November 8, 2001
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, 2001
------------------
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 7, 2001
--------------------------- ------------------------------------
$3.33 1/3 PAR VALUE 5,680,253
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
AT AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30,
2001 AND 2000
Financial Statements Page
Consolidated Statements of Income 3
Consolidated Statements of Cash Flows 4
Consolidated Balance Sheets 5
Notes to Consolidated Financial Statements 7
Management's Discussion and Analysis of Financial Condition 17
And Results of Operations
Exhibits and Reports on Form 8-K 26
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
UNAUDITED
----------
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
2001 2000 2001 2000
-------- -------- --------- ---------
(in thousands, except per share data)
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $76,051 $78,143 $218,319 $207,782
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 7,645 8,700 21,514 26,387
Company-owned generation. . . . . . . . . . . . . . . . . . 1,625 1,343 3,868 4,257
Purchases from others . . . . . . . . . . . . . . . . . . . 45,495 49,493 129,589 128,227
Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,939 3,618 11,713 10,916
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,431 3,515 10,433 10,603
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 1,739 1,826 5,274 5,005
Depreciation and amortization. . . . . . . . . . . . . . . . 3,491 3,516 10,803 11,659
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,930 1,669 5,833 5,459
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 2,183 1,192 5,870 382
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 71,478 74,872 204,897 202,895
-------- -------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 4,573 3,271 13,422 4,887
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 553 617 1,688 1,861
Allowance for equity funds used during construction. . . . . 69 98 128 240
Other income (deductions), net . . . . . . . . . . . . . . . 90 (73) 16 20
-------- -------- --------- ---------
TOTAL OTHER INCOME. . . . . . . . . . . . . . . . . . . . 712 642 1,832 2,121
-------- -------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 5,285 3,913 15,254 7,008
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,491 1,619 4,586 4,927
Other interest . . . . . . . . . . . . . . . . . . . . . . . 215 147 925 402
Allowance for borrowed funds used during construction. . . . (43) (54) (146) (136)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,663 1,712 5,365 5,193
-------- -------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 3,622 2,201 9,889 1,815
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . 235 240 704 779
-------- -------- --------- ---------
Income from continuing operations. . . . . . . . . . . . . . 3,387 1,961 9,185 1,036
Loss on disposal of discontinued segment,
including provisions for operating
losses during phaseout period. . . . . . . . . . . . . . . . - - (150) (1,530)
-------- -------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . $ 3,387 $ 1,961 $ 9,035 $ (494)
======== ======== ========= =========
Common stock data
Basic earnings (loss) per share. . . . . . . . . . . . . . . $ 0.60 $ 0.36 $ 1.61 $ (0.09)
Diluted earnings (loss) per share. . . . . . . . . . . . . . 0.58 0.36 1.56 (0.09)
Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.41 $ 0.41
Weighted average common shares outstanding-basic . . . . . . 5,644 5,505 5,615 5,471
Weighted average common shares outstanding-diluted . . . . . 5,814 5,506 5,777 5,472
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . $ 4,602 $ 6,389 $ 493 $ 10,344
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . 3,622 2,201 9,739 285
Cash Dividends-redeemable cumulative preferred stock . . . . (235) (240) (704) (779)
Cash Dividends-common stock. . . . . . . . . . . . . . . . . (777) (756) (2,316) (2,256)
-------- -------- --------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . $ 7,212 $ 7,594 $ 7,212 $ 7,594
======== ======== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED
SEPTEMBER 30,
2001 2000
--------------- ---------
OPERATING ACTIVITIES: (in thousands)
Net income (loss) before preferred dividends. . . . . . . $ 9,739 $ 285
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . 10,803 11,659
Dividends from associated companies less equity income. 267 (18)
Allowance for funds used during construction. . . . . . (274) (376)
Amortization of purchased power costs . . . . . . . . . 2,607 4,365
Deferred income taxes . . . . . . . . . . . . . . . . . (2,525) 1,781
Excess earnings deferred. . . . . . . . . . . . . . . . 1,050 -
Deferred purchased power costs. . . . . . . . . . . . . (5,254) (1,643)
Accrued purchase power contract option call . . . . . . (3,346) 2,726
Provision for loss on segment disposal. . . . . . . . . 150 1,530
Arbitration costs recovered (deferred). . . . . . . . . 3,229 (3,268)
Rate levelization liability . . . . . . . . . . . . . . 8,613 -
Environmental and conservation deferrals, net . . . . . (2,291) (1,957)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . 3,594 1,713
Accrued utility revenues. . . . . . . . . . . . . . . 1,335 883
Fuel, materials and supplies. . . . . . . . . . . . . 37 (96)
Prepayments and other current assets. . . . . . . . . 713 455
Accounts payable. . . . . . . . . . . . . . . . . . . (3,786) 571
Accrued income taxes payable and receivable . . . . . 3,428 (2,396)
Other current liabilities . . . . . . . . . . . . . . 1,073 (4,369)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 455 (241)
--------------- ---------
Net cash provided by continuing operations. . . . . . . 29,616 11,604
Net change in discontinued segment. . . . . . . . . . . (1,706) 195
--------------- ---------
Net cash provided by operating activities . . . . . . . 27,911 11,799
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . (9,212) (8,551)
Investment in nonutility property . . . . . . . . . . . . (146) (143)
--------------- ---------
Net cash used in investing activities . . . . . . . . . (9,358) (8,694)
--------------- ---------
FINANCING ACTIVITIES:
Proceeds from term loan . . . . . . . . . . . . . . . . . 12,000
Reduction in preferred stock. . . . . . . . . . . . . . . - (1,400)
Issuance of common stock. . . . . . . . . . . . . . . . . 1,283 794
(Investment in) maturity of certificate of deposit. . . . 16,173 (15,150)
Power supply option obligation. . . . . . . . . . . . . . (16,013) 15,000
Reduction in long-term debt . . . . . . . . . . . . . . . (1,700) (1,700)
Short-term debt, net. . . . . . . . . . . . . . . . . . . (15,500) 1,700
Cash dividends. . . . . . . . . . . . . . . . . . . . . . (3,020) (3,035)
--------------- ---------
Net cash used in financing activities . . . . . . . . . (6,776) (3,791)
--------------- ---------
Net increase(decrease) in cash and cash equivalents . . . 11,777 (686)
Cash and cash equivalents at beginning of period. . . . . 341 696
--------------- ---------
Cash and cash equivalents at end of period. . . . . . . . $ 12,118 $ 10
=============== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . $ 4,677 $ 4,420
Income taxes, net . . . . . . . . . . . . . . . . . . . 5,287 1,191
The accompanying notes are an integral part of these consolidated financial
statements.
PART I, ITEM 1
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
AT SEPTEMBER 30, DECEMBER 31,
2001 2000 2000
-------- -------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost. . . . . . . . $296,843 $287,729 $291,107
Less accumulated depreciation. . . . . . . . . 116,540 110,381 110,273
-------- -------- --------
Net utility plant. . . . . . . . . . . . . . . 180,303 177,348 180,834
Property under capital lease . . . . . . . . . 6,449 7,038 6,449
Construction work in progress. . . . . . . . . 8,208 9,535 7,389
-------- -------- --------
Total utility plant, net . . . . . . . . . . 194,960 193,921 194,672
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity. . . . . . . . 14,176 14,672 14,373
Other investments. . . . . . . . . . . . . . . 6,725 6,151 6,357
-------- -------- --------
Total other investments. . . . . . . . . . . 20,901 20,823 20,730
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . 12,118 10 341
Certficate of deposit, pledged as collateral . - 15,150 15,437
Accounts receivable, less allowance for
doubtful accounts of $613, $428, and $463. . . 18,771 16,790 22,365
Accrued utility revenues . . . . . . . . . . . 5,758 6,085 7,093
Fuel, materials and supplies, at average cost. 4,019 3,385 4,056
Prepayments. . . . . . . . . . . . . . . . . . 1,635 1,667 2,525
Income tax receivable. . . . . . . . . . . . . - 3,637 1,613
Other. . . . . . . . . . . . . . . . . . . . . 894 459 222
-------- -------- --------
Total current assets . . . . . . . . . . . . 43,195 47,183 53,652
-------- -------- --------
DEFERRED CHARGES
Demand side management programs. . . . . . . . 6,676 6,586 6,358
Purchased power costs. . . . . . . . . . . . . 20,560 14,583 11,789
Pine Street Barge Canal. . . . . . . . . . . . 12,370 8,700 12,370
Other. . . . . . . . . . . . . . . . . . . . . 14,697 16,200 15,519
-------- -------- --------
Total deferred charges . . . . . . . . . . . 54,303 46,069 46,036
-------- -------- --------
NON-UTILITY
Other current assets . . . . . . . . . . . . . 8 8 8
Property and equipment . . . . . . . . . . . . 251 252 252
Business segment held for disposal . . . . . . - 7,752 -
Other assets . . . . . . . . . . . . . . . . . 822 1,278 1,258
-------- -------- --------
Total non-utility assets . . . . . . . . . . 1,081 9,290 1,518
-------- -------- --------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . $314,440 $317,286 $316,608
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
AT SEPTEMBER 30, DECEMBER 31,
2001 2000 2000
--------- --------- ---------
(in thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock equity
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,656,048, 5,515,490 and 5,582,552) . . . . . . $ 18,907 $ 18,438 $ 18,608
Additional paid-in capital . . . . . . . . . . . 74,306 73,035 73,321
Retained earnings. . . . . . . . . . . . . . . . 7,212 7,594 493
Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378)
--------- --------- ---------
Total common stock equity. . . . . . . . . . . 100,047 98,689 92,044
Redeemable cumulative preferred stock. . . . . . 12,560 12,795 12,560
Long-term debt, less current maturities. . . . . 70,400 80,100 72,100
Term loan, maturing August 2003. . . . . . . . . 12,000 - -
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . 195,007 191,584 176,704
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 6,449 7,038 6,449
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 235 240 235
Current maturities of long-term debt . . . . . . 9,700 6,700 9,700
Short-term debt. . . . . . . . . . . . . . . . . - 9,600 15,500
Accounts payable, trade and accrued liabilities. 5,943 4,870 7,755
Accounts payable to associated companies . . . . 6,536 8,961 8,510
Deferred excess earnings . . . . . . . . . . . . 1,050 - -
Customer deposits. . . . . . . . . . . . . . . . 832 504 696
Purchased power call option liability. . . . . . - 9,299 8,276
Interest accrued . . . . . . . . . . . . . . . . 1,716 1,804 1,150
Energy East power supply obligation. . . . . . . - 15,000 15,419
Other. . . . . . . . . . . . . . . . . . . . . . 3,289 2,170 1,103
--------- --------- ---------
Total current liabilities. . . . . . . . . . . 29,301 59,148 68,344
--------- --------- ---------
DEFERRED CREDITS
SFAS 133 liability . . . . . . . . . . . . . . . 14,381 - -
Accumulated deferred income taxes. . . . . . . . 23,331 27,194 25,644
Unamortized investment tax credits . . . . . . . 3,483 3,766 3,695
Pine Street Barge Canal site cleanup . . . . . . 10,583 8,211 11,554
Other. . . . . . . . . . . . . . . . . . . . . . 21,531 20,345 20,901
Rate levelization liability. . . . . . . . . . . 8,613 - -
--------- --------- ---------
Total deferred credits . . . . . . . . . . . . 81,922 59,516 61,794
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Liabilities of discontinued segment, net . . . . 1,761 - 3,317
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . 1,761 - 3,317
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $314,440 $317,286 $316,608
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
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 include 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 accounting principles generally accepted in the
United States 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 2000 filed on Form
10-K, are adequate to make the information presented not misleading.
The Vermont Public Service Board ("VPSB"), the regulatory commission in
Vermont, sets the rates we charge our customers for their electricity.
Historically we have charged 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
higher revenue months and recognize 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, 2001, there was a deferred
charge of $0.5 million, compared with $0.2 million at September 30, 2000.
In the Company's most recent rate case settlement the VPSB ordered that seasonal
rates be eliminated in April 2001, which is expected to generate approximately
$7.5 million in additional cash flow in 2001. Such deferred revenue was intended
by the VPSB to be used to offset increased costs during 2001, 2002 and 2003,
increasing the likelihood that the Company will earn its allowed rate of return
in those years. Approximately $8.6 million of revenue arising as a result of
the elimination of seasonal rates was deferred through the third quarter of
2001. The Company expects to achieve its allowed rate of return without using
any of the approximately $7.5 million in revenues expected to be deferred during
2001.
The Company's earnings from electric operations are subject to an earnings cap
equal to its allowed rate of return of 11.25%. The Company's policy is to
review its quarterly results and to defer any revenues that are probable of
causing earnings to exceed an 11.25% rate of return ("excess earnings") for the
year. As a result of our review, we deferred $0.1 million of revenue and
recorded a regulatory liability for excess earnings in the same amount during
the quarter ended September 30, 2001. Deferred excess earnings total $1.1
million for the nine months ended September 30, 2001. Under a settlement
agreement with the Vermont Department of Public Service ("DPS" or the
"Department"), and approved by the VPSB, any excess earnings amounts will be
used to write off regulatory assets at December 31, 2001.
The Company reviews its deferred revenue balances arising from excess earnings
and rate levelization each quarter and adjusts those balances as necessary to
reflect the Company's current estimate of its ultimate regulatory liability. See
the discussion under "Commitments and Contingencies - Retail Rate Cases" for
further information.
Certain line items on the prior years' financial statements have been
reclassified for consistent presentation with the current year.
The preparation of financial statements in conformity with generally
accepted accounting principles requires the use of estimates and assumptions
that affect assets and liabilities, and revenues and expenses. Actual results
could differ from those estimates.
UNREGULATED OPERATIONS
We have or have had unregulated, wholly-owned subsidiaries: Northern Water
Resources, Inc.("NWR", formerly known as Mountain Energy, Inc.); Green Mountain
Propane Gas Company Limited ("GMPG"); GMP Real Estate Corporation; and Green
Mountain Resources, Inc. ("GMRI"). On June 30, 1999, we decided to sell the
assets of NWR, and reported its results as income (loss) from operations of a
discontinued segment. See the disclosure under the caption "Segments and
Related Information" for a more detailed discussion. We also have a rental
water heater program that is not regulated by the VPSB. The results of the
operations of these unregulated subsidiaries (excluding NWR) and the rental
water heater program are included Equity 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
significant ownership interests) listed below based on our percentage ownership
(equity method).
VERMONT YANKEE NUCLEAR POWER CORPORATION ("VY")
Percent ownership: 17.9% common
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
------- ------- -------- --------
(in thousands)
Gross Revenue. . . . . $37,868 $44,648 $135,863 $130,042
Net Income Applicable. 1,641 1,559 4,765 4,942
to Common Stock
Equity in Net Income . 296 275 856 890
On October 15, 1999, the owners of VY accepted a bid from AmerGen
for the VY generating plant, intending to complete the sale before December
2000. AmerGen and the DPS negotiated a revised offer in November 2000, which
was subsequently dismissed as insufficient by the VPSB in February 2001. Prior
to the dismissal of the AmerGen offer, Entergy Nuclear Inc. had also made an
offer, secured by a bond which was acceptable to the VPSB, and two other
companies indicated they would participate in an auction, if held. VY has
conducted an auction of the plant.
On August 15, 2001, VY agreed to sell its nuclear power plant to Entergy
Corporation for approximately $180 million. The sale is subject to approval of
the VPSB, the U.S. Nuclear Regulatory Commission, the Federal Energy Regulatory
Commission and other regulatory bodies. A related agreement calls for Entergy
to provide the current output level of the plant to VY's present sponsors,
including GMP, at average annual prices ranging from $39 to $45 per megawatt
hour through 2012. No decommissioning top-off or any other financing by VY is
anticipated to complete the transaction. The sale, if completed, will lower
projected costs over the remaining license period for VY. The Company would
continue to own its equity interest in VY.
VERMONT ELECTRIC POWER COMPANY, INC.("VELCO")
Percent ownership: 29.5% common
30.0% preferred
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
------ ------ ------- -------
(in thousands)
Gross Revenue . . . . $6,806 $7,011 $22,524 $21,151
Net Income. . . . . . 230 309 782 892
Equity in Net Income. 75 93 221 267
VELCO is engaged in the transmission of electric power within the State of
Vermont(the "State"). VELCO has entered into transmission agreements with the
State and various electric utilities, including the Company, and under these
agreements, VELCO bills all costs, including interest on debt and a fixed return
on equity, to the State and others using VELCO's transmission system.
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 are one of
several potentially responsible parties ("PRPs") for cleanup of the Pine Street
Barge Canal ("Pine Street") site in Burlington, Vermont, where coal tar and
other industrial materials were deposited.
In September 1999, we negotiated a final settlement with the United States,
the State, and other parties to a Consent Decree that covers claims with respect
to the site and implementation of the selected site cleanup remedy. In November
1999, the Consent Decree was filed in the federal district court. The Consent
Decree addresses claims by the Environmental Protection Agency("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, 2001, our total expenditures related to the Pine Street
site since 1982 were approximately $24.7 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 of 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, together with our remediation costs, to be approximately $12.4 million
over the next 32 years. The estimated liability is not discounted, and it is
possible that our estimate of future costs could change by a material amount.
We also have recorded an offsetting regulatory asset, 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 Department,
and as applicable, other parties, reached agreements in these cases that the
full amount of the site-related costs reflected in those rate cases should be
recovered in rates.
We proposed in our rate filing made on June 16, 1997 recovery of an
additional $3.0 million in such expenditures. In an Order in that case released
March 2, 1998, the VPSB suspended the recovery 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". The VPSB Order released January
23, 2001 and discussed below did not change the status of Pine Street cost
recovery.
RETAIL RATE CASE
On May 8, 1998, we filed a request with the VPSB to increase our retail
rates by 12.93 percent due to higher power costs, the cost of the January 1998
ice storm, and investments in new plant and equipment (the "1998 rate case").
The Company reached a final settlement agreement with the Department in the
1998 rate case during November 2000. The final settlement agreement contained
the following provisions:
* The Company received a rate increase of 3.42 percent above existing rates,
beginning with bills rendered January 23, 2001, and prior temporary rate
increases became permanent;
* Rates were set at levels that recover the Company's Hydro-Quebec VJO
contract costs, effectively ending the regulatory disallowances experienced by
the Company over the past three years;
* The Company agreed not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a request
for additional rate relief if annual power supply costs increase in excess of
$3.75 million over forecasted levels;
* The Company agreed to write off in 2000 approximately $3.2 million in
unrecovered rate case litigation costs, and to freeze its dividend rate until it
successfully replaces all or substantially all of its short-term credit
facilities with long-term debt or equity financing;
* Seasonal rates were eliminated in April 2001, which is expected to
generate approximately $7.5 million in additional cash flow in 2001 that can be
utilized to offset potential increased costs during 2001, 2002 and 2003;
* The Company agreed to consult extensively with the Department regarding
capital spending commitments for upgrading our electric distribution system and
to adopt customer care and reliability performance standards, in a first step
toward possible development of performance-based rate-making; and
* The Company agreed to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in the Company's 1997 rate case. The Company agreed to an earnings
cap for its electric operations in an amount equal to its allowed rate of return
of 11.25 percent. Amounts earned over the cap will be used to write-off
regulatory assets.
On January 23, 2001, the VPSB Order (the "Settlement Order") approved the
Company's settlement with the Department, with two additional conditions:
* The Settlement Order provided that the Company and its customers share
equally any premium above book value realized by the Company in any future
merger, acquisition or asset sale, subject to an $8.0 million limit on the
customers' share; and
* The Company's further investment in non-utility operations is restricted.
POWER CONTRACT COMMITMENTS
Under an arrangement established on December 5, 1997 ("9701"), Hydro-Quebec
paid $8.0 million to the Company. In return for this payment, we provided
Hydro-Quebec options for the purchase of power. Commencing April 1, 1998 and
effective through 2015, the term of a previous contract with Hydro-Quebec ("the
1987 Contract"), Hydro-Quebec may purchase up to 52,500 MWh ("option A") on an
annual basis, at the 1987 Contract energy prices, which are substantially below
current market prices. The cumulative amount of energy that may be purchased
under option A shall not exceed 950,000 MWh.
Over the same period, Hydro-Quebec may exercise an option to purchase a
total of 600,000 MWh ("option B") at the 1987 Contract energy prices. Under
option B, Hydro-Quebec may purchase no more than 200,000 MWh in any year.
During the first quarter of 2001, Hydro-Quebec exercised option A and
option B, calling for deliveries of 134,592 MWh during June, July and August of
2001. The cumulative amount of power purchased by Hydro-Quebec under option B
is approximately 432,000 MWh. Approximately $6.6 million is currently being
provided annually in rates to cover the net cost of 9701 calls by Hydro-Quebec.
The Company recognized $5.0 million in net expense during the nine months ended
September 30, 2001 to reflect these estimated costs. A regulatory asset of $1.6
million was established for the remaining estimated difference between the
option exercise price and the expected cost of replacement power for 2001. In
conjunction with the Settlement Order, Hydro-Quebec agreed not to call option B
during 2002.
If estimated costs of fulfilling the Hydro-Quebec option calls exceed amounts
recovered in rates and/or amounts previously recorded, the excess cost would be
immediately charged against earnings. No charge for excess cost was required
during the first nine months of 2001. No charges in excess of amounts provided
in rates or previously recorded are anticipated for the remainder of 2001. It
is possible our estimate of future power supply costs could differ materially
from actual results.
Hydro-Quebec's option to curtail energy deliveries pursuant to a July 1994
Agreement can be exercised in addition to these purchase options, if documented
drought conditions exist. The exercise of this curtailment option is limited to
five times through 2015, requiring notice four months in advance of any contract
year, and cannot reduce deliveries by more than approximately 13 percent. The
Company may defer the curtailment by one year.
During 1999, the Company had accrued expected losses for 2000 for
disallowed Hydro-Quebec power supply contracts 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. If the 1999 accruals, consistent
with generally accepted accounting principles, had not been made, power supply
costs would have been $1.9 and $5.7 million higher for the three and nine months
ended September 30, 2000, respectively.
POWER SUPPLY AND TRANSMISSION
A FERC ruling in December 2000 required the New England Independent System
Operator ("ISO") to revise its installed capability ("ICAP") deficiency charge
of $0.17 per kw month to $8.75 per kw month retroactive to August 1, 2000. On
January 10, 2001, FERC stayed its order "to ensure that bills for past periods
will not be assessed until the Commission has considered the pending requests
for rehearing, which, if successful, would then require extensive refunds and
surcharges." On March 6, 2001, FERC issued an Order on Rehearing in which it
partly reversed itself on the ICAP charge. Although the FERC first concluded
that a $8.75 charge is reasonable and that the charge would remain in place
until the ISO supports an acceptable superseding proposal, the FERC then
concluded that reinstating the $8.75 would have an adverse cost impact, and
should be effective only as of April 1, 2001. The FERC allowed the $8.75 charge
to become effective on April 1, 2001 until the effective date of any superseding
charge that the FERC might accept.
In March 2001, a federal court issued a stay preventing reinstatement of
the $8.75 charge, after sixteen New England utilities and energy companies
protested the increased penalty. The federal court lifted the stay but ordered
FERC to further justify its decision and said that a $5 per kW month rate might
be more appropriate. A final default rate of $4.87 was approved by FERC
effective September 2001. The FERC order provides a fourteen day cure period
each month during which utilities may make bilateral purchases to fulfill ICAP
deficiencies and avoid the default rate. The Company's generation and
entitlements cover the majority of its ICAP requirements, except during periods
in which Hydro-Quebec calls for power under 9701. The Company has purchased its
expected ICAP requirements for 2001 at an average price of approximately $4.06
per kW month. The Company has also arranged to purchase its anticipated ICAP
needs during 2002 at an average cost of $2.55 per kW month, and the majority of
its anticipated ICAP needs during 2003 at a cost of $2.85 per kW month.
On April 17, 2001, an Arbitration Tribunal issued its decision in the
arbitration brought by a group of Vermont electric companies and municipal
utilities, known as the Vermont Joint Owners (VJO), against Hydro-Quebec for its
failure to deliver electricity pursuant to the VJO/Hydro-Quebec power supply
contract during the 1998 ice storm. The Company is a member of the VJO.
In its award, the Arbitration Tribunal agreed partially with Hydro-Quebec
and partially with the VJO. In the decision, the Tribunal concluded (i) the
VJO/Hydro-Quebec power supply contract remains in effect and Hydro-Quebec is
required to continue to provide capacity and energy to the Company under the
terms of the VJO contract, which expires in 2015 and (ii) Hydro-Quebec is
required to return certain capacity payments to the VJO.
On July 23, 2001, the Company received approximately $3.2 million
representing its share of refunded capacity payments from Hydro-Quebec. These
proceeds reduced related deferred assets at June 30, 2001, leaving a deferred
balance of unrecovered arbitration costs of approximately $1.4 million. We
believe it is probable that this balance will ultimately be recovered in rates.
4. SEGMENTS AND RELATED INFORMATION
The Company has two reportable segments, the electric utility and NWR. 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.
NWR is an unregulated business that invested in energy generation, energy
efficiency and wastewater treatment projects. As of June 30, 1999, we
classified NWR's net assets and liabilities as "Business Segment Held for Sale",
reflecting the Company's intent to sell NWR's assets. Previously, investment in
NWR appeared as a separate caption, "Equity Investment in Energy Related
Business" in the nonutility section of the consolidated balance sheet.
During 2000, the Company recorded losses of $6.5 million, or $1.19 per
share to reflect revised estimates and actual sales of most of NWR's energy
generation and energy efficiency assets. During the quarter ended June 30,
2001, the Company recorded a provision for loss of approximately $0.2 million or
3 cents per share related to a revision to its estimate of the ultimate costs of
warranty obligations on its waste-water investments. The provisions for loss
from discontinued operations reflect the Company's most recent estimate. The
ultimate loss remains subject to the sale or other disposition of NWR's
remaining assets and liabilities, primarily patents and warranty claims, and tax
liabilities, and could exceed amounts recorded. Results of operations for NWR
are now reported under "Loss on disposal of discontinued segment, net of
applicable income taxes". Provisions for loss on disposal are reported under
"Loss on disposal of discontinued segment, net of applicable income taxes".
Segment information compared with the Company's results includes the following:
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
------- ------- --------- ---------
(in thousands, except per share data)
External revenues
Electric utility . . . . . . . . . . $76,051 $78,143 $218,319 $207,782
NWR segment. . . . . . . . . . . . . 33 733 138 1,351
Net income (loss) from
operations
Electric utility . . . . . . . . . . $ 3,387 $ 1,961 $ 9,185 $ 1,036
NWR segment. . . . . . . . . . . . . - - (150) (1,530)
------- ------- --------- ---------
Consolidated net income (loss). . . . $ 3,387 $ 1,961 $ 9,035 $ (494)
======= ======= ========= =========
Basic earnings (loss) per share
Discontinued operations. . . . . . $ - $ - $ (0.03) $ (0.28)
Continuing operations. . . . . . . 0.60 0.36 1.64 0.19
Diluted earnings per share
Discontinued operations. . . . . . $ - $ - $ (0.03) $ (0.28)
Continuing operations. . . . . . . 0.58 0.36 1.59 0.19
5. NEW ACCOUNTING STANDARD - SFAS 133
In June 1998, the Financial Accounting Standards Board ("FASB") 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 on 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. Accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement or other comprehensive income
and requires that hedges be formally documented, designateed, and assessed for
effectiveness. SFAS 133, as amended by SFAS 137, was 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 objective of the Company's risk management program is to protect cash
flow and earnings by minimizing power supply risks. Transactions permitted by
the risk management program include futures, forward contracts, option
contracts, swaps and transmission congestion rights with counterparties that
have at least investment grade ratings. These transactions are used to hedge
risk of fossil fuel price increases as well as the risk of spot market
electricity price increases. Futures, swaps and forward contracts are used to
hedge market prices should option calls by Hydro-Quebec be exercised. The
Company's risk management policy specifies risk measures, the amount of
tolerable risk exposure, and limits to transaction authority.
The Company's 9701 arrangement with Hydro-Quebec that grants Hydro-Quebec
an option to call for energy deliveries at prices currently below estimated
future market rates through 2015 is a derivative under SFAS 133. We sometimes
use futures contracts (derivatives) to hedge forecasted sales of electric power,
including the 9701 arrangement. The Company also has a power purchase and
supply agreement with Morgan Stanley Capital Group, Inc. ("MS") to hedge the
fair value of fossil fuel prices that is a derivative under SFAS 133.
On April 11, 2001, the VPSB issued an accounting order that requires the
Company to defer recognition of any earnings or other comprehensive income
effects relating to future periods caused by application of SFAS 133, and as a
result, we do not anticipate SFAS 133 to cause earnings volatility. At
September 30, 2001, the Company had a liability reflecting the negative market
position of the two derivatives described above, as well as a corresponding
regulatory asset of approximately $14.4 million related to the derivatives
discussed above. The Company believes that the regulatory asset is probable of
recovery. The regulatory asset is based on current estimates of future market
prices that are likely to change by material amounts.
If a derivative instrument is terminated early because it is probable that
a transaction or forecasted transaction will not occur, any gain or loss would
be recognized in earnings immediately. For derivatives held to maturity, the
earnings impact would be recorded in the period that the derivative is sold or
matures.
6. OTHER NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued Statement of Financial Accounting Standards
No. 141, Business Combinations ("SFAS 141"), and Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS 142").
SFAS 141 requires the use of the purchase method to account for business
combinations and uses a nonamortization approach to purchased goodwill and other
intangible assets. SFAS 142 establishes requirements for evaluating goodwill
and other intangible assets for impairment and provides further guidance on
accounting for intangible assets. The Company does not expect the application
of these accounting standards, when adopted, to materially impact its financial
position or results of operations.
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" ("SFAS") which provides
guidance on accounting for nuclear plant decommissioning costs. The Company has
not yet determined what impact, if any, the accounting standard will have on its
investment in VY.
7. COMPUTATION OF EARNINGS PER SHARE
Earnings per share are based on the weighted average number of common and
common stock equivalent shares outstanding during each period presented. The
Company established a stock incentive plan for all employees during the year
ended December 31, 2000, and options granted are exercisable over vesting
schedules of between one and four years.
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
------ ------ ------ -------
(in thousands)
Net income (loss) before preferred dividends. $3,622 $2,201 $9,739 $ 285
Preferred stock dividend requirement. . . . . 235 240 704 779
------ ------ ------ -------
Net income (loss) applicable to common
stock. . . . . . . . . . . . . . . . . . . $3,387 $1,961 $9,035 $ (494)
====== ====== ====== =======
Average number of common shares-basic . . . . 5,644 5,505 5,615 5,471
Dilutive effect of stock options. . . . . . . 170 1 162 1
Anti-dilutive stock options . . . . . . . . . - - - -
------ ------ ------ -------
Average number of common shares-diluted . . . 5,814 5,506 5,777 5,472
====== ====== ====== =======
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
SEPTEMBER 30, 2001
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" in this section:
* Regulatory and judicial decisions or legislation;
* Weather;
* Energy supply and demand and pricing;
* Availability, terms, and use of capital;
* General economic and business risk;
* Nuclear and environmental issues;
* Changes in technology; and
* Industry restructuring and cost recovery (including stranded costs).
These forward-looking statements represent only our estimates and
assumptions as of the date of this report.
RESULTS OF OPERATIONS
EARNINGS SUMMARY - OVERVIEW
In this section, we discuss our earnings and the principal factors affecting
them. We separately discuss earnings for the utility business and for our
unregulated businesses.
Total basic earnings (loss) per share of Common Stock
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
----- ----- ------- -------
Utility business . . . $0.58 $0.33 $ 1.57 $ 0.11
Unregulated businesses 0.02 0.03 0.07 0.08
----- ----- ------- -------
Earnings(loss) from: . 0.60 0.36 1.64 0.19
Continuing operations
Discontinued segment . - - (0.03) (0.28)
----- ----- ------- -------
Basic earnings
(loss) per share . . $0.60 $0.36 $ 1.61 $(0.09)
===== ===== ======= =======
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.58 in the quarter ended September 30, 2001, compared with earnings of $0.33
per share in the third quarter of 2000.
The third quarter earnings improvement, compared with the same period for 2000,
reflects higher retail operating revenues. Retail operating revenues for the
quarter increased $3.5 million compared with the same period in 2000, reflecting
a 3.42 percent retail rate increase (the "Settlement Order") approved by the
Vermont Public Service Board (the "VPSB") in January 2001 and a 5.0 percent
increase in retail electricity sales.
Power supply costs were $4.8 million lower in the third quarter of 2001,
primarily due to a $6.4 million decrease in low margin wholesale sales of
electricity, offset in part by adjustments that caused approximately $1.9
million in power supply costs paid during 2000 to be expensed in previous
periods, as discussed below.
Basic earnings per share from utility operations for the nine months ended
September 30, 2001 were $1.57 compared with earnings per share of $0.11 for the
same period in 2000, due to the same revenue factors influencing third quarter
results, and to decreased power supply expense associated with the management of
the Company's long-term sale commitment to Hydro-Quebec("9701"), lower Vermont
Yankee costs due to the timing of scheduled outages, a refund of certain
administrative costs from the New England Independent System Operator("ISO") and
lower costs from independent power producers.
The Company had previously accrued losses for disallowed Hydro-Quebec power
supply costs pursuant to VPSB orders. Results for the nine months ended
September 30, 2000 do not reflect any disallowed Hydro-Quebec power supply
costs. If these accruals, consistent with generally accepted accounting
principles, had not been made in prior periods, power supply costs would have
been $1.9 and $5.7 million higher, respectively, for the three and nine months
ended September 30, 2000.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from
continuing operations for the three and nine months ended September 30, 2001
were slightly lower than during the same period in 2000. A financial summary
for these businesses, excluding NWR, follows:
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
----- ----- ----- -----
(in thousands)
Revenue. . . . $ 251 $ 259 $ 761 $ 780
Expense. . . . 139 99 395 341
----- ----- ----- -----
Net Income . . $ 112 $ 160 $ 366 $ 439
===== ===== ===== =====
DISCONTINUED SEGMENT OPERATIONS
As of June 30, 1999, the Company decided to sell or dispose of NWR, a
wholly owned subsidiary that invested in energy generation, energy efficiency
and wastewater treatment businesses. Its results are reported separately after
income (loss) from continuing operations. NWR recognized an additional $0.2
million as a provision for loss for the nine months ended September 30, 2001
reflecting revised estimates of losses on warranty liabilities. The ultimate
loss remains subject to the sale or other disposition of NWR's remaining assets
and liabilities, primarily patents and warranty claims and tax liabilities, and
could exceed amounts recorded. Most of NWR's energy generation and energy
efficiency assets have been sold. Without discontinued operations treatment,
the operating loss for the three months ended September 30, 2001 would have been
approximately $0.1 million compared with a loss of $0.2 million for the same
period a year ago. The operating loss for the nine months ended September 30,
2001 would have been approximately $0.4 million compared with a loss of $1.0
million for the same period in 2000.
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, 2001 and 2000 are
summarized below:
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
---------- ---------- ---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 49,009 $ 45,482 $ 146,548 $ 138,567
Sales for Resale. . . 25,579 31,968 68,177 $ 66,898
Other . . . . . . . . 1,463 693 3,594 $ 2,317
---------- ---------- ---------- ----------
Total Operating Revenues. $ 76,051 $ 78,143 $ 218,319 $ 207,782
========== ========== ========== ==========
MWh sales-Retail. . . . . 499,671 475,952 1,475,820 1,449,017
MWh sales for Resale. . . 673,868 798,317 1,857,252 1,954,277
---------- ---------- ---------- ----------
Total MWh Sales . . . . . 1,173,539 1,274,269 3,333,072 3,403,294
========== ========== ========== ==========
Average Number of Customers
Three months ended Nine months ended
September 30 September 30
2001 2000 2001 2000
------ ------ ------ ------
Residential . . . . . . . 73,075 72,557 73,161 72,288
Commercial and Industrial 12,998 12,835 12,986 12,690
Other . . . . . . . . . . 66 67 65 65
------ ------ ------ ------
Total Number of Customers. . 86,139 85,459 86,212 85,043
====== ====== ====== ======
REVENUES
Revenues from operations in the third quarter of 2001 decreased $2.1
million or 2.7 percent compared with the same period in 2000. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the third quarter of 2001 were $3.5 million or 7.8 percent
higher compared with the same period in 2000, reflecting a 3.42 percent rate
increase effective January 2001, and a 5.0 percent increase in retail MWh sales.
Sales of electricity increased by 6.5 percent to small commercial and industrial
customers, increased by 4.8 percent to residential customers and increased 2.7
percent to lower margin industrial customers during the third quarter of 2001
compared with the same period in 2000. The increase in retail MWh sales was
primarily due to warmer summer temperatures and customer growth.
Retail revenues for the nine months ended September 30, 2001 were $8.0 million
or 5.8 percent higher when compared with the same period in 2000, reflecting the
Settlement Order rate increase and increased retail MWh sales of approximately
1.8 percent.
In the Company's most recent rate case settlement the VPSB ordered that
seasonal rates be eliminated in April 2001, which is expected to generate
approximately $7.5 million in additional cash flow in 2001. Such deferred
revenue was intended by the VPSB to be used to offset increased costs during
2001, 2002 and 2003, increasing the likelihood of the Company earning its
allowed rate of return in those years. Approximately $8.6 million of revenue
arising as a result of the elimination of seasonal rates was deferred through
the third quarter of 2001. The Company expects to achieve its allowed rate of
return without utilizing any of the approximate $7.5 million in revenues
expected to be deferred during 2001.
The Company's earnings from electric operations are subject to an earnings
cap equal to its allowed rate of return of 11.25%. The Company's policy is to
review its quarterly results and to defer any revenues that are probable of
causing earnings to exceed an 11.25% rate of return ("excess earnings") for the
year. As a result of our review, we deferred $0.5 million of revenue and
recorded a regulatory liability for excess earnings in the same amount during
the quarter ended September 2001. Deferred excess earnings total $1.1 million
for the nine months ended September 30, 2001. Under a settlement agreement
with the Vermont Department of Public Service ("DPS" or the "Department"), and
approved by the VPSB, any excess earnings amounts will be used to write off
regulatory assets at December 31, 2001.
We sell wholesale electricity to others for resale. Our revenue from wholesale
sales of electricity decreased $6.4 million in the third quarter of 2001
compared with the same period in 2000, due to a decrease in resales under a
power purchase and supply agreement between the Company and Morgan Stanley
Capital Group, Inc. ("MS"), and decreased sales under various arrangements with
Hydro-Quebec. Under the MS 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.
Our revenue from wholesale sales of electricity increased $1.3 million for the
first nine months of 2001 compared with the same period in 2000. The increases
were due primarily to increased sales to the ISO.
OPERATING EXPENSES
POWER SUPPLY EXPENSES
Power supply expenses decreased $4.8 million or 8.0 percent in the third
quarter of 2001 compared with the same period in 2000.
Power supply expenses at Vermont Yankee decreased $1.1 million or 12.1
percent during the third quarter of 2001 compared with the third quarter of
2000, primarily due to reduced maintenance costs. A proposed sale of the
generating plant is discussed under Part I, Item 2, "Investment in Associated
Companies".
Company-owned generation expenses increased $0.3 million or 21.0 percent in
the third quarter of 2001 compared with the same period in 2000 primarily due to
higher fuel prices
The cost of power that we purchased from other companies decreased
$4.0 million or 8.1 percent in the third quarter of 2001 compared with the same
period in 2000, primarily due to decreased wholesale sales of electricity of
$6.4 million, offset in part by higher energy and capacity costs and adjustments
that caused approximately $1.9 million in power supply costs paid during 2000 to
be expensed in previous periods.Power supply expenses for the first nine months
of 2001 decreased $3.9 million or 2.4 percent when compared with the first nine
months of 2000.
Power supply expense at Vermont Yankee decreased $4.9 million or 18.5 percent
for the first nine months of 2001 compared with the first nine months of 2000,
primarily due to a scheduled outage at the plant during 2001. Vermont Yankee
scheduled outage costs are deferred and amortized over an eighteen month
refueling cycle.
Company-owned generation expenses decreased $0.4 million or 9.1 percent in
the first nine months of 2001 compared with the same period in 2000. During
2001, the Company recorded a reduction of generation expense of approximately
$1.9 million for its costs of running peak generation facilities for system
reliability and we received reimbursement of these amounts from the ISO in July
2001. This reduction was partially offset by increased generation expense
caused by higher fuel costs.
Purchased power expense increased $1.4 million or 1.1 percent in the first
nine months of 2001 compared with the first nine months of 2000. Power supply
costs increased due to accounting adjustments that caused approximately $5.7
million of power supply costs paid during 2000 to be expensed in previous
periods, higher energy prices and the costs of energy purchased to cover
potential shortfalls due to transmission system operating requirements. These
increases were offset in part by decreased costs of managing the replacement
costs of power sold to Hydro-Quebec under 9701during 2001.
The 9701 arrangement allows Hydro-Quebec to exercise an option to purchase power
from the Company at energy prices based on a 1987 contract. During the first
quarter of 2001, Hydro-Quebec exercised its purchase option for delivery of
134,592 MWh during the months of June, July and August of 2001. The Settlement
Order approved by the VPSB includes revenues in 2001 sufficient to provide for
net costs for replacing power purchased by Hydro-Quebec of approximately $6.6
million annually. The Company recognized $1.6 million in expense during the
quarter ended September 30, 2001 to reflect these estimated costs. A regulatory
asset of $1.6 million was established for the remaining estimated difference
between the option exercise price and the expected cost of replacement power to
be recovered during 2001. If the estimated costs of power purchased to supply
Hydro-Quebec option calls exceed amounts recovered in rates and/or amounts
previously recorded, the excess cost would be immediately charged against
earnings. No charge for excess cost was required during the first nine months
of 2001. The Company purchased power sufficient to fulfill the 9701 calls for
this summer, and no charges in excess of amounts provided in rates or previously
recorded are anticipated for the remainder of 2001. The net cost of power to
supply all 9701 option calls during 2001 is estimated at approximately $8.4
million. It is possible our estimate of future power supply costs could differ
materially from actual results.
Both the 9701 arrangement and our forward purchase contracts are considered
derivative instruments as defined by SFAS 133. On April 11, 2001, the VPSB
issued an accounting order that allows the Company to defer recognition of any
earnings or other comprehensive income effect relating to future periods caused
by application of SFAS 133 and as a result, we do not anticipate SFAS 133 to
cause earnings volatility. At September 30, 2001, the Company had a regulatory
asset of approximately $14.4 million related to derivatives that the Company
believes is probable of recovery. The regulatory asset is based on current
estimates of future market prices that are likely to change by material amounts.
OTHER OPERATING EXPENSES
Other operating expenses increased $0.3 million or 8.9 percent in the
third quarter of 2001 compared with the same period in 2000. The increase
reflects higher outside service costs and increased benefit costs. Other
operating expenses increased $0.8 million or 7.3 percent in the first nine
months of 2001 compared with the same period in 2000 for the same reasons,
offset in part by reduced regulatory commission expenses.
TRANSMISSION EXPENSES
Transmission expenses decreased by approximately $0.1 million or 2.4
percent for the three months ended September 30, 2001 compared with the same
period in 2000 due to minor reductions in congestion charges. Transmission
expenses decreased by approximately $0.2 million or 1.6 percent for the nine
months ended September 30, 2001, compared with the same period in 2000 for the
same reason. Congestion charges recorded in the first nine months of 2001 and
2000 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 allocations, but amounts could be material.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses were essentially unchanged during
the third quarter of 2001 compared with the same period in 2000.
Depreciation and amortization expenses decreased $0.9 million or 7.3
percent during the first nine months of 2001 compared with the same period in
2000. The reduction is primarily due to decreased amortization of demand side
management regulatory assets.
TAXES OTHER THAN INCOME TAXES
Other taxes increased $0.3 million or 15.6 percent in the third quarter of
2001 compared with the same period in 2000, primarily due to increases in
property and gross revenue tax. Other taxes increased $0.4 million or 6.8
percent for the first nine months of 2001 compared with the same period in 2000
for the same reason.
INCOME TAXES
Income taxes increased $1.0 million in the third quarter of 2001 compared
with the same period in 2000 due to an increase in pretax book income. Income
taxes increased $5.5 million for the first nine months of 2001 compared with the
same period in 2000 for the same reason.
OTHER INCOME
Other income increased $0.1 million or 10.9 percent for the three months
ended September 30, 2001 compared with the same period in 2000. Other income
decreased $0.3 million or 13.6 percent for the nine months ended September 30,
2001, compared with the same period in 2000 due primarily to a favorable
settlement of a claim in the first quarter of 2000 and reductions in capitalized
returns during construction in 2001.
INTEREST CHARGES
Interest charges decreased $49,000 or 2.9 percent in the third quarter of
2001 compared with the same period in 2000 primarily due to reductions in
interest on long-term debt due to sinking fund redemption.
Interest charges increased $0.2 million or 3.3 percent for the nine months
ended September 30, 2001 compared with the same period in 2000 primarily due to
increased costs associated with the short term credit arrangements discussed
under "Liquidity and Capital Resources" offset in part by reductions in interest
on long-term debt due to sinking fund redemption.
LIQUIDITY AND CAPITAL RESOURCES
In the nine months ended September 30, 2001, we spent $9.9 million
principally for expansion and improvements of our transmission and distribution
plant. We expect to spend an additional $5.9 million during the remainder of
2001.
On June 20, 2001, we renewed a revolving credit agreement (the "Fleet
Agreement") with Fleet National Bank ("Fleet"), joined by KeyBank National
Association ("KeyBank"). The Fleet Agreement is for a period of 364 days, will
expire on June 19, 2002, and is unsecured. No amounts were outstanding on the
Fleet Agreement at September 30, 2001.
On September 20, 2000, we established a $15.0 million revolving credit agreement
with KeyBank (the "KeyBank Agreement") which expired on September 19, 2001.
Pursuant to a September 2000 one year power supply option agreement between the
Company and Energy East Corporation ("EE"), EE made a payment of $15.0 million
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 were not returned to EE. 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 loans made pursuant to the Keybank Agreement.
The payment made by EE was returned to EE along with accrued interest on
September 11, 2001.
The Company executed and delivered a $12.0 million two-year loan agreement with
Fleet, joined by KeyBank. Funding of this facility was contingent upon VPSB
approval. On July 27, 2001 the VPSB approved the financing arrangement and the
loan was funded on August 24, 2001. The Company used this facility, along with
proceeds from the maturing KeyBank certificate of deposit, to terminate the
KeyBank Agreement, and repay the $15.0 million it received from EE pursuant to
the power supply option agreement discussed above. At September 30, 2001, there
was $12.0 million outstanding under the two-year loan agreement.
The credit ratings of the Company's securities are:
Fitch Moody's Standard & Poor's
----- ------- -------------------
First mortgage bonds BBB Baa2 BBB
Preferred stock BBB- Ba2 BB
COMPETITION AND RESTRUCTURING
The electric utility business is experiencing rapid and substantial
changes. These changes are the result of the following trends:
* Disparity in electric rates, transmission, and generation capacity among
and within various regions of the country;
* Improvements in generation efficiency;
* Alternative energy sources;
* The deregulation of the wholesale energy market and the establishment of
an independent system operator; and
* New regulations and legislation in some states intended to foster
competition, also known as restructuring.
We are unable to predict what form future restructuring legislation, if
adopted, will take and what impact that might have on the Company, but it could
be material.
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 ("FASB") had agreed to review the accounting for closure and
removal costs, including decommissioning. The FASB issued a new statement on
accounting standards in August 2001 for "Obligations Associated with Disposal
Activities", which provides guidance on accounting for nuclear plant
decommissioning costs. The Company has not yet determined what impact, if any,
the new accounting standard will have on its investment in VY.
EFFECTS OF INFLATION
Financial statements are prepared in accordance with generally accepted
accounting principles and report operating results in terms of historic costs.
This method of 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.
MARKET RISK
In June 1998, the FASB 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 objective of the Company's risk management program is to protect cash
flow and earnings by minimizing risk. Permitted transactions include futures,
forward contracts, option contracts, swaps and transmission congestion rights
with counter parties that have at least investment grade ratings. These
transactions are used to hedge risk of fossil fuel price increases as well as
the risk of spot market electricity price increases. Futures, swaps and forward
contracts are used to hedge the impact of market prices on the Company should
option calls by Hydro-Quebec be exercised by Hydro-Quebec. The Company's risk
management policy specifies risk measures, the amount of tolerable risk
exposure, and limits to transaction authority.
A sensitivity analysis has been prepared to estimate the exposure to the
market price risk of our electricity commodity positions. Our daily net
commodity position consists of purchased electric capacity. The table below
presents market risk, estimated as the potential loss in fair value resulting
from a hypothetical 10 percent adverse change in prices. Actual prices may
differ materially from those assumed in developing the table.
At September 30, 2001
Fair value Market risk
----------------------- ------------
(in thousands)
Highest long position . $ 19,582 $ 15,880
Highest short position. $ 35,775 $ 13,785
Average position(short) $ (16,192) $ 2,095
26
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SEPTEMBER 30,2001
-----------------
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. NONE
ITEM 5. Other Information
NONE
ITEM 6. (B) REPORTS ON FORM 8-K
----------------------
The following Form 8-K was filed by the Company on the topic and date
indicated:
August 15, 2001 Form 8-K announced an agreement between Vermont Yankee
Nuclear Power Corporation ("Vermont Yankee") and Entergy Corporation to sell
Vermont Yankee's nuclear power plant to Entergy for approximately $180 million.
The Company owns approximately 17.9% of the common stock of Vermont Yankee.
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 09, 2001 /s/Nancy Rowden Brock
-----------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer, Secretary,
and Treasurer