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, 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 NOVEMBER 6, 2000
--------------------------- ------------------------------------
$3.33 1/3 PAR VALUE 5,549,937
<TABLE>
<CAPTION>
PART I, ITEM 1
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION
UNAUDITED
--------------------------
SEPTEMBER 30 SEPTEMBER 30 DECEMBER 31
2000 1999 1999
-------- -------- --------
(In thousands)
<S> <C> <C> <C>
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . . $287,729 $278,820 $283,917
Less accumulated depreciation . . . . . . . . . 110,381 100,792 102,854
-------- -------- --------
Net utility plant . . . . . . . . . . . . . . . 177,348 178,028 181,063
Property under capital lease. . . . . . . . . . 7,038 7,696 7,038
Construction work in progress . . . . . . . . . 9,535 8,745 4,795
-------- --------
Total utility plant, net. . . . . . . . . . . 193,921 194,469 192,896
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . . 14,672 14,814 14,545
Other investments . . . . . . . . . . . . . . . 6,151 6,028 6,120
-------- --------
Total other investments . . . . . . . . . . . 20,823 20,842 20,665
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . 10 456 656
Certficate of deposit, pledged as collateral. . 15,150 - -
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $428, $398 and $398. . . . . . . . . . . . 16,790 15,340 18,503
Accrued utility revenues. . . . . . . . . . . . 6,085 6,312 6,969
Fuel, materials and supplies, at average cost . 3,385 3,281 3,290
Prepayments . . . . . . . . . . . . . . . . . . 1,667 1,597 2,197
Income tax receivable . . . . . . . . . . . . . 3,637 1,190 1,241
Other . . . . . . . . . . . . . . . . . . . . . 459 350 382
-------- --------
Total current assets. . . . . . . . . . . . . 47,183 28,526 33,238
-------- -------- --------
DEFERRED CHARGES
Demand side management programs . . . . . . . . 6,586 7,917 7,640
Purchased power costs . . . . . . . . . . . . . 14,583 2,165 7,435
Pine Street Barge Canal . . . . . . . . . . . . 8,700 8,700 8,700
Other . . . . . . . . . . . . . . . . . . . . . 16,200 18,238 18,078
-------- --------
Total deferred charges. . . . . . . . . . . . 46,069 37,020 41,853
-------- -------- --------
NON-UTILITY
Cash and cash equivalents . . . . . . . . . . . - 21 40
Other current assets. . . . . . . . . . . . . . 8 13 8
Property and equipment. . . . . . . . . . . . . 252 253 253
Equity investment in energy related businesses. - - -
Business segment held for disposal. . . . . . . 7,752 11,835 9,477
Other assets. . . . . . . . . . . . . . . . . . 1,278 1,383 1,321
--------
Total non-utility assets. . . . . . . . . . . 9,290 13,505 11,099
-------- -------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . $317,286 $294,362 $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
--------------------------
SEPTEMBER 30 SEPTEMBER 30 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
5,515,490, 5,382,114 and 5,425,571). . . . . . . $ 18,438 $ 17,992 $ 18,085
Additional paid-in capital . . . . . . . . . . . 73,035 72,501 72,594
Retained earnings. . . . . . . . . . . . . . . . 7,594 12,751 10,344
Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378)
--------- --------- ---------
Total common stock equity. . . . . . . . . . . 98,689 102,866 100,645
Redeemable cumulative preferred stock. . . . . . 12,795 13,035 12,795
Long-term debt, less current maturities. . . . . 80,100 86,800 81,800
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . 191,584 202,701 195,240
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 7,038 7,696 7,038
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 240 1,650 1,640
Current maturities of long-term debt . . . . . . 6,700 1,700 6,700
Short-term debt. . . . . . . . . . . . . . . . . 9,600 4,300 7,900
Accounts payable, trade and accrued liabilities. 4,870 4,430 6,684
Accounts payable to associated companies . . . . 8,961 6,928 6,577
Dividends declared . . . . . . . . . . . . . . . 1,012 291 285
Customer deposits. . . . . . . . . . . . . . . . 504 228 361
Accrued purchased power option call. . . . . . . 9,299 - -
Interest accrued . . . . . . . . . . . . . . . . 1,804 1,774 1,169
Energy East Liability. . . . . . . . . . . . . . 15,000 - -
Other. . . . . . . . . . . . . . . . . . . . . . 1,158 2,565 7,032
---------
Total current liabilities. . . . . . . . . . . 59,148 23,866 38,348
--------- --------- ---------
DEFERRED CREDITS
Accumulated deferred income taxes. . . . . . . . 27,194 24,858 25,201
Unamortized investment tax credits . . . . . . . 3,766 4,048 3,978
Pine Street Barge Canal site cleanup . . . . . . 8,211 9,211 8,815
Other. . . . . . . . . . . . . . . . . . . . . . 20,345 21,942 21,131
---------
Total deferred credits . . . . . . . . . . . . 59,516 60,059 59,125
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Other liabilities. . . . . . . . . . . . . . . . - 40 -
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . - 40 -
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $317,286 $294,362 $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
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
2000 1999 2000 1999
-------- -------- --------- ---------
(In thousands, except per share data)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $78,143 $68,478 $207,782 $187,031
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation . . . . . . . . . . 8,702 8,898 25,482 26,201
Company-owned generation . . . . . . . . . . . . . . . . . . 2,069 1,723 5,400 4,674
Purchases from others. . . . . . . . . . . . . . . . . . . . 49,491 42,801 129,131 104,442
Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,618 3,980 10,916 13,438
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 2,789 2,640 9,461 8,183
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 1,826 1,577 5,005 5,040
Depreciation and amortization. . . . . . . . . . . . . . . . 3,516 3,855 11,659 12,333
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,669 1,771 5,459 5,270
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 1,192 (179) 382 1,156
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 74,872 67,066 202,895 180,737
-------- -------- --------- ---------
OPERATING INCOME (LOSS). . . . . . . . . . . . . . . . . . . 3,271 1,412 4,887 6,294
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 617 408 1,861 2,306
Allowance for equity funds used during construction. . . . . 98 40 240 90
Other income (deductions), net . . . . . . . . . . . . . . . (73) 31 20 192
-------- -------- --------- ---------
TOTAL OTHER INCOME (DEDUCTIONS) . . . . . . . . . . . . . 642 479 2,121 2,588
-------- -------- --------- ---------
INCOME (LOSS) BEFORE INTEREST CHARGES. . . . . . . . . . . . 3,913 1,891 7,008 8,882
-------- -------- --------- ---------
Interest charges
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,619 1,661 4,927 5,054
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . 147 95 402 355
Allowance for borrowed funds used during construction. . . . (54) (25) (136) (54)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,712 1,731 5,193 5,355
-------- -------- --------- ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND . . . . . . . . 2,201 160 1,815 3,527
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . 240 275 779 885
-------- -------- --------- ---------
Income (loss) from continuing operations . . . . . . . . . . 1,961 (115) 1,036 2,642
Net income (loss) from discontinued segment
operations . . . . . . . . . . . . . . . . . . . . . . . . . - 0 - (603)
Loss on disposal, including provisions for
operating losses during phaseout period. . . . . . . . . . . - (4,592) (1,530) (4,592)
-------- -------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . $ 1,961 $(4,707) $ (494) $ (2,553)
======== ======== ========= =========
Common stock data
Basic earnings (loss) per share. . . . . . . . . . . . . . . $ 0.36 $ (0.88) $ (0.09) $ (0.48)
Diluted earnings (loss) per share. . . . . . . . . . . . . . 0.36 (0.88) (0.09) (0.48)
Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.28 $ 0.41
Weighted average common shares outstanding . . . . . . . . . 5,505 5,374 5,471 5,347
Weighted average common and common equivalent
shares outstanding. . . . . . . . . . . . . . . . . . . . 5,506 5,374 5,472 5,347
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . $ 6,389 $18,197 $ 10,344 $ 17,508
Net Income (loss). . . . . . . . . . . . . . . . . . . . . . 2,201 (4,432) 285 (1,668)
Cash Dividends-redeemable cumulative preferred stock . . . . (240) (275) (779) (885)
Cash Dividends-common stock. . . . . . . . . . . . . . . . . (756) (739) (2,256) (2,204)
-------- -------- --------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . $ 7,594 $12,751 $ 7,594 $ 12,751
======== ======== ========= =========
</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 NINE MONTHS ENDED
SEPTEMBER 30
2000 1999
--------------- --------
OPERATING ACTIVITIES: (In thousands)
<S> <C> <C>
Net Income (Loss) . . . . . . . . . . . . . . . . . . . . . $ (494) $(2,553)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . 11,659 12,332
Dividends from associated companies less equity income. . (18) 142
Allowance for funds used during construction. . . . . . . (375) (144)
Amortization of purchased power costs . . . . . . . . . . 4,365 4,607
Deferred income taxes . . . . . . . . . . . . . . . . . . 1,993 1,469
Provision for loss on segment disposal. . . . . . . . . . 1,530 4,592
Deferred purchased power costs. . . . . . . . . . . . . . (1,643) (781)
Accrued purchase power contract option call . . . . . . . 2,726 -
Deferred arbitration costs. . . . . . . . . . . . . . . . (3,268) (1,118)
Amortization of investment tax credits. . . . . . . . . . (212) (212)
Environmental proceedings costs . . . . . . . . . . . . . (1,023) (5,708)
Conservation expenditures . . . . . . . . . . . . . . . . (934) (1,182)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . . 1,713 3,636
Accrued utility revenues. . . . . . . . . . . . . . . . 883 298
Fuel, materials and supplies. . . . . . . . . . . . . . (96) (142)
Prepayments and other current assets. . . . . . . . . . 455 4,639
Accounts payable. . . . . . . . . . . . . . . . . . . . 571 (1,238)
Accrued income taxes payable and receivable . . . . . . (2,396) (1,560)
Other current liabilities . . . . . . . . . . . . . . . (4,369) (2,302)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 537 832
--------------- --------
Net cash provided by continuing operations. . . . . . . . 11,605 15,607
Net change in discontinued segment. . . . . . . . . . . . 195 (138)
--------------- --------
Net cash provided by operating activities . . . . . . . . 11,799 15,469
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . . (8,551) (7,386)
Investment in nonutility property . . . . . . . . . . . . . (143) (176)
--------------- --------
Net cash provided by (used in) investing activities . . . (8,694) (7,562)
--------------- --------
FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . . 794 868
Investment in Certificate of Deposit, pledged for revolver. (15,150) -
Energy East obligation. . . . . . . . . . . . . . . . . . . 15,000 -
Short-term debt, net. . . . . . . . . . . . . . . . . . . . 1,700 (2,700)
Cash dividends. . . . . . . . . . . . . . . . . . . . . . . (3,035) (3,089)
Reduction in preferred stock. . . . . . . . . . . . . . . . (1,400) (1,400)
Reduction in long-term debt . . . . . . . . . . . . . . . . (1,700) (1,700)
--------------- --------
Net cash provided by (used in) financing activities . . . (3,791) (8,021)
--------------- --------
Net increase in cash and cash equivalents . . . . . . . . . (686) (114)
Cash and cash equivalents at beginning of period. . . . . . 696 590
--------------- --------
Cash and cash equivalents at end of period. . . . . . . . . $ 10 $ 476
=============== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . . $ 4,420 $ 4,577
Income taxes, net . . . . . . . . . . . . . . . . . . . . 1,191 997
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 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, the quarterly report
for the three and six months ended June 30, 2000 filed on Form 10-Q, and the
Form 8-K filed on August 29, 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 September 30, 2000, there was a deferred charge of $248,000, compared
with a deferred charge of $676,000 at September 30, 1999. These deferred
charges are amortized through revenue accounts during 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. Sale
of Green Mountain Power Corporation's("GMP" or the "Company") ownership interest
in GMER was completed in the first quarter of 1999. During 1999, we decided to
sell the assets of MEI, and report its results as income (loss) from operations
of a discontinued segment. During June 2000, one of MEI's subsidiary operations
was sold. See the additional discussion under the caption "Segments and Related
Information". 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 Nine months ended
September 30 September 30
2000 1999 2000 1999
------- ------- -------- --------
(in thousands)
<S> <C> <C> <C> <C>
Gross Revenue. . . . . $44,648 $49,029 $130,042 $139,182
Net Income Applicable. $ 1,559 $ 1,580 $ 4,942 $ 4,874
to Common Stock
Equity in Net Income . $ 275 $ 287 $ 890 $ 880
</TABLE>
On October 15, 1999, the owners of Vermont Yankee Nuclear Power Corporation
("Vermont Yankee") accepted a bid from AmerGen Energy Company ("Amergen") for
the Vermont Yankee generating plant. The asset sale will require numerous
regulatory approvals, and has received the approval of the Federal Energy
Regulatory Commission and the Nuclear Regulatory Commission. Decisions are still
pending from the Securities and Exchange Commission, the Internal Revenue
Service, and the VPSB. If approved, the price AmerGen will pay Vermont Yankee
will be approximately $10.0 million for the plant and property.
As a condition of the sale, Vermont Yankee will make a one-time and final
payment of approximately $54.3 million to 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.
The Vermont Department of Public Service, Vermont Yankee, and Amergen are
currently negotiating a revised sale agreement that may increase the price
Amergen will pay for the plant.
VERMONT ELECTRIC POWER COMPANY, INC.
Percent ownership: 29.5% common
30.0% preferred
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30 September 30
2000 1999 2000 1999
------ ------ ------- -------
(in thousands)
<S> <C> <C> <C> <C>
Gross Revenue . . . . $7,011 $6,826 $21,151 $21,031
Net Income. . . . . . $ 309 $ 280 $ 892 $ 901
Equity in Net Income. $ 93 $ 61 $ 267 $ 269
</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 ("Pine Street") 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 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 September 30, 2000, our total expenditures related to the Pine Street
site since 1982 were approximately $23.2 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 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, 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 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 of such expenditures. In an Order in that case released
March 2, 1998, the VPSB suspended the amortization of expenditures associated
with the Pine Street 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 site, taking into account recoveries from insurance carriers and other
PRPs, 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-Quebec
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 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-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".
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-Quebec 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 of 1999 as the result
of our May 8, 1998 rate filing, discussed below.
In its February 27, 1998 Order, the VPSB discussed 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-Quebec 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-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 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-Quebec 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. 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 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-Quebec. 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 during January, 2001. The amendments
maintained the other features of the original MOU, and the second amendment
provides for a provisional pro forma cost of service disallowance of GMP's year
2000 Hydro-Quebec contract costs in the amount of $7.5 million, and 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. At September 30, 2000, total revenues subject to refund
are approximately $20.0 million.
Notwithstanding the interim rate settlement, we are unable to predict
whether regulatory developments 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, eliminating or reducing
dividends, or 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
that 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-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 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 Company's September 30, 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 $28.2 million attributable to net
regulatory assets.
POWER SUPPLY AND TRANSMISSION
One of our power supply arrangements with Hydro-Quebec, referred to as the
"9701 arrangement", allows Hydro-Quebec to exercise an option to purchase power
from the Company at energy prices based on a 1987 contract. 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-Quebec
of approximately $6.6 million. The Company recognized $1.6 million in expense
during the quarter ended September 30, 2000 to reflect these estimated costs. A
regulatory asset of $1.6 million reflects the unrecognized expense that will be
recovered in rates over the remaining quarter of 2000. Additional expense of
$360,000 was recognized in the quarter ended September 30, 2000, primarily for
estimated costs of power purchases in excess of amounts being collected in
rates, to supply energy Hydro-Quebec has indicated it will purchase under the
9701 arrangement through August 2001.
Another power supply arrangement with Hydro-Quebec, referred to as the
"9601 arrangement", or "9601", provides energy that the Company resells to
Morgan Stanley Capital Group("MS", or "Morgan Stanley") under a separate power
supply arrangement. The 9601 arrangement allows Hydro-Quebec to curtail
deliveries of energy should it need to use certain resources to supplement
available supply. During October 2000, we were notified of Hydro-Quebec's
intention to curtail delivery of power during October and November 2000.
Obligations under the MS contract may require that we purchase energy at prices
that could be substantially higher than those normally available under the 9601
arrangement. MS and the Company disagree about the extent to which the Company
is required to provide 9601 energy to MS. The Company believes that MS has
already utilized energy in excess of its 9601 entitlement for 2000. If
Hydro-Quebec were to continue to curtail deliveries during 2001, the Company
estimates such curtailment could raise power supply costs by a range of $3
million to $7 million, depending upon the level of curtailment, the level of
energy required to be delivered under the MS arrangement, and the future price
of energy.
It is possible our estimate of future power supply costs could differ
materially from actual results. Material future losses could result if
Hydro-Quebec elects to exercise its options at levels not included in rates.
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, 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. We have classified MEI's net
assets and liabilities as "Business Segment Held for Sale", reflecting the
Company's intent to dispose of MEI's assets. As of September 30, 2000, MEI had
disposed of one subsidiary operation classified as held for disposal, realizing
proceeds of $1.7 million.
During the fiscal year ended December 31, 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. During the nine
months ended September 30, 2000, MEI also recognized provisions for loss on
disposal of $1.5 million, net of taxes of $1.0 million, for its remaining
operations held for disposal. These 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
materially exceed amounts recorded. Results of operations for MEI are now
reported under "Net income (loss) from operations 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>
Three months ended Nine months ended
September 30 September 30
2000 1999 2000 1999
------- -------- --------- ---------
In thousands
<S> <C> <C> <C> <C>
External revenues
Electric utility. . . . . . . . $78,143 $68,478 $207,782 $187,031
MEI segment . . . . . . . . . . 733 1,171 1,351 3,531
Net income (loss) from
operations
Electric utility. . . . . . . . 1,961 (115) 1,036 2,642
MEI segment . . . . . . . . . . - - - (603)
Provision for loss on
disposal of MEI assets. . . . . - (4,592) (1,530) (4,592)
------- -------- --------- ---------
Consolidated net income (loss) . $ 1,961 $(4,707) $ (494) $ (2,553)
======= ======== ========= =========
Basic earnings (loss) per share
Discontinued operations . . . $ - $ (0.86) $ (0.28) $ (0.97)
Continuing operations . . . . $ 0.36 $ (0.02) $ 0.19 $ 0.49
</TABLE>
17
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 the analysis of
its contracts, including our 9701 arrangement that allows Hydro-Quebec the
option to purchase energy at prices materially below current market costs. The
Company's initial review of the 9701 arrangement indicates that it is a
derivative that would likely require valuation at fair value when SFAS 133 is
adopted. Valuation could result in a material loss and will depend primarily on
the level of recovery provided in rates, and on estimates of future market
prices for energy.
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
SEPTEMBER 30, 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",
"estimates", "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 Nine months ended
September 30 September 30
2000 1999 2000 1999
----- ------- ------- -------
<S> <C> <C> <C> <C>
Utility business . . . $0.33 $(0.04) $ 0.11 $ 0.31
Unregulated businesses 0.03 0.02 0.08 0.18
----- ------- ------- -------
Earnings(loss) from: . 0.36 (0.02) 0.19 0.49
Continuing operations
Discontinued segment . 0.00 (0.86) (0.28) (0.97)
----- ------- ------- -------
Basic earnings
(loss) per share . . $0.36 $(0.88) $(0.09) $(0.48)
===== ======= ======= =======
</TABLE>
UTILITY BUSINESS
The Company recorded earnings from utility operations of $0.33 in the
quarter ended September 30, 2000, compared with a loss from utility operations
of $0.04 in the third quarter of 1999. The increase in earnings was due to the
absence of power supply costs that resulted in a loss for the third quarter of
1999. During that quarter, the Company recognized additional charges to
reflect disallowed Hydro-Quebec power supply contract costs, including costs
related to the 9701 arrangement.
The earnings from utility operations for the nine months ended September 30,
2000 were $0.11 per common share compared with earnings of $0.31 per common
share for the respective 1999 period. The decrease in earnings is primarily due
to increased obligations under arrangement with Hydro-Quebec and changes in
power supply market conditions that resulted in a decline in the value of energy
resources held by the Company, partially offset by higher retail revenues due to
a temporary 3.0 percent retail rate increase and increased retail MWh sales
during 2000. The Company has previously accrued losses for disallowed
Hydro-Quebec power supply costs pursuant to VPSB Orders. Results for the three
and nine months ended September 30, 2000 do not reflect any disallowed
Hydro-Quebec power supply costs, compared with a charge for disallowed power
costs of $1.7 million for the same respective periods during 1999. 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 September 30, 2000 and 1999, respectively, and $5.6
million and $3.9 million for the nine months ended September 30, 2000 and 1999,
respectively.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from continuing
operations for the three months ended September 30, 2000 increased compared with
the same period in 1999, primarily due to an absence of subsidiary losses in the
current year. A financial summary for these businesses, excluding MEI, follows:
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30 September 30
2000 1999 2000 1999
----- ----- ----- ------
(In thousands)
<S> <C> <C> <C> <C>
Revenue. . . . $ 259 $ 265 $ 780 $ 810
Expense. . . . 99 172 $ 341 (137)
----- ----- ----- ------
Net Income . . $ 160 $ 93 $ 439 $ 947
===== ===== ===== ======
</TABLE>
Earnings from unregulated businesses included in results from continuing
operations for the nine months ended September 30, 2000 decreased compared with
results of the same period in 1999, primarily due to a $600,000 (after tax) gain
on the 1999 sale of our remaining interest in Green Mountain Energy Resources,
LLC.
DISCONTINUED SEGMENT OPERATIONS
The Company is in the process of selling or disposing of assets owned by
MEI, a wholly owned subsidiary that invests in energy generation, energy
efficiency and wastewater treatment businesses. No gain or loss on discontinued
operations was recognized in the third quarter ended September 30, 2000,
compared with a loss of $0.86 per share for the third quarter of 1999.
MEI's results are reported separately after income (loss) from continuing
operations. MEI's operating loss for the three months ended September 30, 2000
was previously recognized as provision for loss during the last two quarters of
1999. The operating income for the three months ended September 30, 2000 would
have been approximately $54,000 compared with a loss of $159,000 for the same
period a year ago.
The Company recorded a loss on discontinued operations of $0.28 per share
for the nine months ended September 30, 2000, compared to a loss of $0.97 per
share for the same period in 1999. MEI's operating loss for the nine months
ended September 30, 2000 was previously recognized as provision for loss during
the last two quarters of 1999. The operating loss for the nine months ended
September 30, 2000 would have been approximately $954,000 compared with a loss
of $603,000 for the same period a year ago.
The provisions for loss from discontinued operations reflect management's
current estimate. The ultimate loss remains subject to the consummation of the
sale or other disposition, and could exceed the amounts recorded by a material
amount.
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, 2000 and 1999 are
summarized below:
<TABLE>
<CAPTION>
Three months ended Nine months ended
(dollars in thousands) September 30 September 30
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Operating revenues
Retail . . . . . . . $ 45,482 $ 45,520 $ 138,567 $ 133,980
Sales for Resale . . 31,968 22,248 66,898 50,998
Other. . . . . . . . 693 710 2,317 2,053
---------- ---------- ---------- ----------
Total Operating Revenues $ 78,143 $ 68,478 $ 207,782 $ 187,031
========== ========== ========== ==========
MWh sales-Retail . . . . 475,952 483,684 1,449,017 1,409,009
MWh sales for Resale . . 798,317 684,787 1,954,277 1,669,211
---------- ---------- ---------- ----------
Total MWh Sales. . . . . 1,274,269 1,168,471 3,403,294 3,078,220
========== ========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Average Number of Customers
Three months ended Nine months ended
September 30 September 30
2000 1999 2000 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
Residential . . . . . . . 72,557 71,461 72,288 71,379
Commercial and Industrial 12,835 12,482 12,690 12,413
Other . . . . . . . . . . 67 65 65 66
------ ------ ------ ------
Total Number of Customers. . 85,459 84,008 85,043 83,858
====== ====== ====== ======
</TABLE>
REVENUES
Revenues from operations in the third quarter of 2000 increased 14.1
percent or $9.7 million compared with the same period in 1999. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the third quarter of 2000 were almost identical when compared
with the same period in 1999 reflecting a 3.0 percent temporary rate increase
effective January 1, 2000, and a 1.6 percent decrease in retail MWh sales.
Sales of electricity decreased by 1.6 percent to small commercial and industrial
customers, 2.9 percent to residential customers and 0.8 percent to large lower
margin industrial customers.
We sell wholesale electricity to others for resale. Our revenue from wholesale
sales of electricity increased $9.7 million in the third quarter of 2000
compared with the same period in 1999. These resale transactions are primarily
due to a power purchase and supply agreement between the Company and 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.
Revenues from operations for the nine months ended September 30, 2000
increased 11.1 percent or $20.8 million compared with the same period in 1999.
Retail revenues were 3.4 percent or $4.6 million higher in the first nine
months of 2000 when compared with the same 1999 period, reflecting a 3 percent
temporary rate increase, and a 3.1 percent increase in retail MWh sales. For
the nine months ended September 30, 2000, sales of electricity increased by 2.0
percent to small commercial and industrial customers, 1.6 percent to residential
customers, and 5.1 percent to large lower margin industrial customers compared
with the same 1999 period.
OPERATING EXPENSES
POWER SUPPLY EXPENSES - THREE MONTHS ENDED SEPTEMBER 30, 2000
Power supply expenses increased 15.1 percent or $6.8 million in the third
quarter of 2000 over the same period in 1999.
Power supply expense decreased 2.2% or $195,000 during the third quarter at
Vermont Yankee. The decrease was due to lower than anticipated maintenance and
operating costs. A proposed sale of the generating plant is previously
discussed under Part I, Item 2, "Investment in Associated Companies".
Company-owned generation expenses increased 20.06 percent or $346,000 in
the third quarter of 2000 compared with the same period in 1999 primarily due to
higher fuel costs.
The cost of power that we purchased from other companies increased 15.6
percent or $6.7 million in the third quarter of 2000 over the same period in
1999. This was primarily due to power supply costs for increased wholesale
electric sales of $9.7 million. Power supply costs of $4.7 million under the
9701 arrangement and $1.7 million for the continued disallowance of other
Hydro-Quebec power supply costs during the third quarter of 1999 limited the
increases for 2000.
As described previously herein, the 9701 arrangement allows Hydro-Quebec to
exercise an option to purchase power from the Company at energy prices based on
a 1987 contract which are below current market prices. The Company's temporary
rate settlement in December 1999 includes revenues in 2000 sufficient to provide
for estimated net costs of replacing power purchased by Hydro-Quebec under the
9701 arrangement of approximately $6.6 million. The Company recognized $2.1
million in expense during the quarter ended September 30, 2000 to reflect
estimated costs under the 9701 arrangement. A regulatory asset of $8.2 million
reflects the unrecognized expense that is expected to be recovered in rates
through August 2001. Material future losses could result if Hydro-Quebec
elects to exercise its options at levels not included in rates.
It is possible our estimate of future power supply costs could differ materially
from actual results. The Company hedges some or all of its energy price risk
under the 9701 arrangement through forward purchase contracts. We believe both
the Hydro-Quebec arrangement and the forward purchase contracts may be
potentially considered derivative instruments as defined by SFAS 133.
Management has not estimated the impact on earnings upon adoption of SFAS 133 at
this time, but it may be material. 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-Quebec under the 9701
arrangement. Our costs to meet demand during periods of high energy usage and
to replace such energy repurchases by Hydro-Quebec rose substantially after the
new ISO market rules were implemented on May 1, 1999. 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 since the first half of 1999, our earnings and cash flow
could be adversely impacted by a material amount.
Another power supply arrangement with Hydro-Quebec, referred to as the 9601
arrangement, or 9601, provides energy that the Company resells to MS under a
separate power supply arrangement. The 9601 arrangement allows Hydro-Quebec to
curtail deliveries of energy should it need to use certain resources to
supplement available supply. During October 2000, we were notified of
Hydro-Quebec's intention to curtail delivery of power during October and
November 2000. Obligations under the MS contract may require that we purchase
energy at prices that could be substantially higher than those normally
available under the 9601 arrangement. MS and the Company disagree about the
extent to which the Company is required to provide 9601 energy to MS. The
Company believes that MS has already utilized energy in excess of its 9601
entitlement for 2000. If Hydro-Quebec were to continue to curtail deliveries
during 2001, the Company estimates it could raise power supply costs by a range
of $3 million to $7 million, depending upon the level of curtailment, the level
of energy required to be delivered under the MS arrangement, and the future
price of energy. It is possible our estimate of future power supply costs could
differ materially from actual results. Material future losses could result if
Hydro-Quebec elects to exercise its options at levels not included in rates.
During the three months ended September 30, 2000, the Company deferred an
additional $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. At September 30, 2000, total deferred arbitration costs
were $4.8 million. 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.
POWER SUPPLY EXPENSES - NINE MONTHS ENDED SEPTEMBER 30, 2000
For the nine months ended September 30, 2000, power supply expenses
increased 18.3 percent or $24.7 million compared with the same period in 1999.
At Vermont Yankee, power supply expense decreased 2.8% or $718,000 for the
first nine months of 2000 compared with the same period for 1999, primarily due
to a higher than expected refund of property insurance and lower than expected
maintenance and operating costs.
Company-owned generation expenses increased 15.6 percent or $726,000 for
the first nine months of 2000 compared to the same period in 1999 primarily due
to higher fuel costs incurred for peak generation facilities.
The cost of power that we purchased from other companies during the first
nine months of 2000 increased 23.6 percent or $24.7 million over the same period
in 1999. This was primarily due to a $7.5 million increase in power purchased
under our power purchase and supply agreement with MS, a $5.0 million charge
for power purchases to replace energy sold to Hydro-Quebec under the 9701
arrangement, increased demand charges of $3.6 million under long-term power
arrangements with Hydro-Quebec, changes in power supply market conditions that
resulted in a $4.0 million decline in value of energy resources held by the
Company, and $1.6 million of increased purchases of power from independent power
producers.
OTHER OPERATING EXPENSES
Other operating expenses decreased 9.1 percent or $362,000 in the third
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.
Other operating expense decreased $2.5 million for the first nine months of
2000 when compared with the first nine months of 1999. The 18.7 percent
decrease over the same 1999 fiscal period reflects an absence of costs
associated with the Company's reorganization and reductions in lease expense and
other facilities costs as discussed above. The 1999 period included a benefit
of $1.6 million in expense reductions for the elimination of a regulatory
liability related to the corporate headquarters that was sold.
TRANSMISSION EXPENSES
Transmission expenses increased by $149,000 or 5.6% for the three months
ended September 30, 2000 compared with the same period in 1999. Transmission
expenses increased primarily due to congestion charges associated with the
creation of the ISO as the clearinghouse 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.
For the nine months ended September 30, 2000, transmission expenses
increased 15.6%, or $1.3 million, when compared with the first nine months of
1999, for the same reasons.
MAINTENANCE EXPENSE
Our maintenance expenses increased 15.8 percent or $249,000 in the third
quarter of 2000 compared with the same period in 1999 due primarily to scheduled
maintenance timing differences at a peak generation facility. Maintenance
expenses for the nine months ended September 30, 2000, decreased 0.7 percent or
$35,000 compared with the same period in 1999. An increase in maintenance
expense of generation, transmission, and distribution assets was more than
offset by maintenance expense savings due to the sale of the Company's corporate
headquarters in 1999.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses decreased $339,000 or 8.8 percent
during the third quarter of 2000 compared with the same period in 1999. The
reduction is attributed to decreased amortization of demand side management
assets.
For the first nine months of 2000, depreciation and amortization expense
decreased $673,000 or 5.5 percent compared with the first nine months of 1999.
These differences reflect decreased amortization of demand side management
assets.
TAXES OTHER THAN INCOME TAXES
Other taxes decreased 5.8 percent or $102,000 in the third quarter of 2000
compared with the same period in 1999, reflecting adjustments for negotiated
property tax decreases.
Other taxes increased 3.6 percent or $190,000 in the first nine months of
2000 compared with the same period in 1999, reflecting overall property tax and
gross revenue tax increases.
INCOME TAXES
Provision for income taxes increased $1.4 million in the third quarter of
2000 compared with the same period in 1999 due to an increase in pretax book
income for utility operations.
A decrease in year to date pretax book income resulted in a $775,000
decrease in income tax expense for the nine months ended September 30, 2000 when
compared with the same 1999 period.
OTHER INCOME
Other income for the three months ended September 30, 2000 increased
approximately $209,000 or 51.2 percent from the same 1999 period due primarily
to increases in earnings from associated companies. For the nine months ended
September 30, 2000, other income decreased by $445,000 compared to the same
period in 1999, due primarily to the sale of the Company's remaining interest in
GMER in the first quarter of 1999.
INTEREST CHARGES
Interest charges decreased 1.1 percent or $20,000 in the third quarter of
2000 over the same period in 1999 primarily due to continuing reductions in
long-term debt outstanding.
Interest charges decreased 3.0 percent or $162,000 for the nine months
ended September 30, 2000 compared with the the first nine months of 1999 for the
same reasons.
LIQUIDITY AND CAPITAL RESOURCES
In the nine months ended September 30, 2000, we spent $8.5 million
principally for expansion and improvements of our transmission and distribution
plant, for expenditures related to the Pine Street site, and for computer
information systems. We expect to spend an additional $6.7 million during the
remainder of 2000.
On June 21, 2000, we renewed a $15 million revolving credit agreement with
Fleet National Bank and Citizens Bank of Massachusetts(the "Fleet Agreement").
The Fleet Agreement is for a period of 364 days and will expire on June 20,
2001. We had no borrowings outstanding on the Fleet Agreement at September 30,
2000.
On September 20, 2000, we established a $15 million revolving credit
agreement("KeyBank Agreement") with KeyBank National Association("KeyBank").
The agreement is for a period of 364 days and will expire on September 19, 2001.
Pursuant to a one year power supply option agreement between the Company and
Energy East Corporation("EE"), EE made a payment of $15,000,000 to the Company.
In exchange, the Company gave EE an option to purchase energy from certain
wholly owned production facilities, for a period not to exceed 15 years, if the
funds are not returned to EE upon request after September 2001. The Company was
required to invest the funds provided by EE in a certificate of deposit at
KeyBank pledged by the Company to secure the repayment of the Keybank revolving
credit facility. At September 30, 2000, there was $9.6 million outstanding on
the KeyBank Agreement.
We believe amounts available under the two revolving credit facilities will
be sufficient to meet our forecasted borrowing requirements through June 2001.
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 agreements, could lead all of our lenders to seek to enter into new
credit agreements that have 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
* Adverse material accounting treatment under SFAS 5 or SFAS 71 is required.
The credit ratings of the Company's securities are:
Fitch Moody's Standard & Poor's
-------------------
First mortgage bonds BB+ Ba1 BBB
Unsecured medium term debt BB- -- --
Preferred stock B+ ba3 BB
On August 25, 2000, Fitch (formerly Duff & Phelps) downgraded the credit
ratings of the Company to below investment grade and maintained the ratings on
Rating Watch-Negative. Moody's, Fitch's and Standard & Poor's credit ratings
for the Company remain on Negative Watch, Rating Watch-Negative 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".
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 a material 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 primarily
financed through long-term debt.
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SEPTEMBER 30,2000
-----------------
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
--------
10-b-86 Revolving Credit Agreement with Keybank
10-b-87 Amendment to Fleet Revolving Credit Agreement
10-b-88 Energy East Power Purchase Option Agreement
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
----------------------
A report on Form 8-K was filed August 25, 2000, announcing the credit rating
downgrade by Fitch (formerly Duff and Phelps). Fitch downgraded the Company's
first mortgage bonds to BB+ from BBB, and preferred securities from BB+ to B+.
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 10, 2000 /s/Nancy Rowden Brock
------------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer, Secretary,
and Treasurer
Date: November 10, 2000 /s/ R.J. Griffin
------------------
R. J. Griffin, Controller
