August 11, 2000
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________________
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 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 AUGUST 8, 2000
--------------------------- -----------------------------------
$3.33 1/3 PAR VALUE 5,514,035
<TABLE>
<CAPTION>
PART I, ITEM 1
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION
UNAUDITED
----------
JUNE 30 JUNE 30 DECEMBER 31
2000 1999 1999
---------- -------- ------------
(In thousands)
<S> <C> <C> <C>
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . . $ 287,105 $277,018 $ 283,917
Less accumulated depreciation . . . . . . . . . 107,934 98,716 102,854
---------- -------- ------------
Net utility plant . . . . . . . . . . . . . . . 179,171 178,302 181,063
Property under capital lease. . . . . . . . . . 7,038 7,696 7,038
Construction work in progress . . . . . . . . . 7,037 8,956 4,795
---------- ------------
Total utility plant, net. . . . . . . . . . . 193,246 194,954 192,896
---------- -------- ------------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . . 14,708 15,016 14,545
Other investments . . . . . . . . . . . . . . . 6,043 5,895 6,120
---------- ------------
Total other investments . . . . . . . . . . . 20,751 20,911 20,665
---------- -------- ------------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . 4,755 7,293 656
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $398 and $449. . . . . . . . . . . . . . . 17,155 16,747 18,503
Accrued utility revenues. . . . . . . . . . . . 6,371 5,773 6,969
Fuel, materials and supplies, at average cost . 3,063 2,822 3,290
Prepayments . . . . . . . . . . . . . . . . . . 340 910 2,197
Income tax receivable . . . . . . . . . . . . . 4,042 762 1,241
Other . . . . . . . . . . . . . . . . . . . . . 178 261 382
---------- ------------
Total current assets. . . . . . . . . . . . . 35,904 34,568 33,238
---------- -------- ------------
DEFERRED CHARGES
Demand side management programs . . . . . . . . 6,586 8,518 7,640
Purchased power costs . . . . . . . . . . . . . 9,663 2,841 7,435
Pine Street Barge Canal . . . . . . . . . . . . 8,700 8,700 8,700
Other . . . . . . . . . . . . . . . . . . . . . 16,598 19,019 18,078
---------- ------------
Total deferred charges. . . . . . . . . . . . 41,547 39,078 41,853
---------- -------- ------------
NON-UTILITY
Cash and cash equivalents . . . . . . . . . . . 39 18 40
Other current assets. . . . . . . . . . . . . . 8 63 8
Property and equipment. . . . . . . . . . . . . 253 253 253
Intangible assets . . . . . . . . . . . . . . . - - -
Equity investment in energy related businesses. - - -
Business segment held for disposal. . . . . . . 8,033 16,433 9,477
Other assets. . . . . . . . . . . . . . . . . . 1,294 1,350 1,321
------------
Total non-utility assets. . . . . . . . . . . 9,627 18,117 11,099
---------- -------- ------------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . $ 301,075 $307,628 $ 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
-----------
JUNE 30 JUNE 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
5,498,037, 5,344,920 and 5,425,571). . . . . . . $ 18,327 $ 17,892 $ 18,085
Additional paid-in capital . . . . . . . . . . . 72,913 72,331 72,594
Retained earnings. . . . . . . . . . . . . . . . 6,389 18,197 10,344
Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378)
----------- --------- -------------
Total common stock equity. . . . . . . . . . . 97,251 108,042 100,645
Redeemable cumulative preferred stock. . . . . . 12,795 14,435 12,795
Long-term debt, less current maturities. . . . . 80,100 86,800 81,800
----------- --------- -------------
Total capitalization . . . . . . . . . . . . . 190,146 209,277 195,240
----------- --------- -------------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 7,038 7,696 7,038
----------- --------- -------------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 1,640 1,650 1,640
Current maturities of long-term debt . . . . . . 6,700 1,700 6,700
Short-term debt. . . . . . . . . . . . . . . . . - - 7,900
Accounts payable, trade and accrued liabilities. 6,400 6,941 6,684
Accounts payable to associated companies . . . . 8,808 6,994 6,577
Dividends declared . . . . . . . . . . . . . . . 286 320 285
Customer deposits. . . . . . . . . . . . . . . . 379 226 361
Accrued purchased power option call. . . . . . . 12,478 - -
Interest accrued . . . . . . . . . . . . . . . . 1,151 1,165 1,169
Deferred revenues. . . . . . . . . . . . . . . . 3,580 3,124 -
Other. . . . . . . . . . . . . . . . . . . . . . 3,144 2,287 7,032
-------------
Total current liabilities. . . . . . . . . . . 44,566 24,407 38,348
----------- --------- -------------
DEFERRED CREDITS
Accumulated deferred income taxes. . . . . . . . 26,487 24,311 25,201
Unamortized investment tax credits . . . . . . . 3,836 4,119 3,978
Pine Street Barge Canal site cleanup . . . . . . 8,910 13,803 8,815
Other. . . . . . . . . . . . . . . . . . . . . . 20,092 23,946 21,131
-------------
Total deferred credits . . . . . . . . . . . . 59,325 66,179 59,125
----------- --------- -------------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Current liabilities. . . . . . . . . . . . . . . - - -
Other liabilities. . . . . . . . . . . . . . . . - 69 -
----------- --------- -------------
Total non-utility liabilities. . . . . . . . . - 69 -
----------- --------- -------------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $ 301,075 $307,628 $ 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 SIX MONTHS ENDED
JUNE 30 JUNE 30
2000 1999 2000 1999
--------- -------- --------- ---------
(In thousands, except per share data)
<S> <C> <C> <C> <C>
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 61,927 $59,535 $129,639 $118,553
--------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . . . . . . . . 8,719 8,944 16,779 17,302
Company-owned generation. . . . . . . . . . . . . . . . . . . . . . . . . 2,126 1,926 3,330 2,950
Purchases from others . . . . . . . . . . . . . . . . . . . . . . . . . . 42,994 33,136 79,640 61,642
Other operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,671 4,166 7,299 9,458
Transmission. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,188 2,847 6,672 5,543
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,553 1,893 3,179 3,464
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 3,977 4,238 8,144 8,478
Taxes other than income . . . . . . . . . . . . . . . . . . . . . . . . . 1,765 1,685 3,791 3,499
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,069) (276) (811) 1,335
--------- -------- --------- ---------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . 64,924 58,559 128,023 113,671
--------- -------- --------- ---------
OPERATING INCOME (LOSS) . . . . . . . . . . . . . . . . . . . . . . . . . (2,997) 976 1,616 4,882
--------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations . . . . . . . 620 564 1,244 1,898
Allowance for equity funds used during construction . . . . . . . . . . . 79 30 141 50
Other income (deductions), net. . . . . . . . . . . . . . . . . . . . . . (91) 107 94 161
--------- -------- --------- ---------
TOTAL OTHER INCOME (DEDUCTIONS). . . . . . . . . . . . . . . . . . . . 608 701 1,479 2,109
--------- -------- --------- ---------
INCOME (LOSS) BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . . (2,389) 1,677 3,095 6,991
--------- -------- --------- ---------
Interest charges
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,647 1,689 3,308 3,394
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111 110 255 260
Allowance for borrowed funds used during construction . . . . . . . . . . (42) (16) (82) (30)
--------- -------- --------- ---------
TOTAL INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . 1,716 1,783 3,481 3,624
--------- -------- --------- ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . . . . (4,105) (106) (386) 3,367
DISCONTINUED OPERATIONS
Dividends on preferred stock. . . . . . . . . . . . . . . . . . . . . . . 270 305 539 610
--------- -------- --------- ---------
Income (loss) from continuing operations. . . . . . . . . . . . . . . . . (4,375) (411) (925) 2,757
Net income (loss) from discontinued segment
operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - (82) - (603)
Loss on disposal, including provisions for
operating losses during phaseout period . . . . . . . . . . . . . . . . . (1,530) - (1,530) -
--------- -------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . ($5,905) ($493) ($2,455) $ 2,154
========= ======== ========= =========
Common stock data
Basic and diluted earnings (loss) per share from discontinued operations. ($0.28) ($0.01) ($0.28) ($0.11)
Basic and diluted earnings (loss) per share from continuing operations. . (0.80) (0.08) (0.17) 0.52
--------- -------- --------- ---------
Basic and diluted earnings (loss) per share . . . . . . . . . . . . . . . ($1.08) ($0.09) ($0.45) $ 0.40
========= ======== ========= =========
Cash dividends declared per share . . . . . . . . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.28 $ 0.28
Weighted average shares outstanding . . . . . . . . . . . . . . . . . . . 5,472 5,344 5,455 5,331
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period . . . . . . . . . . . . . . . . . . . . . . $ 13,046 $19,425 $ 10,344 $ 17,508
Net Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,635) (188) (1,916) 2,764
Cash Dividends-redeemable cumulative preferred stock. . . . . . . . . . . (270) (305) (539) (610)
Cash Dividends-common stock . . . . . . . . . . . . . . . . . . . . . . . (752) (735) (1,500) (1,465)
--------- -------- --------- ---------
Balance - end of period . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,389 $18,197 $ 6,389 $ 18,197
========= ======== ========= =========
</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 SIX MONTHS ENDED
JUNE 30,
2000 1999
--------- ---------
(In thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income (Loss) . . . . . . . . . . . . . . . . . . . . $ (2,455) $ 2,764
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . 8,144 8,478
Dividends from associated companies less equity income. (57) (38)
Allowance for funds used during construction. . . . . . (223) (80)
Amortization of purchased power costs . . . . . . . . . 3,058 3,795
Deferred income taxes . . . . . . . . . . . . . . . . . 1,286 922
Deferred revenues . . . . . . . . . . . . . . . . . . . 3,580 3,124
Provision for loss on segment disposal. . . . . . . . . 1,530 -
Deferred purchased power costs. . . . . . . . . . . . . (3,103) (378)
Accrued purchase power contract option call . . . . . . 12,478 -
Deferred arbitration costs. . . . . . . . . . . . . . . (2,157) (550)
Amortization of investment tax credits. . . . . . . . . (141) (141)
Environmental proceedings costs . . . . . . . . . . . . (155) (1,117)
Conservation expenditures . . . . . . . . . . . . . . . (671) (744)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . 1,347 2,229
Accrued utility revenues. . . . . . . . . . . . . . . 597 838
Fuel, materials and supplies. . . . . . . . . . . . . 226 317
Prepayments and other current assets. . . . . . . . . 2,064 4,788
Accounts payable. . . . . . . . . . . . . . . . . . . 1,947 1,340
Accrued income taxes payable and receivable . . . . . (2,801) (370)
Other current liabilities . . . . . . . . . . . . . . (3,888) (3,089)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 734 (141)
--------- ---------
Net cash provided by continuing operations. . . . . . . 21,341 21,947
Net change in discontinued segment. . . . . . . . . . . (86) 362
--------- ---------
Net cash provided by operating activities . . . . . . . 21,255 22,309
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . (5,982) (5,313)
Investment in nonutility property . . . . . . . . . . . . (97) (97)
--------- ---------
Net cash provided by (used in) investing activities . . (6,080) (5,410)
--------- ---------
FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . 561 598
Short-term debt, net. . . . . . . . . . . . . . . . . . . (7,900) (7,000)
Cash dividends. . . . . . . . . . . . . . . . . . . . . . (2,039) (2,076)
Reduction in preferred stock. . . . . . . . . . . . . . . - -
Reduction in long-term debt . . . . . . . . . . . . . . . (1,700) (1,700)
--------- ---------
Net cash provided by (used in) financing activities . . (11,078) (10,178)
--------- ---------
Net increase in cash and cash equivalents . . . . . . . . 4,097 6,721
Cash and cash equivalents at beginning of period. . . . . 696 590
--------- ---------
Cash and cash equivalents at end of period. . . . . . . . $ 4,793 $ 7,311
========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . $ 1,029 $ 3,692
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
JUNE 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 months ended March 31, 2000 filed on Form 10-Q, and the Form 8-K
filed on April 19, 2000, are adequate to make the information presented not
misleading.
The Vermont Public Service Board ("VPSB"), the regulatory commission in
Vermont, sets the rates we charge our customers for their electricity. We
charge our customers higher rates for billing cycles in December through March
and lower rates for the remaining months. These are called seasonally
differentiated rates. In order to eliminate the impact of the seasonally
differentiated rates, we defer some of the revenues from those four months and
account for them in later periods when we have lower revenues or higher costs.
By deferring certain revenues we are able to better match our revenues to our
costs. On June 30, 2000, there were deferred revenues of $6.4 million compared
with $6.1 million at June 30, 1999. These deferred revenues are accreted into
revenue throughout the current year.
UNREGULATED OPERATIONS
We have or have had unregulated, wholly-owned subsidiaries: Mountain
Energy, Inc. ("MEI"), Green Mountain Propane Gas Company Limited ("GMPG"), GMP
Real Estate Corporation, Lease-Elec, Inc., Green Mountain Resources, Inc.
("GMRI"), and Green Mountain Energy Resources, LLC("GMER"). Lease-Elec, Inc.
has been inactive for a number of years and was dissolved April 3, 2000. Sale
of Green Mountain Power Corporation's("GMP" or the "Company") ownership interest
in GMER was completed in the first quarter of 1999. On June 30, 1999, we
decided to sell the assets of MEI, and reported its results as income (loss)
from operations of a discontinued segment. During June 2000, one of MEI's
subsidiary operations was sold. See the disclosure under the caption "Segments
and Related Information" for a more detailed discussion. We also have a rental
water heater program that is not regulated by the VPSB. The results of the
operations of these subsidiaries (excluding MEI) and the rental water heater
program are included in earnings of affiliates and non-utility operations in the
Other Income section of the Consolidated Comparative Income Statements.
2. INVESTMENT IN ASSOCIATED COMPANIES
We recognize net income from our affiliates (companies in which we have
ownership interests) listed below based on our percentage ownership (equity
method).
VERMONT YANKEE NUCLEAR POWER CORPORATION
Percent ownership: 17.9% common
<TABLE>
<CAPTION>
Three months ended Six months ended
in thousands June 30 June 30
2000 1999 2000 1999
------------------- ----------------- ------- -------
<S> <C> <C> <C> <C>
Gross Revenue . . . . $ 44,702 $ 46,376 $85,394 $90,153
Net Income Applicable 1,639 1,638 3,383 3,294
to Common Stock
Equity in Net Income. $ 301 $ 299 $ 615 $ 593
</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 range from approximately $10.0 million to $23.5 million for the plant and
property, depending upon when the sale occurs.
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.
VERMONT ELECTRIC POWER COMPANY, INC.
Percent ownership: 29.5% common
30.0% preferred
<TABLE>
<CAPTION>
Three months ended Six months ended
in thousands June 30 June 30
2000 1999 2000 1999
------------------- ----------------- ------- -------
<S> <C> <C> <C> <C>
Gross Revenue. . . . $ 7,425 $ 7,271 $14,140 $14,205
Net Income . . . . . 310 329 583 621
Equity in Net Income $ 90 $ 122 $ 174 $ 208
</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 June 30, 2000, our total expenditures related to the Pine Street
site since 1982 were approximately $22.3 million. This includes amounts not
recovered in rates, amounts recovered in rates, and amounts for which rate
recovery has been sought but which are presently awaiting further VPSB action.
The bulk of these expenditures consisted of transaction costs. Transaction
costs include legal and consulting costs associated with the Company's
opposition to the EPA's earlier proposals for a more expensive remedy at the
site, litigation and related costs necessary to obtain settlements with insurers
and other 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-Qu bec
contract discussed below;
* the VPSB's modification of our calculation of rate base;
* the exclusion of future capital projects from rate base;
* suspension of recovery of Pine Street Barge Canal site expenditures;
* various cost of service reductions in payroll and operations and
maintenance; and
* a reduction in our requested allowed return on equity from 13 percent to
11.25 percent.
The VPSB Order denied us the right to charge customers $5.48 million of
the annual costs for power purchased under our contract with Hydro-Qu bec. The
VPSB denied recovery of these costs for the following reasons:
* the VPSB claimed that we had acted imprudently by committing to the power
contract with Hydro-Quebec in August 1991 (the imprudence disallowance); and
* to the extent that the costs of power to be purchased from Hydro-Qu bec
are now higher than current estimates of market prices for power during the
Contract term, after accounting for the imprudence disallowance, the contract
power is not "used and useful".
Generally accepted accounting principles required that we record in the
first quarter of 1998 the losses resulting from the disallowed recovery of a
portion of the 1998 Hydro-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 1999 as the result of
our May 8, 1998 rate filing, discussed below.
In its February 27, 1998 Order, the VPSB talked about its policies that do
not allow a utility to recover imprudent expenditures and the costs of power
supply contract purchases that the VPSB decides are not used and useful. The
VPSB stated in its Order that the methods and measures used in this rate case
were provisional and applied to this rate case only. If the VPSB were to apply
the same, or similar, methods and measures that they used in the 1997 rate case
Order to future power contract costs in our 1998 retail rate case, we would
likely be required to recognize a charge to income of approximately $154 million
before income taxes. The $154 million estimate represents primarily the 20
percent disallowance for Hydro-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 Barge Canal site
expenditures. The MOU was approved by the VPSB on December 11, 1998. The MOU
did not provide for any specific disallowance of power costs under our purchase
power contract with Hydro-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 by December 31, 2000. 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 June 30, 2000, total revenues subject to refund are
approximately $16.6 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 June 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 $26.3 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 the right 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 June 30, 2000 to reflect these estimated
costs. A regulatory asset of $3.3 million reflects the unrecognized expense
that will be recovered in rates over the remaining months of 2000. Additional
expense of $6.9 million was recognized in the quarter ended June 30, 2000,
primarily for estimated costs of power purchases in excess of amounts being
collected in rates to supply energy Hydro-Quebec has indicated they will
purchase under the 9701 arrangement through February 2001. This expense included
amounts recognized to reflect the decline in the value of energy resources
acquired to meet power supply obligations. 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 June 30, 2000, MEI had
disposed of certain of its operations 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
quarter ended June 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>
Segment reconciliation
Three months ended Six months ended
In thousands except June 30 June 30
per share data 2000 1999 2000 1999
-------------------- ------------------ --------- --------
<S> <C> <C> <C> <C>
External revenues
Electric utility. . . . . . . $ 61,927 $ 59,535 $129,639 $118,553
MEI segment . . . . . . . . . 521 1,583 618 2,360
Net income (loss) from
operations
Electric utility. . . . . . . (4,375) (412) (925) 2,757
MEI segment . . . . . . . . . - (81) (603)
Provision for loss on
disposal of MEI assets. . . . (1,530) - (1,530) -
-------------------- ------------------ --------- --------
Consolidated net income (loss) $ (5,905) $ (493) $ (2,455) $ 2,154
==================== ================== ========= ========
</TABLE>
16
08/11/003:15 PM
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 the 9701 arrangement with Hydro-Quebec 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 once 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
JUNE 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," "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 Six months ended
all periods ended June 30 2000 1999 2000 1999
------------------- ----------------- ------- -------
<S> <C> <C> <C> <C>
Utility business . . . . . ($0.83) ($0.09) ($0.22) $ 0.35
Unregulated businesses . . 0.03 0.01 0.05 0.16
------------------- ----------------- ------- -------
Earnings(loss) from: . . . (0.80) (0.08) (0.17) 0.52
Continuing operations
Discontinued segment . . . (0.28) (0.01) (0.28) (0.11)
------------------- ----------------- ------- -------
Basic and diluted earnings
(loss) per share . . . . ($1.08) ($0.09) ($0.45) $ 0.40
=================== ================= ======= =======
</TABLE>
UTILITY BUSINESS
The Company recorded losses from utility operations of $0.83 in the quarter
ended June 30, 2000, compared with a loss from utility operations of $0.09 in
the second quarter of 1999. The loss was due primarily to increased power
supply costs of $9.8 million resulting from obligations under the 9701
arrangement with Hydro-Quebec, and to changes in power supply market conditions
that resulted in a decline in the value of energy resources held by the Company.
Increased energy purchases from independent power producers due to above-average
levels of rainfall also contributed to the loss.
The loss from utility operations for the six months ended June 30, 2000 was
$0.22 per common share compared with earnings of $0.35 per common share for the
respective 1999 period. The decrease in earnings reflects obligations under the
9701 arrangement with Hydro-Quebec and to changes in power supply market
conditions that resulted in a decline in the value of energy resources held by
the Company, partially offset by reduced operating costs in 2000 resulting from
our 1999 reorganization effort 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 six months
ended June 30, 2000 and 1999 do not reflect any disallowed Hydro-Quebec power
supply costs. If these accruals, consistent with generally accepted accounting
principles, had not been made, power supply costs would have been $1.9 million
and $1.3 million higher for the three months ended June 30, 2000 and 1999,
respectively, and $3.7 million and $2.6 million for the six months ended June
30, 2000 and 1999, respectively.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from
continuing operations for the three months ended June 30, 2000 increased
compared with the same period in 1999, mostly 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 Six months ended
June 30 June 30 June 30 June 30
2000 1999 2000 1999
------------------- ----------------- -------- ---------
(In thousands)
<S> <C> <C> <C> <C>
Revenue. . . . $ 258 $ 274 $ 521 $ 545
Expense. . . . 117 253 $ 242 (309)
------------------- ----------------- -------- ---------
Net Income . . $ 141 $ 21 $ 279 $ 854
=================== ================= ======== =========
</TABLE>
Earnings from unregulated businesses included in results from continuing
operations for the six months ended June 30, 2000 decreased compared with
results of the same period in 1999 primarily due to six month earnings for GMRI
of $595,000 in 1999, reflecting 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. Its results are reported
separately after income (loss) from continuing operations. MEI's operating loss
for the three months ended June 30, 2000 was previously recognized as provision
for loss during the last two quarters of 1999. The operating loss for the three
months ended June 30, 2000 would have been approximately $211,000 compared with
a loss of $82,000 for the same period a year ago.
MEI's operating loss for the six months ended June 30, 2000 was previously
recognized as provision for loss during the last two quarters of 1999. The
operating loss for the six months ended June 30, 2000 would have been
approximately $1.1 million compared with a loss of $603,000 for the same period
a year ago.
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatthour (MWh) sales and average number of
customers for the three and six months ended June 30, 2000 and 1999 are
summarized below:
<TABLE>
<CAPTION>
Three months ended Six months ended
(dollars in thousands) June 30 June 30
2000 1999 2000 1999
------------------- ----------------- ---------- ----------
<S> <C> <C> <C> <C>
Operating revenues
Retail. . . . . . . . $ 43,535 $ 41,689 $ 93,085 $ 88,460
Sales for Resale. . . 17,630 17,154 34,930 28,750
Other . . . . . . . . 762 692 1,624 1,343
------------------- ----------------- ---------- ----------
Total Operating Revenues. $ 61,927 $ 59,535 $ 129,639 $ 118,553
=================== ================= ========== ==========
MWh sales-Retail. . . . . 456,550 438,852 974,316 925,325
MWh sales for Resale. . . 588,275 556,632 1,155,960 984,424
------------------- ----------------- ---------- ----------
Total MWh Sales . . . . . 1,044,825 995,484 2,130,276 1,909,749
=================== ================= ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Three months ended Six months ended
Average Number of Customers June 30 June 30
2000 1999 2000 1999
------------------ ---------------- ------ ------
<S> <C> <C> <C> <C>
Residential . . . . . . . 72,093 71,144 72,127 71,329
Commercial and Industrial 12,672 12,395 12,603 12,371
Other . . . . . . . . . . 64 65 64 67
------------------ ---------------- ------ ------
Total Number of Customers. . 84,829 83,604 84,794 83,767
================== ================ ====== ======
</TABLE>
REVENUES
Revenues from operations in the second quarter of 2000 increased 4.0
percent or $2.4 million compared with the same period in 1999. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the second quarter of 2000 were $1.8 million or 4.4
percent higher than for the same period in 1999 reflecting a 3.0 percent
temporary rate increase effective January 1, 2000, and a 4.0 percent increase in
retail MWh sales. Sales of electricity increased by 2.0 percent to small
commercial and industrial customers, 4.5 percent to residential customers and
5.9 percent to large lower margin industrial customers.
We sell wholesale electricity to others for resale. Our revenue from
wholesale sales of electricity increased $475,000 in the second 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 Morgan
Stanley Capital Group, Inc.("MS"), effective February 1999. Under the
agreement, we sell power to MS at predefined operating and pricing parameters.
MS then sells to us, at a predefined price, power sufficient to serve
pre-established load requirements.
Revenues from operations for the six months ended June 30, 2000 increased
9.4 percent or $11.1 million compared with the same period in 1999. Retail
revenues were 5.2 percent or $4.6 million higher in the first half of 2000 when
compared with the same 1999 period, reflecting a 3 percent temporary rate
increase, and a 5.2 percent increase in retail MWh sales. Year 2000 sales of
electricity increased by 3.9 percent to small commercial and industrial
customers, 4.3 percent to residential customers, and 8.4 percent to large lower
margin industrial customers.
OPERATING EXPENSES
POWER SUPPLY EXPENSES - THREE MONTHS ENDED JUNE 30, 2000
Power supply expenses increased 17.3 percent or $9.8 million in the second
quarter of 2000 over the same period in 1999.
Power supply expense decreased 2.5% or $224,000 during the second quarter
at Vermont Yankee. The decrease was due to a higher than expected refund of
property insurance, and 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 10.4 percent or $200,000 in the
second quarter of 2000 compared with the same period in 1999 primarily due to
the higher fuel costs.
The cost of power that we purchased from other companies increased 29.8
percent or $9.8 million in the second quarter of 2000 over the same period in
1999. This was primarily due to increased obligations of $4.5 million under the
9701 arrangement with Hydro-Qu bec, changes in power supply market conditions
that resulted in a $4.0 million decline in value of energy resources held by the
Company, $1.2 million of increased purchases of power from independent power
producers, and $1.3 million of increased capacity costs under another
arrangement with Hydro-Qu bec. These increases were offset in part by lower unit
energy costs as compared to the second quarter of 1999 caused by cooler weather.
As described previously herein, the 9701 arrangement allows Hydro-Qu bec 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-Qu bec under the
9701 arrangement of approximately $6.6 million. The Company recognized $1.6
million in expense during the quarter ended June 30, 2000 to reflect these
estimated costs. A regulatory asset of $3.3 million reflects the unrecognized
expense that will be recovered in rates over the remaining months of 2000. The
second quarter loss reflects estimated costs of power purchases in excess of
amounts being collected in rates to supply energy Hydro-Qu bec has indicated
they will purchase under the 9701 arrangement through February 2001. Material
future losses could result if Hydro-Qu bec 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-Qu bec 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-Qu bec under the 9701
arrangement discussed above. Our costs to serve demand during periods of warmer
than normal temperatures in summer months and to replace such energy repurchases
by Hydro-Qu bec rose substantially after the ISO replaced NEPOOL as the
governing power supply. The cost of securing future power supplies has also
risen substantially in tandem with higher summer supply costs. The Company
cannot predict the duration or the extent to which future prices will continue
to trade above historical levels of cost. If the new markets continue to
experience the volatility evident since the first half of 1999, our earnings and
cash flow could be adversely impacted by a material amount.
During the three months ended June 30, 2000, the Company deferred an
additional $2.2 million in arbitration costs related to our pursuit of claims
against Hydro-Qu bec arising from its suspension of deliveries during and after
the 1998 ice storm. At June 30, 2000, total deferred arbitration costs were
$3.7 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 - SIX MONTHS ENDED JUNE 30, 2000
For the six months ended June 30, 2000, power supply expenses increased
21.8 percent or $17.9 million over the same period in 1999.
At Vermont Yankee, power supply expense decreased 3.0% or $523,000 for the
first six 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 12.9 percent or $380,000 for
the first six 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
six months of 2000 increased 29.2 percent or $18.0 million over the same period
in 1999. This was primarily due to a $9.4 million increase in power purchased
under a power purchase and supply agreement with MS, increased obligations of
$8.3 million under long-term power arrangements with Hydro-Qu bec, changes in
power supply market conditions that resulted in a $4.0 million decline in value
of energy resources held by the Company and $1.4 million of increased purchases
of power from independent power producers. These increases were offset in part
by reductions in purchases from other energy providers, loss accrual adjustments
for the continued regulatory disallowance of Hydro-Qu bec power supply costs and
lower energy costs caused by cooler summer weather.
OTHER OPERATING EXPENSES
Other operating expenses decreased 11.9 percent or $495,000 in the second
quarter of 2000 compared with the same period in 1999. The reduction in
expense reflects the Company's reorganization efforts and includes the absence
of reorganization costs which were incurred in 1999, fewer employees, and
reductions in lease expense and facilities costs due to the sale of our
corporate headquarters building in 1999. The 1999 second quarter included a
benefit of $1.6 million in expense reductions for an adjustment to a prior
accrual for estimated losses on the sale of our corporate headquarters.
Other operating expense decreased $2.2 million for the first six months of
2000 when compared with the first six months of 1999. The 22.8 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.
TRANSMISSION EXPENSES
Transmission expenses increased by $341,000 or 11.9% for the three months
ended June 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 six months ended June 30, 2000, transmission expenses increased
20.4%, or $1.1 million, when compared with the first six months of 1999, for the
same reasons.
MAINTENANCE EXPENSE
Our maintenance expenses decreased 17.9 percent or $340,000 in the second
quarter of 2000 compared to the same period in 1999 due primarily to scheduled
maintenance timing differences at a peak generation facility. For the six
months ended June 30, 2000, maintenance expenses decreased 8.2 percent or
$284,000 compared to the same period in 1999 primarily due to the sale of the
Company's corporate headquarters in 1999.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses decreased $262,000 or 6.2 percent
during the second 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 six months of 2000, depreciation and amortization expense
decreased $334,000 or 3.9 percent compared with the first half of 1999. These
differences reflect decreased amortization of demand side management assets.
TAXES OTHER THAN INCOME TAXES
Other taxes increased 4.7 percent or $80,000 in the second quarter of 2000
compared with the same period in 1999, reflecting property tax and gross revenue
tax increases.
Other taxes increased 8.3 percent or $292,000 in the first half of 2000
compared with the same period in 1999, reflecting property tax and gross revenue
tax increases.
INCOME TAXES
Provision for income taxes decreased $2.8 million in the second quarter of
2000 compared with the same period in 1999 due to a decrease in pretax book
income for utility operations.
A decrease in year to date pretax book income resulted in a $2.1 million
decrease in income tax expense for the six months ended June 30, 2000 when
compared with the same 1999 period.
OTHER INCOME
Other income for the three months ended June 30, 2000 decreased
approximately $93,000 or 13.2 percent from the same 1999 period due primarily to
decreases in earnings from subsidiaries. For the six months ended June 30,
2000, other income decreased by $630,000 compared to the first half of 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 3.8 percent or $68,000 in the second quarter of
2000 over the same period in 1999 primarily due to continuing reductions in
long-term debt outstanding.
Interest charges decreased 3.9 percent or $143,000 for the six months ended
June 30, 2000 compared with that of 1999 for the same reasons.
LIQUIDITY AND CAPITAL RESOURCES
In the six months ended June 30, 2000, we spent $6.0 million principally
for expansion and improvements of our transmission and distribution plant, for
expenditures related to the Pine Street Barge Canal site, and for computer
information systems. We expect to spend an additional $8.5 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 agreement is for a
period of 364 days and will expire on June 20, 2001. We had no borrowings
outstanding on the revolving credit agreement at June 30, 2000. Amounts
available under the renewed agreement are not by themselves expected to be
sufficient to meet our operating requirements through December 31, 2000. The
Company has received a commitment letter for an additional $15 million line of
credit with another lender and expects to complete the agreement prior to
October 1, 2000. We believe amounts available under the two agreements will be
more than 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 agreement, to seek to enter into a new credit agreement that has terms
that are less advantageous to the Company, and/or to immediately call in all
outstanding loans. Some of those events are:
* The VPSB issues an order in our currently suspended 1998 rate case that
triggers a material adverse change for the Company; or
* Hydro-Qu bec is unwilling to make new arrangements regarding the cost of
our long-term contract with it; or
* Adverse accounting treatment under SFAS 5 or SFAS 71 is required.
The credit ratings of the Company's securities are:
Duff & Phelps Moody's Standard & Poor's
--------------- ------- -------------------
First mortgage bonds BBB Ba1 BBB
Unsecured medium term debt BBB- -- --
Preferred stock BB+ ba2 BB
During April 2000, Moody's Investor Service downgraded the rating of the
Company's first mortgage bonds from Baa3 to Ba1. Moody's, Duff & Phelps' and
Standard & Poor's credit ratings for the Company remain on Negative Watch,
Rating Watch-Down and Credit Watch Negative, respectively, due to the high level
of regulatory and public policy uncertainty in Vermont and certain positions
argued by the Department in our rate cases.
COMPETITION AND RESTRUCTURING
The electric utility business is experiencing rapid and substantial
changes. These changes are the result of the following trends:
* Surplus generating capacity;
* Disparity in electric rates among and within various regions of the
country;
* Improvements in generation efficiency;
* Alternative energy sources;
* Increasing demand for customer choice; and
* New regulations and legislation intended to foster competition, also known
as "restructuring".
YEAR 2000 COMPUTER COMPLIANCE
We experienced no interruption in the delivery of electricity due to the
transition from December 31, 1999 to January 1, 2000. We also have not
experienced any significant events related to the year 2000 transition on any of
our software applications or embedded systems. Potential problems with future
dates continue to pose risk to the Company. Our ability to deliver electricity
to our customers could also be impacted if one of our major power suppliers or
vendors of telecommunication service experienced a date-related system failure.
An interruption in power supplied by other delivery systems, such as the
independent system operator (ISO) for New England, could also cause power
delivery problems for us. The contingency planning process implemented by the
Company during 1999 remains in place.
We believe that our planning was adequate to secure Year 2000 readiness of
our critical systems. Nevertheless, maintaining Year 2000 security is subject
to various risks and uncertainties, many of which are described above. We are
not able to predict all the factors that could cause actual results to differ
materially 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 maintain Year 2000 readiness with respect to critical
systems, there could be a material adverse effect on our results of operations,
financial position and cash flows.
NUCLEAR DECOMMISSIONING
The staff of the SEC has questioned certain current accounting practices of
the electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in
financial statements. In response to these questions, the Financial Accounting
Standards Board had agreed to review the accounting for closure and removal
costs, including decommissioning. We do not believe that changes in such
accounting, if required, would have an adverse effect on the results of
operations due to our current and future ability to recover decommissioning
costs through rates.
EFFECTS OF INFLATION
Financial statements are prepared in accordance with generally accepted
accounting principles and report operating results in terms of historic costs.
This accounting provides reasonable financial statements but does not always
take inflation into consideration. As rate recovery is based on these
historical costs and known and measurable changes, the Company is able to
receive some rate relief for inflation. It does not receive immediate rate
recovery relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation on
plant costs are generally offset by the fact that these assets are financed
through long-term debt.
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
JUNE 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
At the Annual Shareholders Meeting held May 18, 2000, three items were
voted upon by Shareholders. The items and voting results are listed below.
Item 1, A proposal to change the structure of the Board of Directors to
allow the Board to consist of between seven and ten members as determined by
vote of the Board was approved with the following voting results:
Votes for, 4,420,048; votes against,151,517; abstentions, 862,604.
Item 2, Shareholders elected the nominees listed below as Directors of this
company, with votes cast as indicated.
Merrill O. Burns, votes for, 4,462,948; votes against, 161,969;
abstentions, 809,252.
Christopher L. Dutton, votes for, 4,463,051; votes against, 161,866;
abstentions, 809,252.
Directors continuing in office were Nordahl Brue, Lorraine Chickering, John
V. Cleary, Euclid Irving, William Bruett, David R. Coates, Martin L. Johnson and
Thomas P. Salmon.
Item 3, a proposal to create a new stock incentive plan to provide for
discretionary awards by the Board or its designee was approved with the
following voting results: votes for, 2,329,994; votes against, 846,672;
abstentions, 2,257,503. Form S-8 to register the additional common shares to be
issued under the stock incentive plan was filed July 27, 2000.
ITEM 5. Other Information
NONE
ITEM 6. (A) EXHIBITS
--------
27 Financial Data Schedule
(B) REPORTS ON FORM 8-K
----------------------
A report on Form 8-K was filed on April 19, 2000 announcing the results of
recent credit reviews by major credit rating agencies. Two agencies reaffirmed
the existing investment grade rating for all Company securities and one agency
downgraded to one level below investment grade the Company's first mortgage
bonds.
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SIGNATURES
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
---------------------------------------
(Registrant)
Date: August 11, 2000 /s/Nancy Rowden Brock
------------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer, Secretary,
and Treasurer
Date: August 11, 2000 /s/ R.J. Griffin
------------------
R. J. Griffin, Controller
EXHIBIT 27 This Schedule contains summary financial information extracted
from the Consolidated Balance Sheet as of June 30, 2000 and the related
Consolidated Statements of Income and Cash Flows for the three and six months
ended June 30, 2000, and is qualified in its entirety by reference to such
financial statements.
GREEN MOUNTAIN POWER CORPORATION
FINANCIAL DATA SCHEDULE
FORM 10-Q JUNE 30, 2000
Period - Type 6 Months
Fiscal Year End December 31, 2000
Period End June 30, 2000
Book Value Per Book
Total Net Utility Plant $193,246
Other Property and Investments 20,751
Total Current Assets 35,904
Total Deferred Charges 41,547
Other Assets 9,627
Total Assets 301,075
Common Stock 18,327
Capital Surplus, Paid In 72,913
Retained Earnings 6,389
Total Common Stockholders Equity 97,251
Preferred Stock - Mandatory Redemption 1,640
Preferred Stock - Not Mandatory Redemption 12,795
Long Term Debt, Net 80,100
Short Term Notes 0
Long Term Notes Payable 0
Commercial Paper 0
Long Term Debt - Current Portion 6,700
Preferred Stock - Current Portion 1,640
Capital Lease Obligations 7,038
Capital Leases - Current Obligations 0
Other Items Capital and Liability 95,551
Total Capitalization and Liabilities 301,075
Gross Operating Revenue 129,639
Income Tax Expense (811)
Other Operating Expenses 128,834
Total Operating Expenses 128,023
Operating Income 1,616
Other Income, Net 1,479
Income Before Interest Expense 3,095
Total Interest Expense 3,481
Loss from discontinued operations (1,530)
Net Income(loss) (1,916)
Preferred Stock Dividends 539
Earnings Available for Common Stock (2,455)
Common Stock Dividends 1,500
Total Interest On Bonds 3,481
Cash Flow from Operations 21,341
Earnings Per Share - Primary (.45)
Earnings Per Share - Diluted (.45)
(Dollars in thousands except per share amounts)
