November 11, 1999
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 SEPTEMBER 30, 1999
------------------
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 SEPTEMBER 30, 1999
- --------------------------- -----------------------------------
$3.33 1/3 PAR VALUE 5,382,114
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE BALANCE SHEETS
(UNAUDITED)
SEPTEMBER 30 SEPTEMBER 30 DECEMBER 31
------------- ------------- -------------
1999 1998 1998
-------- -------- --------
<S> <C> <C> <C>
(In thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . . $278,820 $272,276 $276,853
Less accumulated depreciation . . . . . . . . . 100,792 94,623 94,604
-------- -------- --------
Net utility plant . . . . . . . . . . . . . . 178,028 177,653 182,249
Property under capital lease. . . . . . . . . . 7,696 8,342 7,696
Construction work in progress . . . . . . . . . 8,745 11,158 5,611
-------- --------
Total utility plant, net. . . . . . . . . . 194,469 197,153 195,556
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . . 14,814 16,324 15,048
Other investments . . . . . . . . . . . . . . . 6,028 5,515 5,630
-------- --------
Total other investments . . . . . . . . . . 20,842 21,839 20,678
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . 456 129 439
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $398, $327 and $449. . . . . . . . . . . . 15,340 13,946 18,977
Accrued utility revenues. . . . . . . . . . . . 6,312 5,383 6,611
Fuel, materials and supplies, at average cost . 3,281 3,377 3,139
Prepayments . . . . . . . . . . . . . . . . . . 1,597 9,523 6,091
Other . . . . . . . . . . . . . . . . . . . . . 1,540 2,917 443
-------- --------
Total current assets. . . . . . . . . . . . 28,526 35,275 35,700
-------- -------- --------
DEFERRED CHARGES
Demand side management programs . . . . . . . . 7,917 11,087 10,590
Purchased power costs . . . . . . . . . . . . . 2,165 7,258 5,708
Pine Street Barge Canal . . . . . . . . . . . . 8,700 5,000 5,000
Other . . . . . . . . . . . . . . . . . . . . . 18,238 12,621 14,278
-------- --------
Total deferred charges. . . . . . . . . . . 37,020 35,966 35,576
-------- -------- --------
NON-UTILITY
Cash and cash equivalents . . . . . . . . . . . 21 42 151
Other current assets. . . . . . . . . . . . . . 13 8,254 3,409
Property and equipment. . . . . . . . . . . . . 253 1,217 1,213
Intangible assets . . . . . . . . . . . . . . . - 19 1,658
Equity investment in energy related businesses. - 12,351 12,357
Business segment held for disposal. . . . . . . 11,835 - -
Other assets. . . . . . . . . . . . . . . . . . 1,383 5,000 8,526
-------- --------
Total non-utility assets. . . . . . . . . . 13,505 26,883 27,314
-------- -------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . $294,362 $317,116 $314,824
======== ======== ========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
-1-
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE BALANCE SHEETS
(UNAUDITED)
SEPTEMBER 30 SEPTEMBER 30 DECEMBER 31
------------- ------------- -------------
1999 1998 1998
--------- --------- ---------
<S> <C> <C> <C>
(In thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common Stock Equity
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,382,114, 5,261,906 and 5,313,296). . . . . $ 17,992 $ 17,717 $ 17,711
Additional paid-in capital . . . . . . . . . . 72,501 71,570 71,914
Retained earnings. . . . . . . . . . . . . . . 12,751 21,566 17,508
Treasury stock, at cost (15,856 shares). . . . (378) (378) (378)
--------- --------- ---------
Total common stock equity. . . . . . . . . . 102,866 110,475 106,755
Redeemable cumulative preferred stock. . . . . . 14,685 16,335 16,085
Long-term debt, less current maturities. . . . . 86,800 88,500 88,500
--------- --------- ---------
Total capitalization . . . . . . . . . . . . 204,351 215,310 211,340
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 7,696 8,342 7,696
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of long-term debt . . . . . . 1,700 1,700 1,700
Short-term debt. . . . . . . . . . . . . . . . . 4,300 8,500 7,000
Accounts payable, trade and accrued liabilities. 4,430 5,910 5,453
Accounts payable to associated companies . . . . 6,928 5,714 7,143
Dividends declared . . . . . . . . . . . . . . . 291 327 362
Customer deposits. . . . . . . . . . . . . . . . 228 171 336
Taxes accrued. . . . . . . . . . . . . . . . . . - - 370
Interest accrued . . . . . . . . . . . . . . . . 1,774 1,878 1,203
Deferred revenues. . . . . . . . . . . . . . . . - - -
Other. . . . . . . . . . . . . . . . . . . . . . 2,565 1,928 5,258
Total current liabilities. . . . . . . . . . 22,216 26,128 28,825
--------- --------- ---------
DEFERRED CREDITS
Accumulated deferred income taxes. . . . . . . . 24,858 27,319 23,389
Unamortized investment tax credits . . . . . . . 4,048 4,331 4,260
Pine Street Barge Canal site cleanup . . . . . . 9,211 11,183 11,220
Other. . . . . . . . . . . . . . . . . . . . . . 21,942 17,140 21,020
Total deferred credits . . . . . . . . . . . 60,059 59,973 59,889
--------- --------- ---------
NON-UTILITY
Current liabilities. . . . . . . . . . . . . . . - 316 720
Other liabilities. . . . . . . . . . . . . . . . 40 7,047 6,354
--------- --------- ---------
Total non-utility liabilities. . . . . . . . 40 7,363 7,074
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $294,362 $317,116 $314,824
========= ========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
-2-
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
(UNAUDITED)
Part 1 - Item 1
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
-------------------- --------------------
1999 1998 1999 1998
--------- -------- --------- ---------
(In thousands, except amounts per share)
<S> <C> <C> <C> <C>
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 68,478 $47,984 $187,031 $138,648
--------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . . . . . . 8,898 8,374 26,201 24,520
Company-owned generation. . . . . . . . . . . . . . . . . . . . . . . 1,723 1,307 4,674 5,336
Purchases from others . . . . . . . . . . . . . . . . . . . . . . . . 41,717 19,582 104,442 59,082
Other operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,980 5,485 13,438 14,742
Transmission. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,724 2,393 8,183 7,061
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,577 1,199 5,040 3,663
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . 3,855 3,878 12,333 12,181
Taxes other than income . . . . . . . . . . . . . . . . . . . . . . . . 1,771 1,733 5,270 5,499
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (179) 886 1,156 291
--------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . . . . . . . 67,066 44,837 180,737 132,375
--------- -------- --------- ---------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . 1,412 3,147 6,294 6,273
--------- -------- --------- ---------
OTHER INCOME
Equity (loss) in earnings of affiliates and non-utility operations. . . 408 720 2,306 1,521
Allowance for equity funds used during construction . . . . . . . . . . 40 51 90 149
Other income (deductions), net. . . . . . . . . . . . . . . . . . . . . 31 215 192 (671)
--------- -------- --------- ---------
Total other income (deductions) . . . . . . . . . . . . . . . . . . . 479 986 2,588 999
--------- -------- --------- ---------
INCOME (LOSS) BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 1,891 4,133 8,882 7,272
--------- -------- --------- ---------
INTEREST CHARGES
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,661 1,704 5,054 5,287
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 370 355 714
Allowance for borrowed funds used during construction . . . . . . . . . (25) (62) (54) (168)
--------- -------- --------- ---------
Total interest charges. . . . . . . . . . . . . . . . . . . . . . . . 1,731 2,012 5,355 5,833
--------- -------- --------- ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS
AND DISCONTINUED SEGMENT. . . . . . . . . . . . . . . . . . . . . . . . 160 2,121 3,527 1,439
Dividends on preferred stock. . . . . . . . . . . . . . . . . . . . . . . 275 310 885 991
--------- -------- --------- ---------
INCOME FROM CONTINUING OPERATIONS . . . . . . . . . . . . . . . . . . . (115) 1,811 2,642 448
Net income(loss) from discontinued segment
operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - (178) (603) (1,290)
Loss on disposal, including provisions
for operating losses during phaseout period . . . . . . . . . . . . . (4,592) - (4,592) -
--------- -------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . ($4,707) $ 1,633 ($2,553) ($842)
========= ======== ========= =========
COMMON STOCK DATA
Basic and diluted earnings (loss) per share
from continuing operations. . . . . . . . . . . . . . . . . . . . . . ($0.02) $ 0.34 $ 0.49 $ 0.09
Basic and diluted earnings (loss) per share . . . . . . . . . . . . . . ($0.88) $ 0.31 ($0.48) ($0.16)
Cash dividends declared per share . . . . . . . . . . . . . . . . . . . $ 0.14 $ 0.28 $ 0.41 $ 0.83
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . 5,374 5,261 5,347 5,226
CONSOLIDATED COMPARATIVE STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Balance - beginning of period . . . . . . . . . . . . . . . . . . . . . . $ 18,197 $21,379 $ 17,508 $ 26,717
Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,432) 1,943 (1,668) 149
--------- -------- --------- ---------
13,765 23,322 15,840 26,866
--------- -------- --------- ---------
Cash Dividends-redeemable cumulative preferred stock. . . . . . . . . . . 275 310 885 991
Cash Dividends-common stock . . . . . . . . . . . . . . . . . . . . . . . 739 1,446 2,204 4,309
--------- -------- --------- ---------
1,014 1,756 3,089 5,300
--------- -------- --------- ---------
Balance - end of period . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,751 $21,566 $ 12,751 $ 21,566
========= ======== ========= =========
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
(UNAUDITED)
Part 1 - Item 1
TWELVE MONTHS ENDED
SEPTEMBER 30
---------------------------
1999 1998
--------- ---------
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $232,687 $184,510
--------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . 34,589 33,086
Company-owned generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,750 7,177
Purchases from others. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127,067 75,305
Other operating. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,987 18,957
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,511 9,719
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,567 5,046
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,210 16,133
Taxes other than income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,013 7,181
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (502) 1,902
--------- ---------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227,192 174,506
--------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,495 10,004
--------- ---------
OTHER INCOME
Equity (loss) in earnings of affiliates and non-utility operations . . . . . . . . . . . . . . 2,385 1,859
Allowance for equity funds used during construction. . . . . . . . . . . . . . . . . . . . . . 44 28
Other income (deductions), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 772 (68)
--------- ---------
Total other income (deductions). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,201 1,819
--------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,696 11,823
--------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,759 7,053
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 657 1,037
Allowance for borrowed funds used during construction. . . . . . . . . . . . . . . . . . . . . (17) (136)
--------- ---------
Total interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,399 7,954
--------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND
DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,297 3,869
Dividends on preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,190 1,326
--------- ---------
INCOME FROM CONTINUING OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 2,543
Net income(loss) from discontinued segment
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,399) (2,198)
Loss on disposal, including provisions for
operating losses during phaseout period. . . . . . . . . . . . . . . . . . . . . . . . . . . (4,592) -
--------- ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (5,884) $ 345
========= =========
COMMON STOCK DATA
Basic and diluted earnings per share from continung operations . . . . . . . . . . . . . . . . $ 0.02 $ 0.49
Basic and diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -$1.10 $ 0.07
Cash dividends declared per share. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.55 $ 1.10
Weighted average shares outstanding. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,333 5,212
CONSOLIDATED COMPARATIVE STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Balance - beginning of period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,566 $ 26,949
Net Income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,694) 1,671
--------- ---------
16,872 28,620
--------- ---------
Cash Dividends-redeemable cumulative preferred stock . . . . . . . . . . . . . . . . . . . . . . 1,190 1,326
Cash Dividends-common stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,931 5,728
--------- ---------
4,121 7,054
--------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 12,751 $ 21,566
========= =========
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.
- - 3a -
<TABLE>
<CAPTION>
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Part 1 - Item 1 NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------ ------------
1999 1998
--------- --------
<S> <C> <C>
(In thousands)
OPERATING ACTIVITIES:
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ($2,553) $ 149
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . 12,332 12,181
Dividends from associated companies less equity income . . . . . . . . . . . . . 142 (464)
Allowance for funds used during construction . . . . . . . . . . . . . . . . . . (144) (317)
Amortization of purchased power costs. . . . . . . . . . . . . . . . . . . . . . 4,607 4,833
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,469 3,818
Provision for loss on segment disposal . . . . . . . . . . . . . . . . . . . . . 4,592 0
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . . . . . (781) (7,808)
Deferred arbitration costs . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,118) 0
Amortization of investment tax credits . . . . . . . . . . . . . . . . . . . . . (212) (212)
Environmental proceedings costs. . . . . . . . . . . . . . . . . . . . . . . . . (5,708) 3,078
Conservation expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,182) (1,165)
Changes in:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,636 3,419
Accrued utility revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . 298 1,123
Fuel, materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . (142) (115)
Prepayments and other current assets . . . . . . . . . . . . . . . . . . . . . 4,639 (5,805)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,238) (2,865)
Taxes accrued. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,560) (4,356)
Interest accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 571 567
Other current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . (2,873) (705)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 832 (1,632)
--------- --------
Net cash provided by continuing operations . . . . . . . . . . . . . . . . . . . . 15,607 3,724
Net cash provided (used) by discontinued segment . . . . . . . . . . . . . . . . . (138) 0
--------- --------
Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . 15,469 3,724
INVESTING ACTIVITIES:
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,386) (9,220)
Investment in nonutility property. . . . . . . . . . . . . . . . . . . . . . . . . . (176) 230
Proceeds from sale of propane subsidiary . . . . . . . . . . . . . . . . . . . . . . - 11,500
--------- --------
Net cash provided by (used in) investing activities. . . . . . . . . . . . . . . . (7,562) 2,510
--------- --------
FINANCING ACTIVITIES:
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 868 1,249
Short-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,700) 5,884
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,089) (5,300)
Reduction in preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,400) (1,400)
Reduction in long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,700) (6,767)
--------- --------
Net cash provided by (used in) financing activities. . . . . . . . . . . . . . . . (8,021) (6,334)
--------- --------
Net increase in cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . (114) (100)
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . 590 271
--------- --------
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . $ 476 $ 171
========= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized). . . . . . . . . . . . . . . . . . . . . . . $ 4,577 $ 5,239
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 997 1,536
The accompanying notes are an integral part of the consolidated financial statements.
-4-
</TABLE>
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1999
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 1998 filed on Form 10-K, 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 in which we have lower revenues or higher
costs. By deferring certain revenues we are able to better match our revenues
to our costs. On September 30, 1999, there was a deferred charge of $676,000
compared to a deferred charge of $1.1 million for the same period in 1998.
These deferred charges are amortized against revenue in the final fiscal quarter
as the seasonal rates are implemented.
FINANCIAL SUMMARY OF 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"). 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. 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. A financial summary for these
businesses follows:
14
November 12, 1999;9:24 AM
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30 September 30
1999 1998 1999 1998
----- ----- ------ -------
In thousands
<S> <C> <C> <C> <C>
Revenue. . . . . $ 265 $ 290 $ 810 $2,588
Expense. . . . . 172 109 (137) 2,589
----- ----- ------ -------
Net Income(Loss) $ 93 $ 181 $ 947 $ (1)
===== ===== ====== =======
</TABLE>
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).
<TABLE>
<CAPTION>
VERMONT YANKEE NUCLEAR POWER CORPORATION
Percent ownership: 17.9% common
Three months ended Nine months ended
In thousands September 30 September 30
1999 1998 1999 1998
------- ------- -------- --------
<S> <C> <C> <C> <C>
Gross Revenue . . . . $49,029 $43,186 $139,182 $152,269
Net Income Applicable
To Common Stock 1,580 1,816 4,874 5,324
Equity in Net Income. $ 287 $ 334 $ 880 $ 947
</TABLE>
<TABLE>
<CAPTION>
VERMONT ELECTRIC POWER COMPANY, INC.
Percent ownership: 29.5% common
30.0% preferred
Three months ended Nine months ended
In thousands September 30 September 30
1999 1998 1999 1998
------ ------ ------- -------
<S> <C> <C> <C> <C>
Gross Revenue . . . . $6,826 $7,799 $21,031 $28,480
Net Income applicable
To common stock. . . 280 274 901 858
Equity in Net Income. $ 61 $ 84 $ 269 $ 247
</TABLE>
On October 15, 1999, the owners of Vermont Yankee Nuclear Power Corporation
accepted a bid from Philadelphia-based AmerGen Energy Company for the
540-megawatt Vernon 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 $54.3 million to pre-pay the plant's
decommissioning fund. In return, AmerGen will assume full responsibility for all
future operating costs and the estimated $800 million for decommissioning the
plant at the end of its operating license in 2012. The current owners have
agreed to buy power from the plant for periods that may extend up to twelve
years, depending upon the option selected by each individual owner. Green
Mountain Power Corporation ("The Company")and the other current owners are also
responsible for their share of the unrecovered plant and other costs resulting
from the sale.
3. 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 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. In
1994, the EPA established a coordinating council, with representatives of the
PRPs, environmental and community groups, the City of Burlington and the State
of Vermont("State"), presided over by a neutral facilitator.
In June 1998, the Coordinating Council reached a consensus agreement on a
recommended plan for remediation of the Pine Street Barge Canal site. As part
of the Council's process of reaching a consensus recommendation, the Company and
certain other parties conditionally agreed to fund environmentally beneficial
projects in the greater Burlington area, the cost of which may reach $3.0
million. In June 1998, the EPA formally proposed the Council's recommended plan
and received public comments.
On September 29, 1998, the EPA issued its final Record of Decision,
announcing selection of the proposed remedy. The proposed remedy includes:
* Construction of an underwater cover over canal sediments that present the
highest risk to the environment;
* Placement of a soil cap over certain contaminated wetland areas and
restoration of those areas;
* Improvements that will better distribute storm water entering the site;
and
* Monitoring of the site to ensure that the cap is effective over the long
term and that harmful contamination does not migrate offsite.
As of September 30, 1999, our total expenditures related to the Pine Street
Barge Canal site since 1982 were approximately $21.8 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 our
opposition to the EPA's earlier proposals for the site, as well as litigation
and related costs necessary to obtain settlements with insurers and other PRPs
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. Site-related response costs include costs
incurred pursuant to the 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.
The EPA has made claims against the Company for additional past response
costs associated with the Pine Street Barge Canal site in an amount exceeding
$11 million. The EPA also has advised us that we may be responsible for
implementation of further response activities at the site. In early 1998, the
United States and the State of Vermont asked us to begin "fast-track"
negotiation of tentative terms of settlement of all cost reimbursement and
natural resource damages claims of the United States and the State. Those
negotiations began immediately, involved other PRPs as well, and included
discussion of our potential contribution claims against the United States. In
May 1998, a confidential tentative agreement was reached on issues under
discussion.
In September 1999, we negotiated a final settlement with the United States,
the State, and other parties over terms of a Consent Decree that covers claims
addressed in the earlier negotiations and implementation of the selected remedy.
The Company executed the Consent Decree on September 27, 1999, and other parties
have been adding their signatures in September and October. The Consent Decree
must be submitted to a federal court for approval and adoption as its order. We
have entered into various confidential settlement agreements with other PRPs
that provide for sharing of past response costs, future cleanup costs and
related future federal and state monetary claims.
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. Specifically, we proposed rate recognition of our non-recovered
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 full rate recovery of the Pine Street Barge Canal costs, the
Vermont Department of Public Service (the Department), and as applicable, other
intervenors, reached agreements with the Company in these cases that the full
amount of the Pine Street Barge Canal costs reflected in those rate cases should
be recovered in rates. Our rates, as approved by the VPSB in those proceedings,
reflected the Pine Street Barge Canal related expenditures referred to above.
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 PRPs, should be "shared" between customers and shareholders of the
Company. In response to the Company's Motion for Reconsideration, the VPSB on
June 8, 1998 stated "our intent, and we believe the fair reading of our Order,
was to reserve for a future docket issues pertaining to the sharing of
remediation-related costs between the Company and its customers."
We estimate that we have recovered or secured, or will recover, through
past 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 have estimated that
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, to resolve monetary claims of the EPA and the
State and to remediate the site, are likely to be in the range of $8.7 to $12.5
million. In 1998, we recorded a liability of $5 million to recognize the low
end of our previous estimated range of costs. In the second quarter of 1999, we
recorded the additional liability of $3.7 million that reflects increased
estimates of site monitoring costs to be incurred over the next 33 years. 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 since we believe it is probable that we will receive
future revenues to recover these costs.
4. 1997 RETAIL RATE CASE
On June 16, 1997, we filed a request with the VPSB to increase our 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) to cover increased cost of service.
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 were designed to increase annual revenues by $5.6 million.
The VPSB, in its Order dated February 27, 1998, denied us the right to
charge customers $5.48 million of the costs for power purchased under our
contract with Hydro-Quebec. 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-Quebec in August 1991 (the imprudence disallowance), and
* To the extent that the costs of power to be purchased from Hydro-Quebec
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".
As a result of the rate order, we recorded in the first quarter of 1998 the
losses resulting from the disallowed recovery of a portion of the 1998
Hydro-Quebec power supply contract costs. The amount charged to first quarter
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. The agreement to suspend our 1998 rate case, as
described below, delayed the date of a final decision on the 1998 rate case to
December 15, 1999. Accordingly, we recognized an additional loss of $5.25
million in the last quarter of 1998 representing the effect of the continued
disallowance of $5.48 million of annual Hydro-Quebec power costs through
December 15, 1999.
In its February 27, 1998 Order, the VPSB described 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 also
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 it used in the 1997 rate case Order
to future power contract costs in our 1998 retail rate case, we would likely be
required to take a charge to income of approximately $162 million pre-tax.
This $162 million estimate represents primarily the 20 percent disallowance for
Hydro-Quebec power costs that the VPSB considered imprudent in its Order.
If the VPSB does not modify in future regulatory proceedings its ruling
that the costs of power purchased from Hydro-Quebec 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 Statement of Financial
Accounting Standards("SFAS") No. 71("SFAS 71"), Accounting for the Effects of
Certain Types of Regulation, 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 September 30, 1999 balance sheet, if we were required to
discontinue the application of SFAS 71, we would be required to record as an
extraordinary item an after-tax charge to earnings of approximately $24.2
million attributable to net regulatory assets.
In June 1998, we appealed the VPSB's February 27, 1998 Order and its June
8, 1998 Reconsideration Order to the Vermont Supreme Court. The briefing of the
case by all parties was completed in January 1999. Oral argument before the
Vermont Supreme Court was held on March 16, 1999.
We believe that the decisions in the VPSB's Order and Reconsideration Order
are factually inaccurate and legally incorrect. Specifically, we are appealing
the VPSB's determination that we were imprudent in committing to the
Hydro-Quebec 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 orders deprive the Company's shareholders of their
property in an unconstitutional manner. The VPSB's decisions, if not changed,
could have a significant negative impact on our reported financial condition,
and could impact our credit ratings, dividend policy and financial viability.
5. 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, our largest customer and an intervenor in the case,
agreed to stay, effective November 16, 1998, 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 MOU provides for a 5.5 percent
temporary retail rate increase, to produce $8.9 million in annualized additional
revenue, effective with service rendered December 15, 1998. An additional
surcharge will be permitted, without further VPSB order, in order to produce
additional revenues necessary to provide the Company with the capacity to
finance estimated 1999 Pine Street Barge Canal site expenditures of $5.8
million. The MOU was approved by the VPSB on December 11, 1998.
An amendment to the MOU, requested by the Company, the Department of Public
Service, and IBM, was approved by the VPSB to extend the stay of the 1998 rate
case through December 15, 1999. The approved amendment calls for a final rate
order to be issued by March 31, 2000, and the Company has recorded a $1.6
million loss in the current quarter resulting from the continued disallowance of
Hydro-Quebec power supply costs occurring through the period ending March 31,
2000.
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.
6. 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
our investment in MEI as "Business Segment held for sale", reflecting the
Company's intent to sell MEI's assets within the next twelve months.
In the third quarter of 1999, the Company recorded a provision for loss on
disposal of $4.6 or $.86 per share, primarily for the anticipated sale of MEI's
energy generation and demand side management investments. At this time, the
Company is unable to identify the extent of any losses, if any, that might
result from a sale of MEI's wastewater businesses. Results of operations for
MEI are 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 to the Company's results includes the following:
<TABLE>
<CAPTION>
Segment reconciliation
In thousands except Three months ended Nine months ended
per share data September 30 September 30
1999 1998 1999 1998
-------- -------- --------- ---------
<S> <C> <C> <C> <C>
External revenues
Electric utility. . . . . . . $68,478 $47,984 $187,031 $138,648
MEI segment . . . . . . . . . 1,171 645 3,531 457
Net income (loss) from
Operations
Electric utility. . . . . . . (115) 1,811 2,642 448
MEI segment . . . . . . . . . - (178) (603) (1,290)
Provision for loss on
Disposal of MEI assets. . . . (4,592) - (4,592) -
-------- -------- --------- ---------
Consolidated net income (loss) $(4,707) $ 1,633 $ (2,553) $ (842)
======== ======== ========= =========
</TABLE>
7. 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 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 could increase volatility in earnings
and other comprehensive income.
8. RECLASSIFICATION
Certain line items on the prior year's financial statements have been
reclassified for consistent presentation with the current year.
<PAGE>
27
NOVEMBER 12, 1999;9:24 AM
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
SEPTEMBER 30, 1999
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 or legislation;
* 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 Nine months ended
September 30 September 30
1999 1998 1999 1998
------- ------- -------- --------
<S> <C> <C> <C> <C>
Continuing Operations:
Utility business . . . . . ($0.04) $ 0.31 $ 0.31 $ 0.09
Unregulated businesses . . 0.02 0.03 0.18 0.00
------- ------- -------- --------
Earnings(loss) from
Continuing operations. . . (0.02) 0.34 0.49 0.09
Discontinued segment . . . (0.86) (0.03) (0.97) (0.25)
------- ------- -------- --------
Basic and diluted earnings
(loss) per share . . . . . ($0.88) $ 0.31 ($0.48) ($0.16)
======= ======= ======== ========
</TABLE>
UTILITY BUSINESS
The Company recorded a loss from utility operations of $0.04 in the quarter
ended September 30, 1999, compared to earnings of $0.31 in the third quarter of
1998. Higher costs of purchased power following the deregulation of energy
markets in New England during the second quarter of 1999, the continued
regulatory disallowance of a portion of our Hydro Quebec power supply and the
increase in capacity costs under the same contract adversely impacted results.
The higher power supply costs were offset in part by higher retail revenues due
to a 5.5 percent temporary retail rate increase granted by the VPSB in December
1998 and a 5.4 percent increase in retail sales of electricity.
Earnings from utility operations for the nine months ended September 30, 1999
were $0.31 per common share, compared to $0.09 in the nine months ended
September 30, 1998. Operating income was virtually identical for both years
with higher power supply and transmission costs being offset by higher revenues
in 1999 as compared to 1998. The lower 1998 earnings reflect a $900,000 (pretax)
write-off of our investment in the Searsburg wind facility under orders issued
by the VPSB, higher interest charges and increased preferred dividend costs.
UNREGULATED BUSINESSES
Earnings from our unregulated businesses included in results from
continuing operations in the third quarter of 1999 decreased 48.8% to $93,000
from the $181,000 in the same period of 1998, primarily due to income of
approximately $66,000 in the 1998 quarter for GMRI, compared to a loss of $9,000
in the third quarter of 1999.
Earnings from unregulated businesses included in results from
continuing operations for the nine months ended September 30, 1999 were greater
than the same period in 1998 due to:
* The sale in March 1998 of the assets of GMPG, which had lost $146,000 in
the first nine months of 1998;
* GMRI had losses of $224,000 in 1998 compared to nine month earnings of
$586,000 in 1999, reflecting a $600,000 (after tax) gain on the 1999 sale of our
remaining interest in GMER and the absence of pilot operations that ended in
1998.
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 loss for the three months ended
September 30, 1999 was $4.6 million compared to a loss of $178,000 for the same
period a year ago. MEI also reported a loss of $5.2 million in the first nine
months of 1999 compared to a loss of $1.3 million for the same period in 1998.
As discussed under Part I, Item 6., "Segments and Related Information", the 1999
losses included a provision for loss on disposal, net of tax benefits of $3.0
million, amounting to $4.6 million for both the three and nine periods ended.
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatthour (MWh) sales and average number
of customers for the three and nine months ended September 30, 1999 and 1998 are
summarized below:
<TABLE>
<CAPTION>
(dollars in thousands) Three months ended Nine months ended
September 30 September 30
1999 1998 1999 1998
-------- -------- ---------- ----------
<S> <C> <C> <C> <C>
Operating revenues
Retail . . . . . . . $ 45,520 $ 41,708 $ 133,980 $ 122,874
Sales for Resale . . 22,248 5,612 50,998 13,761
Other. . . . . . . . 710 663 2,053 2,013
-------- -------- ---------- ----------
Total Operating Revenues $ 68,478 $ 47,983 $ 187,031 $ 138,648
======== ======== ========== ==========
MWH sales-Retail . . . . 483,684 435,228 1,409,009 1,369,975
MWH sales for Resale . . 684,787 115,693 1,669,211 424,228
-------- -------- ---------- ----------
Total MWH Sales. . . . . 995,484 550,921 3,078,220 1,794,203
======== ======== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Average Number of Customers
Three months ended Nine months ended
September 30 September 30
1999 1998 1999 1998
------ ------ ------ ------
<S> <C> <C> <C> <C>
Residential . . . . . . . 71,461 71,449 71,379 71,263
Commercial and Industrial 12,482 12,233 12,413 12,168
Other . . . . . . . . . . 65 70 66 70
------ ------ ------ ------
Total Number of Customers 84,008 83,752 83,858 83,501
====== ====== ====== ======
</TABLE>
REVENUES
Revenues from operations in the third quarter of 1999 increased 42.7
percent or $20.5 million compared with the same period in 1998. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the third quarter of 1999 were $3.8 million or 9.1
percent higher than for the same period in 1998 due primarily to the 5.5 percent
temporary retail rate increase that became effective in December 1998 and due to
warmer than normal summer temperatures that increased sales of electricity by
5.4 percent.
We sell wholesale electricity to others for resale. Our revenue from
wholesale sales of electricity increased $16.6 million in the third quarter of
1999 compared to the same period in 1998. The increase was primarily due to a
power purchase and supply agreement between the Company and Morgan Stanley
Capital Group, Inc.("MS"), entered into in 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 revenues increased 34.9 percent for the nine months ended
September 30, 1999 compared to the same period in 1998.
Year to date retail revenues increased 9.0 percent or $11.1 million over the
same period in 1998, due primarily to the 5.5 percent temporary retail rate
increase discussed above, a 3.61 percent rate increase granted by the VPSB in
its Order dated February 27, 1998 and a 2.9 percent increase in sales of
electricity to retail customers. Wholesale revenues for the first nine months of
1999 increased approximately $37.2 million over the same period of 1998
primarily due to the new power purchase and supply agreement with MS.
OPERATING EXPENSES
POWER SUPPLY EXPENSES - THREE MONTHS ENDED SEPTEMBER 30, 1999
Our power supply expenses increased 78.9 percent or $23.1 million in the
third quarter of 1999 over the same period in 1998.
Power supply expenses increased 6.3% or $524,000 during the third quarter
at Vermont Yankee ("VY"). The increase was due to timing differences for
maintenance expenditures and for other operating expenditures related to the
proposed sale of VY assets. The proposed sale is previously discussed under
Part I, Item 2, "Investment in Associated Companies".
Company-owned generation expenses increased 31.8 percent or $416,000 in the
third quarter of 1999 compared with the same period in 1998 primarily due to
higher demand caused by warmer than normal temperatures that necessitated the
use of our high-cost generating facilities.
The cost of power that we purchased from other companies increased 113
percent or $22.1 million in the third quarter of 1999 over the same period in
1998. This was primarily due to the following:
* A $17.7 million increase reflecting the MS power purchase and supply
contract discussed above, whereby we buy power from MS that is sufficient to
serve pre-established load requirements at a pre-defined price;
* A $1.6 million loss accrued as a result of the extension of the Company's
1998 retail rate case through March 31, 2000;
* A $1.0 million increase in the capacity costs in 1999 associated with our
long-term Hydro-Quebec power supply contract;
* An increase in the costs of short-term power following the deregulation of
energy markets in New England, as well as an increase in our costs to serve
increased local loads and to supply power to meet contractual obligations during
the quarter; and
* These amounts were offset by a reclassification of $1.1 million from power
supply expense to transmission expense during the quarter and a reduction of
$800,000 in small power producer costs due to unusual precipitation patterns.
An Independent System Operator ("ISO") 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 Quebec under an arrangement
negotiated in 1997. Our costs to serve demand during periods of warmer than
normal temperatures in summer months and to replace such energy repurchases by
Hydro Quebec 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 second and third quarters of 1999, our earnings and
cash flow could be adversely impacted by a material amount.
POWER SUPPLY EXPENSES - NINE MONTHS ENDED SEPTEMBER 30, 1999
For the nine months ended September 30, 1999, power supply expenses
increased 52.1 percent or $46.4 million over the same period in 1998.
VY power supply costs declined by 6.9 percent in 1999 over the same period
in 1998 primarily as a result of timing differences between scheduled outages
during the two years. Costs associated with scheduled outages at VY are
amortized over an 18-month refueling cycle.
Company-owned generation expenses decreased 12.4 percent or $662,000 for
the first nine months of 1999 compared to the same period in 1998 primarily due
to the ice storm in 1998, which required the use of high-cost generating
facilities to replace power that was unavailable from Hydro-Quebec. This
decrease more than offset the increase occurring in the second and third
quarters of 1999 due to the unavailability of certain nuclear generation in the
region and the higher demand caused by warmer than normal summer temperatures.
The cost of power that we purchased from other companies during the first
nine months of 1999 increased 76.8 percent or $45.4 million over the same period
in 1998. This was primarily due to the following:
* A $41.0 million increase in power purchased, reflecting the MS power
purchase and sale contract discussed above, whereby we buy power from MS that is
sufficient to serve pre-established load requirements at a predefined price;
* A $3.4 million increase in 1999 capacity costs associated with our
long-term Hydro-Quebec power supply contract;
* An increase in the cost of power following the deregulation of energy
markets in New England, and an increase in the costs to serve increased local
loads and contractual obligations described above;
* A $1.6 million loss accrued as a result of the extension of
the Company's 1998 retail rate case; and
* The incremental cost to replace less expensive power we had purchased
from Merrimack Unit #2 under a contract that expired in April 1998.
These increases were partially offset by:
* The absence in the first quarter of 1999 of a $4.6 million loss accrued in
the first quarter of 1998 related to our long-term Hydro-Quebec power contract
as a result of the VPSB order in our 1997 rate case; and
* A $1.4 million reversal in the first quarter of 1999 of a $5.25
million loss accrued in the fourth quarter of 1998 resulting from the continued
disallowance of Hydro-Quebec power costs during 1999;
* A $1.4 million decline in small power producer costs due to unusual
precipitation patterns.
We have deferred $1.1 million in arbitration costs related to our pursuit of
claims against Hydro-Quebec 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 27.4 percent or $1.5 million in the
third quarter of 1999 compared to the same period in 1998. In 1998, we
recognized a $1.4 million estimated loss arising as a result of our intention to
terminate our corporate headquarters lease. For the nine months ended September
30,1999, other operating expenses decreased 8.9 percent or $1.3 million from the
same 1998 period. The decrease resulted from the estimated loss in 1998 and the
elimination in 1999 of $1.2 million in deferred credits relating to the lease
and sale of our former corporate headquarters, in part offset by increased costs
associated with our reorganization. We negotiated the purchase of the operating
lease for our corporate headquarters and sold the facility on April 29, 1999.
TRANSMISSION EXPENSES
Transmission expenses increased by $1.33 million or 55.6% for the three
months ended September 30, 1999 as compared to the same period in 1998. The
increase was primarily due to a reclassification between transmission and power
supply costs that arose in conjunction with the deregulation of energy markets
in New England. The reclassification had no impact on earnings. For the nine
months ended September 30, 1999, transmission expenses increased 15.9% primarily
due to restructuring costs associated with the creation of the ISO as the
clearing house for power trades in New England and also due to our increased
tree trimming expenses.
MAINTENANCE EXPENSES
Our maintenance expenses increased 31.5 percent or $378,000 in the third
quarter of 1999 compared to the same period in 1998 due to the amortization of
tree trimming and storm costs incurred during prior periods. For the nine months
ended September 30, 1999, maintenance expenses increased 37.6 percent or $1.4
million compared to the same period in 1998 for the same reason. The increases
for both the three and nine month periods ended September 30, 1999 reflect the
provisions of the MOU, which suspended our 1998 retail rate case in November,
1998, and provided for a seven year amortization of costs incurred during the
severe ice storm of January 1998, an increase of $1 million in rights of way
maintenance and pole treatment programs and increased amortization of previously
deferred tree trimming and storm costs.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses were substantially unchanged in the
third quarter of 1999 as compared to the same period in 1998. For the first nine
months of 1999, depreciation and amortization expense increased $151,000 or 2.1
percent from the first nine months of 1998 due to higher amortization of
previously deferred energy conservation, software and workforce reduction costs
that were partially offset by the suspension in March 1998 of amortization
charges related to the Pine Street Barge Canal site as discussed under Part I,
Item 1, "Environmental matters".
TAXES OTHER THAN INCOME TAXES
Other taxes decreased 2.2 percent or $37,000 in the third quarter of 1999
compared with the same period in 1998, reflecting property tax increases. Other
taxes decreased $230,000 or 4.2 percent in the nine month period ended September
30, 1999 compared to 1998 due to reappraisals in certain municipalities that
reduced property taxes during the first half of 1999.
INCOME TAXES
Income taxes decreased $1.1 million in the third quarter of 1999 compared
to the same period in 1998 due to a decrease in pretax book income for core
electric operations. Income taxes increased by $866,000 for the nine months
ended September 30, 1999 over 1998 due to an increase in pretax book income for
core electric operations.
OTHER INCOME
Other income for the three months ended September 30, 1999 decreased
approximately $507,000 or 51.4 percent over the same 1998 period due primarily
to decreases in earnings from affiliated companies and subsidiaries as well as a
decline in interest income due under an agreement with one of our power
suppliers. Gains from the 1999 sale of our remaining interest in GMER and a
$900,000 write-off of our investment in the Searsburg wind facility in 1998
under orders issued by the VPSB are reflected in the $1.6 million increase in
other income for the nine months ended September 30, 1999 compared to the first
nine months of 1998.
INTEREST CHARGES
Interest charges decreased 13.9 percent or $280,000 in the third quarter of
1999 over the same period in 1998 primarily due to a reduction in long-term and
short-term debt outstanding.
Interest charges decreased $478,000 or 8.2 percent in the first nine months of
1999 compared to the first nine months of 1998 for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
In the nine months ended September 30, 1999, we spent $14.6 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 $5.4 million during the
remainder of 1999.
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 $4.3
million of borrowings outstanding on the revolving credit agreement at September
30, 1999. 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-Quebec is unwilling to make new arrangements regarding the cost of
our long-term contract with it; or
* Adverse accounting treatment under SFAS 5 and SFAS 71 is required.
The credit ratings of the Company's securities are:
Duff & Phelps Moody's Standard & Poor's
--------------- ------- -------------------
First mortgage bonds BBB Baa3 BBB
Unsecured medium term debt BBB- -- --
Preferred stock BB+ ba2 BB
On August 25, 1999, Moody's Investor Service downgraded the rating of the
Company's outstanding preferred stock to "ba2" from "ba1". 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 use computer software, hardware, and other equipment in our business
that could be affected by the date transition to the next century. Our primary
Year 2000 concern is the possibility of interruptions in delivery of electricity
to our customers. We are not able to predict the impact of any interruption on
our operations or earnings, but the impact could be material.
In the past several years, we purchased and installed new customer service
and financial management systems. These systems have greatly reduced our
exposure to date-related problems. We have also replaced equipment that would
have been affected by the date change.
Management has established a project team to address Year 2000 issues. The
team has focused on three elements that are integral to the project: business
continuity; project management; and risk management. Business continuity
involves the continuation of reliable electric supply and service in a safe and
cost-effective manner. Project management involves defining and meeting the
project scope schedule and budget. Risk management involves customer
management, contingency planning and legal issues. In addition to these
internal efforts, we have been working with various industry groups to
coordinate electric utility industry Year 2000 efforts.
The approach to identifying and addressing non-compliant software
applications and embedded systems consists of the following stages: inventory
and awareness; assessment; renovation; testing; and implementation. The first
stage is to inventory all applications and systems. The assessment stage
involves determining whether software applications and embedded systems are Year
2000 compliant and prioritizing remediation needs based on risk management. The
renovation stage involves remediating or upgrading applications and systems to
make them Year 2000 ready. The testing stage determines whether the renovated
applications and systems are Year 2000 ready. The implementation stage occurs
when the tested applications and systems are deployed.
The following table summarizes the status at September 30, 1999 of our
progress toward achieving Year 2000 readiness. The figures set forth in the
table represent the estimated extent to which each phase of the Year 2000
project for software applications and embedded systems have been completed.
<TABLE>
<CAPTION>
Software Embedded
Applications Systems
---------------------
<S> <C> <C>
Inventory 100% 100%
Assessment 100% 100%
Renovation 100% 100%
Testing 95% 100%
Implementation 95% 100%
</TABLE>
We have also developed contingency plans for major outages and have adapted
these to the special problems posed by the date change to the next century. If
an unexpected outage does occur we can operate equipment manually and will have
personnel at important locations on New Years Eve 1999 and into 2000.
Our Year 2000 project focuses on those facets of our business that are
required to deliver reliable electric service. The project encompasses the
computer systems that support our core business functions such as customer
information and billing, finance, procurement, supply and personnel as well as
the components of metering, transmission, distribution and generation support.
The project also focuses on embedded systems, instrumentation and control
systems in facilities.
Our current schedule is subject to change, depending on developments that
may arise through unforeseen business circumstances, and through remediation and
testing phases of our compliance effort. 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 ISO for
New England, could also cause power delivery problems for us. We are
participating in the efforts of the ISO's New England Joint Oversight Committee
to ensure that the systems and delivery of electricity in New England are in
compliance. We have asked these companies to send written reports on their
status in eliminating Year 2000 issues that could negatively affect their
ability to serve us. All other major vendors or businesses that we depend on
for services or supplies have also been asked to report on their status.
The total cost of upgrading software that would not otherwise be replaced
in accordance with our business plans is approximately $376,000. Approximately
$198,000 has been expended as of September 30, 1999, for external labor,
hardware and software costs, and for the costs of employees who are dedicated to
the Year 2000 project. The foregoing amounts do not include the cost of new
software applications installed as a result of strategic replacement projects
described earlier. Such replacement projects have not been accelerated because
of Year 2000 issues.
The cost of the project and the dates on which we plan to complete our Year
2000 modifications are based on management's best estimates, which were derived
using numerous assumptions of future events, including the continued
availability of certain resources, third parties' Year 2000 readiness and other
factors. Further, we expect to incur additional costs after 1999 to remediate
and replace less critical software applications and embedded systems.
We have also developed contingency plans to address the most reasonably
likely worst case scenarios that could occur in the event that various Year 2000
issues are not resolved in a timely manner. Contingency planning is an ongoing
process and will continue through the fourth quarter of 1999.
The phases of our contingency planning process included business impact
analysis, contingency planning and testing. Business impact analysis requires
business unit personnel to evaluate the impact of mission-critical systems
failure on our core business operations, focusing on specific failure scenarios
and how they can be mitigated. The necessary conditions for enacting the plans
are documented along with the appropriate personnel responsible in each of the
business units should a Year 2000 failure occur. Additionally we have
participated in system readiness drills to simulate major outages and restart
capability and will continue to participate in scheduled drills in 1999.
We believe that we have adequately tested our Year 2000 readiness for our
critical systems. Nevertheless, achieving Year 2000 readiness 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 from our current expectations as to our Year 2000 readiness.
However, if we, or third parties with whom we have significant business
relationships, fail to achieve 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.
WORKFORCE REDUCTIONS
Through GMPworks, our internal efficiency effort, we are examining
critically all work done at the Company. Through the third quarter of 1999,
approximately 90 employees out of a population of 290 as of the beginning of the
year have elected to leave through early retirement or separation programs.
During the second quarter, we recorded a liability of $6.0 million representing
our estimate of pension and separation costs related to the programs. We also
recorded a regulatory asset of $6.0 million consistent with past rate treatment.
During the third quarter, we reduced the liability and related regulatory asset
by $1.3 million due primarily to the recognition of past pension asset gains.
This transaction had no impact on earnings. We continue to believe that it is
probable that we will receive future revenues to recover these costs.
POTENTIAL LEGISLATION
During November 1999, United States Senator Jeffords attached an amendment
to legislation approved by the Senate that may void the contracts between
Vermont utilities and Hydro-Quebec. It is unclear at this time what the
consequences of such legislation might be if the bill becomes law next year.
28
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SEPTEMBER 30, 1999
------------------
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
----------------------
NONE
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SIGNATURES
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
- -----------------------------------
(Registrant)
Date:November 14, 1999 /s/ Nancy Rowden Brock
----------------------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer and
Treasurer
Date:November 14, 1999 /s/ R. J. Griffin
---------------------------
R. J. Griffin, Controller
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