097 539
------------ ------------ ------------ ------------
Net Income Applicable to Common Stock......................... $3,022 $3,315 $6,818 $8,024
============ ============ ============ ============
Common Stock Data
Earnings per share.......................................... $0.59 $0.67 $1.34 $1.63
Cash dividends declared per share........................... $0.275 $0.53 $1.335 $1.59
Weighted average shares outstanding......................... 5,138 4,959 5,093 4,910
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................. $25,344 $25,950 $26,916 $26,412
Net Income.................................................... 3,371 3,474 7,915 8,563
------------ ------------ ------------ ------------
28,715 29,424 34,831 34,975
------------ ------------ ------------ ------------
Cash Dividends - redeemable cumulative preferred stock........ 349 159 1,097 539
- common stock................................. 1,417 2,625 6,785 7,796
------------ ------------ ------------ ------------
1,766 2,784 7,882 8,335
------------ ------------ ------------ ------------
Balance - end of period....................................... $26,949 $26,640 $26,949 $26,640
============ ============ ============ ============
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
Part 1 - Item 1
<CAPTION>
Nine Months Ended
September 30
---------------------------------------
1997 1996
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income............................................................ $7,915 $8,563
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization..................................... 12,407 12,102
Dividends from associated companies less equity income............ 85 162
Allowance for funds used during construction...................... (826) (427)
Amortization of purchased power costs............................. (2,969) 4,068
Deferred income taxes............................................. 1,238 (62)
Deferred purchased power costs.................................... (44) (5,761)
Amortization of investment tax credits............................ (232) (193)
Environmental proceedings costs, ................................. (869) (1,420)
Conservation expenditures......................................... (1,482) (2,049)
Changes in:
Accounts receivable............................................. 2,166 4,755
Accrued utility revenues........................................ 1,238 1,259
Fuel, materials and supplies.................................... 77 (163)
Prepayments and other current assets............................ (2,770) 367
Accounts payable................................................ (2,558) (1,204)
Taxes accrued................................................... (154) 1,049
Interest accrued................................................ 685 (29)
Other current liabilities....................................... (753) (523)
Other............................................................. (2,595) (819)
----------------- -----------------
Net cash provided by operating activities........................... 10,559 19,675
----------------- -----------------
Investing Activities:
Construction expenditures........................................... (12,366) (11,946)
Investment in nonutility property................................... (765) (1,338)
----------------- -----------------
Net cash used in investing activities............................. (13,131) (13,284)
----------------- -----------------
Financing Activities:
Issuance of common stock............................................ 2,502 3,635
Short-term debt, net................................................ 13,000 15,000
Cash dividends...................................................... (7,882) (8,335)
Reduction in preferred stock........................................ (1,400) (1,400)
Reduction in long-term debt......................................... (3,769) (15,033)
----------------- -----------------
Net cash provided by (used in) financing activities............... 2,451 (6,133)
----------------- -----------------
Net increase (decrease) in cash and cash equivalents................ (121) 258
Cash and cash equivalents at beginning of period.................... 749 160
----------------- -----------------
Cash and Cash Equivalents at End of Period.............................. $628 $418
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid year-to-date for:
Interest (net of amounts capitalized)............................ $5,019 $5,755
Income taxes..................................................... 3,854 3,534
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1997
Part 1 -- ITEM 1
1. SIGNIFICANT ACCOUNTING POLICIES
Pursuant to an order of the Vermont Public Service Board (VPSB), the
Company's rate structure is seasonally differentiated, with higher rates
billed during the four winter months and lower rates billed during the
remaining eight months of the year. In order to match revenues with
related costs more accurately on an interim basis, the Company
recognizes revenue in a manner that seeks to eliminate the impact of
such seasonally differentiated rates. At September 30, 1997 and 1996,
the Company had recorded deferred revenues of $380,000 and $550,000,
respectively, in accordance with this policy. This deferred asset is
recognized as an expense in subsequent interim periods.
Included in equity in earnings of affiliates and non-utility operations
in the Other Income section of the Consolidated Comparative Income
Statements are the results of operations of the Company's rental water
heater program, which is not regulated by the VPSB, and five of the
Company's wholly-owned subsidiaries, Green Mountain Propane Gas Company,
Mountain Energy, Inc., GMP Real Estate Corporation, Green Mountain
Resources, Inc. and Lease-Elec, Inc., all of which are unregulated.
Summarized financial information for the rental water heater program and
such wholly-owned subsidiaries is as follows:
Three Months Ended Nine Months Ended
September 30 September 30
----------------- -----------------
1997 1996 1997 1996
---- ---- ---- ----
(In Thousands) (In Thousands)
Revenue . . . . . . . . $2,362 $2,595 $8,397 $9,311
Expenses . . . . . . . . 2,411 2,288 9,383 8,261
------- ------ ------- ------
Net Income . . . . . . . $ (49) $ 307 $ (986) $1,050
======= ====== ======= ======
2. INVESTMENT IN ASSOCIATED COMPANIES
The Company accounts for its investment in the companies listed below
using the equity method. Summarized financial information is as
follows:
Vermont Yankee Nuclear Power Corporation
Three Months Ended Nine Months Ended
September 30 September 30
-------------------- -----------------
1997 1996 1997 1996
---- ---- ---- ----
(In Thousands)
Gross Revenue . . . . . $41,967 $55,068 $126,771 $138,106
Net Income Applicable
to Common Stock . . . 1,721 1,735 5,244 5,035
Company's Equity in
Net Income . . . . . 315 310 961 895
Vermont Electric Power Company, Inc.
Three Months Ended Nine Months Ended
September 30 September 30
------------------- -----------------
1997 1996 1997 1996
---- ---- ---- ----
(In Thousands)
Gross Revenue . . . . . $12,702 $12,722 $37,838 $37,134
Net Income
Before Dividends . . 267 304 976 955
Company's Equity in
Net Income (Includes
preferred equity) . . 75 86 280 295
3. ENVIRONMENTAL MATTERS
Public concern for the environment has resulted in increased government
regulation of the licensing and operation of electric generation,
transmission and distribution facilities. The electric industry
typically uses or generates a range of potentially hazardous products in
its operations. The Company must meet various land, water, air and
aesthetic requirements as administered by local, state and federal
regulatory agencies. The Company maintains an environmental compliance
and monitoring program that includes employee training, regular
inspection of Company facilities, research and development projects,
waste handling and spill prevention procedures and other activities.
Subject to developments concerning the Pine Street Barge Canal Site
described below, the Company believes that it is in substantial
compliance with such requirements, and no material complaints concerning
compliance by the Company with present environmental protection
regulations are outstanding.
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. The
Company has been notified by the Environmental Protection Agency (EPA)
that it is one of several potentially responsible parties (PRPs) for
cleanup of the Pine Street Barge Canal Site in Burlington, Vermont,
where coal tar and other industrial materials were deposited. From the
late 19th century until 1967, gas was manufactured at the Pine Street
Barge Canal Site by a number of enterprises, including the Company. In
1990, the Company was one of the 14 parties that agreed to pay a total
of $945,000 of the EPA's past response costs under a Consent Decree.
The Company remains a PRP for other past, ongoing and future response
costs. In November 1992, the EPA proposed a cleanup plan estimated by
the EPA to cost $47 million. In June 1993, the EPA withdrew this
cleanup plan in response to public concern about the plan and its cost.
The cost of any future cleanup plan, the magnitude of unresolved EPA
cost recovery claims, and the Company's share of such costs are
uncertain at this time.
Since 1994, the EPA has established a coordinating council, with
representatives of the PRPs, environmental and community groups, the
City of Burlington and the State of Vermont presided over by a neutral
facilitator. The council has determined, by consensus, what additional
studies were appropriate for the site, and is addressing the question of
additional response activities. The EPA, the State of Vermont and other
parties have entered into two consent orders for completion of
appropriate studies. Work is continuing under the second of those
orders. Most recently, on September 23, 1997, the council reached
tentative agreement on a key component of the proposed remedy for the
Pine Street site, namely, placement of an underwater sand/silt cap on
areas of the canal and wetland sediments, combined with long-term
monitoring to ensure effectiveness of the cap and to ensure that
groundwater does not reach Lake Champlain, adjacent to the site. The
EPA has estimated the costs of this remedy at between $6 and $10
million. In addition, the council is exploring supplemental projects in
and around the site and Burlington as part of a larger plan to improve
environmental conditions in the vicinity.
On December 1, 1994, the Company and two other PRPs, New England
Electric System (NEES) and Vermont Gas Systems (VGS), entered into a
confidential agreement with the State of Vermont, the City of Burlington
and nearly all other landowner PRPs under which, subject to certain
qualifications, the liability of those landowner PRPs for future
Superfund response costs would be limited and specified. On December 1,
1994, the Company entered into a confidential agreement with VGS
compromising contribution and cost recovery claims of each party and
contractual indemnity claims of the Company arising from the 1964 sale
of the manufactured gas plant to VGS. In March 1996, the Company and
NEES entered into a confidential agreement compromising past and future
contribution and cost recovery claims of both parties relating to
response costs. The Company understands that the EPA has incurred
substantial unrecovered response sums at the site which the company
believes may exceed $8.0 million. The Company has not yet received a
formal demand for these costs.
In December 1991, the Company brought suit against eight previous
insurers seeking recovery of unrecovered past costs, cost of defense and
indemnity against future liabilities associated with environmental
problems at the site. Discovery in the case, which was previously
subject to a stay, is largely complete. A trial in this litigation is
scheduled for late 1997. The Company has reached confidential final
settlements with two of the defendants in this litigation, is in
discussions with several other defendants which may lead to settlement,
and has obtained summary judgment declaring one insurer's duty to
defend.
The Company has deferred amounts received from third parties, under
confidential settlements, pending resolution of the Company's ultimate
liability with respect to the site and rate recognition of that
liability. Although the cost of the council's tentative remediation
plan, described above, is not expected to approach EPA's earlier
estimate of remediation costs for its original clean-up plan, the
Company is unable to predict at this time the magnitude of any liability
resulting from potential claims for the costs to investigate and
remediate the site, or the likely disposition or magnitude of claims the
Company may have against others, including its insurers, except to the
extent described above.
Through rate cases filed in 1991, 1993, 1994 and 1995, the Company has
sought and received recovery for ongoing expenses associated with the
Pine Street Barge Canal Site. Specifically, the Company proposed rate
recognition of its unrecovered expenditures incurred between January 1,
1991 and June 30, 1995 (in the total of approximately $8.7 million) for
technical consultants and legal assistance in connection with the EPA's
enforcement action at the site and insurance litigation. While
reserving the right to argue in the future about the appropriateness of
rate recovery for Pine Street Marsh related costs, the Company and the
Vermont Department of Public Service (the Department) reached agreements
in these cases that the full amount of Pine Street Marsh costs reflected
in those rate cases should be recovered in rates. The Company's rates
approved by the VPSB in those proceedings reflected the Pine Street
Marsh related expenditures referred to above. The Company has proposed
in a rate filing made on June 16, 1997 recovery of an additional $3.0
million in such expenditures.
Management expects to seek and (assuming recovery consistent with the
previous regulatory treatment set forth above) receive ratemaking
treatment for unreimbursed costs incurred beyond the amounts for which
ratemaking treatment has been received.
An authoritative accounting standard, Statement of Position (SOP) 96-1,
has been issued by the accounting profession addressing environmental
remediation obligations. This SOP addresses, among other things,
regulatory benchmarks that are likely triggers of the accrual of
estimated losses, the costs included in the measurement, including
incremental costs of remediation efforts such as post-remediation
monitoring and long-term operation and maintenance costs and costs of
compensation and related benefits of employees devoting time to the
remediation. This SOP, adopted by the Company in January 1997, as
required, did not have a material adverse effect on the Company's
financial position or results of operations, due to current ratemaking
treatment. Should a change in the Company's historical ratemaking occur
this conclusion could change.
4. 1995 Retail Rate Case
In September 1995, the Company filed a 12.7 percent retail rate increase
to cover higher power supply costs, to support additional investment in
plant and equipment, to fund expenses associated with the Pine Street
Barge Canal Site, and to cover higher costs of capital. Early in 1996,
the Company settled this rate case with the Department and other
parties.
The settlement became possible when the Company negotiated a new
arrangement with Hydro-Quebec that will reduce the Company's net power-
supply costs below the amounts anticipated in the rate increase request.
The settlement provided: projected additional annual revenues of $7.6
million; an overall increase in retail rates of 5.25 percent effective
June 1, 1996; target return on equity for utility operations of 11.25
percent; and recovery of $1.3 million of costs associated with the Pine
Street site, amortized over five years. In the event that the target
return on equity is exceeded, the Company would accelerate the
amortization of certain demand side management expenditures in the next
year for which rate recovery otherwise would have been sought. The VPSB
approved the settlement in an order dated May 23, 1996. An accounting
order received from the VPSB on December 31, 1996 continues the
limitation on return on equity from utility operations through December
31, 1997.
5. 1997 Retail Rate Case
On June 16, 1997, the Company filed a request with the VPSB to increase
retail rates by 16.7 percent and the target return on common equity from
11.25 percent to 13 percent. The retail rate increase is needed to
cover higher power supply costs and the Company's rising cost of
capital. (See Management's Discussion and Analysis of Financial
Condition and Results of Operations - Recent Developments.)
6. SFAS 128
In March 1997, the Financial Accounting Standards Board issued a new
accounting standard, Statement of Financial Accounting Standards (SFAS)
128, Earnings per Share. SFAS 128, effective for financial statements
issued for annual periods ending after December 15, 1997, replaces the
definition of primary earnings per share, calculated in accordance with
the provisions of APB 15, with a new calculation, basic earnings per
share. Management believes that the implementation of SFAS 128 will not
have a material impact on the Company's financial position or results of
operations.
7. COMPETITION AND RESTRUCTURING
For information regarding competition and restructuring, see
Management's Discussion and Analysis of Financial Condition and Results
of Operations-Competition and Restructuring.
8. RECLASSIFICATION
Certain line items on the prior year's financial statement have been
reclassified for consistent presentation with the current year.
The Consolidated Financial Statements are unaudited
and, in the opinion of the Company, reflect the
adjustments necessary to a fair statement of the
results of the interim periods. All such
adjustments, except as specifically noted in the
Consolidated Financial Statements, are of a normal,
recurring nature.
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
SEPTEMBER 30, 1997
Part 1 -- ITEM 2
This section presents management's assessment of Green Mountain Power
Corporation's (the Company) financial condition and the principal
factors having an impact on the results of its operations. This
discussion should be read in conjunction with the consolidated financial
statements and notes thereto contained in this quarterly report. This
section contains forward-looking statements as defined under the
securities laws. Actual results could differ materially from those
projected. This section, particularly under "Competition and
Restructuring" and "Risk Factors," lists some of the reasons why results
could differ materially from those projected.
RESULTS OF OPERATIONS
Earnings Summary
Earnings per share of common stock in the third quarter of 1997 were
$0.59 compared to $0.67 per share in the third quarter of 1996.
Earnings for electric operations were $0.60 per share in the third
quarter of 1997, $0.01 per share lower than the same period in 1996.
Earnings for unregulated operations were $0.07 per share lower than the
same quarter of 1996.
Earnings for electric operations were lower because of higher power
supply costs caused primarily by nuclear plant outages in New England.
Earnings were further reduced by dividends associated with the issuance
of additional preferred stock in October 1996 and higher taxes. These
decreases were substantially offset by the recognition in earnings
pursuant to an accounting order of the Vermont Public Service Board
(VPSB) of $2.4 million related to an $8 million payment expected to be
received under a Memorandum of Understanding entered into with Hydro-
Quebec.
Earnings for unregulated operations were lower primarily due to lower
earnings by two of the Company's wholly-owned subsidiaries. Mountain
Energy, Inc., the Company's subsidiary that invests in energy generation
and efficiency projects, earned $250,000 less in the third quarter of
1997 than during the same period of 1996 due to an anticipated decline
in rates for power sold by one of its wind facilities in California.
Green Mountain Resources Inc.'s (GMRI) loss in the third quarter of 1997
was $130,000 greater than during the same period of 1996 due to the
development costs of its investment in Green Mountain Energy Resources
L.L.C. (GMER) the retail energy company in which the Company sold a
majority interest to the Sam Wyly Family during the third quarter of
1997.
Operating Revenues and MWh Sales
Operating revenues, megawatthour (MWh) sales and average number of
customers are summarized as follows:
Three Months Ended Nine Months Ended
September 30 September 30
------------------- -------------------
1997 1996 1997 1996
---- ---- ---- ----
Operating Revenues
(In thousands)
Retail . . . . . . $ 38,679 $ 38,239 $ 117,729 $ 114,367
Sales for Resale . 4,335 5,025 13,719 16,262
Other . . . . . . 560 1,159 2,012 2,675
--------- --------- --------- ---------
Total Operating
Revenues . . . . $ 43,574 $ 44,423 $ 133,460 $ 133,304
========= ========= ========= =========
MWh Sales
Retail . . . . . . 438,240 431,630 1,337,309 1,319,767
Sales for Resale . 142,339 158,846 460,920 562,677
------- -------- --------- ---------
Total MWh Sales . 580,579 590,476 1,798,229 1,882,444
======= ======== ========= =========
Average Number of Customers
Residential . . . 70,692 70,226 70,612 70,133
Commercial &
Industrial . . . 12,018 11,872 11,991 11,835
Other . . . . . . . 75 77 76 76
------ ------ ------ ------
Total Customers . . 82,785 82,175 82,679 82,044
====== ====== ====== ======
Total operating revenues in the third quarter of 1997 decreased 1.9
percent compared to the same period in 1996. Retail revenues increased
1.2 percent in the third quarter of 1997 over the same period in 1996
primarily due to a 2.2 percent increase in sales of electricity to the
Company's commercial and industrial customers resulting from modest
customer growth. Wholesale revenues decreased 13.7 percent in the third
quarter of 1997 compared to the same period in 1996 primarily due to a
reduction in low-margin, off-system sales, which had a minimal impact on
earnings. Other operating revenues decreased 51.7 percent in the third
quarter of 1997 compared to the same period in 1996 primarily due to a
one-time adjustment in 1996 to account for higher tariff charges under
an interconnection agreement between Central Vermont Public Service
Corporation (CVPS) and the Company. This decrease was offset to a large
extent by a decrease in transmission expenses related to the same one-
time adjustment.
For the nine months ended September 30, 1997, total operating revenues
were virtually unchanged compared to the same period in 1996. Retail
revenues increased 2.9 percent over the same period in 1996 due
primarily to a 5.25 percent retail rate increase that went into effect
in June 1996 and an increase in sales to IBM. This increase in retail
sales was partially offset by a reduction in sales of electricity to the
Company's residential customers caused by winter temperatures in the
first quarter of 1997 that were substantially warmer than normal.
Wholesale revenues decreased 15.7 percent compared to the same period in
1996 primarily due to a reduction in low-margin, off-system sales, which
had a minimal impact on earnings. Other operating revenues decreased
24.8 percent compared to the same period in 1996 primarily due to a one-
time adjustment in 1996 resulting from higher tariff charges under an
interconnection agreement between CVPS and the Company. This decrease
was offset to a large extent by a decrease in transmission expenses
related to the same one-time adjustment.
Operating Expenses
Power supply expenses decreased 4.1 percent in the third quarter of 1997
compared to the same period in 1996 primarily due to a reduction in the
cost of power purchased from others reflecting the recognition in the
third quarter of 1997 of $2.4 million, consistent with allowed
ratemaking treatment under a VPSB accounting order related to a payment
of $8 million expected to be received under a Memorandum of
Understanding entered into with Hydro-Quebec in 1996. (The remaining
$2.4 million is expected to be recognized in income in the fourth
quarter of 1997.) This decrease was partially offset by an increase in
Company-owned generation expense resulting from the increased usage of a
Company-owned plant necessitated by the outage of certain nuclear power
plants in the region and an increase in power supply expenses from
Vermont Yankee.
Power supply expenses decreased 1.2 percent for the nine months ended
September 30, 1997 compared to the same period in 1996 due to
recognition of $5.6 million to date under the said Memorandum of
Understanding entered into with Hydro-Quebec.
Transmission expenses decreased 20.2 percent in the third quarter of
1997 compared to the same period in 1996 primarily due to higher tariff
charges under an interconnection agreement between CVPS and the Company
in 1996 resulting in a one-time adjustment. This decrease was offset to
a large extent by a decrease in other operating revenues related to the
same one-time adjustment. Transmission expenses increased 1.4 percent
for the nine months ended September 30, 1997 over the same period in
1996 primarily due to higher tariffs under a new operating agreement
with New England Power Company.
Other operating expenses were virtually unchanged in the third quarter
of 1997 compared to the same period in 1996. Other operating expenses
decreased 10.0 percent for the nine months ended September 30, 1997
compared to the same period in 1996 primarily due to an increase in work
performed on behalf of GMRI, effectively reducing payroll expenses for
the Company. Additionally, the organizational changes attributable to
the creation of GMER resulted in fewer employees for the Company causing
a reduction in payroll expenses.
Depreciation and amortization expenses decreased 3.9 percent in the
third quarter of 1997 compared to the same period in 1996 as some of the
Company's older demand side management programs have become fully
amortized resulting in lower amortization expenses in 1997. Depreciation
and amortization expenses increased 2.5 percent for the nine months
ended September 30, 1997 over the same period in 1996 primarily due to
depreciation associated with additional investment in the Company's
utility plant.
Taxes other than income taxes increased 16.5 percent in the third
quarter of 1997 over the same period in 1996 primarily due to higher
municipal property taxes associated with the newly constructed wind
generating facility in Searsburg, Vermont that went into commercial
operation in June 1997. Taxes other than income taxes increased 9.8
percent for the nine months ended September 30, 1997 over the same
period in 1996 for the same reason. In June 1997, the Governor signed
legislation that changed the method of municipal property taxation in
Vermont. The legislation has resulted in a statewide uniform property
tax rate but provides localities the flexibility to levy local taxes.
Currently, Vermont municipalities are evaluating the impact of this
legislation on future tax assessments. The Company is unable to predict
at this time whether this legislation will have a material impact on the
Company's operations.
Income Taxes
Income taxes were higher in the third quarter of 1997 compared to the
same period in 1996 primarily due to an increase in taxable income for
the Company's core operations. Income taxes were higher for the nine
months ended September 30, 1997 compared to the same period in 1996 for
the same reason. In June 1997, the Vermont corporate income tax rate
increased from 8.25 percent to 9.75 percent, retroactive to January 1,
1997, as part of a broad package of tax legislation related to statewide
property tax and education finance reform. As a result of this
increase, the Company will pay approximately $732,000 in additional
income taxes in future periods based on the deferred tax assets and
liabilities as of September 30, 1997. Management expects to seek and
receive ratemaking treatment in order to collect these amounts from
ratepayers.
Other Income
Other income decreased 16.3 percent in the third quarter of 1997
compared to the same period in 1996 primarily due to a $250,000 decrease
in earnings experienced by Mountain Energy, Inc., the Company's wholly-
owned subsidiary that invests in energy generation and efficiency
projects and a loss of $130,000 greater than during the same period of
1996 due to development costs associated with the investment by the
Company's subsidiary, GMRI, in GMER, the retail energy company in which
the Company sold a majority interest to the Sam Wyly Family during the
third quarter of 1997. These decreases were partially offset by an
increase in interest income resulting from the accrual of interest
related to an $8.0 million payment expected to be received from Hydro-
Quebec later this year (See the discussion in "Operating Expenses"
above) and an increase in the allowance for equity funds used during
construction resulting from higher average construction work in progress
balances during the period. Other income decreased 40.2 percent for the
nine months ended September 30, 1997 primarily due to a loss that was
$1.6 million greater than the loss experienced in 1996 by GMRI resulting
from the development costs associated with its investment in GMER
discussed above. Additionally, a $416,000 decrease in earnings
experienced by Mountain Energy, Inc. was due to an anticipated decline
in rates for power sold by one of its wind facilities in California.
These decreases were partially offset by an increase in the allowance
for equity funds used during construction and an increase in interest
income resulting for the same reasons discussed above.
Interest Charges
Interest charges increased 4.5 percent in the third quarter of 1997 over
the same period in 1996 primarily due to an increase in long-term
interest charges related to the sale of $10 million and $4 million of
the Company's first mortgage bonds in November and December 1996,
respectively. This increase was partially offset by a decrease in
interest charges related to a lower amount of short-term debt
outstanding during the period. Interest charges decreased 0.7 percent
for the nine months ended September 30, 1997 compared to the same period
in 1996 primarily due to a reduction in interest charges related to a
lower amount of short-term debt outstanding during the period. This
decrease was offset to a large extent by an increase in long-term
interest charges related to the sale of $10 million and $4 million of
the Company's first mortgage bonds in November and December 1996,
respectively.
LIQUIDITY AND CAPITAL RESOURCES
Dividends on preferred stock increased 118.7 percent in the third
quarter of 1997 over the same period in 1996 due to the issuance in
October 1996 of $12 million of the Company's 7.32 percent Class E,
Series 1, preferred stock. Dividends on preferred stock increased 103.7
percent for the nine months ended September 30, 1997 over the same
period in 1996 for the same reason.
For the nine months ended September 30, 1997, construction and
conservation expenditures totaled $17.0 million. Such expenditures in
1997 are expected to be approximately $24.6 million, principally for
expansion and improvements of the Company's transmission and
distribution plant, for the Company's wind turbine generation project,
for conservation measures, and for management information systems.
At September 30, 1997, the Company had lines of credit with two banks
totaling $8.0 million, with borrowings outstanding of $3.6 million.
Borrowings under these lines of credit are at interest rates based on
various market rates and are generally less than the prime rate. The
Company has fee arrangements on its lines of credit ranging from 0 to
1/8 percent and no compensating balance requirements. These lines of
credit are subject to periodic review and renewal during the year by the
various banks. On August 12, 1997, the Company entered into a revolving
credit agreement in the amount of $45 million with three banks, which
replaces a portion of its lines of credit. The agreement is subject in
part to regulatory approval, which the Company expects to receive. At
September 30, 1997, borrowings outstanding under this revolving credit
agreement were $10.4 million.
Dividend Policy - On September 17, 1997, the Company's Board of
Directors announced a reduction in the quarterly dividend from $0.53 per
share to $0.275 per share on the Company's common stock.
Historically, the Company has based its dividend policy on the continued
validity of three assumptions: The ability to achieve earnings growth,
the receipt of an allowed rate of return that accurately reflects the
Company's cost of capital, and the retention of its exclusive franchise.
In light of this dividend policy, the lack of earnings growth over the
last four years and the likelihood of lower earnings in 1997 and 1998
caused the Board to conclude that a reduction was necessary.
The Company's common stock dividend payout has ranged from 94 to 96
percent of earnings over the past four years. The Company's revised
dividend policy, which incorporates a target payout ratio of 60 to 70
percent, reflects the greater risks facing the Company as a result of
the changing environment for the electric utility industry. This policy
establishes a target payout that is in line with industry trends and is
comparable to that of other similar companies in the utility industry.
The resulting higher level of retained earnings will enhance the
Company's ability to pursue growth opportunities.
COMPETITION AND RESTRUCTURING
The electric utility business is being subjected to rapidly increasing
competitive pressures stemming from a combination of trends, including
the presence of surplus generating capacity, a disparity in electric
rates among and within various regions of the country, improvements in
generation efficiency, increasing demand for customer choice, and new
regulations and legislation intended to foster competition. To date,
this competition has been most prominent in the bulk power market, in
which non-utility generators have significantly increased their market
share.
Electric utilities historically have had exclusive franchises for the
retail sale of electricity in specified service territories. As a
result, competition for retail customers has been limited to: (i)
competition with alternative fuel suppliers, primarily for heating and
cooling; (ii) competition with customer-owned generation; and (iii)
direct competition among electric utilities to attract major new
facilities to their service territories. These competitive pressures
have led the Company and other utilities to offer, from time to time,
special discounts or service packages to certain large customers.
In states across the country, including the New England states, there
has been an increasing number of proposals to allow retail customers to
choose their electricity suppliers, with incumbent utilities required to
deliver that electricity over their transmission and distribution
systems (also known as "retail wheeling"). Increased competitive
pressure in the electric utility industry may restrict the Company's
ability to charge prices high enough to recover embedded costs, such as
the cost of purchased power obligations or of generation facilities
owned by the Company. The amount by which such costs might exceed
market prices is commonly referred to as "stranded costs".
Regulatory and legislative authorities at the federal level and among
states across the country, including Vermont, are considering how to
facilitate competition for electricity sales at the wholesale and retail
levels. For a discussion of restructuring proceedings in Vermont, refer
to the Company's Annual Report on Form 10-K for the year ended December
31, 1996 - "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Future Outlook".
In response to a Vermont Department of Public Service (the Department)
petition, the VPSB opened a proceeding on utility industry restructuring
by order dated October 17, 1995. On December 29, 1995, the Company
released its proposed restructuring plan, calling for corporate
separation into a regulated company for transmission and distribution
functions and an unregulated company for generation and sales functions.
On October 16, 1996, the VPSB issued a Draft Report and Order which
proposed the commencement of competitive retail sales of electricity in
early 1998, while distribution and transmission functions would remain
subject to regulation. The Company and other parties responded to the
Draft Report and Order in November 1996, and the VPSB issued its Final
Report on December 31, 1996.
The Final Report requires that Vermont investor-owned utilities divide
their competitive retail and regulated distribution and transmission
functions into separate corporate subsidiaries in order to achieve a
functional separation of regulated and unregulated businesses, and
provides for competition for all customer classes to be completed by the
end of 1998. In view of this change in structure as well as the unknown
relative level of competition each corporation may face, the Company
cannot predict the future cost or availability of capital for the new
subsidiary corporations. Furthermore, most of the assets of the Company
are encumbered by a lien of the Company's First Mortgage Indenture. The
Company cannot predict with certainty at this time the cost and
feasibility of obtaining approval from the existing bondholders, to the
extent that it is determined that such approvals are necessary, in order
to achieve functional separation.
The Final Report proposes an approach that takes into account multiple
factors that the VPSB believes will "create the opportunity for full
recovery of stranded costs provided they are legitimate, verifiable,
otherwise recoverable, prudently incurred and non-mitigable," but the
Final Report also states the VPSB's belief that "an opportunity for full
recovery must be explicitly tied to successful mitigation." The Final
Report further provides that, where a utility has successfully mitigated
its stranded costs, the opportunity should exist for substantial or full
recovery of stranded costs when the magnitude of the post-mitigation
stranded costs, among other things, allows for rates that are comparable
to regional rates.
The Final Report proposes that allowed stranded cost recovery be
accomplished through the use of a non-bypassable access charge, or
Competitive Transition Charge (CTC), collected by the regulated
distribution company. The Final Report also endorses the securitization
of stranded costs through the assignment of CTC receipts as a means of
achieving lower-cost financing and the Final Report supports legislative
action to achieve these savings.
In early April 1997, the Vermont Senate passed Senate Bill No. 62 (S.
62), an electric utility restructuring bill, which requires passage by
the Vermont House of Representatives and signature by the Governor
before becoming law. This bill was opposed by the Company and other
utilities in Vermont in the legislative session that ended in June 1997.
S.62 establishes several goals, including the conflicting objectives
that stranded costs be shared equally between utilities and customers
and that the continuing financial integrity of the utility be preserved.
Under S. 62, full retail competition in Vermont would have started in
October 1998 and the VPSB was given considerable discretion to weigh
various potentially conflicting objectives, including the two objectives
set forth above, in deciding the extent to which and manner under which
a utility can recover stranded costs. S. 62 also provides: (1) that
utilities must either divest unregulated enterprises or "functionally
separate" them from regulated business activities; (2) an incentive for
the early closing and decommissioning of the Vermont Yankee nuclear
power plant; (3) that any retail electricity provider in Vermont shall
have "ownership" of sufficient tradable renewable energy credits as
defined in S. 62; (4) that the VPSB may order performance-based
regulation for distribution functions if it finds that departure from
cost-of-service regulation is in the public interest; (5) for the
provision of out placement service and severance pay for utility
employees adversely affected by restructuring, with such costs shared
equally by the utility and its customers; and (6) that if a utility has
received some above-market cost recovery and then the utility is
acquired, the VPSB is to determine how much, if at all, the value of the
acquired company was enhanced by the recovery of above-market costs and
thereafter determine how the enhanced value should be shared equitably
between the acquired utility's shareholders and customers.
The Company has strenuously opposed the enactment of S.62 into law
principally because its stranded cost sharing provisions would
jeopardize the Company's financial viability. Under Statement of
Financial Accounting Standards (SFAS) 101, Accounting for the
Discontinuation of Application of FASB Statement No. 71, the Company
would then be required to write off a material amount of its regulatory
assets, and the resulting losses would limit the Company's access to
capital.
In mid-April 1997, the Vermont House of Representatives indicated
through its Speaker that there was insufficient time in the legislative
session (which ended in June 1997) to act upon a utility restructuring
bill. S.62 was not considered by the Vermont House of Representatives
in the last legislative session and, accordingly, has not been enacted.
On July 28, 1997, the Speaker of the House named an eleven member non-
standing committee to consider reform of the Vermont Electric Utility
Regulatory System. In mid-October 1997, the Chair of the Committee,
following a vote of the members, reported that the Committee did not
recommend that the Vermont Legislature consider legislation to allow
customer choice at this time.
There is no assurance that any restructuring legislation will be enacted
by the Vermont General Assembly in its next session that begins in
January 1998 or, if legislation is enacted, that it will be consistent
with the terms of the Final Report. The Company has stated its position
that if legislation is enacted that threatens the Company's financial
integrity, it will pursue all remedies available to it under law.
Risk Factors -- The major risk factors affecting the impact of electric
industry restructuring upon the Company, including the recovery of
stranded costs, are: (i) regulatory and legal decisions; (ii) the market
price of power; and (iii) the amount of market share retained by the
Company. There can be no assurance that a final restructuring plan
ordered by the VPSB, the courts, or through legislation will include a
CTC that would allow for full recovery of stranded costs and include a
fair return on those costs as they are being recovered. If laws are
enacted or regulatory decisions are made that do not offer an
opportunity to adequately recover stranded costs, the Company believes
it has substantial legal arguments to challenge such laws or decisions.
The largest category of the Company's stranded costs are future costs
under long-term power purchase contracts. The Company intends to pursue
compliance with the steps outlined in the Final Report and aggressively
to pursue mitigation efforts in order to maximize its recovery of these
costs. The magnitude of stranded costs for the Company is largely
dependent upon the future market price of power. The Company has
discussed various market price scenarios with interested parties for the
purpose of identifying stranded costs. Preliminary market price
assumptions, which are likely to change, have resulted in estimates of
the Company's stranded costs of between $259 million and $866 million,
on an undiscounted basis.
If retail competition is implemented in Vermont and elsewhere, the
Company is unable to predict the impact of this competition on its
revenues, on the Company's ability to retain existing customers and
attract new customers, or on 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 71 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 A.2 in the Notes to Consolidated Financial
Statements for the year ending December 31, 1996, the Company meets the
criteria for the application of SFAS 71. In the event the Company
determines that it no longer meets those criteria, the accounting impact
would be an extraordinary, non-cash charge to operations of an amount
that could be material. Factors that could give rise to the
discontinuance of SFAS 71 include (1) increasing competition that
restricts the Company's ability to establish prices to recover specific
costs and (2) a change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation.
The Company believes that the provisions of the Final Report, if
implemented, would meet the criteria for continuing application of SFAS
71 as to those costs for which recovery is permitted. S.62, however,
would not meet the criteria for the continuing application of SFAS 71.
Under SFAS 5, Accounting for Contingencies, the passage of S.62 or other
restructuring legislation or order, would also require the Company to
immediately estimate and record losses, on an undiscounted basis, for
any discretionary above market power purchase contracts and other costs
which are not probable of recovery from customers, to the extent that
those costs are estimable. Because the Company is unable to predict what
form enacted legislation will take, however, it cannot predict if or to
what extent SFAS 71 will continue to be applicable in the future.
Members of the staff of the Securities and Exchange Commission have
raised questions concerning the continued applicability of SFAS 71 to
certain other electric utilities facing restructuring. The Emerging
Issues Task Force (EITF) reviewed accounting issues associated with
electric utility restructuring. On May 22, 1997, the EITF indicated
that write-offs of generation-related regulatory assets would not be
required to the extent that such assets are being recovered via a non-
bypassable charge arising from a levy on regulated products or services
provided by the utility.
On July 24, 1997, the EITF indicated that utilities should immediately
discontinue application of the SFAS 71 for those business segments which
will become unregulated, if the utility has a final plan in place for
transition to competition. To the extent that the discontinued segment
has assets secured in arrangements defined in the May 1997, EITF
statement, those assets would continue to be accounted for under SFAS
71.
The Company cannot predict whether restructuring legislation enacted by
the Vermont General Assembly or any subsequent report or actions of, or
proceedings before, the VPSB or Vermont General Assembly would have a
material adverse effect on the Company's operations, financial condition
or credit ratings. The Company's failure to recover a significant
portion of its purchased power costs, or to retain and attract customers
in a competitive environment, would have a material adverse effect on
the Company's business, including its operating results, cash flows and
ability to pay dividends at current levels.
Recent Developments
Green Mountain Resources, Inc.
On August 6, 1997, the Company and the Sam Wyly Family announced that
their affiliates will jointly own Green Mountain Energy Resources L.L.C.,
a Delaware limited liability company in which GMRI, a wholly-owned
subsidiary of the Company, was the sole owner. GMER is competing in the
emerging consumer retail energy market starting in California where
customers are able to choose their electricity supplier as of November
1, 1997. GMER intends to create a retail brand of electricity and
natural gas that will be sold to consumers who care about the
environment in competitive markets across the nation. An affiliate of
the Sam Wyly Family, Green Funding I, L.L.C. (the "Investor") has
entered into an Operating Agreement with GMRI governing the ownership of
GMER. Pursuant to the terms of the Operating Agreement, the Investor
has agreed to invest up to $30 million in GMER in exchange for an equity
interest of 67 percent while GMRI has contributed certain assets and
business development concepts in exchange for an equity interest of 33
percent in GMER. These ownership interests may be reduced to 55.47
percent and 25.67 percent, respectively, if GMER warrants and options
issued to GMER management and consultants are exercised. GMRI's
ownership percentage of GMER will be further diluted if the Investor
and/or third parties contribute additional capital to GMER and GMRI does
not make pro rata additional capital contributions at such time. GMRI
received payment of $4 million from GMER at the closing as reimbursement
for certain development expenses incurred. Pursuant to the terms of the
Operating Agreement, funds provided by the Investor will be used to pay
future GMER development expenses and operating costs. GMRI is not
obligated to fund future development costs, and the Operating Agreement
provides that GMRI will not be allocated operating losses from GMER,
thus limiting the Company's shareholders' future financial risk while
preserving their opportunity to participate in the success of GMER. In
addition, the Company and the Investor have agreed that neither the
Company nor the Investor will compete against GMER in the retail energy
business for a period of seven years.
1997 Retail Rate Case
On June 16, 1997, the Company filed a request with the VPSB to increase
retail rates by 16.7 percent ($26 million in additional revenues) and
the target return on common equity from 11.25 percent to 13 percent.
Initial hearings before the VPSB began November 3, 1997. The VPSB has
allowed the intervention of various other parties.
In August 1997, several groups, including the Vermont Public Interest
Research Group (VPIRG), demanded that the VPSB appoint an independent
counsel to advocate against recovery of Hydro-Quebec power costs by the
Company. The VPSB issued an order appointing an "independent
investigator," described as a person or persons who will perform a
rigorous and impartial analysis of Company's actions with respect to its
power supply options, including the Hydro-Quebec contract. On November
7, 1997, the VPSB selected a firm to undertake the tasks.
In October 1997, a Hearing Officer in the case recommended "bifurcation"
of the Hydro-Quebec power contract issues from the case, indicating his
position that there was not enough time to review adequately the issues
in the remaining five months of the statutory period (seven months from
date of filing under Vermont law). The Company has opposed bifurcation
on the basis that if the Hearing Officer meant to suggest that the
Company would not receive rate relief, including these power costs as of
March 1998, the concept would give rise to numerous, difficult legal
questions. The VPSB accepted extensive briefing on the issue but has
not indicated when, if at all, it will act on any proposal relating to
bifurcation.
In testimony filed with the VPSB on October 17, 1997, the Department
asked the VPSB to find the Company's negotiation, execution and decision
to "lock in" the contract with Hydro-Quebec to be imprudent and
uneconomic. The Department had supported the contract in the period
1989-1991 after completing its own analysis, based on substantially the
same information that was available to the Company. The VPSB in 1990,
1991, 1992 and 1994 issued orders that determined the contract to be
needed to supply electricity to Vermont customers, economically
beneficial to the State and an appropriate part of the Company's
legally-required least-cost integrated resource plan.
On October 31, 1997, the Company filed with the VPSB Objections and a
Motion to Strike relating to the Hydro Quebec contract testimony and
requested that the Board schedule oral argument on the motion prior to
November 17, 1997. The Board has scheduled argument for November 14,
1997.
Management Changes
Douglas G. Hyde, a director, President and Chief Executive Officer of
the Company, resigned those positions with the Company effective August
6, 1997 in order to become the President and Chief Executive Officer of
GMER. Thomas C. Boucher, Vice President, Energy Resources and Planning;
Kevin W. Hartley, Vice President, Marketing; Karen K. O'Neill, Vice
President Organizational Development; and Peter H. Zamore, General
Counsel of the Company, resigned those offices in order to join Mr. Hyde
as members of the GMER management team.
The Company's Board of Directors elected Christopher L. Dutton as
President and Chief Executive Officer and a director of the Company
effective August 6, 1997. Mr. Dutton has served as Chief Financial
Officer of the Company since 1995. He joined the Company in 1984 and
served as Vice President and General Counsel before being named Chief
Financial Officer of the Company.
On October 6,1997, the Company's Board of Directors elected the
following officers: Richard B. Hieber, Senior Vice President and Chief
Operating Officer; Michael H. Lipson, General Counsel; Edwin M. Norse,
Vice President and Chief Financial Officer and Treasurer; and Stephen C.
Terry, Senior Vice President, Corporate Development. Jonathan H. Winer
will continue to serve as President of the Company's subsidiary,
Mountain Energy, Inc. and will assume new responsibilities as part of
the Company's senior management.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Not Applicable.
GREEN MOUNTAIN POWER CORPORATION
September 30, 1997
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings
See Notes 3, 4 and 5 of Notes to Consolidated Financial
Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
NONE.
ITEM 5. Other Information
NONE
ITEM 6. (a) EXHIBITS
27 Financial Data Schedule
(b) REPORTS ON FORM 8-K
The Company filed a Form 8-K on September
9, 1997, announcing a dividend reduction.
GREEN MOUNTAIN POWER CORPORATION
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.
GREEN MOUNTAIN POWER CORPORATION
(Registrant)
Date: November 13, 1997 /s/ E. M. Norse
E. M. Norse, Vice President, Chief
Financial Officer and Treasurer
Date: November 13, 1997 /s/ R. J. Griffin
R. J. Griffin, Controller
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This schedule contains summary financial information extracted from the
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to such financial statements.
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