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 March 31, 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 March 31, 1997
$3.33 1/3 Par Value 5,065,551
<TABLE>
GREEN MOUNTAIN POWER CORPORATION
Consolidated Comparative Balance Sheets
(Unaudited)
Part 1 - Item 1
<CAPTION>
March 31 December 31
----------------------------------- ----------------
1997 1996 1996
---------------- ---------------- ----------------
(In thousands) (In thousands)
<S> <C> <C> <C>
ASSETS
Utility Plant
Utility plant, at original cost.................... $248,514 $240,298 $248,135
Less accumulated depreciation...................... 83,652 78,085 81,286
---------------- ---------------- ----------------
Net utility plant................................ 164,862 162,213 166,849
Property under capital lease....................... 9,006 9,778 9,006
Construction work in progress...................... 17,073 10,041 13,998
---------------- ---------------- ----------------
Total utility plant, net......................... 190,941 182,032 189,853
---------------- ---------------- ----------------
Other Investments
Associated companies, at equity ................... 15,776 16,052 15,769
Other investments.................................. 5,137 4,516 4,865
---------------- ---------------- ----------------
Total other investments.......................... 20,913 20,568 20,634
---------------- ---------------- ----------------
Current Assets
Cash............................................... 88 616 238
Temporary investments.............................. 6,980 -- --
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 17,002 19,554 17,733
Accrued utility revenues .......................... 5,870 5,951 6,662
Fuel, materials and supplies, at average cost...... 3,607 3,188 3,621
Prepayments........................................ 1,783 1,843 2,206
Other.............................................. 348 227 441
---------------- ---------------- ----------------
Total current assets............................. 35,678 31,379 30,901
---------------- ---------------- ----------------
Deferred Charges
Demand side management programs.................... 15,599 18,119 16,409
Environmental proceedings costs.................... 7,974 7,887 7,991
Purchased power costs.............................. 8,377 5,833 9,163
Other.............................................. 11,703 8,726 9,661
---------------- ---------------- ----------------
Total deferred charges........................... 43,653 40,565 43,224
---------------- ---------------- ----------------
Non-Utility
Cash and cash equivalents.......................... 143 1,427 511
Other current assets............................... 4,366 2,519 3,979
Property and equipment............................. 11,702 11,397 11,226
Intangible assets.................................. 2,239 2,466 2,555
Equity investment in energy related businesses..... 12,239 13,308 12,494
Other assets....................................... 8,232 8,484 9,162
---------------- ---------------- ----------------
Total non-utility assets......................... 38,921 39,601 39,927
---------------- ---------------- ----------------
Total Assets........................................... $330,106 $314,145 $324,539
================ ================ ================
CAPITALIZATION AND LIABILITIES
Capitalization
Common Stock Equity
Common stock,$3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,081,407, 4,897,212 and 5,037,143)........... $16,919 $16,324 $16,790
Additional paid-in capital....................... 68,732 65,320 68,226
Retained earnings................................ 27,187 27,716 26,916
Treasury stock, at cost (15,856 shares).......... (378) (378) (378)
---------------- ---------------- ----------------
Total common stock equity...................... 112,460 108,982 111,554
Redeemable cumulative preferred stock.............. 19,310 8,930 19,310
Long-term debt, less current maturities............ 94,900 83,934 94,900
---------------- ---------------- ----------------
Total capitalization........................... 226,670 201,846 225,764
---------------- ---------------- ----------------
Capital lease obligation............................... 9,006 9,778 9,006
---------------- ---------------- ----------------
Current Liabilities
Current maturuties of long-term debt............... 1,700 3,500 3,034
Short-term debt.................................... 816 13,014 1,016
Accounts payable, trade, and accrued liabilities... 4,402 3,726 6,140
Accounts payable to associated companies........... 6,913 6,232 6,621
Dividends declared................................. 381 194 381
Customer deposits.................................. 670 746 689
Taxes accrued...................................... 3,149 3,588 986
Interest accrued................................... 2,090 1,844 1,382
Deferred revenues ................................. 5,989 5,615 --
Other.............................................. 795 370 788
---------------- ---------------- ----------------
Total current liabilities...................... 26,905 38,829 21,037
---------------- ---------------- ----------------
Deferred Credits
Accumulated deferred income taxes.................. 26,500 24,651 26,726
Unamortized investment tax credits................. 4,749 5,015 4,825
Other.............................................. 23,682 22,058 23,417
---------------- ---------------- ----------------
Total deferred credits......................... 54,931 51,724 54,968
---------------- ---------------- ----------------
Non-Utility
Current liabilities................................ 1,142 1,223 1,752
Other liabilities.................................. 11,452 10,745 12,012
---------------- ---------------- ----------------
Total non-utility liabilities.................. 12,594 11,968 13,764
---------------- ---------------- ----------------
Total Capitalization and Liabilities................... $330,106 $314,145 $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
March 31
-----------------------------------------
1997 1996
----------------- -----------------
(In thousands, except amounts per share)
<S> <C> <C>
Operating Revenues ............................................. $47,204 $48,415
----------------- -----------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation .................. 7,766 7,411
Company-owned generation................................... 846 846
Purchases from others...................................... 17,780 18,668
Other operating............................................... 4,235 4,907
Transmission.................................................. 3,046 2,691
Maintenance................................................... 1,118 1,122
Depreciation and amortization................................. 4,241 3,875
Taxes other than income....................................... 1,916 1,777
Income taxes.................................................. 2,005 2,045
----------------- -----------------
Total operating expenses................................... 42,953 43,342
----------------- -----------------
Operating income......................................... 4,251 5,073
----------------- -----------------
Other Income
Equity in earnings of affiliates and non-utility operations... 419 856
Allowance for equity funds used during construction........... 194 40
Other income and deductions, net.............................. 282 15
----------------- -----------------
Total other income.......................................... 895 911
----------------- -----------------
Income before interest charges............................ 5,146 5,984
----------------- -----------------
Interest Charges
Long-term debt................................................ 1,864 1,814
Other......................................................... 76 228
Allowance for borrowed funds used during construction........ (109) (123)
----------------- -----------------
Total interest charges...................................... 1,831 1,919
----------------- -----------------
Net Income...................................................... 3,315 4,065
Dividends on preferred stock.................................... 374 190
----------------- -----------------
Net Income Applicable to Common Stock........................... $2,941 $3,875
================= =================
Common Stock Data
Earnings per share............................................ $0.58 $0.80
Cash dividends declared per share............................. $0.53 $0.53
Weighted average shares outstanding........................... 5,044 4,860
Consolidated Comparative Statements of Retained Earnings
(Unaudited)
Balance - beginning of period................................... $26,916 $26,412
Net Income...................................................... 3,315 4,065
----------------- -----------------
30,231 30,477
----------------- -----------------
Cash Dividends - redeemable cumulative preferred stock.......... 374 190
- common stock................................... 2,670 2,571
----------------- -----------------
3,044 2,761
----------------- -----------------
Balance - end of period......................................... $27,187 $27,716
================= =================
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>
Three Months Ended
March 31
---------------------------------------
1997 1996
----------------- -----------------
(In thousands)
<S> <C> <C>
Operating Activities:
Net Income........................................................... $3,315 $4,065
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 4,241 3,875
Dividends from associated companies less equity income........... (7) (29)
Allowance for funds used during construction..................... (303) (164)
Deferred purchased power costs................................... (14) (145)
Amortization of purchased power costs............................ (165) 1,715
Deferred income taxes............................................ (99) (515)
Deferred revenues ............................................... 5,989 5,615
Amortization of investment tax credits........................... (76) (92)
Environmental proceedings costs.................................. (417) (365)
Conservation expenditures........................................ (607) (891)
Changes in:
Accounts receivable............................................ 731 (1,474)
Temporary investments ......................................... (6,980) --
Accrued utility revenues....................................... 792 572
Fuel, materials, and supplies.................................. 14 124
Prepayments and other current assets........................... 130 1,683
Accounts payable............................................... (1,445) (2,582)
Taxes accrued.................................................. 2,163 3,017
Interest accrued............................................... 708 (3)
Other current liabilities...................................... (623) (13)
Other............................................................ 368 336
----------------- -----------------
Net cash provided by operating activities.......................... 7,715 14,729
----------------- -----------------
Investing Activities:
Construction expenditures.......................................... (3,553) (2,275)
Investment in nonutility property.................................. (252) (2,145)
----------------- -----------------
Net cash used in investing activities............................ (3,805) (4,420)
----------------- -----------------
Financing Activities:
Issuance of common stock........................................... 635 1,270
Short-term debt, net............................................... (200) 4,599
Reduction in long-term debt........................................ (1,819) (11,533)
Cash dividends..................................................... (3,044) (2,762)
----------------- -----------------
Net cash used in financing activities............................ (4,428) (8,426)
----------------- -----------------
Net increase (decrease) in cash and cash equivalents............... (518) 1,883
Cash and Cash equivalents at beginning of period................... 749 160
----------------- -----------------
Cash and Cash Equivalents at End of Period............................. $231 $2,043
================= =================
Supplemental Disclosure of Cash Flow Information:
Cash paid during the quarter for:
Interest (net of amounts capitalized)........................... $1,176 $1,987
Income taxes.................................................... 158 2
The accompanying notes are an integral part of the consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 March 31, 1997 and 1996, the
Company had recorded deferred revenues of $6.0 million and $5.6 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
March 31
------------------
1997 1996
---- ----
(In thousands)
Revenue . . . . . . . . . . . . . . . . . . . $3,537 $3,925
Expenses . . . . . . . . . . . . . . . . . . . 3,677 3,557
------- ------
Net Income . . . . . . . . . . . . . . . . . $ (140) $ 368
======= ======
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
March 31
------------------
1997 1996
---- ----
(In thousands)
Vermont Yankee Nuclear Power Corporation
Gross Revenue . . . . . . . . . . . . . . . . . $40,421 $39,756
Net Income Applicable to Common Stock . . . . . 1,775 1,598
Company's Equity in Net Income . . . . . . . . 337 280
Vermont Electric Power Company, Inc.
Gross Revenue . . . . . . . . . . . . . . . . . $12,436 $12,289
Net Income Before Dividends . . . . . . . . . . 429 298
Company's Equity in Net Income
(Includes preferred equity) . . . . . . . . . 113 82
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. 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.
6. 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."
7. 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
MARCH 31, 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 first quarter of 1997 were
$0.58, compared to $0.80 per share in the first quarter of 1996. The
decrease in earnings was primarily due to a reduction in sales of
electricity caused by warmer than normal winter weather.
Operating Revenues and MWh Sales
Operating revenues, megawatthour (MWh) sales and average number of
customers are summarized as follows:
Three Months Ended
March 31
------------------
1997 1996
---- ----
Operating Revenues (In thousands)
Retail . . . . . . . . . . . . . . . . . . $ 41,678 $ 41,102
Sales for Resale . . . . . . . . . . . . . 4,765 6,470
Other . . . . . . . . . . . . . . . . . . 761 843
-------- --------
Total Operating Revenues . . . . . . . . $ 47,204 $ 48,415
======== ========
MWh Sales
Retail . . . . . . . . . . . . . . . . . . 476,612 485,091
Sales for Resale . . . . . . . . . . . . . 160,936 239,287
------- -------
Total MWh Sales . . . . . . . . . . . . . 637,548 724,378
======= =======
Average Number of Customers
Residential . . . . . . . . . . . . . . . 70,562 70,112
Commercial & Industrial . . . . . . . . . 11,955 11,799
Other . . . . . . . . . . . . . . . . . . 77 74
------ ------
Total Customers . . . . . . . . . . . . . 82,594 81,985
====== ======
Total operating revenues decreased 2.5 percent in the first quarter of
1997 compared to the same period in 1996. Retail revenues increased 1.4
percent in the first quarter of 1997 over the same period in 1996. A 1.8
percent decrease in retail sales of electricity, resulting from winter
temperatures that were 5.7 percent warmer than normal and 4.3 percent
warmer than those in 1996, was slightly offset by a 5.25 percent retail
rate increase that went into effect in June 1996. Wholesale revenues
decreased 26.4 percent in the first quarter of 1997 compared to the same
period in 1996 primarily due to a reduction in off-system sales, having
a minimal impact on earnings.
Operating Expenses
Power supply expenses decreased 2.0 percent in the first quarter of 1997
compared to the same period in 1996. Power supply expenses from Vermont
Yankee increased 4.8 percent in the first quarter of 1997 over the same
period in 1996 primarily due to increased costs associated with plant
engineering studies. This increase was more than offset by a 4.8 percent
decrease in power purchased from others primarily due to the recognition
of $800,000 in income, 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 in the amount 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. The remaining
$7.2 million will be recognized in income over the remaining 9 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 complete discussion of this Memorandum of
Understanding.)
On April 25, 1997, Vermont Yankee experienced an unplanned outage that
occurred in conjunction with calibration of certain reactor systems.
Vermont Yankee had planned to shut down the facility the following week
for repairs. Vermont Yankee began this planned work earlier since the
reactor was down and all work was completed by May 8, 1997. The Company
anticipates that additional costs associated with replacement power will
be approximately $450,000.
Other operating expenses decreased 13.7 percent in the first quarter of
1997 compared to the same period in 1996 primarily due to an increase in
work performed on behalf of Green Mountain Resources, Inc. (GMRI) and
Green Mountain Energy Partners L.L.C. (GMEP), effectively reducing
payroll expenses for the Company. (See Other Income below.)
Transmission expenses increased 13.2 percent in the first 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.
Maintenance expenses were virtually unchanged in the first quarter of
1997 compared to the same period in 1996.
Depreciation and amortization expenses increased 9.4 percent in the
first quarter of 1997 over the same period in 1996 primarily due to the
amortization of expenditures related to energy conservation programs and
the Pine Street Marsh environmental matter and to depreciation
associated with additional investment in the Company's utility plant.
Taxes other than income taxes increased 7.8 percent in the first quarter
of 1997 over the same period in 1996 primarily due to an increase in
municipal property taxes. The Vermont legislature is currently
considering legislative proposals that would change the method of
municipal property taxation in Vermont. The Company is unable to
predict at this time whether such legislation, if enacted, will have any
material impact on the Company.
Income Taxes
Income taxes decreased 2.0 percent in the first quarter of 1997 compared
to the same period in 1996 primarily due to a decrease in taxable
income.
Other Income
Other income decreased 1.9 percent in the first quarter of 1997 compared
to the same period in 1996 primarily due to a $54,000 decrease in
earnings experienced by Green Mountain Propane Gas Company, the
Company's wholly-owned propane subsidiary, a $122,000 decrease in
earnings experienced by Mountain Energy, Inc., the Company's wholly-
owned subsidiary that invests in energy generation and efficiency
projects, and a $332,000 loss experienced by GMRI, the Company's wholly-
owned subsidiary that participates in various pilot programs providing
retail customer choice in the purchase of electricity. The loss
experienced by GMRI was mitigated to a large extent by the
aforementioned reduction in the Company's payroll expenses for work
performed on the behalf of GMRI and GMEP. GMRI intends to participate in
the retail marketing of electricity in states that are opening their
markets to competition in 1998, including California. GMRI is seeking
investment partners to provide the funds required for these retail
activities.
The decrease in other income was offset to a large extent by 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), and by an increase in the
allowance for equity funds used during construction resulting from
higher average construction work in progress balances during the period.
Interest Charges
Interest charges decreased 4.6 percent in the first 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 partially offset by an
increase in long-term interest charges related to the sale of $10
million and $4 million of the Company's first mortgage bonds in November
and December 1996, respectively.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 1997, construction and conservation
expenditures totaled $4.0 million. Such expenditures in 1997 are
expected to be approximately $22.4 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 March 31, 1997, the Company had lines of credit with six banks
totaling $40.0 million, with borrowings outstanding of $800,000.
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.
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 strong 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. Should restructuring be approved in Vermont or 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 Vermont Public Service Board (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), the 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 is being
opposed by the Company and other utilities in Vermont. 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 start in October
1998 and the VPSB is 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 this legislative session (which is scheduled to end
in May 1997) to act upon a utility restructuring bill. The Company has
continued to urge the enactment during this legislative session of
restructuring legislation compatible with the terms of the MOU or, at a
minimum, legislation that would permit the securitization of stranded
cost recovery through the authorization of a grantor trust financing
mechanism. However, there is no assurance that any restructuring
legislation will be enacted by the Vermont General Assembly 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. In addition, the Company intends to file an
application with the VPSB for a sizable rate increase if no
restructuring legislation is enacted during this legislative session in
order to recover cost increases, including Hydro-Quebec power supply
costs which are expected to increase from $26 million in 1997 to $43
million in 1998.
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 or SFAS 5 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) has agreed to
review accounting issues associated with electric utility restructuring.
Under generally accepted accounting principles, the Company will follow
any EITF consensus on accounting issues relative to restructuring,
including the continued application of 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 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.
GREEN MOUNTAIN POWER CORPORATION
March 31, 1997
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings
See Notes 3 and 4 of Notes to Consolidated Financial Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
NONE
ITEM 5. Other Information
NONE
ITEM 6. (a) EXHIBITS
27 Financial Data Schedule
(b) REPORTS ON FORM 8-K
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: May 14, 1997 /s/ C. L. Dutton
C. L. Dutton, Vice President, Chief
Financial Officer and Treasurer
Date: May 14, 1997 /s/ R. J. Griffin
R. J. Griffin, Controller
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This schedule contains summary financial information extracted from the
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