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, 1996
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, 1996
$3.33 1/3 Par Value 4,977,978
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1 - Item 1
<CAPTION>
September 30 December 31
----------------------------------- ----------------
1996 1995 1995
---------------- ---------------- ----------------
(In thousands) (In thousands)
ASSETS
ELECTRIC UTILITY
<S> <C> <C> <C>
Utility Plant
Utility plant, at original cost.................... $247,067 $234,597 $239,291
Less accumulated depreciation...................... 81,050 74,542 75,797
---------------- ---------------- ----------------
Net utility plant................................ 166,017 160,055 163,494
Property under capital lease....................... 9,778 10,278 9,778
Construction work in progress...................... 11,536 8,658 8,727
---------------- ---------------- ----------------
Total utility plant, net......................... 187,331 178,991 181,999
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity (Note 2)........... 15,862 16,216 16,024
Other investments.................................. 4,760 4,078 4,224
---------------- ---------------- ----------------
Total other investments.......................... 20,622 20,294 20,248
---------------- ---------------- ----------------
Current Assets
Cash............................................... 71 60 84
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 13,326 16,387 18,081
Accrued utility revenues (Note 1).................. 5,264 4,651 6,523
Fuel, materials and supplies, at average cost...... 3,474 3,599 3,312
Prepayments........................................ 1,257 1,418 1,890
Other.............................................. 1,405 249 326
---------------- ---------------- ----------------
Total current assets............................. 24,797 26,364 30,216
---------------- ---------------- ----------------
Deferred Charges
Demand side management programs.................... 14,830 15,731 18,367
Environmental proceedings costs.................... 8,286 7,747 7,893
Purchased power costs.............................. 9,095 1,682 8,433
Other.............................................. 11,532 11,482 8,258
---------------- ---------------- ----------------
Total deferred charges........................... 43,743 36,642 42,951
---------------- ---------------- ----------------
NON-UTILITY
Cash and cash equivalents.......................... 348 1,977 76
Other current assets............................... 3,242 2,358 4,055
Property and equipment............................. 11,198 11,354 11,478
Intangible assets.................................. 2,631 2,735 2,580
Equity investment in energy related businesses..... 13,957 9,963 10,999
Other assets....................................... 7,698 8,235 8,680
---------------- ---------------- ----------------
Total non-utility assets......................... 39,074 36,622 37,868
---------------- ---------------- ----------------
Total Assets........................................... $315,567 $298,913 $313,282
================ ================ ================
CAPITALIZATION AND LIABILITIES
ELECTRIC UTILITY
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
4,993,834, 4,808,571 and 4,850,496)........... $16,646 $16,028 $16,168
Additional paid-in capital....................... 67,363 63,204 64,206
Retained earnings................................ 26,640 25,937 26,412
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 110,271 104,791 106,408
Redeemable cumulative preferred stock.............. 7,530 9,135 8,930
Long-term debt, less current maturities............ 80,900 67,134 91,134
---------------- ---------------- ----------------
Total capitalization........................... 198,701 181,060 206,472
---------------- ---------------- ----------------
Capital lease obligation............................... 9,778 10,278 9,778
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 3,034 7,833 7,833
Short-term debt.................................... 23,416 23,016 8,416
Accounts payable, trade, and accrued liabilities... 2,956 4,669 5,529
Accounts payable to associated companies........... 8,380 4,537 7,011
Dividends declared................................. 160 198 194
Customer deposits.................................. 573 694 816
Taxes accrued...................................... 1,620 1,180 571
Interest accrued................................... 1,817 1,657 1,847
Other.............................................. 312 937 412
---------------- ---------------- ----------------
Total current liabilities...................... 42,268 44,721 32,629
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 24,869 23,218 25,292
Unamortized investment tax credits................. 4,914 5,185 5,107
Other.............................................. 23,202 22,242 21,642
---------------- ---------------- ----------------
Total deferred credits......................... 52,985 50,645 52,041
---------------- ---------------- ----------------
NON-UTILITY
Current liabilities................................ 978 896 1,124
Other liabilities.................................. 10,857 11,313 11,238
---------------- ---------------- ----------------
Total non-utility liabilities.................. 11,835 12,209 12,362
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $315,567 $298,913 $313,282
================ ================ ================
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
------------------------------- -------------------------------
1996 1995 1996 1995
------------ ------------ ------------ ------------
(In thousands, except amounts per share)
<S> <C> <C>
Operating Revenues (Note 1)................................... $44,423 $39,781 $133,304 $116,931
------------ ------------ ------------ ------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation................. 7,680 7,263 23,184 22,065
Company-owned generation................................. 985 1,297 2,557 3,328
Purchases from others.................................... 15,020 12,548 48,898 36,850
Other operating............................................. 4,313 4,323 13,959 13,596
Transmission................................................ 3,136 2,528 8,350 7,440
Maintenance................................................. 1,106 1,074 3,492 3,158
Depreciation and amortization............................... 4,179 3,848 12,102 10,257
Taxes other than income..................................... 1,644 1,609 5,030 4,844
Income taxes................................................ 1,941 1,465 4,380 4,315
------------ ------------ ------------ ------------
Total operating expenses................................. 40,004 35,955 121,952 105,853
------------ ------------ ------------ ------------
Operating Income....................................... 4,419 3,826 11,352 11,078
------------ ------------ ------------ ------------
Other Income
Equity in earnings of affiliates and non-utility operations. 823 1,153 2,603 2,693
Allowance for equity funds used during construction......... 2 -- 92 27
Other income and deductions, net............................ 54 (2) 82 54
------------ ------------ ------------ ------------
Total other income........................................ 879 1,151 2,777 2,774
------------ ------------ ------------ ------------
Income before interest charges.......................... 5,298 4,977 14,129 13,852
------------ ------------ ------------ ------------
Interest Charges
Long-term debt.............................................. 1,614 1,580 5,125 4,924
Other....................................................... 324 414 776 1,065
Allowance for borrowed funds used during construction....... (114) (88) (335) (427)
------------ ------------ ------------ ------------
Total interest charges.................................... 1,824 1,906 5,566 5,562
------------ ------------ ------------ ------------
Net Income.................................................... 3,474 3,071 8,563 8,290
Dividends on preferred stock.................................. 159 194 539 582
------------ ------------ ------------ ------------
Net Income Applicable to Common Stock......................... $3,315 $2,877 $8,024 $7,708
============ ============ ============ ============
Common Stock Data
Earnings per share.......................................... $0.67 $0.60 $1.63 $1.63
Cash dividends declared per share........................... $0.53 $0.53 $1.59 $1.59
Weighted average shares outstanding......................... 4,959 4,771 4,910 4,724
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................. $25,950 $25,584 $26,412 $25,727
Net Income.................................................... 3,474 3,071 8,563 8,290
------------ ------------ ------------ ------------
29,424 28,655 34,975 34,017
------------ ------------ ------------ ------------
Cash Dividends - redeemable cumulative preferred stock........ 159 194 539 582
- common stock................................. 2,625 2,524 7,796 7,498
------------ ------------ ------------ ------------
2,784 2,718 8,335 8,080
------------ ------------ ------------ ------------
Balance - end of period....................................... $26,640 $25,937 $26,640 $25,937
============ ============ ============ ============
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
---------------------------------------
1996 1995
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income.................................................... $8,563 $8,290
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization............................. 12,102 10,257
Dividends from associated companies less equity income ... 162 468
Allowance for funds used during construction.............. (427) (453)
Amortization of purchased power costs..................... 4,068 4,328
Deferred income taxes..................................... (62) 1,546
Deferred revenues......................................... -- 303
Amortization of gain on sale of property.................. (40) (40)
Deferred purchased power costs............................ (5,761) (5,522)
Amortization of investment tax credits.................... (193) (205)
Environmental proceedings costs, net...................... (1,420) (837)
Changes in:
Accounts receivable..................................... 4,755 (1,147)
Accrued utility revenues................................ 1,259 1,361
Fuel, materials and supplies............................ (163) (285)
Prepayments and other current assets.................... 367 3,809
Accounts payable........................................ (1,204) (1,142)
Taxes accrued........................................... 1,049 (261)
Interest accrued........................................ (29) (296)
Other current liabilities............................... (523) (147)
Other..................................................... (779) 596
----------------- -----------------
Net cash provided by operating activities................... 21,724 20,623
----------------- -----------------
Investing Activities:
Construction expenditures................................... (11,946) (9,524)
Conservation expenditures................................... (2,049) (2,535)
Investment in nonutility property........................... (1,338) (4,287)
----------------- -----------------
Net cash used in investing activities..................... (15,333) (16,346)
----------------- -----------------
Financing Activities:
Issuance of common stock.................................... 3,635 3,262
Issuance of long-term debt.................................. -- 1,916
Short-term debt, net........................................ 15,000 2,802
Cash dividends.............................................. (8,335) (8,080)
Reduction in preferred stock................................ (1,400) --
Reduction in long-term debt................................. (15,033) (4,833)
----------------- -----------------
Net cash used in financing activities..................... (6,133) (4,933)
----------------- -----------------
Net increase (decrease) in cash and cash equivalents........ 258 (656)
Cash and cash equivalents at beginning of period............ 160 2,693
----------------- -----------------
Cash and Cash Equivalents at End of Period...................... $418 $2,037
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid year-to-date for:
Interest (net of amounts capitalized).................... $5,755 $6,180
Income taxes............................................. 3,534 2,949
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996
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, 1996 and 1995,
the Company had recorded deferred revenues of $550,000 and $700,000,
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
------------------ -----------------
1996 1995 1996 1995
---- ---- ---- ----
(In Thousands) (In Thousands)
Revenue . . . . . . . . $2,595 $2,938 $9,311 $8,562
Expenses . . . . . . . . 2,288 2,310 8,261 7,393
------ ------ ------ ------
Net Income . . . . . . . $ 307 $ 628 $1,050 $1,169
====== ====== ====== ======
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:
Three Months Ended Nine Months Ended
September 30 September 30
------------------ -----------------
(In Thousands)
1996 1995 1996 1995
---- ---- ---- ----
Vermont Yankee Nuclear Power Corporation
Gross Revenue . . . . . . $55,068 $38,350 $138,106 $136,768
Net Income Applicable
to Common Stock . . . . . 1,735 1,647 5,035 5,121
Company's Equity in Net
Income . . . . . . . . . 310 299 895 887
Vermont Electric Power Company, Inc.
Gross Revenue . . . . . . $12,722 $12,259 $ 37,134 $ 37,091
Net Income Before
Dividends . . . . . . . . 304 302 955 950
Company's Equity in Net
Income (Includes preferred
equity) . . . . . . . . . 86 91 295 283
3. ENVIRONMENTAL MATTERS
In 1982, the United States Environmental Protection Agency (EPA)
notified the Company that the EPA, pursuant to the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980
(CERCLA), was considering spending public funds in response to claimed
releases of allegedly hazardous substances at what since has become
known as the Pine Street Barge Canal Site (Site) in Burlington, Vermont.
A manufactured-gas facility was owned and operated on part of the Site
by several separate enterprises, including the Company, from the late
19th century to 1967. The EPA's notice stated that the Company may be a
"potentially responsible party" (PRP) under CERCLA from which
reimbursement of costs of investigation and corrective action may be
sought. On February 23, 1988, the Company received a Special Notice
letter from the EPA stating that the letter constituted a formal demand
for reimbursement of response costs, including interest thereon,
incurred and to be incurred at the Site.
On December 5, 1988, the EPA brought suit against the Company, New
England Electric System (NEES), and Vermont Gas Systems, Inc. (VGS) in
the United States District Court for the District of Vermont seeking
reimbursement for costs it incurred in conducting activities in 1985 to
remove allegedly hazardous substances from a portion of the Site, and
seeking a declaratory judgment concerning liability of the defendants
for all subsequent response costs associated with that area, known as
the Maltex Pond Area. The complaint alleged that the removal costs were
at least $741,000. The EPA also sought interest on this amount from the
date the funds were expended and costs of litigation, including
attorneys' fees. The Company entered certain cross-claims and third-
party claims. Fourth-party defendants also were joined. In July 1990,
without admission of liability, the Company and 13 other settling
defendants signed a proposed Consent Decree settling the removal action
litigation, paying collectively $945,000. Individual contributions were
confidential. On December 26, 1990, upon the unopposed motion of the
United States, the Consent Decree was entered by the Court.
During 1989, the EPA began a Remedial Investigation (RI) and Feasibility
Study (FS) relating to the Site. In late 1990 and in 1991, the EPA
conducted a second phase of RI work and studied the treatability of
soils and groundwater at the Site.
On November 6, 1992, the EPA released its final RI/FS reports and
announced a proposed remedy with an estimated total present value of
$47.0 million. This amount included 30 years' estimated operation and
maintenance costs, with a net present value of $26.4 million. The EPA's
proposed remedy called for construction of a large above-grade
Containment/Disposal Facility (CDF) that also would have consisted of
subsurface vertical barriers and a low permeability cap, with collection
trenches and a hydraulic control system to capture groundwater for
eventual treatment. The proposed remedy also included a long-term
monitoring program and construction of new wetlands.
The Company and other PRPs submitted extensive comments to the EPA
opposing the proposed remedy and, in response to an earlier request from
the EPA, a detailed analysis of an alternative remedy anticipated to
cost approximately $20 million. In June 1993, in response to
overwhelming negative comment, the EPA withdrew its proposed remedy and
announced that it would work with all interested parties in developing a
new proposal. The EPA then established a coordinating council, with
representatives of PRPs, environmental groups, and government agencies,
and presided over by a neutral facilitator. The council has reached
consensus on additional studies appropriate for the Site and is
beginning to address remedy selection.
In July 1994, the Company, NEES, and VGS entered into an Administrative
Order by Consent with the EPA, pursuant to which these PRPs conducted
certain additional studies agreed to by the coordinating council. A
second phase, including tasks carried over from the first phase,
additional field studies and preparation of an addendum feasibility
study, will be completed in early 1997 by the Company and NEES under a
second Order. The EPA did not require reimbursement for its past RI/FS
study costs as a condition to allowing the PRPs to conduct these
additional studies. The EPA has previously announced that ultimately it
will seek to hold the Company and other PRPs liable for such costs,
which have been estimated to be at least $4.5 million. The Company has
sufficient reserves on its balance sheet to cover such costs.
On December 1, 1994, (i) the Company, NEES and VGS entered into a
confidential agreement with the State, the City of Burlington and nearly
all other landowner PRPs under which the liability of those landowner
PRPs for future Superfund response costs would be limited and specified
and (ii) 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 contribution and
cost recovery claims of each party concerning the Site.
In December 1991, the Company brought suit against several previous
insurers seeking recovery of unrecovered past costs and indemnity
against future liabilities associated with environmental problems at the
Site. Discovery in the case is largely complete, with the exception of
expert discovery. Further discovery has been stayed by the court until
the revised RI/FS reports are finalized, the Company's liability is
finally determined or January 1, 1997, which ever comes first. In 1994,
the United States District Judge granted the Company's Motion for
Summary Judgment with respect to defense costs against one defendant and
denied it against another defendant. The Company has reached
confidential settlements with two of the other defendant insurers. One
settling defendant provided the Company with comprehensive general
liability insurance between 1976 and 1982 and with environmental
impairment liability insurance from 1981 to 1984. The other provided
the Company with second layer excess liability coverage for a seven-
month period in 1976.
The Company has deferred amounts received from third parties pending
resolution of the Company's ultimate liability with respect to the Site
and rate recognition of that liability. The Company is unable to
predict at this time the magnitude of any liability resulting from
potential claims concerning 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 and 1994, the Company has sought
and received recovery for ongoing expenses associated with the Site.
Specifically, the Company proposed rate recognition of its unrecovered
expenditures between January 1991 and June 30, 1994 (totaling
approximately $7.3 million) for technical consultants and legal
assistance in connection with the EPA's enforcement actions at the Site
and insurance litigation. While reserving the right to argue in the
future about the appropriateness of rate recovery for all Site-related
costs, the Company and the Vermont Department of Public Service (the
Department) and, in some instances, other parties in the rate
proceedings, reached agreements in these cases that the full amount of
Site costs reflected in those rate cases should be recovered in rates.
The Company's rates approved by the VPSB on April 2, 1992, on May 13,
1994 and on June 5, 1995 reflected the Site related expenditures
referred to above.
In a rate case filed on September 15, 1995, the Company sought recovery
in rates of approximately $1.3 million in expenses associated with the
Site. This amount represented the Company's unrecovered expenditures
between July 1994 and June 1995 for technical consultants and legal
assistance in connection with 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 all Site-related costs
(and whether recovery or non-recovery of past costs and any insurance
proceeds or proceeds from PRP's is relevant to such issue), the parties
to the case reached agreement that the full amount of Site costs
reflected in the Company's 1995 rate case should be recovered in rates.
This agreement was approved by the VPSB on May 23, 1996.
Management expects to seek and (assuming treatment 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.
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
site, and to cover higher costs of capital. Early in 1996, the Company
settled this rate case with the Department and other parties, enabling
the Company to conduct its business and achieve satisfactory financial
results without the drain on human resources and the additional costs
that rate increase litigation imposes.
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 provides: 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 electric operations
of 11.25 percent; and recovery of $1.3 million of costs associated with
the Pine Street site, amortized over five years. The VPSB approved the
settlement in an order dated May 23, 1996.
5. 1994 Retail Rate Case
On September 26, 1994, the Company filed a request with the VPSB to
increase retail rates by 13.9 percent. The increase was needed
primarily to cover the rising cost of existing power sources, the cost
of new power sources the Company has secured to replace power supply
that will be lost in the near future, and the cost of energy efficiency
programs the Company has implemented for its customers. The Company,
the Department and the other parties in the proceeding reached a
settlement agreement providing for a 9.25 percent retail rate increase
effective June 15, 1995, and a target return on equity for utility
operations of 11.25 percent. The agreement was approved by the VPSB on
June 9, 1995.
6. SFAS 121
Statement of Financial Accounting Standards (SFAS) 121, Accounting for
the Impairment of Long Lived Assets, which was implemented by the
Company on January 1, 1996, requires that any assets, including
regulatory assets, which are no longer probable of recovery through
future revenues, be revalued based upon future cash flows. SFAS 121
requires that a rate-regulated enterprise recognize an impairment loss
for the amount of costs excluded from recovery. As of September 30,
1996, based upon the regulatory environment within which the Company
currently operates, SFAS 121 did not have an impact on the Company's
financial position or results of operations. Competitive influences or
regulatory developments may impact this status in the future.
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 statements 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, 1996
Part 1 -- ITEM 2
RESULTS OF OPERATIONS
Earnings Summary
Earnings per share of common stock in the third quarter of 1996 were
$0.67 compared to $0.60 in the third quarter of 1995. The increase in
earnings was primarily due to a 5.25 percent retail rate increase that
went into effect in June 1996 and an increase in sales of electricity to
the Company's commercial and industrial customers.
For both the nine months ended September 30, 1996 and 1995, earnings per
share of common stock were $1.63.
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
------------------ ------------------
1996 1995 1996 1995
---- ---- ---- ----
Operating Revenues
(In thousands)
Retail . . . . . $ 38,239 $ 34,400 $ 114,367 $ 101,694
Sales for Resale . 5,025 4,762 16,262 12,780
Other . . . . . . . . 1,159 619 2,675 2,457
-------- -------- ---------- ----------
Total Operating
Revenues . . . $ 44,423 $ 39,781 $ 133,304 $ 116,931
======== ======== ========== ==========
MWh Sales
Retail . . . . . . . 431,630 418,522 1,319,767 1,277,465
Sales for Resale . 158,846 192,502 562,677 446,268
------- ------- --------- ---------
Total MWh Sales . 590,476 611,024 1,882,444 1,723,733
======= ======= ========= =========
Average Number of Customers
Residential . . . 70,226 69,710 70,133 69,572
Commercial &
Industrial . . . . 11,872 11,759 11,835 11,717
Other . . . . . . . 77 74 76 76
------ ------ ------ ------
Total Customers 82,175 81,543 82,044 81,365
====== ====== ====== ======
Total operating revenues in the third quarter of 1996 increased
11.7 percent over the same period in 1995. Retail revenues increased
11.2 percent in the third quarter of 1996 over the same period in 1995
primarily due to a 5.25 percent retail rate increase that went into
effect in June 1996 and a 3.8 percent increase in electricity sales to
the Company's commercial and industrial customers. Wholesale revenues
increased 5.5 percent in the third quarter of 1996 over the same period
in 1995 primarily due to regional market conditions that resulted in an
increase in the unit price of wholesale power.
For the nine months ended September 30, 1996, total operating revenues
increased 14.0 percent over the same period in 1995. For the first nine
months of 1996, retail revenues increased 12.5 percent over the same
period in 1995, primarily due to a 9.25 percent retail rate increase
that took effect in June 1995 and a 5.25 percent retail rate increase
that took effect in June 1996, as well as increased electricity sales in
the first quarter of 1996 caused by colder (but normal) winter weather
and modest growth in the business sector. For the nine months ended
September 30, 1996, wholesale revenues increased 27.3 percent over the
same period in 1995 primarily due to regional market conditions that
allowed the Company to buy electricity and resell it to other entities
at prices slightly higher than the purchase price.
Operating Expenses
Power supply expenses increased 12.2 percent in the third quarter of
1996 over the same period in 1995 primarily due to higher costs for
power purchased from Hydro-Quebec, an increase in power purchased from
independent power producers and costs associated with the scheduled
refueling outage at Vermont Yankee. Power costs for purchases from
Hydro-Quebec would have been higher in 1996 but for a reduction in those
charges negotiated early in 1996. (See Note 4 of Notes to Consolidated
Financial Statements). Power supply expenses increased
19.9 percent for the nine months ended September 30, 1996 over the same
period in 1995 for the same reasons.
In early November 1996, the Company entered into a Memorandum of
Understanding with Hydro-Quebec providing for the payment to the Company
of $8 million in 1997 in exchange for Hydro-Quebec's right to elect, on
or before September 1, 1997, one of two options to purchase power. Under
the first option, for the period commencing November 1, 1997 and
effective through the remaining term of the 1987 power supply agreement
between the Company and Hydro-Quebec (the 1987 Agreement), which expires in
2015, Hydro-Quebec can exercise an option to purchase on an annual basis,
at energy prices established in accordance with the 1987 Agreement, an
amount of energy equivalent to the Company's firm capacity entitlements in
the 1987 Agreement, delivered at up to an approximately 10.5% capacity
factor, or 105,000 MWH. Under the second option, for the period commencing
November 1, 1997 and effective through the remaining term of the 1987
Agreement, Hydro-Quebec can exercise an option to purchase on an annual
basis, at energy prices established in accordance with the 1987 Agreement,
an amount of energy equivalent to the Company's firm capacity
entitlements in the 1987 Agreement, delivered at up to an approximately
5.25% capacity factor, or 52,500 MWH. Hydro-Quebec also would have the
right under the second option to elect to purchase up to 600,000
megawatt hours of power from the Company over the remaining term of the
1987 Agreement, commencing November 1, 1997, at the energy prices
established in accordance with the 1987 Agreement, subject to certain
annual and hourly volume limitations.
The obligations of the parties under the Memorandum of Understanding
are subject to the following conditions: (1) approval by the Board of
Directors of Hydro-Quebec, (2) the receipt of all necessary regulatory
approvals, and (3) the receipt by the Company of an accounting order
of the VPSB on terms acceptable to the Company. It is anticipated that
the agreement refected in the Memorandum of Understanding, together
with an acceptable accounting order from the VPSB, will permit the
Company to avoid the filing of a rate increase application before the
VPSB providing rate relief effective in 1997. The Company estimates
that the future costs associated with the Memorandum of Understanding
to be approximately $8 million on a net present value basis.
Transmission expenses increased 24.0 percent in the third quarter of
1996 over the same period in 1995 primarily due to higher tariff rates
under an interconnection agreement between Central Vermont Public
Service and the Company. This increase was offset to a large extent by
revenues generated by the same interconnection agreement. Transmission
expenses increased 12.2 percent for the nine months ended September 30,
1996 over the same period in 1995 for the same reason.
Other operating expenses were virtually unchanged in the third quarter
of 1996 compared to the same period in 1995. Other operating expenses
increased 2.7 percent for the nine months ended September 30, 1996 over
the same period in 1995 primarily due to costs associated with the
Company's initiatives to improve quality and efficiency and to an
increase in the reserve for bad debts.
Maintenance expenses were virtually unchanged in the third quarter of
1996 compared to the same period in 1995. Maintenance expenses
increased 10.6 percent for the nine months ended September 30, 1996 over
the same period in 1995 primarily due to costs associated with increased
usage of certain generating facilities.
Depreciation and amortization expenses increased 8.6 percent in the
third quarter of 1996 over the same period in 1995 primarily due to the
amortization of expenditures related to energy conservation programs,
the Pine Street Barge Canal environmental matter and insurance
litigation and to additional investment in the Company's utility plant.
(See Note 3 of Notes to Consolidated Financial Statements.)
Depreciation and amortization expenses increased 18.0 percent for the
nine months ended September 30, 1996 over the same period in 1995 for
the same reasons.
Taxes other than income taxes were virtually unchanged in the third
quarter of 1996 compared to the same period in 1995. Taxes other than
income taxes increased 3.8 percent for the nine months ended September
30, 1996 over the same period in 1995 primarily due to an increase in
gross revenue taxes.
Income Taxes
Income taxes increased 32.5 percent in the third quarter of 1996 over
the same period in 1995 primarily due to an increase in taxable income.
Income taxes were virtually unchanged for the nine months ended
September 30, 1996 compared to the same period in 1995.
Other Income
Other income decreased 23.7 percent in the third quarter of 1996
compared to the same period in 1995 primarily due to a $282,000 loss
experienced by Green Mountain Resources, Inc.(GMRI), the Company's wholly
owned subsidiary that participates through Green Mountain Energy
Partners L.L.C.(GMEP) in various pilot programs providing retail
customer choice in the purchase of electricity. This loss was mitigated
to a large extent by offsetting payments received by the Company from
GMRI and GMEP for work performed on their behalf. Other income for the nine
months ended September 30, 1996 was virtually unchanged compared to the
same period in 1995.
Interest Charges
Interest charges decreased 4.3 percent in the third quarter of 1996
compared to the same period in 1995 primarily due to a decrease in
short-term interest charges resulting from a decrease in short-term debt
outstanding during the period. Interest charges for the nine months
ended September 30, 1996 were virtually unchanged compared to the same
period in 1995.
Agreement with IBM
In February 1995, the Company and IBM entered into an Economic
Development Agreement (EDA) that established the price to be paid by IBM
at its Essex Junction, Vermont, facility for incremental electric usage
during 1995, 1996 and, at IBM's option, 1997. The contract, which is
intended to promote growth in IBM's operations and create jobs in the
Company's service area, applies only to that portion of IBM's load that
exceeds its 1994 consumption level. Most of IBM's electric usage is
billed under the Company's tariff rate. The EDA price, although lower
than the Company's tariff rate, exceeds the Company's marginal costs of
providing this incremental electric service to IBM. The VPSB approved
the EDA in June 1995. The Company believes that the EDA benefits the
Company because it encourages the incremental purchase of electricity by
IBM at a price above the Company's marginal cost of providing such
incremental service. Sales to IBM represented 12.9 percent of the
Company's operating revenues in 1995.
LIQUIDITY AND CAPITAL RESOURCES
For the nine months ended September 30, 1996, construction expenditures
totaled $14.0 million. Such expenditures in 1996 are expected to be
approximately $22.5 million, principally for expansion and improvements
of the Company's transmission and distribution plant, for conservation
measures and for the construction of a 6 megawatt wind turbine
generating plant located in southern Vermont.
The Company continues to supplement internally generated funds with
external financing to fund construction and conservation expenditures,
refinancings and other cash requirements.
In January 1996, a portion of the proceeds from the sale of $24 million
of the Company's first mortgage bonds in December 1995 was used to
refund $7.2 million of the Company's 10.7 percent first mortgage bonds.
In October 1996, the Company issued $12 million of its preferred stock
at a dividend rate of 7.32 percent, and in November 1996 the Company
sold $10 million of its first mortgage bonds at an interest rate of 7.18
percent. The proceeds from both transactions were used to repay short-
term debt, to retire fixed income securities and for other general
corporate purposes.
The Company presently anticipates issuing an additional $4 million of
first mortgage bonds in the fourth quarter of 1996. The proceeds will
be used to repay short-term debt, to retire fixed income securities and
for other general corporate purposes.
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 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 have historically 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 or of generation. The amount by which such
costs might exceed market prices is commonly referred to as "stranded
costs".
Regulatory and legislative authorities at the federal and state levels,
including Vermont, are considering how to facilitate competition for
electricity sales at the wholesale and retail levels. In October 1994,
the VPSB and the Department convened a "Roundtable on Competition and
the Electric Industry" (the Roundtable), consisting of representatives
of utilities (including the Company), customers, environmental groups
and other affected parties. In July 1995, a subgroup of the Roundtable
agreed on a set of 14 principles intended to guide the debate in Vermont
concerning competition. These principles, among other things, call for
exploration of the potential for retail competition, honoring of past
utility commitments incurred under regulation, protection for low income
customers, and continued exploration of renewable resources, energy
efficiency and environmental protections.
On September 14, 1995, Governor Dean of Vermont announced his desire to
provide for competition and a restructuring of the utility industry.
The Governor's announcement included proposed legislative adoption of
restructuring principles in 1996, a VPSB proceeding to address the
issue, filing by Vermont electric utilities of detailed plans by May 1,
1996, and implementation of restructuring by the end of 1997. In
response to a Department petition, the VPSB opened a proceeding on
electric utility industry restructuring by order dated October 17, 1995.
The VPSB has established a schedule for its investigation that calls for
the VPSB to complete its docket and make a presentation to the Vermont
General Assembly for its 1997 session.
On December 29, 1995, the Company released its proposed restructuring
plan. The Company's plan provides for restructuring, enabled by new
Vermont legislation, by January 1, 1998. Under this plan, individual
utilities would be functionally separated into their competitive and
regulated components. The Company advocates a holding company structure
to accomplish this goal, with each component in a separate corporate
subsidiary. The competitive component would consist of generating
assets, purchased power entitlements, electricity sales, energy
efficiency/demand-side management services, and other customer services.
The regulated component would consist of transmission and local
distribution activities, which can be provided more cost effectively by
one firm, rather than multiple providers. In addition, a regional
Independent System Operator (ISO) would coordinate the transmission and
generation functions to ensure non-discriminatory access and the safety
and reliability of the region's transmission systems and an adequate
power supply. This ISO would perform functions similar to those
currently provided by NEPOOL.
Under the Company's plan, all customers would be free to choose any
retail electrical energy supplier that offered service in their
community, and the retail suppliers would be free to offer their
products and services in any state in which they were certified to
operate. A customer who did not choose a new energy supplier would
continue to be served by the retail supplier that was affiliated with
the utility that served the customer before the restructuring.
The Company has proposed in its plan full recovery of stranded costs
through a customer access charge recovered primarily on a fixed monthly
basis from all customers on the transmission and distribution system.
It is the Company's position that equity and economic efficiency require
that utilities be allowed to recover all of their stranded costs which
were incurred to fulfill their obligations to provide reliable service
as a regulated public utility. Certain parties participating in the
Roundtable and related VPSB proceedings described above have taken
positions opposing the recovery of stranded costs.
On October 16, 1996, the VPSB issued a Draft Report and Order (the
"Draft Report") in its Investigation into the Restructuring of the
Electric Utility Industry in Vermont. The Draft Report sets forth
recommendations for restructuring of the electric utility industry in
Vermont which will require further legislative action. The Draft Report
proposes the commencement of competitive retail sales of electricity in
early 1998, while distribution and transmission functions would remain
subject to regulation. The Draft Report addresses industry
restructuring issues, including, among others, the provision of customer
choice, division of generation and distribution functions, treatment of
stranded costs, required use and development of renewable energy
resources, national and regional policies assuring environmental quality
and establishment of a regional independent system operator and power
exchange system. The Draft Report requests comment from interested
parties by November 15, 1996. The VPSB will consider comments received
from interested parties and will thereafter issue a final report and
order.
The Draft Report states that, rather than prohibiting common ownership
of competitive and regulated components at this time, the VPSB would
require Vermont investor-owned utilities to divide their competitive and
regulated functions into separate corporate subsidiaries in order to
achieve a functional separation. Associated rules would determine how
such subsidiaries will interact with each other.
The Draft 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
Draft Report also states the VPSB's belief that "an opportunity for full
recovery must be explicitly tied to successful mitigation." The Draft
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 reasonably
comparable to regional rates. The Draft Report calls for a multi-step
process which would involve (1) a rigorous estimation of stranded costs
(which in turn would require an estimate of future power costs) and a
determination of the extent to which stranded costs can be mitigated,
(2) an adjustment of stranded costs and (3) a stranded cost
reconciliation proceeding. The process would consider each utility's
estimate of stranded costs and the success of its mitigation efforts on
a case by case basis.
The Draft Report is not a final report or order concerning the
restructuring of the electric utility industry in the State of Vermont.
The Company intends to submit comments to the VPSB in accordance with
the schedule set forth in the Draft Report. The largest category of the
Company's stranded costs are future costs under long-term power purchase
contracts and the Company intends to comply with the steps outlined in
the Draft Report and aggressively pursue mitigation efforts in order to
maximize its recovery of these costs. The Company, however, can give no
assurances that it will be successful in realizing mitigation of these
costs to the extent suggested by the VPSB or that it will otherwise be
able to achieve full or substantial recovery of these costs.
Thus, the Company cannot predict whether the Draft Report or any
subsequent report or actions of, or proceedings before, the VPSB or
Vermont Legislature 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 likely have a material adverse effect on the
Company's business, including its operating results, cash flows and
ability to pay dividends at current levels.
Vermont Yankee Operating Expenses
Vermont Yankee anticipates that operating expenses for 1996 will exceed
the level of such expenses incurred during 1995 by approximately $3.5
million, of which approximately $650,000 will be allocated to the
Company. In 1996, Vermont Yankee elected to accelerate certain safety
and management related projects intended to improve efficiency of the
plant and assure compliance with Nuclear Regulatory Commission
regulations and the facility's operating license.
Federal Open Access Tariff Orders
On April 24, 1996, the Federal Energy Regulatory Commission ("FERC")
issued Orders 888 and 889 which, among other things, require the filing
of open access transmission tariffs by electric utilities, and the
functional separation by utilities of their transmission operations from
other utility operations. FERC Order 888 also supports the full
recovery of legitimate and verifiable costs previously incurred under
federal or state regulation. The Company is currently in the process of
responding to the orders. On July 9, 1996, the Company filed with the
FERC the non-discriminatory open access tariffs required by Order 888.
The tariffs defined GMP's transmission system to include subtransmission
facilities owned by GMP and GMP's entitlement to facilities owned by
VELCO, a corporation engaged in the transmission of electric power
within the State of Vermont in which the Company has an equity interest.
The GMP tariffs included charges related to the use of the VELCO
transmission system by customers. Other Vermont utilities required to
make filings with the FERC under Order 889 followed the same course of
action. VELCO, in turn, submitted to the FERC a request for waiver of
its obligation to file a separate open access transmission tariff. On
September 11, 1996, the FERC denied VELCO's waiver request. The Company
is also in process of complying with FERC's regulations relating to
OASIS, the electronic bulletin board to be used to post availability of
transmission capacity. The Company also intends to functionally
separate its transmission operations by the deadline recently extended
by the FERC to January 3, 1997. The Company does not anticipate any
material adverse effects or loss of wholesale customers due to the FERC
Orders mentioned above.
Central Vermont Public Service Transmission Charges
On August 28, 1996, the Company received a bill totaling approximately
$1.9 million from Central Vermont Public Service Corporation (CVPS) for
service at certain transmission interconnections that are the subject of
a 1993 interconnection agreement between the Company and CVPS. The bill
covered the period October 1993 through June 1996.
In September 1996, the Company charged approximately $700,000 of the
CVPS invoice to transmission rent expense. The Company disputes the
amount of the CVPS billing and estimates its liability in the range of
$1.0 million to $1.3 million, inclusive of amounts already expensed.
The Company will seek regulatory relief for amounts not previously
collected in rates for these services.
The Company has submitted a bill totaling approximately $500,000 to CVPS
for its services under the same interconnection agreement, and credited
this amount to transmission services in September 1996. CVPS disputes
approximately $100,000 of the amount billed by the Company.
Retail Competition Pilot Programs
The State of New Hampshire has undertaken an experiment to provide
retail customer choice in the purchase of electricity. The Company's
wholly-owned subsidiary (Green Mountain Resources, Inc.), along with the
wholly-owned subsidiaries of three large energy companies -- Hydro-
Quebec, Consolidated Natural Gas Company, and Noverco, Inc. -- is
participating in the New Hampshire pilot program, one of the nation's
first significant attempts to test the viability of retail electric
competition, through a limited liability company (Green Mountain Energy
Partners L.L.C.). Green Mountain Energy Partners L.L.C. has been
competing since May 1996 with approximately two dozen other suppliers to
serve 17,000 eligible customers. The pilot program will extend two
years, with service that began in June 1996.
The Commonwealth of Massachusetts has also authorized Bay State Gas
Company's Pioneer Valley Customer Choice Residential Pilot Program (the
"Bay State Gas Pilot") in which Green Mountain Energy Partners L.L.C. is
participating. The Bay State Gas Pilot permits the retail sale of
natural gas to up to 10,000 residential customers and will extend for
two years with service beginning in November 1996. Green Mountain
Energy Partners L.L.C. may decide to participate in other retail energy
programs that are developed.
Because of the limited nature of these pilot programs, the Company
anticipates that there will be no material effect on 1996 consolidated
earnings as a consequence of the activities of Green Mountain Energy
Partners L.L.C. in these pilot programs. The Company believes that
participation in these pilot programs will enhance the capability of
Green Mountain Energy Partners L.L.C. to compete in additional markets
that are opened for retail electric and natural gas customer choice.
GREEN MOUNTAIN POWER CORPORATION
September 30, 1996
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
3-a-2 Amendment to the Company's Restated
Articles of Association, dated as of
October 11, 1996.
27 Financial Data Schedule
(b) REPORTS ON FORM 8-K
Form 8-K was not required to be filed
during the current quarter
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 14, 1996 /s/ C. L. Dutton
C. L. Dutton, Vice President, Chief
Financial Officer and Treasurer
Date: November 14, 1996 /s/ R. J. Griffin
R. J. Griffin, Controller
Exhibit 3-a-2
AMENDMENT TO THE ARTICLES OF ASSOCIATION
PREFERRED STOCK, CLASS E, SERIES 1,
OF GREEN MOUNTAIN POWER CORPORATION
Green Mountain Power Corporation, a corporation organized and
existing under the laws of the State of Vermont having its registered
office in South Burlington, County of Chittenden, and State of Vermont,
in accordance with Section 6.02 of Title 11A of the Vermont Statutes
Annotated (eff. January 1, 1994), submits the following Statement for
the purpose of establishing and designating a series of shares of its
capital stock and fixing and determining the relative rights and
preferences thereof:
1. The name of the Corporation is Green Mountain Power
Corporation.
2. The following is a copy of the resolution establishing and
designating a series of shares and fixing and determining the relative
rights and preferences thereof:
RESOLVED that, pursuant to the authority vested in this Pricing
Committee of the board of directors in accordance with
resolutions of the board of directors dated October 7,
1996, the Articles of Association of this Corporation, and
in accordance with Section 6.02 of Title 11A of the
Vermont Statutes Annotated (eff. January 1, 1994), there
is hereby established out of the authorized but unissued
shares of the Preferred Stock, Class E, par value of One
Hundred Dollars ($100.00) per share of this Corporation, a
series of such Preferred Stock consisting of One Hundred
Twenty Thousand (120,000) shares, designated as the
Preferred Stock, Class E, Series 1 (the "shares"), and
that such Series shall have the following relative rights
and preferences:
(1) Dividends. (a) Regular Dividend. Out of any assets
of the Corporation available for dividends, the
holders of the shares shall be entitled to receive,
but only when and as declared by the board of
directors, dividends at an annual rate of 7.32% of the
par value thereof, calculated on the basis of a 360-
day year of twelve 30-day months and no more, payable
quarterly on March 1, June 1, September 1 and
December 1 in each year beginning December 1, 1996
(each a "dividend payment date"), to the stockholders
of record on a date not more than 30 days prior to
such payment date, as may be determined by the board
of directors. Dividends (including Additional
Dividends as defined in paragraph (b) below) on the
shares, shall be cumulative and shall accrue on a
day-to-day basis from and after the date of issue of
such shares whether or not they have been declared
and whether or not there are profits, surplus or
other funds of the Corporation legally available for
the payment of dividends.
(b) Dividend Adjustment. If one or more
amendments to the Internal Revenue Code of 1986, as
amended (the "Code"), are enacted that reduce the
percentage of the dividends received deduction as
specified in Section 243(a)(1) of the Code or any
successor provision (the "Dividends Received
Percentage") below the existing Dividends Received
Percentage (currently 70%), the amount of each
dividend payable per share on the shares for dividend
payments made on or after the effective date of such
change shall be adjusted by multiplying the amount of
the dividend payable determined as described in
paragraph (a) above (before adjustment) by a factor,
which shall be the number determined in accordance
with the following formula (the "DRD Formula"), and
rounding the result to the nearest cent:
1-(.35 (1-.70))
---------------
1-(.35 (1-DRP))
For purposes of the DRD Formula, "DRP"
means the Dividends Received Percentage applicable to
the dividend in question. No amendment to the Code,
other than a change in the Dividends Received
Percentage, will give rise to an adjustment.
Notwithstanding the foregoing provisions, in the
event that, with respect to any such amendment, the
Corporation will receive either an unqualified
opinion of independent nationally recognized tax
counsel selected by the Corporation or a private
letter ruling or similar form of authorization from
the Internal Revenue Service to the effect that such
an amendment would not apply to dividends payable on
the shares, then any such amendment will not result
in the adjustment provided for pursuant to the DRD
Formula. The opinion referenced in the immediately
preceding sentence will be based upon a specific
exception in the legislation amending the DRP or upon
a published pronouncement of the Internal Revenue
Service addressing such legislation. Unless the
context otherwise requires, references to dividends
in these Resolutions will mean dividends as adjusted
by the DRD Formula. The Corporation's calculation of
the dividends payable, as so adjusted and as
certified accurate as to calculation and reasonable
as to method by the independent certified public
accountants then regularly engaged by the
Corporation, will be final and not subject to review
absent manifest error.
If any amendment to the Code which
reduces the Dividends Received Percentage to below
70% is enacted after declaration of, and applies to,
a dividend payable on a dividend payment date, the
amount of dividend payable on such dividend payment
date will not be increased. Instead, an amount equal
to the excess of (i) the product of the dividend paid
by the Corporation on such dividend payment date and
the factor determined in accordance with the DRD
Formula (where the DRP used in the DRD Formula would
be equal to the reduced Dividends Received
Percentage) over (ii) the dividend paid by the
Corporation on such dividend payment date, will be
payable to holders of record on the next succeeding
dividend payment date in addition to any other
amounts payable on such date.
In addition, if, prior to March 31,
1997, an amendment to the Code is enacted that
reduces the Dividends Received Percentage to below
70% and such reduction retroactively applies to a
dividend payment date as to which the Corporation
previously paid dividends on the shares (each an
"Affected Dividend Payment Date"), the Corporation
will pay (if declared) additional dividends (the
"Additional Dividends") on the next succeeding
dividend payment date (or if such amendment is
enacted after the dividend payable on such dividend
payment date has been declared, on the second
succeeding dividend payment date following the date
of enactment) to holders of record on such succeeding
dividend payment date in an amount equal to the
excess of (i) the product of the dividends paid by
the Corporation on each Affected Dividend Payment
Date and the factor determined in accordance with the
DRD Formula (where the DRP used in the DRD Formula
would be equal to the Dividends Received Percentage
applied to each Affected Dividend Payment Date) over
(ii) the dividend paid by the Corporation on each
Affected Dividend Payment Date.
Additional Dividends will not be paid in
respect of the enactment of any amendment to the Code
on or after March 31, 1997 which retroactively
reduces the Dividends Received Percentage to below
70%, or if prior to March 31, 1997, such amendment
would not result in an adjustment due to the
Corporation having received either an opinion of
counsel or tax ruling referred to in the third
preceding paragraph. The Corporation will only make
one payment of Additional Dividends.
In the event that the amount of dividends
payable per share on the shares is adjusted pursuant
to the DRD Formula and/or Additional Dividends are to
be paid, the Corporation will cause notice of each
such adjustment and, if applicable, any Additional
Dividends, to be sent to the holders of record of the
shares as they appear on the stock books of the
Corporation on such record dates, not more than 50
days nor less than 10 days preceding the payment
dates thereof as shall be fixed by the Corporation
board of directors.
In the event that the Dividends Received
Percentage is reduced to 40% or less, the Corporation
may, at its option, redeem the shares, in whole but
not in part, as described in paragraph 3(b) hereof.
(2) Liquidation. In the event of any liquidation,
dissolution or winding up of this Corporation, the
holders of the shares, shall be entitled to receive
the amounts prescribed in Section 6.02 of the
Restated Articles of Association, as amended, of this
Corporation. In furtherance of the rights of holders
of the shares, under said Section 6.02, for the
purpose of specifying the amounts which such holders
shall be entitled to receive in case such
liquidation, dissolution or winding up shall have
been voluntary, the holders of such shares shall
receive the amount per share equal to the redemption
premium, if any, that would be payable if such shares
were redeemed at the option of the Corporation as
described in paragraph 3 below.
(3) Redemption. (a) Except as described in paragraph (b)
below, the shares are not redeemable prior to October 15,
2006. On or after October 15, 2006, such shares may be
redeemed, at the sole option of the Corporation,
expressed by vote of its board of directors, in
whole, or in part by lot, on at least 30 days' notice
at the applicable redemption price per share set
forth below for the period in which such redemption
occurs, plus accrued and unpaid dividends.
Twelve Month Period Redemption Price
Beginning October 15 Per Share
-------------------- ----------------
2006 103.66
2007 103.30
2008 102.93
2009 102.57
2010 102.20
2011 101.83
2012 101.47
2013 101.10
2014 100.74
2015 100.37
2016 and thereafter 100.00
(b) Notwithstanding the foregoing
provisions, in the event that the Dividends Received
Percentage is reduced to 40% or less, and, as a
result, the amount of dividends on the shares payable
on any dividend payment date will be or is adjusted
upwards as described in paragraph 1(b) hereof, the
Corporation may, at its option expressed by a vote of
its board of directors, redeem the shares, in whole
but not in part, provided that within 90 days of the
date on which the amendment to the Code is enacted
which reduces the Dividends Received Percentage to
40% or less, the Corporation sends notice to holders
of the shares of such redemption. A redemption of
the shares in accordance with this paragraph will
take place on the date specified in the notice, which
shall be not less than 30 days nor more than 60 days
from the date such notice is sent to holders of the
shares. A redemption of the shares in accordance
with this paragraph shall be at the applicable
redemption price set forth in the following table, in
each case plus accrued and unpaid dividends (whether
or not declared) thereon to, but excluding, the date
fixed for redemption, including any changes in
dividends payable due to changes in the Dividends
Received Percentage and Additional Dividends, if any.
Redemption Period Redemption Price
Per Share
October 17, 1996 to October 14, 1997. . . .. 105.00
October 15, 1997 to October 14, 1998. . . . 104.00
October 15, 1998 to October 14, 1999 . . . . 103.00
October 15, 1999 to October 14, 2000 . . . . 102.00
October 15, 2000 to October 14, 2001 . . . . 101.00
On or after October 15, 2001 .. . . . . . . 100.00
(c) The Corporation will have no
sinking fund obligations in connection with the
shares.
(4) Voting Powers and Other Rights. The
holders of the shares shall have such voting powers
and other rights and be subject to such restrictions
and qualification as are set forth in Sections 6, 7
and 8 of the Restated Articles of Association, as
amended, of this Corporation.
(5) Conversion or Exchange Rate. The shares
will not be entitled to conversion or exchange rights.
3. The date of adoption of the foregoing resolution by the
Pricing Committee of the board of directors of the Corporation was
October 10, 1996 in accordance with the authority granted to such
Committee by the board of directors of the Corporation pursuant to
resolutions of the board of directors adopted on October 7, 1996 and
Section 8.25 of Title 11A of the Vermont Statute Annotated (eff. January
1, 1994).
4. Said resolution was duly adopted by the Pricing Committee
of the board of directors of Green Mountain Power Corporation pursuant
to authority given to it by the board of directors of the Corporation.
IN WITNESS WHEREOF this Statement has been executed in duplicate
this 11th day of October 1996.
GREEN MOUNTAIN POWER CORPORATION
ATTEST: By: /s/Douglas G. Hyde
President
/s/Veronica M. Fallon By: /s/Donna S. Laffan
Secretary
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet as of September 30, 1996 and the related
Statements of Income and Cash Flows for the nine months ended
September 30, 1996 and is qualified in its entirety by reference to
such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 187,331
<OTHER-PROPERTY-AND-INVEST> 20,622
<TOTAL-CURRENT-ASSETS> 24,797
<TOTAL-DEFERRED-CHARGES> 43,743
<OTHER-ASSETS> 39,074
<TOTAL-ASSETS> 315,567
<COMMON> 16,646
<CAPITAL-SURPLUS-PAID-IN> 66,985
<RETAINED-EARNINGS> 26,640
<TOTAL-COMMON-STOCKHOLDERS-EQ> 110,271
6,720
810
<LONG-TERM-DEBT-NET> 80,900
<SHORT-TERM-NOTES> 23,416
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 3,034
0
<CAPITAL-LEASE-OBLIGATIONS> 9,778
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 80,438
<TOT-CAPITALIZATION-AND-LIAB> 315,567
<GROSS-OPERATING-REVENUE> 133,304
<INCOME-TAX-EXPENSE> 4,380
<OTHER-OPERATING-EXPENSES> 117,572
<TOTAL-OPERATING-EXPENSES> 121,952
<OPERATING-INCOME-LOSS> 11,352
<OTHER-INCOME-NET> 2,777
<INCOME-BEFORE-INTEREST-EXPEN> 14,129
<TOTAL-INTEREST-EXPENSE> 5,566
<NET-INCOME> 8,563
539
<EARNINGS-AVAILABLE-FOR-COMM> 8,024
<COMMON-STOCK-DIVIDENDS> 7,796
<TOTAL-INTEREST-ON-BONDS> 5,125
<CASH-FLOW-OPERATIONS> 21,724
<EPS-PRIMARY> 1.63
<EPS-DILUTED> 1.63
</TABLE>
