May 12, 2000
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________________
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2000
--------------
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 INCORPORATION (I.R.S. EMPLOYER
IDENTIFICATION NO.)
OR ORGANIZATION)
163 ACORN LANE
COLCHESTER, VT 05446
- --------------------- -----------
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 AT APRIL 28, 2000
- --------------------------- -----------------------------------
$3.33 1/3 PAR VALUE 5,481,977
<PAGE>
<TABLE>
<CAPTION>
PART I, ITEM 1
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION
UNAUDITED
----------
MARCH 31 MARCH 31 DECEMBER 31
2000 1999 1999
---------- --------- ------------
(In thousands)
<S> <C> <C> <C>
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . . $ 285,071 $ 276,614 $ 283,917
Less accumulated depreciation . . . . . . . . . 105,490 96,804 102,854
---------- --------- ------------
Net utility plant . . . . . . . . . . . . . . . 179,581 179,810 181,063
Property under capital lease. . . . . . . . . . 7,038 7,696 7,038
Construction work in progress . . . . . . . . . 5,310 7,699 4,795
---------- ------------
Total utility plant, net. . . . . . . . . . . 191,929 195,205 192,896
---------- --------- ------------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . . 14,653 15,057 14,545
Other investments . . . . . . . . . . . . . . . 5,990 5,763 6,120
---------- ------------
Total other investments . . . . . . . . . . . 20,643 20,820 20,665
---------- --------- ------------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . 7,514 11,574 656
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $398 and $449. . . . . . . . . . . . . . . 20,339 18,457 18,503
Accrued utility revenues. . . . . . . . . . . . 7,019 6,223 6,969
Fuel, materials and supplies, at average cost . 3,272 3,140 3,290
Prepayments . . . . . . . . . . . . . . . . . . 1,591 1,893 3,438
Other . . . . . . . . . . . . . . . . . . . . . 217 213 382
---------- ------------
Total current assets. . . . . . . . . . . . . 39,952 41,500 33,238
---------- --------- ------------
DEFERRED CHARGES
Demand side management programs . . . . . . . . 7,158 9,493 7,640
Purchased power costs . . . . . . . . . . . . . 11,281 4,062 7,435
Pine Street Barge Canal . . . . . . . . . . . . 8,700 5,000 8,700
Other . . . . . . . . . . . . . . . . . . . . . 17,456 8,689 18,078
---------- ------------
Total deferred charges. . . . . . . . . . . . 44,595 27,244 41,853
---------- --------- ------------
NON-UTILITY
Cash and cash equivalents . . . . . . . . . . . 41 149 40
Other current assets. . . . . . . . . . . . . . 8 2,682 8
Property and equipment. . . . . . . . . . . . . 253 431 253
Intangible assets . . . . . . . . . . . . . . . - 1,585 -
Equity investment in energy related businesses. - 11,804 -
Business segment held for disposal. . . . . . . 9,797 - 9,477
Other assets. . . . . . . . . . . . . . . . . . 1,306 9,664 1,321
------------
Total non-utility assets. . . . . . . . . . . 11,405 26,315 11,099
---------- --------- ------------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . $ 308,524 $ 311,084 $ 299,751
========== ========= ============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION
UNAUDITED
-----------
MARCH 31 MARCH 31 DECEMBER 31
2000 1999 1999
----------- ---------- -------------
(In thousands except share data)
<S> <C> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock equity
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,463,948, 5,342,381 and 5,425,571). . . . . . . $ 18,215 $ 17,799 $ 18,085
Additional paid-in capital . . . . . . . . . . . 72,766 72,123 72,594
Retained earnings. . . . . . . . . . . . . . . . 13,046 19,425 10,344
Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378)
----------- ---------- -------------
Total common stock equity. . . . . . . . . . . 103,649 108,969 100,645
Redeemable cumulative preferred stock. . . . . . 12,795 14,435 12,795
Long-term debt, less current maturities. . . . . 81,800 88,500 81,800
----------- ---------- -------------
Total capitalization . . . . . . . . . . . . . 198,244 211,904 195,240
----------- ---------- -------------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 7,038 7,696 7,038
----------- ---------- -------------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 1,640 1,650 1,640
Current maturities of long-term debt . . . . . . 6,700 1,700 6,700
Short-term debt. . . . . . . . . . . . . . . . . - - 7,900
Accounts payable, trade and accrued liabilities. 6,814 4,826 6,684
Accounts payable to associated companies . . . . 7,057 5,664 6,577
Dividends declared . . . . . . . . . . . . . . . 285 364 285
Customer deposits. . . . . . . . . . . . . . . . 351 361 361
Taxes accrued. . . . . . . . . . . . . . . . . . 756 2,472 -
Interest accrued . . . . . . . . . . . . . . . . 1,883 1,888 1,169
Deferred revenues. . . . . . . . . . . . . . . . 7,163 6,146 -
Other. . . . . . . . . . . . . . . . . . . . . . 5,371 3,803 7,032
-------------
Total current liabilities. . . . . . . . . . . 38,020 28,874 38,348
----------- ---------- -------------
DEFERRED CREDITS
Accumulated deferred income taxes. . . . . . . . 25,718 23,780 25,201
Unamortized investment tax credits . . . . . . . 3,907 4,189 3,978
Pine Street Barge Canal site cleanup . . . . . . 8,985 5,000 8,815
Other. . . . . . . . . . . . . . . . . . . . . . 26,612 21,734 21,131
-------------
Total deferred credits . . . . . . . . . . . . 65,222 54,703 59,125
----------- ---------- -------------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Current liabilities. . . . . . . . . . . . . . . - 525 -
Other liabilities. . . . . . . . . . . . . . . . - 7,382 -
----------- ---------- -------------
Total non-utility liabilities. . . . . . . . . - 7,907 -
----------- ---------- -------------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $ 308,524 $ 311,084 $ 299,751
=========== ========== =============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
FOR THE THREE MONTHS ENDED
MARCH 31,
2000 1999
-------- --------
(In thousands, except per share data)
<S> <C> <C>
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . $67,712 $59,018
-------- --------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . . . . . . . . 8,060 8,359
Company-owned generation. . . . . . . . . . . . . . . . . . . . . . . . . 1,204 1,025
Purchases from others . . . . . . . . . . . . . . . . . . . . . . . . . . 36,646 28,506
Other operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,627 5,292
Transmission. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,483 2,695
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,626 1,570
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 4,167 4,240
Taxes other than income . . . . . . . . . . . . . . . . . . . . . . . . . 2,027 1,814
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,259 1,611
--------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . 63,099 55,112
-------- --------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,613 3,906
-------- --------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations . . . . . . . 624 1,335
Allowance for equity funds used during construction . . . . . . . . . . . 62 20
Other income (deductions), net. . . . . . . . . . . . . . . . . . . . . . 185 53
--------
TOTAL OTHER INCOME (DEDUCTIONS). . . . . . . . . . . . . . . . . . . . 871 1,408
-------- --------
INCOME BEFORE INTEREST CHARGES. . . . . . . . . . . . . . . . . . . . . . 5,484 5,314
-------- --------
Interest charges
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,661 1,703
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144 150
Allowance for borrowed funds used during construction . . . . . . . . . . (40) (14)
--------
TOTAL INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . 1,765 1,839
-------- --------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . . . . 3,719 3,475
DISCONTINUED OPERATIONS
Dividends on preferred stock. . . . . . . . . . . . . . . . . . . . . . . 270 305
-------- --------
Income (loss) from continuing operations. . . . . . . . . . . . . . . . . 3,449 3,170
Net income (loss) from discontinued segment
operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - (522)
Loss on disposal, including provisions for
operating losses during phaseout period . . . . . . . . . . . . . . . . . - -
-------- --------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . $ 3,449 $ 2,648
======== ========
Common stock data
Basic and diluted earnings (loss) per share from discontinued operations. $ 0.00 ($0.10)
Basic and diluted earnings (loss) per share from continuing operations. . 0.63 0.60
Basic and diluted earnings (loss) per share . . . . . . . . . . . . . . . 0.63 0.50
Cash dividends declared per share . . . . . . . . . . . . . . . . . . . . 0.14 0.14
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . 5,437 5,318
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period . . . . . . . . . . . . . . . . . . . . . . $10,344 $17,508
Net Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,719 2,953
Cash Dividends-redeemable cumulative preferred stock. . . . . . . . . . . (270) (305)
Cash Dividends-common stock . . . . . . . . . . . . . . . . . . . . . . . (747) (731)
Balance - end of period . . . . . . . . . . . . . . . . . . . . . . . . . $13,046 $19,425
======== ========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
FOR THE TWELVE MONTHS ENDED
MARCH 31,
2000 1999
--------- ---------
(In thousands, except per share data)
<S> <C> <C>
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . $259,741 $196,391
--------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . . . . . . . . 34,688 33,147
Company-owned generation. . . . . . . . . . . . . . . . . . . . . . . . . 5,761 4,602
Purchases from others . . . . . . . . . . . . . . . . . . . . . . . . . . 150,839 87,312
Other operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,917 22,167
Transmission. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,589 9,823
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,783 5,558
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 16,114 15,874
Taxes other than income . . . . . . . . . . . . . . . . . . . . . . . . . 7,507 7,100
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,890 1,745
---------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . 251,088 187,328
--------- ---------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,653 9,063
--------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations . . . . . . . 1,700 2,771
Allowance for equity funds used during construction . . . . . . . . . . . 176 70
Other income (deductions), net. . . . . . . . . . . . . . . . . . . . . . 1,040 862
---------
TOTAL OTHER INCOME (DEDUCTIONS). . . . . . . . . . . . . . . . . . . . 2,916 3,703
--------- ---------
Income before interest charges. . . . . . . . . . . . . . . . . . . . . . 11,569 12,766
--------- ---------
Interest charges
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,674 6,896
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 552 950
Allowance for borrowed funds used during construction . . . . . . . . . . (117) (71)
---------
TOTAL INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . 7,109 7,775
--------- ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . . . . 4,460 4,991
DISCONTINUED OPERATIONS
Dividends on preferred stock. . . . . . . . . . . . . . . . . . . . . . . 1,119 1,260
--------- ---------
Income (loss) from continuing operations. . . . . . . . . . . . . . . . . 3,341 3,731
Net income (loss) from discontinued segment
operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (82) (1,851)
Loss on disposal, including provisions for
operating losses during phaseout period . . . . . . . . . . . . . . . . . (6,676) -
--------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . ($3,417) $ 1,880
========= =========
Common stock data
Basic and diluted earnings (loss) per share from discontinued operations. ($1.25) ($0.35)
Basic and diluted earnings (loss) per share from continuing operations. . 0.62 0.71
Basic and diluted earnings (loss) per share . . . . . . . . . . . . . . . (0.63) 0.36
Cash dividends declared per share . . . . . . . . . . . . . . . . . . . . 0.55 0.83
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . 5,390 5,273
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period . . . . . . . . . . . . . . . . . . . . . . $ 19,425 $ 21,884
Net Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . ($2,298) $ 3,140
Cash Dividends-redeemable cumulative preferred stock. . . . . . . . . . . (1,119) (1,260)
Cash Dividends-common stock . . . . . . . . . . . . . . . . . . . . . . . (2,962) (4,339)
Balance - end of period . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,046 $ 19,425
========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
GREEN MOUNTAIN POWER CORPORATION
FOR THE THREE MONTHS ENDED MARCH 31,
2000 1999
-------- --------
(In thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income (Loss) . . . . . . . . . . . . . . . . . . . . $ 3,449 $ 2,953
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . 4,167 4,240
Dividends from associated companies less equity income. (111) (10)
Allowance for funds used during construction. . . . . . (102) (34)
Amortization of purchased power costs . . . . . . . . . 1,500 1,889
Deferred income taxes . . . . . . . . . . . . . . . . . 518 391
Deferred revenues . . . . . . . . . . . . . . . . . . . 7,163 6,146
Provision for loss on segment disposal. . . . . . . . . - -
Deferred purchased power costs. . . . . . . . . . . . . 54 (243)
Deferred arbitration costs. . . . . . . . . . . . . . . (457) -
Amortization of investment tax credits. . . . . . . . . (71) (71)
Environmental proceedings costs . . . . . . . . . . . . (80) (243)
Conservation expenditures . . . . . . . . . . . . . . . (462) (311)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . (1,836) 519
Accrued utility revenues. . . . . . . . . . . . . . . (50) 388
Fuel, materials and supplies. . . . . . . . . . . . . 18 (1)
Prepayments and other current assets. . . . . . . . . 773 5,156
Accounts payable. . . . . . . . . . . . . . . . . . . 611 (2,106)
Taxes accrued . . . . . . . . . . . . . . . . . . . . 1,997 2,102
Interest accrued. . . . . . . . . . . . . . . . . . . 714 685
Other current liabilities . . . . . . . . . . . . . . (1,671) (1,624)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 1,569 650
-------- --------
Net cash provided by continuing operations. . . . . . . 17,691 20,476
Net change in discontinued segment. . . . . . . . . . . (320) -
-------- --------
Net cash provided by operating activities . . . . . . . 17,371 20,476
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . (1,852) (1,539)
Investment in nonutility property . . . . . . . . . . . . (44) 19
-------- --------
Net cash provided by (used in) investing activities . . (1,896) (1,520)
-------- --------
FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . 301 297
Short-term debt, net. . . . . . . . . . . . . . . . . . . (7,900) (7,000)
Cash dividends. . . . . . . . . . . . . . . . . . . . . . (1,017) (1,036)
Reduction in preferred stock. . . . . . . . . . . . . . . - -
Reduction in long-term debt . . . . . . . . . . . . . . . - (84)
-------- --------
Net cash provided by (used in) financing activities . . (8,616) (7,823)
-------- --------
Net increase in cash and cash equivalents . . . . . . . . 6,859 11,133
Cash and cash equivalents at beginning of period. . . . . 696 590
-------- --------
Cash and cash equivalents at end of period. . . . . . . . $ 7,555 $11,723
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . $ 1,029 $ 1,103
Income taxes, net . . . . . . . . . . . . . . . . . . . - -
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
PART I -- ITEM 1
1. SIGNIFICANT ACCOUNTING POLICIES
It is our opinion that the financial information contained in this report
reflects all normal, recurring adjustments necessary to present a fair statement
of results for the period reported, but such results are not necessarily
indicative of results to be expected for the year due to the seasonal nature of
our business and includes other adjustments discussed elsewhere in this report
necessary to reflect fairly the results of the interim periods. Certain
information and footnote disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted in this Form 10-Q pursuant to the rules and regulations of
the Securities and Exchange Commission. However, the disclosures herein, when
read with the annual report for 1999 filed on Form 10-K, and the Form 8-K filed
on April 19, 2000, are adequate to make the information presented not
misleading.
The Vermont Public Service Board ("VPSB"), the regulatory commission in
Vermont, sets the rates we charge our customers for their electricity. We
charge our customers higher rates for billing cycles in December through March
and lower rates for the remaining months. These are called seasonally
differentiated rates. In order to eliminate the impact of the seasonally
differentiated rates, we defer some of the revenues from those four months and
account for them in later periods when we have lower revenues or higher costs.
By deferring certain revenues we are able to better match our revenues to our
costs. On March 31, 2000, there was deferred revenue of $7.2 million compared
with $6.1 million at March 31, 1999. These deferred revenues are accreted into
revenue throughout the current year.
UNREGULATED OPERATIONS
We have or have had unregulated, wholly-owned subsidiaries: Mountain
Energy, Inc. ("MEI"), Green Mountain Propane Gas Company Limited ("GMPG"), GMP
Real Estate Corporation, Lease-Elec, Inc., Green Mountain Resources, Inc.
("GMRI"), and Green Mountain Energy Resources, LLC("GMER"). Lease-Elec, Inc.
has been inactive for a number of years and was dissolved April 3, 2000. GMER's
sale was completed in the first quarter of 1999. On June 30, 1999, we decided
to sell the assets of MEI, and report its results as income (loss) from
operations of a discontinued segment. See the disclosure under the caption
"Segments and Related Information" for a more detailed discussion. We also
have a rental water heater program that is not regulated by the VPSB. The
results of the operations of these subsidiaries (excluding MEI) and the rental
water heater program are included in earnings of affiliates and non-utility
operations in the Other Income section of the Consolidated Comparative Income
Statements.
2. INVESTMENT IN ASSOCIATED COMPANIES
We recognize net income from our affiliates (companies in which we have
ownership interests) listed below based on our percentage ownership (equity
method).
VERMONT YANKEE NUCLEAR POWER CORPORATION
Percent ownership: 17.9% common
<TABLE>
<CAPTION>
Three months ended
in thousands March 31
2000 1999
------------------- -------
<S> <C> <C>
Gross Revenue . . . . $ 40,692 $43,777
Net Income Applicable 1,744 1,656
to Common Stock
Equity in Net Income. 314 294
</TABLE>
On October 15, 1999, the owners of Vermont Yankee Nuclear Power Corporation
accepted a bid from AmerGen Energy Company for the Vermont Yankee generating
plant. The asset sale will require numerous regulatory approvals, including the
Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the
Securities and Exchange Commission and the VPSB. Assuming a final closing date
for the transaction of July 1, 2000, AmerGen will pay Vermont Yankee
approximately $23.5 million for the plant and property.
As a condition of the sale, Vermont Yankee's current owners will make a
one-time and final payment of approximately $54.3 million to pre-pay the plant's
decommissioning fund. The final payment may vary depending on the earnings of
the decommissioning trust fund during the period prior to completion of the
sale. In return, AmerGen will assume full responsibility for all future
operating costs and the obligation to decommission the plant at the end of its
life. The Company has agreed to buy power from the plant for periods that may
extend up to twelve years. The Company and the other current owners are also
responsible to Vermont Yankee for their share of the unrecovered plant and other
costs resulting from the sale.
<TABLE>
<CAPTION>
Vermont Electric Power Company
Percent Ownership: 29.5% common
30.0% preferred
Three months ended
in thousands March 31
2000 1999
------------------- ------
<S> <C> <C>
Gross Revenue. . . . $ 6,715 $6,934
Net Income . . . . . 273 292
Equity in Net Income 84 86
</TABLE>
3. COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL MATTERS
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air
and aesthetic requirements as administered by local, state and federal
regulatory agencies. We believe that we are in substantial compliance with these
requirements, and that there are no outstanding material complaints about the
Company's compliance with present environmental protection regulations, except
for developments related to the Pine Street Barge Canal site.
PINE STREET BARGE CANAL SITE
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. We have
previously been notified by the Environmental Protection Agency ("EPA") that we
are one of several potentially responsible parties ("PRPs") for cleanup of the
Pine Street Barge Canal site in Burlington, Vermont, where coal tar and other
industrial materials were deposited. We remain a PRP for other past, ongoing and
future response costs. In September 1999, we negotiated a final settlement with
the United States, the State of Vermont (State), and other parties to a Consent
Decree that covers claims with respect to the site and implementation of the
selected site cleanup remedy. The Consent Decree has been approved by the
federal district court, and addresses claims by the EPA for past Pine Street
Barge Canal site costs, natural resource damage claims and claims for past and
future oversight costs. The Consent Decree also provides for the design and
implementation of response actions at the site.
As of March 31, 2000, our total expenditures related to the Pine Street
Barge Canal site since 1982 were approximately $22.3 million. This includes
amounts not recovered in rates, amounts recovered in rates, and amounts for
which rate recovery has been sought but which are presently awaiting further
VPSB action. The bulk of these expenditures consisted of transaction costs.
Transaction costs include legal and consulting costs associated with the
Company's opposition to the EPA's earlier proposals for a more expensive remedy
at the site, litigation and related costs necessary to obtain settlements with
insurers and other PRP's to provide amounts required to fund the clean up
(remediation costs), and to address liability claims at the site. A smaller
amount of past expenditures was for site-related response costs, including costs
incurred pursuant to EPA and state orders that resulted in funding response
activities at the site, and to reimbursing the EPA and the State for oversight
and related response costs. The EPA and the State have asserted and affirmed
that all costs related to these orders are appropriate costs of response under
CERCLA for which the Company and other PRPs were legally responsible.
We estimate that we have recovered or secured, or will recover, through
settlements of litigation claims against insurers and other parties, amounts
that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We currently estimate
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, are likely to be in the range of $8.7 to $12.5 million. The estimated
liability is not discounted, and it is possible that our estimate of future
costs could change by a material amount. We also have recorded an offsetting
regulatory asset and we believe that it is probable that we will receive future
revenues to recover these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and
received recovery for ongoing expenses associated with the Pine Street Barge
Canal site. While reserving the right to argue in the future about the
appropriateness of full rate recovery of the site related costs, the Company and
the Vermont Department of Public Service, (the Department), and as applicable,
other parties, reached agreements in these cases that the full amount of the
site-related costs reflected in those rate cases should be recovered in rates.
We proposed in our rate filing made on June 16, 1997 recovery of an
additional $3.0 million in such expenditures. In an Order in that case released
March 2, 1998, the VPSB suspended the amortization of expenditures associated
with the Pine Street Barge Canal site pending further proceedings. Although it
did not eliminate the rate base deferral of these expenditures, or make any
specific order in this regard, the VPSB indicated that it was inclined to agree
with other parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance carriers
and other PRP's, should be shared between customers and shareholders of the
Company. In response to our Motion for Reconsideration, the VPSB on June 8,
1998 stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
1997 RETAIL RATE CASE
On June 16, 1997, the Company filed a request with the VPSB to increase
retail rates by 16.7 percent ($26 million in additional annual revenues) and to
increase the target return on common equity from 11.25 percent to 13 percent.
In our final submissions to the VPSB we asked for an increase of 14.4 percent
($22 million in additional annual revenues) due to changed estimates of costs to
be incurred in the rate year. On March 2, 1998, the VPSB released its Order
dated February 27, 1998 in the then pending rate case. The VPSB authorized us
to increase our rates by 3.61 percent, which gave us increased annual revenues
of $5.6 million.
The difference between the $22 million we asked for and the $5.6 million
the VPSB authorized was due to the following:
* disallowance of the cost of power associated with the Hydro-Qu bec
contract discussed below;
* the VPSB's modification of our calculation of rate base;
* the exclusion of future capital projects from rate base;
* suspension of recovery of Pine Street Barge Canal site expenditures;
* various cost of service reductions in payroll and operations and
maintenance; and
* a reduction in our requested allowed return on equity from 13 percent to
11.25 percent.
The VPSB Order denied us the right to charge customers $5.48 million of
the annual costs for power purchased under our contract with Hydro-Qu bec. The
VPSB denied recovery of these costs for the following reasons:
* the VPSB claimed that we had acted imprudently by committing to the power
contract with Hydro-Qu bec in August 1991 (the imprudence disallowance); and
* to the extent that the costs of power to be purchased from Hydro-Qu bec
are now higher than current estimates of market prices for power during the
Contract term, after accounting for the imprudence disallowance, the contract
power is not "used and useful".
Generally accepted accounting principles required that we record in the
first quarter of 1998 the losses resulting from the disallowed recovery of a
portion of the 1998 Hydro-Qu bec power contract costs. The amount charged to
income of $4.6 million (pre-tax) was less than the full disallowance because we
expected that new rates would become effective in January 1999 as the result of
our May 8, 1998 rate filing, discussed below.
In its February 27, 1998 Order, the VPSB talked about its policies that do
not allow a utility to recover imprudent expenditures and the costs of power
supply contract purchases that the VPSB decides are not used and useful. The
VPSB stated in its Order that the methods and measures used in this rate case
were provisional and applied to this rate case only. If the VPSB were to apply
the same, or similar, methods and measures that they used in the 1997 rate case
Order to future power contract costs in our 1998 Retail Rate Case, we would
likely be required to recognize a charge to income of approximately $154 million
before income taxes. The $154 million estimate represents primarily the 20
percent disallowance for Hydro-Qu bec power costs that the VPSB considered
imprudent in its 1997 order. We are unable to estimate the loss (from
disallowance) to be recorded for power purchased after December 31, 2000, if
any, until the pending 1998 rate case is completed.
On March 20, 1998, we filed with the VPSB a Motion for Reconsideration of
and to Alter or Amend certain aspects of the VPSB's Order released on March 2,
1998. Immediately following the issuance of the June 8, 1998 VPSB order on our
Motion for Reconsideration, which mainly reaffirmed the earlier order, Duff &
Phelps and Standard & Poor's lowered our securities credit ratings. Moody's
also subsequently lowered our securities credit ratings.
In June 1998, we appealed the VPSB's February 27, 1998 order and the June
8, 1998 reconsideration order to the Vermont Supreme Court. Specifically, we are
appealing the VPSB's determination that we were imprudent in committing to the
Hydro-Qu bec contract in August 1991, and its ruling that because the contract
power is priced over-market under current forecasts of market prices, it is
therefore considered "not used and useful". The Company asserts, among other
arguments, that the VPSB's order deprives the Company's shareholders of their
property in an unconstitutional manner. The Court, with briefs and arguments
completed, has the appeal under advisement. If not changed, the VPSB's decision
could have a significant negative impact on our reported financial condition,
and could impact our credit ratings, dividend policy and financial viability.
1998 RETAIL RATE CASE
On May 8, 1998, we filed a request with the VPSB to increase our retail
rates by 12.93 percent. We requested the retail rate increase because of the
following:
* The higher cost of power;
* The cost of the January 1998 ice storm; and
* Investments in new plant and equipment.
On November 18, 1998, by Memorandum of Understanding (MOU), the Company,
the Department and IBM agreed to stay rate proceedings in the 1998 rate case
until or after September 1, 1999, or such earlier date as the parties may later
agree to or the VPSB may order. The agreement to suspend our 1998 rate case
delayed the date of a final decision on the 1998 rate case to December 15, 1999,
and we recognized an additional loss of $5.25 million in the last quarter of
1998 representing the effect of the continued disallowance of Hydro-Qu bec costs
through December 15, 1999. The MOU provided for a 5.5% temporary retail rate
increase, to produce $8.9 million in annualized additional revenue, effective
with service rendered December 15, 1998. In the event that the VPSB issues a
final order that allows a retail rate increase that is less than the temporary
rates, all sums collected in excess of such final rates would be refunded by
adjusting rates on a prospective basis, by customer class, to reflect the
appropriate refund amounts. At March 31, 2000, total revenues subject to refund
are approximately $13.3 million. An additional surcharge was permitted, without
further VPSB order, in order to produce additional revenues necessary to provide
the Company with the capacity to finance 1999 Pine Street Barge Canal site
expenditures. The MOU was approved by the VPSB on December 11, 1998. The MOU
did not provide for any specific disallowance of power costs under our purchase
power contract with Hydro-Qu bec. Issues respecting recovery of such power
costs were preserved for future proceedings. Also, in the event that the
Vermont Supreme Court issues an order reversing the VPSB's orders in our 1997
rate case prior to issuance of a final order in the 1998 rate case, any
resulting adjustments in rates will not become effective until the VPSB issues a
final order in the 1998 rate case. The MOU provides that nothing in it will
reduce or limit our entitlement to full recovery of any amounts due us if we
should prevail on the appeal.
The stay and suspension of this pending rate case and the temporary rate
levels agreed to in the MOU were designed to allow us to continue to provide
adequate and efficient service to our customers while we seek mitigation of
power supply costs.
On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments to the MOU that the Company had entered into with the Department and
IBM. The two amendments continued the stay of proceedings until September 1,
2000, with a final decision expected by December 31, 2000. The amendments
maintained the other features of the original MOU, and the second amendment
provides for a temporary rate increase of 3 percent, in addition to the current
temporary rate level, effective as of January 1, 2000. The temporary rates are
still subject to refund in the final rate case decision, if the final rates set
are lower than the temporary rates. The Court dismissed an appeal by one party
to the rate case, the American Association of Retired Persons (AARP), which
argued that the VPSB should have ordered the Company to post a bond or escrow
for the temporary rate increase.
Notwithstanding the interim rate settlement, we are unable to predict
whether the MOU or other future events, singularly or in combination, could
cause our lending banks to refuse to allow further borrowings under our
revolving loan agreement, to seek to enter into a new credit agreement with us
and/or to immediately call in all outstanding loans. If we are unable to borrow
on a short-term basis, we will evaluate all potential alternatives available at
the time, including, but not limited to, the filing of a petition for
reorganization under the United States Bankruptcy Code.
SFAS 71 provides guidance in preparing financial statements for public
utilities that meet certain criteria of SFAS 71. The three criteria that we
must meet in order to follow that accounting guidance are:
* our rates for regulated services and products provided to our customers
must be established by or be subject to approval by an independent, third-party
regulator;
* the regulated rates are designed to recover our specific costs of
providing the regulated services or products; and
* depending on demand for regulated services and products, and the level of
competition, direct and indirect, it is reasonable to assume that our rates are
set at levels that will recover our costs and that these rates can be charged to
and collected from our customers. This criterion must also take into account
anticipated changes in levels of demand or competition during the recovery
period for any capitalized costs.
We meet these criteria presently, and the application of SFAS 71 requires
we defer certain costs that would typically be accounted for as expense in an
unregulated entity; these costs are referred to as deferred charges or
regulatory assets. Our ability to defer a cost is subject to our ability to
provide evidence that the following additional criteria are met:
* it is probable that the inclusion of the capitalized (deferred) cost in
allowed costs for rate making purposes will provide future revenue in an amount
at least equal to the capitalized (deferred) cost; and
* the future revenue will be provided to permit recovery of the previously
incurred cost rather than to provide for expected levels of similar future
costs.
If the VPSB does not modify its ruling that the costs of power purchased
from Hydro-Qu bec are above estimated market rates and are not used and useful
and, therefore, a portion of such costs is not recoverable, we would likely
conclude that the VPSB has changed its approach to setting rates from cost-based
rate making to another form of regulation. We would then be required to
discontinue application of SFAS 71 and eliminate all regulatory assets and
liabilities that arose from prior actions of the VPSB. The write-off of these
regulatory assets and liabilities, net of any tax effects, would be charged to
income as an extraordinary item for the financial reporting period in which the
discontinuation of SFAS 71 occurs.
Based on the March 31, 2000 balance sheet, if we are required to
discontinue the application of SFAS 71, we would be required to recognize an
after-tax charge to earnings of approximately $28.5 million attributable to net
regulatory assets.
POWER SUPPLY AND TRANSMISSION
An agreement with Hydro-Qu bec allows their right to exercise an option to
purchase power from the Company at energy prices based on a 1987 contract.
During the first quarter of 2000, Hydro-Qu bec exercised its purchase option for
delivery of a of 135,700 MWh during the months of June, July and August of 2000.
The Company's temporary rate settlement of December 1999 includes revenues in
2000 sufficient to provide for estimated net costs of replacing power purchased
by Hydro-Qu bec of approximately $6.5 million. The Company recognized $1.6
million in expense during the quarter ended March 31, 2000 to reflect these
estimated costs. A regulatory asset of $4.9 million was established for the
remaining estimated difference between the option exercise price and the
expected cost of replacement power for 2000. It is possible our estimate of
future power supply costs could differ materially from actual results.
Transmission expense may rise due to the failure of unique equipment
connecting Vermont's transmission system to that of New York. Vermont Electric
Power Company, Inc. (VELCO) owns and operates most of the high voltage
transmission system in Vermont. The Company is responsible for approximately 30
percent of VELCO's costs. Until the equipment is replaced, Vermont Electric
Power Company (VELCO) will likely have to secure other generation or
transmission capacity to maintain system reliability. VELCO believes it will
receive the necessary regulatory approvals in time to allow it to maintain
system reliability, but cannot control the timing or content of regulatory
responses. If approvals are not received or are delayed, or if VELCO is
otherwise unable to carry out plans referred to above, conditions may arise that
will require VELCO to impose one or more blackouts in the Chittenden County,
Vermont area pending the installation of other system improvements. The cost
of the interim facilities VELCO plans to install will be substantial(estimated
at $4.5 million through January 2001). VELCO is seeking to have such costs
spread among all electric utilities in New England. The probability of securing
such cost sharing is uncertain at this time.
4. SEGMENTS AND RELATED INFORMATION
In 1998, the Company adopted SFAS NO. 131, Disclosures About Segments of an
Enterprise and Related Information.
The Company has two reportable segments, the electric utility and Mountain
Energy, Inc. ("MEI"). The electric utility is engaged in the distribution and
sale of electrical energy in the State of Vermont and also reports the results
of its wholly-owned unregulated subsidiaries (GMPG, GMRI, GMP Real Estate,
Lease-Elec, Inc., and the rental water heater program) as a separate line item
in the Other Income Section in the Consolidated Statement of Income.
MEI is an unregulated business that invests in energy generation, energy
efficiency and wastewater treatment projects. As of June 30, 1999, we
classified MEI's net assets and liabilities as "Business Segment Held for Sale",
reflecting the Company's intent to sell MEI's assets within the next twelve
months. Previously, investment in MEI appeared as a separate caption, "Equity
Investment in Energy Related Business" in the nonutility section of the
consolidated balance sheet.
Subsequent to June 30, 1999, the Company's provisions for loss on disposal
totaled $6.7 million or $1.25 per share, primarily to recognize estimated future
losses from the expected sale of MEI's assets, including anticipated operating
losses until expected disposal. The provisions for loss from discontinued
operations reflect the Company's current estimate. The ultimate loss remains
subject to the consummation of the sale or other disposition, and could exceed
amounts recorded. Results of operations for MEI are now reported under "Loss on
disposal of discontinued segment, net of applicable income taxes". Provisions
for loss on disposal are reported under "Loss on disposal of discontinued
segment, net of applicable income taxes". Segment information compared with the
Company's results includes the following:
<TABLE>
<CAPTION>
Segment reconciliation
Three months ended
In thousands except March 31 March 31
per share data 2000 1999
------------------- ----------
<S> <C> <C>
External revenues
Electric utility. . . . . . . $ 67,712 $ 59,018
MEI segment . . . . . . . . . 97 777
Net income (loss) from
operations
Electric utility. . . . . . . 3,449 3,170
MEI segment . . . . . . . . . - (522)
Provision for loss on
disposal of MEI assets. . . . - -
------------------- ----------
Consolidated net income (loss) $ 3,449 $ 2,648
=================== ==========
</TABLE>
16
5. SFAS 133
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative
Instruments and Hedging Activities. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
133 requires that changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SFAS 133, as amended by SFAS
137, is effective for the Company beginning the first quarter of 2001. SFAS 133
must be applied to (a) derivative instruments and (b) either all derivative
instruments embedded in hybrid contracts or those embedded instruments that were
issued, acquired, or substantively modified on or after January 1, 1998 or
January 1, 1999 (as elected by the Company).
The Company has a contract with Morgan Stanley to hedge the fair value of
fossil fuel prices. We also sometimes use future contracts to hedge forecasted
wholesale sales of electric power including material sales commitments. Under
SFAS 133, the Company would recognize in earnings the value of hedging
instruments to the extent that they are ineffective in hedging exposures related
to these contracts.
The Company has not yet quantified the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of or the method of
adoption of SFAS 133. However, SFAS 133 is likely to increase volatility in
earnings and other comprehensive income. The Company has begun analysis of its
contracts, including a material sales commitment to Hydro-Qu bec at prices below
current market costs. The Company's initial review of the sales commitment
indicates that it is a derivative that may require valuation at fair value once
SFAS 133 is adopted.
6. RECLASSIFICATION
Certain line items on the prior year's financial statements have been
reclassified for consistent presentation with the current year.
<PAGE>
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
MARCH 31, 2000
PART I -- ITEM 2
In this section, we explain the general financial condition and the results
of operations for Green Mountain Power Corporation (the Company) and its
subsidiaries. This includes:
* Factors that affect our business;
* Our earnings and costs in the periods presented and why they changed
between periods;
* The source of our earnings;
* Our expenditures for capital projects year-to-date and what we
expect they will be in the future;
* Where we expect to get cash for future capital expenditures; and
* How all of the above affects our overall financial condition.
As you read this section it may be helpful to refer to the consolidated
financial statements and notes in Part I-Item 1.
There are statements in this section that contain projections or estimates
and are considered to be "forward-looking" as defined by the Securities and
Exchange Commission. In these statements, you may find words such as
"believes," "expects," "plans," or similar words. These statements are not
guarantees of our future performance. There are risks, uncertainties and other
factors that could cause actual results to be different from those projected.
Some of the reasons the results may be different are listed below and are
discussed under "Competition and Restructuring" and "Year 2000 Computer
Compliance" in this section:
* Regulatory decisions, legislation, or accounting changes;
* Weather;
* Energy supply and demand and pricing;
* Availability, terms, and use of capital;
* General economic and business risk;
* Nuclear and environmental issues;
* Changes in technology; and
* Industry restructuring and cost recovery (including stranded costs).
These forward-looking statements represent only our estimates and
assumptions as of the date of this report.
RESULTS OF OPERATIONS
EARNINGS SUMMARY- OVERVIEW
In this section, we discuss our earnings and the principal factors affecting
them. We separately discuss earnings for the utility business and for our
unregulated businesses.
<TABLE>
<CAPTION>
Total earnings (loss) per share of Common Stock
Three months ended Twelve months ended
all periods ended March 31, 2000 1999 2000 1999
------------------- --------------------- -------- -------
<S> <C> <C> <C> <C>
Utility business. . . . . . $ 0.63 $ 0.44 $ 0.55 $ 0.48
Unregulated businesses. . . 0.00 0.16 0.08 0.23
------------------- --------------------- -------- -------
Earnings(loss) from:. . . . 0.63 0.60 0.62 0.71
Continuing operations
Discontinued segment. . . . 0.00 (0.10) (1.25) (0.35)
------------------- --------------------- -------- -------
Basic and diluted earnings
(loss) per share. . . . . $ 0.63 $ 0.50 ($0.63) $ 0.36
=================== ===================== ======== =======
</TABLE>
UTILITY BUSINESS
The Company recorded earnings from utility operations of $0.63 in the
quarter ended March 31, 2000, compared with utility earnings of $0.44 in the
first quarter of 1999. Operating income was 18.1 percent, or $707,000 higher in
the first quarter of 2000 compared with the first quarter of 1999. A $1.7
million decrease in other operating expense due to our 1999 reorganization
effort, higher retail revenues due to a 3.0 percent temporary retail rate
increase effective January 2000, and higher sales of electricity were partially
offset by higher power supply and transmission costs.
The Company has previously accrued losses for disallowed Hydro-Qu bec power
supply contracts pursuant to VPSB orders. Results for the three months ended
March 31, 2000 and 1999 do not reflect any disallowed Hydro-Qu bec power supply
costs. If these accruals, consistent with generally accepted accounting
principles, had not been made, power supply costs would have been $1.9 million
and $1.3 million higher for the three months ended March 31, 2000 and 1999,
respectively.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from
continuing operations for the three months ended March 31, 2000 were much less
than during the same period in 1999 due to a $606,000 gain on the 1999 sale of
our remaining interest in GMER. A financial summary for these businesses,
excluding MEI, follows:
<TABLE>
<CAPTION>
Three months ended
March 31 March 31
2000 1999
------------------- ----------
(In thousands)
<S> <C> <C>
Revenue. . . . $ 262 $ 271
Expense. . . . 125 (563)
------------------- ----------
Net Income . . $ 137 $ 834
=================== ==========
</TABLE>
DISCONTINUED SEGMENT OPERATIONS
As of June 30, 1999, the Company decided to sell or dispose of MEI, a
wholly owned subsidiary that invests in energy generation, energy efficiency
and wastewater treatment businesses. Its results are reported separately after
income (loss) from continuing operations. MEI's operating loss for the three
months ended March 31, 2000 was previously recognized as provision for loss
during the last two quarters of 1999. The operating loss for the three months
ended March 31, 2000 would have been approximately $879,000 compared with a loss
of $522,000 for the same period a year ago.
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatthour (MWh) sales and average number of
customers for the three months ended March 31, 2000 and 1999 are summarized
below:
<TABLE>
<CAPTION>
Three months ended
(dollars in thousands) March 31
2000 1999
------------------- --------
<S> <C> <C>
Operating revenues
Retail. . . . . . . . $ 49,550 $ 46,771
Sales for Resale. . . 17,300 11,596
Other . . . . . . . . 862 651
------------------- --------
Total Operating Revenues. $ 67,712 $ 59,018
=================== ========
MWh sales-Retail. . . . . 520,222 486,473
MWh sales for Resale. . . 567,685 427,792
------------------- --------
Total MWh Sales . . . . . 1,087,907 914,265
=================== ========
</TABLE>
<TABLE>
<CAPTION>
Three months ended
Average Number of Customers March 31
2000 1999
------------------ ------
<S> <C> <C>
Residential . . . . . . . 72,165 71,423
Commercial and Industrial 12,574 12,366
Other . . . . . . . . . . 64 68
------------------ ------
Total Number of Customers. . 84,803 83,857
================== ======
</TABLE>
REVENUES
Revenues from operations in the first quarter of 2000 increased 14.7
percent or $8.7 million compared with the same period in 1999. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the first quarter of 2000 were $2.8 million or 5.9
percent higher than for the same period in 1999 reflecting a 3.0 percent
temporary rate increase effective January 1, 2000, and a 6.9 percent increase in
retail MWh sales. Sales of electricity increased by 5.8 percent to small
commercial and industrial customers, 4.1 percent to residential customers and
11.0 percent to lower margin industrial customers.
We sell wholesale electricity to others for resale. Our revenue from
wholesale sales of electricity increased $5.7 million in the first quarter of
2000 compared with the same period in 1999. The increase was due to a power
purchase and supply agreement between the Company and Morgan Stanley Capital
Group, Inc.("MS"), effective February 1999. Under the agreement, we sell power
to MS at predefined operating and pricing parameters. MS then sells to us, at a
predefined price, power sufficient to serve pre-established load requirements.
OPERATING EXPENSES
POWER SUPPLY EXPENSES - THREE MONTHS ENDED MARCH 31, 2000
Power supply expenses increased 21.1 percent or $8.0 million in the first
quarter of 2000 over the same period in 1999.
Power supply expenses decreased 3.6% or $299,000 during the first quarter
at Vermont Yankee ("VY"). The decrease was due to a higher than expected refund
of property insurance from NEIL and lower billings for maintenance. A proposed
sale of the generating plant is previously discussed under Part I, Item 2,
"Investment in Associated Companies".
Company-owned generation expenses increased 17.5 percent or $179,000 in the
first quarter of 2000 compared with the same period in 1999 primarily due to
higher cost of fuels for steam plants, and higher maintenance costs at Stony
Brook, a jointly owned facility.
The cost of power that we purchased from other companies increased 28.6
percent or $8.1 million in the first quarter of 2000 over the same period in
1999. This was primarily due to a $8.7 million increase reflecting the MS power
purchase and supply agreement effective February 1999, as discussed above. The
increase was partially offset by reductions in purchases from other energy
providers. Power supply costs also rose under an agreement with Hydro-Qu bec.
The agreement allows Hydro-Qu bec to exercise an option to purchase power from
the Company at energy prices based on a 1987 contract. During the first quarter
of 2000, Hydro-Qu bec exercised its purchase option for delivery of 135,700 MWh
during the months of June, July and August of 2000. The Company's temporary
rate settlement of December 1999 includes revenues in 2000 sufficient to provide
for estimated net costs of replacing power purchased by Hydro-Qu bec of
approximately $6.5 million. The Company recognized $1.6 million in expense
during the quarter ended March 31, 2000 to reflect these estimated costs. A
regulatory asset of $4.9 million was established for the remaining estimated
difference between the option exercise price and the expected cost of
replacement power for 2000. It is possible our estimate of future power supply
costs could differ materially from actual results. The Company has hedged its
energy price risk under this agreement through forward purchase contracts. Both
the Hydro-Qu bec agreement and the forward purchase contracts are considered
derivative instruments as defined by SFAS 133. There may be an impact on
earnings upon adoption of SFAS 133, which management has not estimated at this
time. See Note 3 to the Consolidated Financial Statements, "Commitments and
Contingencies, Power Supply," for additional information.
The Independent System Operator ("ISO") New England replaced the New
England Power Pool("NEPOOL") effective May 1, 1999. The ISO works as a
clearinghouse for purchasers and sellers of electricity in the new deregulated
markets. Sellers place bids for the sale of their generation or purchased power
resources and if demand is high enough the output from those resources is sold.
We must purchase electricity to meet customer demand during periods of high
usage and to replace energy repurchased by Hydro-Qu bec under the option
arrangement discussed above. Our costs to serve demand during periods of warmer
than normal temperatures in summer months and to replace such energy repurchases
by Hydro-Qu bec rose substantially after the ISO replaced NEPOOL as the
governing power supply. The cost of securing future power supplies has also
risen substantially in tandem with higher summer supply costs. The Company
cannot predict the duration or the extent to which future prices will continue
to trade above historical levels of cost. If the new markets continue to
experience the volatility evident in the first half of 1999, our earnings and
cash flow could be adversely impacted by a material amount.
During the three months ended March 31, 2000, the Company deferred an
additional $456,000 in arbitration costs related to our pursuit of claims
against Hydro-Qu bec arising from its suspension of deliveries during and after
the 1998 ice storm. The Company has received an accounting order from the VPSB
providing for the deferral of these charges, subject to final determination in a
future rate proceeding. We believe it is probable that the arbitration costs
will ultimately be recovered in rates.
OTHER OPERATING EXPENSES
Other operating expenses decreased 31.4 percent or $1.7 million in the
first quarter of 2000 compared with the same period in 1999. The reduction in
expense reflects the Company's reorganization efforts and includes the absence
of reorganization costs which were incurred in 1999, fewer employees, and
reductions in lease expense and facilities costs due to the sale of our
corporate headquarters building in 1999. The 1999 quarter included a benefit of
$1.6 million in expense reductions for an adjustment to a prior accrual for
estimated losses on the sale of our corporate headquarters.
TRANSMISSION EXPENSES
Transmission expenses increased by $788,000 or 29.2% for the three months
ended March 31, 2000 compared with the same period in 1999. Transmission
expenses increased primarily due to restructuring costs and congestion charges
associated with the creation of the ISO as the clearing house for power trades
in New England. Congestion charges reflect the lack of adequate transmission or
generation capacity in certain locations within New England, and these charges
are allocated to all ISO New England members. The Company is unable to predict
the magnitude or duration of future congestion charge allocation, but amounts
could be material.
Transmission expense may rise due to the March 2000 failure of unique
equipment connecting Vermont's transmission system to that of New York. Vermont
Electric Power Company, Inc. (VELCO) owns and operates most of the high voltage
transmission system in Vermont. The Company is responsible for approximately 30
percent of VELCO's costs. Until replaced, Vermont Electric Power Company
(VELCO) will likely have to secure other generation or transmission capacity to
maintain system reliability. VELCO believes it likely that it will receive the
necessary approvals in time to allow it to maintain system reliability, but
cannot control the timing or content of regulatory responses. If approvals are
not received or delayed, or if VELCO is otherwise unable to carry out plans
referred to above, conditions may arise that will require VELCO to impose one or
more blackouts in the Chittenden County, Vermont area pending the installation
of other system improvements. The cost of the interim facilities VELCO plans
to install will be substantial (estimated at $4.5 million through January 2001).
VELCO is seeking to have such costs spread among all electric utilities in New
England. The probability of securing such cost sharing is uncertain at this
time.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses decreased $73,000 or 1.8 percent
during the first quarter of 2000 compared with the same period in 1999. The
reduction is attributed to decreased amortization of demand side management
assets.
TAXES OTHER THAN INCOME TAXES
Other taxes increased 11.7 percent or $213,000 in the first quarter of 2000
compared with the same period in 1999, reflecting property tax and gross revenue
tax increases.
INCOME TAXES
Income taxes increased $648,000 in the first quarter of 2000 compared with
the same period in 1999 due to an increase in pretax book income for core
electric operations.
OTHER INCOME
Other income for the three months ended March 31, 2000 decreased
approximately $537,000 or 38.1 percent from the same 1999 period due primarily
to decreases in earnings from subsidiaries. GMRI recorded no activity in the
current quarter while recognizing a $605,000 gain in the first quarter of 1999
from the sale of its remaining interest in GMER.
INTEREST CHARGES
Interest charges decreased 4.0 percent or $74,000 in the first quarter of
2000 over the same period in 1999 primarily due to continuing reductions in
long-term debt outstanding.
LIQUIDITY AND CAPITAL RESOURCES
In the three months ended March 31, 2000, we spent $2.2 million principally
for expansion and improvements of our transmission and distribution plant, for
programs to help our customers conserve electricity (conservation), for
expenditures related to the Pine Street Barge Canal site, and for computer
information systems. We expect to spend an additional $12.6 million during the
remainder of 2000.
On June 23, 1999, we renewed a revolving credit agreement with Fleet
National Bank and State Street Bank and Trust Company. The agreement is for a
period of 364 days and will expire on June 21, 2000. The commitment of $15
million represents a reduction from the previous commitment of $45 million. We
believe the amounts available under the new agreement will be sufficient to meet
our forecasted borrowing requirements during the 364-day period. We had no
borrowings outstanding on the revolving credit agreement at March 31, 2000. On
October 1, 1999, State Street's commercial banking assets, including our
revolving credit agreement, became part of Citizens Financial Group.
There are a number of future events that, singularly or in combination,
could lead the banks to refuse to allow further borrowings under the existing
credit agreement, to seek to enter into a new credit agreement that has terms
that are less advantageous to the Company, and/or to immediately call in all
outstanding loans. Some of those events are:
* The VPSB issues an order in our currently suspended 1998 rate case that
triggers a material adverse change for the Company; or
* Hydro-Qu bec is unwilling to make new arrangements regarding the cost of
our long-term contract with it; or
* Adverse accounting treatment under SFAS 5 or SFAS 71 is required.
The credit ratings of the Company's securities are:
Duff & Phelps Moody's Standard & Poor's
--------------- ------- -------------------
First mortgage bonds BBB Ba1 BBB
Unsecured medium term debt BBB- -- --
Preferred stock BB+ ba2 BB
During April 2000, Moody's Investor Service downgraded the rating of the
Company's first mortgage bonds from Baa3 to Ba1, reflecting Moody's uncertainty
about the Company's ability to meet liquidity needs if its banks do not renew
its revolving credit agreement. Duff & Phelps' and Standard & Poor's credit
ratings for the Company remain on Rating Watch-Down and Credit Watch Negative,
respectively, due to the high level of regulatory and public policy uncertainty
in Vermont and certain positions argued by the Department in our rate cases.
COMPETITION AND RESTRUCTURING
The electric utility business is experiencing rapid and substantial
changes. These changes are the result of the following trends:
* Surplus generating capacity;
* Disparity in electric rates among and within various regions of the
country;
* Improvements in generation efficiency;
* Alternative energy sources;
* Increasing demand for customer choice; and
* New regulations and legislation intended to foster competition, also known
as "restructuring".
YEAR 2000 COMPUTER COMPLIANCE
We experienced no interruption in the delivery of electricity due to the
transition from December 31, 1999 to January 1, 2000. We also have not
experienced any significant events related to the year 2000 transition on any of
our software applications or embedded systems. Potential problems with future
dates continue to pose risk to the Company. Our ability to deliver electricity
to our customers could also be impacted if one of our major power suppliers or
vendors of telecommunication service experienced a date-related system failure.
An interruption in power supplied by other delivery systems, such as the
independent system operator (ISO) for New England, could also cause power
delivery problems for us. The contingency planning process implemented by the
Company during 1999 remains in place.
We believe that our planning was adequate to secure Year 2000 readiness of
our critical systems. Nevertheless, maintaining Year 2000 security is subject
to various risks and uncertainties, many of which are described above. We are
not able to predict all the factors that could cause actual results to differ
materially form our current expectations as to our Year 2000 readiness.
However, if we, or third parties with whom we have significant business
relationships, fail to maintain Year 2000 readiness with respect to critical
systems, there could be a material adverse effect on our results of operations,
financial position and cash flows.
NUCLEAR DECOMMISSIONING
The staff of the SEC has questioned certain current accounting practices of
the electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in
financial statements. In response to these questions, the Financial Accounting
Standards Board had agreed to review the accounting for closure and removal
costs, including decommissioning. We do not believe that changes in such
accounting, if required, would have an adverse effect on the results of
operations due to our current and future ability to recover decommissioning
costs through rates.
EFFECTS OF INFLATION
Financial statements are prepared in accordance with generally accepted
accounting principles and report operating results in terms of historic costs.
This accounting provides reasonable financial statements but does not always
take inflation into consideration. As rate recovery is based on these
historical costs and known and measurable changes, the Company is able to
receive some rate relief for inflation. It does not receive immediate rate
recovery relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation on
plant costs are generally offset by the fact that these assets are financed
through long-term debt.
23
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
MARCH 31,2000
-------------
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings
See Notes 3, 4 and 5 of Notes to Consolidated Financial Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
NONE
ITEM 5. Other Information
NONE
ITEM 6. (A) EXHIBITS
--------
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
----------------------
A report on Form 8-K was filed on April 19, 2000 announcing the results of
recent credit reviews by major credit rating agencies. Two agencies reaffirmed
the existing investment grade rating for all securities and one agency
downgraded to one level below investment grade the Company's first mortgage
bonds.
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 12, 2000 /s/Nancy Rowden Brock
------------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer, Secretary,
and Treasurer
Date:May 12, 2000 /s/ R.J. Griffin
------------------
R. J. Griffin, Controller
EXHIBIT 27 This Schedule contains summary financial information extracted
from the Consolidated Balance Sheet as of March 31, 2000 and the related
Consolidated Statements of Income and Cash Flows for the three months ended
March 31, 2000, and is qualified in its entirety by reference to such financial
statements.
GREEN MOUNTAIN POWER CORPORATION
FINANCIAL DATA SCHEDULE
FORM 10-Q MARCH 31, 2000
Period - Type 3 Months
Fiscal Year End March 31, 2000
Period End March 31, 2000
Book Value Per Book
Total Net Utility Plant $191,929
Other Property and Investments 20,643
Total Current Assets 39,952
Total Deferred Charges 44,595
Other Assets 11,405
Total Assets 308,524
Common Stock 18,215
Capital Surplus, Paid In 72,766
Retained Earnings 13,046
Total Common Stockholders Equity 103,649
Preferred Stock - Mandatory Redemption 1,880
Preferred Stock - Not Mandatory Redemption 12,555
Long Term Debt, Net 88,500
Short Term Notes 0
Long Term Notes Payable 0
Commercial Paper 0
Long Term Debt - Current Portion 6,700
Preferred Stock - Current Portion 1,640
Capital Lease Obligations 7,038
Capital Leases - Current Obligations 0
Other Items Capital and Liability 94,902
Total Capitalization and Liabilities 308,524
Gross Operating Revenue 67,712
Income Tax Expense 2,259
Other Operating Expenses 60,840
Total Operating Expenses 63,099
Operating Income 4,613
Other Income, Net 871
Income Before Interest Expense 5,484
Total Interest Expense 1,765
Loss from discontinued operations 0
Net Income 3,449
Preferred Stock Dividends 270
Earnings Available for Common Stock 3,449
Common Stock Dividends 747
Total Interest On Bonds 1,661
Cash Flow from Operations 17,371
Earnings Per Share - Primary .63
Earnings Per Share - Diluted .63
(Dollars in thousands except per share amounts)
