SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________
FORM 10-Q
X Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended June 30, 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 June 30, 1997
$3.33 1/3 Par Value 5,118,430
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1 - Item 1
<CAPTION>
June 30 December 31
----------------------------------- ----------------
1997 1996 1996
---------------- ---------------- ----------------
(In thousands) (In thousands)
<S> <C> <C> <C>
ASSETS
Utility Plant
Utility plant, at original cost.................... $249,511 $245,536 $248,135
Less accumulated depreciation...................... 85,492 79,817 81,286
---------------- ---------------- ----------------
Net utility plant................................ 164,019 165,719 166,849
Property under capital lease....................... 9,006 9,778 9,006
Construction work in progress...................... 20,586 9,186 13,998
---------------- ---------------- ----------------
Total utility plant, net......................... 193,611 184,683 189,853
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity ................... 14,026 16,011 15,769
Other investments.................................. 5,271 4,640 4,865
---------------- ---------------- ----------------
Total other investments.......................... 19,297 20,651 20,634
---------------- ---------------- ----------------
Current Assets
Cash............................................... 131 69 238
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 14,805 14,537 17,733
Accrued utility revenues .......................... 5,438 5,248 6,662
Fuel, materials and supplies, at average cost...... 3,478 3,381 3,621
Prepayments........................................ 524 536 2,206
Other.............................................. 354 286 441
---------------- ---------------- ----------------
Total current assets............................. 24,730 24,057 30,901
---------------- ---------------- ----------------
Deferred Charges
Demand side management programs.................... 14,690 17,448 16,409
Environmental proceedings costs.................... 7,948 8,056 7,991
Purchased power costs.............................. 9,963 5,747 9,163
Other.............................................. 12,781 8,310 9,661
---------------- ---------------- ----------------
Total deferred charges........................... 45,382 39,561 43,224
---------------- ---------------- ----------------
Non-Utility
Cash and cash equivalents.......................... 165 263 511
Other current assets............................... 5,192 2,481 3,979
Property and equipment............................. 12,321 11,348 11,226
Intangible assets.................................. 2,184 2,402 2,555
Equity investment in energy related businesses..... 13,661 14,578 12,494
Other assets....................................... 12,994 8,110 9,162
---------------- ---------------- ----------------
Total non-utility assets......................... 46,517 39,182 39,927
---------------- ---------------- ----------------
Total Assets........................................... $329,537 $308,134 $324,539
================ ================ ================
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,134,286, 4,951,169 and 5,037,143)........... $17,095 $16,503 $16,790
Additional paid-in capital....................... 69,733 66,496 68,226
Retained earnings................................ 25,344 25,950 26,916
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 111,794 108,571 111,554
Redeemable cumulative preferred stock.............. 19,310 8,930 19,310
Long-term debt, less current maturities............ 93,200 82,234 94,900
---------------- ---------------- ----------------
Total capitalization........................... 224,304 199,735 225,764
---------------- ---------------- ----------------
Capital lease obligation............................... 9,006 9,778 9,006
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,700 1,700 3,034
Short-term debt.................................... 6,316 18,615 1,016
Accounts payable, trade, and accrued liabilities... 6,367 3,333 6,140
Accounts payable to associated companies........... 7,514 5,993 6,621
Dividends declared................................. 375 190 381
Customer deposits.................................. 507 581 689
Taxes accrued...................................... 491 1,644 986
Interest accrued................................... 1,335 1,341 1,382
Deferred revenues ................................. 2,854 2,566 --
Other.............................................. 811 230 788
---------------- ---------------- ----------------
Total current liabilities...................... 28,270 36,193 21,037
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 27,467 23,943 26,726
Unamortized investment tax credits................. 4,705 4,995 4,825
Other.............................................. 23,377 22,132 23,417
---------------- ---------------- ----------------
Total deferred credits......................... 55,549 51,070 54,968
---------------- ---------------- ----------------
Non-Utility
Current liabilities................................ 1,084 712 1,752
Other liabilities.................................. 11,324 10,646 12,012
---------------- ---------------- ----------------
Total non-utility liabilities.................. 12,408 11,358 13,764
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $329,537 $308,134 $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 Six Months Ended
June 30 June 30
------------------------------- -------------------------------
1997 1996 1997 1996
------------ ------------ ------------ ------------
(In thousands, except amounts per share)
<S> <C> <C> <C> <C>
Operating Revenues ........................................... $42,682 $40,467 $89,886 $88,881
------------ ------------ ------------ ------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation ................ 8,473 8,093 16,239 15,504
Company-owned generation................................. 1,199 726 2,045 1,572
Purchases from others.................................... 14,948 15,210 32,728 33,878
Other operating............................................. 4,007 4,740 8,242 9,647
Transmission................................................ 2,914 2,523 5,961 5,214
Maintenance................................................. 1,141 1,264 2,259 2,386
Depreciation and amortization............................... 4,152 4,048 8,392 7,923
Taxes other than income..................................... 1,692 1,610 3,608 3,387
Income taxes................................................ 1,165 394 3,170 2,439
------------ ------------ ------------ ------------
Total operating expenses................................. 39,691 38,608 82,644 81,950
------------ ------------ ------------ ------------
Operating Income....................................... 2,991 1,859 7,242 6,931
------------ ------------ ------------ ------------
Other Income
Equity in earnings of affiliates and non-utility operations. (289) 923 130 1,780
Allowance for equity funds used during construction......... 200 49 394 89
Other income and deductions, net............................ 119 15 401 30
------------ ------------ ------------ ------------
Total other income........................................ 30 987 925 1,899
------------ ------------ ------------ ------------
Income before interest charges.......................... 3,021 2,846 8,167 8,830
------------ ------------ ------------ ------------
Interest Charges
Long-term debt.............................................. 1,826 1,696 3,690 3,511
Other....................................................... 85 224 161 452
Allowance for borrowed funds used during construction...... (120) (98) (229) (221)
------------ ------------ ------------ ------------
Total interest charges.................................... 1,791 1,822 3,622 3,742
------------ ------------ ------------ ------------
Net Income.................................................... 1,230 1,024 4,545 5,088
Dividends on preferred stock.................................. 374 190 749 379
------------ ------------ ------------ ------------
Net Income Applicable to Common Stock......................... $856 $834 $3,796 $4,709
============ ============ ============ ============
Common Stock Data
Earnings per share.......................................... $0.17 $0.17 $0.75 $0.96
Cash dividends declared per share........................... $0.53 $0.53 $1.06 $1.06
Weighted average shares outstanding......................... 5,096 4,911 5,070 4,885
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................. $27,187 $27,716 $26,916 $26,412
Net Income.................................................... 1,230 1,024 4,545 5,088
------------ ------------ ------------ ------------
28,417 28,740 31,461 31,500
------------ ------------ ------------ ------------
Cash Dividends - redeemable cumulative preferred stock........ 374 190 749 379
- common stock................................. 2,699 2,600 5,368 5,171
------------ ------------ ------------ ------------
3,073 2,790 6,117 5,550
------------ ------------ ------------ ------------
Balance - end of period....................................... $25,344 $25,950 $25,344 $25,950
============ ============ ============ ============
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>
Six Months Ended
June 30
---------------------------------------
1997 1996
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income........................................................... $4,545 $5,088
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 8,392 7,923
Dividends from associated companies less equity income........... 1,743 13
Allowance for funds used during construction..................... (623) (311)
Amortization of purchased power costs............................ (1,732) 3,174
Deferred income taxes............................................ 994 (1,149)
Deferred revenues ............................................... 2,854 2,566
Deferred purchased power costs................................... (25) (1,518)
Amortization of investment tax credits........................... (120) (112)
Environmental proceedings costs, net............................. (804) (917)
Conservation expenditures........................................ (1,052) (1,507)
Changes in:
Accounts receivable............................................ 2,928 3,544
Accrued utility revenues....................................... 1,224 1,275
Fuel, materials and supplies................................... 143 (69)
Prepayments and other current assets........................... 556 2,970
Accounts payable............................................... 1,120 (3,214)
Taxes accrued.................................................. (495) 1,073
Interest accrued............................................... (46) (505)
Other current liabilities...................................... (835) (834)
Other............................................................ (6,259) 342
----------------- -----------------
Net cash provided by operating activities.......................... 12,508 17,832
----------------- -----------------
Investing Activities:
Construction expenditures.......................................... (9,148) (7,187)
Investment in non-utility property................................. (1,040) (2,716)
----------------- -----------------
Net cash used in investing activities............................ (10,188) (9,903)
----------------- -----------------
Financing Activities:
Issuance of common stock........................................... 1,813 2,626
Short-term debt, net............................................... 5,300 10,200
Cash dividends..................................................... (6,117) (5,550)
Reduction in long-term debt........................................ (3,769) (15,033)
----------------- -----------------
Net cash used in financing activities............................ (2,773) (7,757)
----------------- -----------------
Net increase (decrease) in cash and cash equivalents............... (453) 172
Cash and cash equivalents at beginning of period................... 749 160
----------------- -----------------
Cash and Cash Equivalents at End of Period............................. $296 $332
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid year-to-date:
Interest (net of amounts capitalized)........................... $3,787 $4,351
Income taxes.................................................... 1,849 2,436
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 June 30, 1997 and 1996, the
Company had recorded deferred revenues of $2.9 million and $2.6 million,
respectively, in accordance with this policy. These deferred revenues
are recognized 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 Six Months Ended
June 30 June 30
1997 1996 1997 1996
---- ---- ---- ----
(In Thousands) (In Thousands)
Revenue . . . . . . . . . $2,498 $2,792 $6,036 $6,717
Expenses . . . . . . . . . 3,295 2,417 6,973 5,975
------- ------ ------- ------
Net Income . . . . . . . . $ (797) $ 375 $ (937) $ 742
======= ====== ======= ======
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 Six Months Ended
June 30 June 30
1997 1996 1997 1996
---- ---- ---- ----
(In Thousands)
Vermont Yankee Nuclear Power Corporation
Gross Revenue . . . . . $44,383 $43,282 $84,804 $83,038
Net Income Applicable
to Common Stock . . . 1,748 1,702 3,523 3,300
Company's Equity in
Net Income . . . . . 309 305 646 585
Three Months Ended Six Months Ended
June 30 June 30
1997 1996 1997 1996
---- ---- ---- ----
(In Thousands)
Vermont Electric Power Company, Inc.
Gross Revenue . . . . . $12,700 $12,123 $25,136 $24,412
Net Income
Before Dividends . . 280 365 709 663
Company's Equity in
Net Income (Includes
preferred equity) . . 92 127 205 209
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 Marsh 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 Marsh 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 Marsh 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 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. 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.
In December 1991, the Company brought suit against eight previous
insurers seeking recovery of unrecovered past costs and indemnity
against future liabilities associated with environmental problems at the
site. Discovery in the case, which was previously subject to a stay, is
proceeding and 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 and has
obtained summary judgment declaring one insurer's duty to defend.
The Company has deferred amounts received, under confidential
settlement, 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 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 Marsh 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 Vermont Public Service Board (VPSB) in those proceedings
reflected the Pine Street Marsh related expenditures referred to above.
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
Marsh 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 increase is needed to cover higher
power supply costs and the Company's rising cost of capital.
6. SFAS 128
In March 1997, the Financial 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 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
JUNE 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 second quarter of 1997 were
$0.17, the same per share earnings as in same period of 1996. The
Company's improved operating performance in the second quarter of 1997
was offset by a loss experienced by Green Mountain Resources, Inc.
(GMRI), the Company's wholly-owned subsidiary that has been developing a
national retail energy marketing strategy designed to focus on retail
markets that are opened to competition. GMRI has participated in
various pilot programs providing retail customer choice in the purchase
of electricity and natural gas. (See "Other Income" and "Recent
Developments" below.)
For the six months ended June 30, 1997 and 1996, earnings per share of
common stock were $0.75 and $0.96, respectively.
OPERATING REVENUES AND MWH SALES
Operating revenues, megawatthour (MWh) sales and average number of
customers are summarized as follows:
Three Months Ended Six Months Ended
June 30 June 30
1997 1996 1997 1996
---- ---- ---- ----
Operating Revenues
(In thousands)
Retail . . . . . . $ 37,373 $ 35,026 $ 79,051 $ 76,128
Sales for Resale . 4,619 4,768 9,384 11,238
Other . . . . . . 690 672 1,451 1,515
--------- --------- --------- ---------
Total Operating
Revenues . . . . $ 42,682 $ 40,466 $ 89,886 $ 88,881
========= ========= ========= =========
MWh Sales
Retail . . . . . . 422,457 403,046 899,069 888,137
Sales for Resale . 157,645 164,545 318,581 403,832
------- ------- --------- ---------
Total MWh Sales . 580,102 567,591 1,217,650 1,291,969
======= ======= ========= =========
Average Number of Customers
Residential . . . 70,581 70,062 70,572 70,087
Commercial &
Industrial . . . 12,000 11,834 11,978 11,817
Other . . . . . . . 75 78 75 76
------ ------ ------ ------
Total Customers . . 82,656 81,974 82,625 81,980
====== ====== ====== ======
Total operating revenues in the second quarter of 1997 increased 5.5
percent over the same period in 1996. Retail revenues increased 6.7
percent in the second quarter of 1997 over the same period in 1996
primarily due to a 5.8 percent increase in sales of electricity to the
Company's commercial and industrial customers resulting from an increase
in usage by IBM and modest overall customer growth and a 5.25 percent
retail rate increase that went into effect in June 1996. Wholesale
revenues decreased 3.1 percent in the second quarter of 1997 compared to
the same period in 1996 primarily due to a reduction in off-system
sales.
For the six months ended June 30, 1997, total operating revenues
increased 1.1 percent over the same period in 1996. Retail revenues
increased 3.8 percent over the same period in 1996. An increase in
retail revenues resulting from a 5.25 retail rate increase that went
into effect in June 1996 and an increase in sales of electricity to IBM
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 16.5 percent over the same period in 1996
primarily due to a reduction in low-margin, off-system sales, which had
a minimal impact on earnings.
On June 16, 1997, the Company filed a request with the Vermont Public
Service Board (VPSB) to increase retail rates by 16.7 percent and the
target return on common equity from 11.25 percent to 13 percent. The
increase is needed to cover higher power supply costs and the Company's
rising cost of capital. The Vermont Senate in April 1997 passed
legislation that would have provided for the restructuring of the
electric utility industry in Vermont. (See "Competition and
Restructuring" below.) The Company objected to the provisions in this
legislation relating to committed power supply cost recovery. This
legislation was not acted upon by the Vermont House of Representatives,
which has begun hearings on restructuring this summer. The
uncertainties associated with the current rate case and restructuring
legislation have adversely affected the Company's ability to raise
money. The Company's near-term financial performance depends in large
measure on the Company's success in recovering the above-described costs
in its pending rate case (or on its ability to reduce such costs in the
future) and on the enactment of reasonable restructuring legislation in
Vermont.
OPERATING EXPENSES
Power supply expenses increased 2.5 percent in the second quarter of
1997 over the same period in 1996 primarily due to 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 Vermont Yankee costs related to
engineering studies undertaken to assure compliance with Nuclear
Regulatory Commission requirements. These increases were partially
offset by a reduction in the cost of power purchased from others
reflecting the recognition in the second quarter of $2.4 million,
consistent with allowed ratemaking treatment, related to a payment to be
received under a Memorandum of Understanding entered into with Hydro-
Quebec in November 1996. The Memorandum of Understanding provides for a
payment to the Company of $8.0 million in 1997 for Hydro-Quebec's right
to elect, on or before September 1, 1997, one of two options to purchase
power from the Company in the future. The remaining $4.8 million will be
recognized in income over the remaining six months of 1997. (See 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--Results of Operations-Power Supply Expenses" and
Note K to the Company's Consolidated Financial Statements contained
therein for a more complete discussion of this Memorandum of
Understanding.)
Power supply expenses were virtually unchanged for the six months ended
June 30, 1997 compared to the same period in 1996. An increase in power
supply expenses from Vermont Yankee and higher Company-owned generation
costs were almost entirely offset by a reduction in power purchased from
others for the same reasons discussed above.
Other operating expenses decreased 15.5 percent in the second quarter of
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. Other operating expenses decreased 14.6 percent for the
six months ended June 30, 1997 compared to the same period in 1996
primarily due to the reason set forth above. (See "Other Income"
below.)
Transmission expenses increased 15.5 percent in the second quarter of
1997 over the same period in 1996 primarily due to higher tariff rates
under an interconnection agreement between Central Vermont Public
Service Corporation (CVPS) and the Company and an increase in other
tariff rates. Transmission expenses increased 14.3 percent for the six
months ended June 30, 1997 over the same period in 1996 primarily due to
higher tariff rates under an interconnection agreement between CVPS and
the Company.
Maintenance expenses decreased 9.8 percent in the second quarter of 1997
compared to the same period in 1996 primarily due to a decrease in
scheduled maintenance activity related to the Company's investment in
the Stony Brook plant. Maintenance expenses decreased 5.3 percent for
the six months ended June 30, 1997 compared to the same period in 1996
for the same reason.
Depreciation and amortization expense increased 2.6 percent in the
second quarter of 1997 over the same period in 1996 primarily due to
depreciation associated with additional investment in the Company's
utility plant. Depreciation and amortization expenses increased 5.9
percent for the six months ended June 30, 1997 compared to the same
period in 1996 primarily due to depreciation associated with additional
investment in the Company's utility plant and the amortization of
expenditures related to energy conservation programs and the Pine Street
Marsh environmental matter.
Taxes other than income taxes increased 5.1 percent in the second
quarter of 1997 over the same period in 1996 primarily due to an
increase in municipal property taxes. Taxes other than income taxes
increased 6.5 percent for the six months ended June 30, 1997 compared to
the same period in 1996 for the same reason. In June 1997, Governor
Howard Dean 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 second 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 six
months ended June 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 $726,000 in additional
income taxes based on the deferred tax assets and liabilities as of June
30, 1997. Management expects to seek and receive ratemaking treatment
in order to collect these amounts from ratepayers in future periods.
OTHER INCOME
Other income decreased 96.9 percent in the second quarter of 1997
compared to the same period in 1996 primarily due to the recognition of
a $1.3 million loss, or $0.26 per share, incurred by GMRI, the Company's
wholly-owned subsidiary through which the Company participates in the
retail energy business. The loss primarily represents expenses incurred
by GMRI in the development of the retail energy business to be conducted
by Green Mountain Energy Resources L.L.C. ("GMER"), a Delaware limited
liability company in which GMRI was the sole member. GMER was formed to
participate in the retail marketing of electricity and natural gas in
states that are opening their markets to competition in 1998 and
thereafter, including California where retail competition is scheduled
to begin on January 1, 1998. In order to obtain needed capital for this
venture, on August 6, 1997, GMRI entered into an agreement with Green
Funding I, L.L.C., an affiliate of the Sam Wyly Family, which acquired a
67 percent membership interest in GMER. A substantial portion of
additional development costs incurred in the second and third quarters
of 1997 will be recovered in payments from GMER pursuant to the terms of
that transaction. (See "Recent Developments" section in the
Management's Discussion and Analysis of Financial Condition and Results
of Operations for more details concerning the said transaction.) GMRI's
loss was partially offset by an increase in the allowance for equity
funds used during construction resulting from higher average
construction work in progress balances during the period and an increase
in interest income resulting from the accrual of interest related to the
$8.0 million payment due from Hydro-Quebec later this year (See the
discussion in "Operating Expenses" above). Other income decreased 51.3
percent for the six months ended June 30, 1997 compared to the same
period in 1996 primarily due to a $1.6 million loss, or $0.32 per share,
experienced by GMRI. This decrease was partially offset by an increase
in the allowance for equity funds used during construction and an
increase in interest income for the same reasons discussed above.
INTEREST CHARGES
Interest charges decreased 1.7 percent in the second quarter of 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. Interest charges decreased 3.2
percent for the six months ended June 30, 1997 compared to the same
period in 1996 for the same reasons.
LIQUIDITY AND CAPITAL RESOURCES
Dividends on preferred stock increased 97.4 percent in the second
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 97.4
percent for the six months ended June 30, 1997 compared to the same
period in 1996 for the same reason.
For the six months ended June 30, 1997, construction and conservation
expenditures totaled $9.4 million. Such expenditures in 1997 are
expected to be approximately $24.9 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 June 30, 1997, the Company had lines of credit with five banks
totaling $30.0 million, with borrowings outstanding of $6.3 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 1/8 to
1/4 percent and no compensating balance requirements. These lines of
credit are subject to periodic review and renewal during the year by the
various banks. Effective August 12, 1997, the Company entered into a
revolving credit agreement in the amount of $45 million with three
banks, which will replace a portion of its existing lines of credit.
Dividend Policy -- The Company's current dividend policy is based 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. As discussed under "Competition and
Restructuring," there is a movement in Vermont to restructure the
electric utility industry in order to permit competition in the
generation and retail sale of electricity. Such restructuring would,
among other things, lead to a loss of the Company's current exclusive
franchise for selling electricity at retail, even though the Company
would retain its exclusive franchise to provide distribution service.
Also, a business operating in a competitive environment, including any
unregulated activities by the Company, would by its nature engender a
different type of earnings growth and volatility than is found in a
regulated entity. The uncertainty concerning the Company's pending rate
increase application and the implementation of restructuring in Vermont
and its impact on the Company has resulted in an increase in the
Company's capital costs due to the marketplace's perception of the risk
associated with the Company's business. Should restructuring be
approved in Vermont or any of the other conditions identified above no
longer obtain, it is likely that the Company will reconsider its
dividend policy and make appropriate changes so that anticipated payout
levels are more commensurate with the risk of any new business
activities to be undertaken and consistent with the capital needs of its
businesses.
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
Order on December 31, 1996.
The Final Order 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 Order 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 Order also states the VPSB's belief that "an opportunity for full
recovery must be explicitly tied to successful mitigation." The Final
Order 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 Order 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 Order also endorses the securitization
of stranded costs through the assignment of CTC receipts as a means of
achieving lower-cost financing and the Final Order supports legislative
action to achieve these savings.
The Company, CVPS, representatives of the Governor of Vermont and the
Department have negotiated a Memorandum of Understanding (MOU) that
would outline agreed-upon positions among the parties relative to the
recovery of stranded costs, distribution company rates, corporate
unbundling and societal benefit programs. The parties to the MOU
mutually would support those provisions in connection with any proposed
legislation before the Vermont General Assembly and in any regulatory
proceeding before the VPSB. If all of the terms of the MOU are not
included in final restructuring legislation and in an implementing VPSB
Order, the MOU will be of no force or effect.
Although not yet executed, it is likely that the MOU will include the
following financial terms:
If the Company were able to reduce its power costs by $105 million
(on a net present value basis assuming a 10% discount rate), then
it would be conclusively deemed to have adequately mitigated
stranded costs for the purpose of recovering its remaining stranded
costs. The closer the Company is to the mitigation target, the
greater the likelihood that the Company will recover all of its
remaining stranded costs.
The CTC would be fixed initially at $30/MWh for the first two years
of retail competition. Any under-collections or over-collections of
the CTC, respectively, would be added to or subtracted from the
unrecovered stranded cost balance. The CTC would be adjusted
annually thereafter to achieve recovery of stranded costs by the
end of 2012.
Unbundled distribution subsidiary rates would be frozen for 1998
and 1999 and adjusted by 70% of the change in the consumer price
index for calendar years 2000 through 2004. Some portion of the
frozen and subsequent rates would be dependent on achieving
mutually agreed upon performance targets regarding quality of
service. The distribution subsidiary would also be able to
petition the VPSB for relief due to significant factors out of the
control of the distribution subsidiary, such as, but not limited
to, a change in income tax rates, the need for significant capital
expenditures to meet material customer expansions, natural
catastrophes or significant changes in load growth.
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 is not based on the MOU and 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) 71, Accounting for Certain Types
of Regulation, 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. 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 Order or the MOU. 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 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 Order 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 both the Final Order and
MOU, 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
On August 6, 1997, the Company and the Sam Wyly Family announced that
their affiliates will jointly own GMER, which will compete in the
emerging consumer retail energy market starting in California where
customers will begin choosing their electricity supplier as early as
November 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 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 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.
Douglas G. Hyde, a director, President and Chief Executive Officer of
the Company, has 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 Hartley, Vice President, Marketing; Karen K.
O'Neill, Vice President Organizational Development; and Peter H. Zamore,
General Counsel of the Company have resigned those offices in order to
join Mr. Hyde as members of the GMER management team.
The Company's Board of Directors has 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. In addition to Mr. Dutton, the
members of the Company's senior management, and their current positions,
are Richard B. Hieber, Vice President Operations and Engineering;
Michael H. Lipson, Assistant General Counsel; Edwin M. Norse, Vice
President, Financial Development; Stephen C. Terry, Vice President,
Customer and Government Relations; and Jonathan H. Winer, President of
the Company's subsidiary, Mountain Energy, Inc. Following this
organizational change, the Company's total number of employees will be
approximately 330.
The Company's Board of Directors unanimously supported Mr. Hyde's
decision to become President of GMER which the Board of Directors
believes will add significant long-term value to the Company and is the
preferred vehicle for the Company's participation in the developing
national retail energy market. Press releases issued by the Company
concerning this transaction are filed herewith as Exhibits 99(a) and
99(b) and are incorporated by reference herein.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Not Applicable.
GREEN MOUNTAIN POWER CORPORATION
June 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
At the Annual Shareholders Meeting held May 15, 1997,
shareholders elected the nominees listed below as Directors of
the company. The voting results are set forth below. There
were no other items brought before the meeting.
Election of Directors
Shareholders elected the nominees for Director as
follows:
Broker
Total Votes Total Votes Non-Votes
Nominee FOR AGAINST Absentions
- -------------------- ----------- ----------- ----------
Class II (term expires 2000)
Merrill O. Burns 4,137,855 53,808 845,401
Douglas G. Hyde 4,135,155 56,508 845,401
Ruth W. Page 4,118,663 73,000 845,401
Directors Continuing in Office
Class I (term expires 1999)
William H. Bruett
Richard I. Fricke
Martin L. Johnson
Thomas P. Salmon
Class III (term expires 1998)
Nordahl L. Brue
Lorraine E. Chickering
John V. Cleary
Euclid A. Irving
ITEM 5. Other Information
NONE
ITEM 6. (a) EXHIBITS
27 Financial Data Schedule
99(a) Company Press Release dated 8/6/97
99(b) Company Press Release dated 8/6/97
(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: August 14, 1997 /s/ C. L. Dutton
C. L. Dutton, President, Chief
Financial Officer and Treasurer
Date: August 14, 1997 /s/ R. J. Griffin
R. J. Griffin, Controller
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<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheet as of June 30, 1997 and the related
Consolidated Statements of Income and Cash Flows for the six months
ended June 30, 1997, and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 193,611
<OTHER-PROPERTY-AND-INVEST> 19,297
<TOTAL-CURRENT-ASSETS> 24,730
<TOTAL-DEFERRED-CHARGES> 45,382
<OTHER-ASSETS> 46,517
<TOTAL-ASSETS> 329,537
<COMMON> 17,095
<CAPITAL-SURPLUS-PAID-IN> 69,355
<RETAINED-EARNINGS> 25,344
<TOTAL-COMMON-STOCKHOLDERS-EQ> 111,794
6,560
12,750
<LONG-TERM-DEBT-NET> 93,200
<SHORT-TERM-NOTES> 6,316
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 1,700
0
<CAPITAL-LEASE-OBLIGATIONS> 9,006
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 88,211
<TOT-CAPITALIZATION-AND-LIAB> 329,537
<GROSS-OPERATING-REVENUE> 89,886
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<OTHER-OPERATING-EXPENSES> 79,474
<TOTAL-OPERATING-EXPENSES> 82,644
<OPERATING-INCOME-LOSS> 7,242
<OTHER-INCOME-NET> 925
<INCOME-BEFORE-INTEREST-EXPEN> 8,167
<TOTAL-INTEREST-EXPENSE> 3,622
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<EARNINGS-AVAILABLE-FOR-COMM> 3,796
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NEWS
FOR IMMEDIATE RELEASE #22-97
August 6, 1997
GMP-WYLY CREATE NATIONAL ENERGY BRAND FOR CONSUMERS WHO CARE ABOUT THE
ENVIRONMENT
SOUTH BURLINGTON, VT . . . Green Mountain Power Corporation (GMP) and The
Wyly Family announced today that a company their affiliates jointly own will
compete in the emerging consumer retail energy market, starting in
California where customers will begin choosing their electricity supplier as
early as November 1997.
Using a planned $30 million investment by The Wyly Family,
and three years' advance work by a GMP subsidiary, the new company will
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. The company, Green Mountain Energy Resources L.L.C. (GMER), is
owned by an affiliate of the Wylys and a subsidiary of GMP. GMER is based
in South Burlington, Vermont.
Douglas G. Hyde, President and CEO of Green Mountain Power,
will leave GMP to become President of GMER. "We intend to unleash the power
of consumer choice and in the process create a market for environmentally
attractive energy," he said. "We know from our earlier work that customers
want to buy energy sources that do not threaten the planet, and we know how
to provide them with that opportunity. GMER is already registered to sell
energy in California, and we're eager to get into other markets as soon as
they open up."
Sam Wyly said, "We're combining three elements that can't
fail: The Vermont environmental ethic, Texas capital and old-fashioned
American entrepreneurs' frontier spirit. We're taking that combination into
a brand new market that's bigger than the telephone industry. And it's
clear to me that now, at the outset of this new industry, no one knows more
about the market than the people running Green Mountain Energy Resources."
The Wyly Family is the principal investor in GMER. A subsidiary of GMP
will retain a 33 percent equity interest in return for its development work.
The Wyly investment will provide funds for continued development and the
costs of operating the company.
"The creation and funding of GMER is the logical -- and
certainly exciting -- next step in the pursuit of opportunity in the energy
retail market as it develops across the country," Mr. Hyde said. "GMP has
been an enthusiastic and, we believe, successful leader in bringing
competitive choices to retail energy consumers in Massachusetts and New
Hampshire. Now, the initiative and resources of the Wylys make it possible
to continue the transformation by creating a market-oriented company with
strong financial backing that will be fully operational by the time retail
sales begin in California in January."
The Wylys are Dallas entrepreneurs who have founded and helped build
several substantial successful publicly traded growth companies, including
Sterling Commerce (SE); Sterling Software (SSW); and Michaels Stores (MIKE),
a retail chain selling arts, crafts, frames and floral with more than 450
stores nationwide, including 79 in California; and Maverick Capital, a
private hedge fund.
Mr. Wyly said, "This investment opportunity is created by the oncoming
transition of the electric and gas utility market in America from monopolies
to one of free market competition. Results will be similar to those created
over the past 25 years as the USA telephone monopolies evolved into a
competitive business in which customers had choice as to the service and
equipment they want as opposed to being forced to buy a service or product
from a monopoly provider. We expect the same benefits to customers over the
coming 25 years in terms of customers getting what they want as opposed to
getting what they are told they can have.
"The Wylys and Green Mountain believe that clean air is enormously
important to American consumers, and we intend to offer them an opportunity
to direct the dollars they spend toward cleaner energy resources," Mr. Wyly
continued.
The first state to give its citizens a choice in electricity will be
California, which opens up to retail competition in January 1998. Last
month, GMER was one of the first to file to compete in this new free market
environment in the USA. "We expect Rhode Island and Massachusetts to
shortly follow California's lead. Other states will follow with a lag time
that depends on how soon state legislatures can be convinced to give
consumers a choice," Mr. Wyly said.
"Green Mountain Power, serving 160,000 people in its service territory in
Vermont, has one of the most enlightened board and management teams in the
industry. The process this team initiated will allow our new jointly-owned
company to go beyond Vermont and pursue a market of 270 million Americans,"
said Mr. Wyly.
Members of the GMP senior management team who will join Mr. Hyde in moving
to the new company with new responsibilities are Julie Blunden, California
Regional Director; Thomas Boucher, Vice President, Energy Supply, Business
Development and Customer Operations; Kevin Hartley, Vice President,
Marketing; Karen O'Neill, Vice President, Regional Development and Strategic
Alliances; and Peter Zamore, Vice President, General Counsel and Secretary.
Also part of the senior management team will be David Luther, a former
Senior Vice President of Corning, Inc., who will hold the title at GMER of
Vice President - Finance and Administration, and Treasurer.
Mr. Hyde said, "I am also very pleased that this new national venture will
be Vermont-based. It will create new opportunities for Vermonters who will
eventually work for this enterprise. We hope this business will grow so
that it will employ more than 100 people in the near future."
The GMP Board of Directors approved the GMER plan and also elected -
effective today - Christopher L. Dutton as the new President and CEO, and a
member of the Board of Directors of GMP. Mr. Dutton, 48, has been Chief
Financial Officer of GMP since 1995 and for ten years before that he was
General Counsel.
NEWS
FOR IMMEDIATE RELEASE
#23-97
August 6, 1997
CHRISTOPHER L. DUTTON NAMED CEO OF GMP
SOUTH BURLINGTON, Vt. ... The Board of Directors of Green Mountain Power
Corporation today elected Christopher L. Dutton as President and Chief
Executive Officer of GMP. He succeeds President and CEO Douglas G. Hyde,
who chose to accept the position of President of the newly formed Green
Mountain Energy Resources L.L.C. (GMER), a national retail energy marketing
company.
Mr. Dutton, 48, also was elected to GMP's Board of Directors. He has been
Chief Financial Officer of GMP since 1995. He joined GMP in 1984 and was
General Counsel and Vice President before being named Chief Financial
Officer. Mr. Hyde had been CEO of GMP since 1993 and had held a variety of
management positions, including Executive Vice President, since joining the
Company as corporate attorney in 1977.
GMER is a company jointly-owned by GMP and the Dallas-based Wyly Family to
compete in the emerging national retail energy market. GMP owns 33 percent
of GMER, which already is registered to sell energy in California when that
market opens in January. As President of GMER, Mr. Hyde will be the top
executive and will lead former GMP management executives who have joined him
in the new venture -- Thomas Boucher, Kevin Hartley, Karen O'Neill, and
Peter Zamore.
Former Vermont Governor Thomas P. Salmon, chairman of the Board of
Directors at GMP, called the GMER venture and the management shift at GMP
"another milestone in the long history of this Vermont company." He said
the Board of Directors "unanimously supported Doug Hyde's decision to take
over the new retail operation, which we believe will add significant
long-term value to our shareholders' investment in Green Mountain Power."
Mr. Salmon said the Board's strong support for the changes was due, in
part, "to our total confidence in Chris Dutton and his management team."
Mr. Hyde said, "I have worked side by side with Chris Dutton since I
recruited him to be General Counsel 13 years ago. During that period he has
contributed enormously in several different capacities to the success of
GMP. The Company is very fortunate to have such a strong leader."
Mr. Dutton announced the senior management team at GMP, in addition to
himself: Richard Hieber, Michael Lipson, Edwin Norse, Stephen Terry and
Jonathan Winer. Currently, Mr. Hieber is Vice President, Electric
Operations and Engineering; Mr. Lipson is Assistant General Counsel; Mr.
Norse is Vice President, Financial Development; Mr. Terry is Vice President,
Customer and Government Relations; and Mr. Winer is President of Mountain
Energy, Inc., a wholly-owned subsidiary of GMP.
Mr. Dutton said the smaller senior management group will have broad
responsibilities for operation of the Company, which will continue efforts
begun earlier to flatten the organization while improving productivity and
performance. In 1992, GMP had 392 employees. With the latest
organizational changes, the workforce will be about 330.
Mr. Dutton said, "The separation of the competitive retail energy company
from GMP is the final step in a transition that has been in progress for
three years. We have known this day would arrive with the opening up of big
markets like California and we're convinced that Doug and his management
team at GMER will succeed."
Until now, he said, GMP shareholders have financed the development work for
the retail operation. The Wyly Family will provide future development
financing for GMER, limiting GMP shareholders' future financial risk while
preserving their opportunity to participate in the success of the retail
company.
Mr. Dutton noted that most of GMP's 345 employees have been involved
entirely with operations of the regulated Vermont utility and thus their
work will not be greatly affected by creation of the new retail company.
"Our business continues to focus on supplying electric service to 83,000
Vermont customers," he said. "Unless the industry is restructured in
Vermont, we will provide the electricity and deliver it to homes and
businesses. If restructuring is enacted here, we will continue to provide
the distribution service to those same customers regardless who sells them
the electricity. In addition, we'll continue our efforts to pursue other
opportunities to develop new business ideas to benefit shareholders. We're
thrilled at the prospect for shareholder value presented by GMER and we will
seek new additional financial opportunities as we go forward."
