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, 2002
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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
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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
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INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES X NO
---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
CLASS - COMMON STOCK OUTSTANDING AT NOVEMBER 6, 2002
- --------------------------- ------------------------------------
$3.33 1/3 PAR VALUE 5,729,240
PART I FINANCIAL INFORMATION
GREEN MOUNTAIN POWER CORPORATION
INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
AT AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30,
2002 AND 2001
ITEM 1. FINANCIAL STATEMENTS PAGE
Consolidated Statements of Income 3
Consolidated Statements of Cash Flows 4
Consolidated Balance Sheets 5
Notes to Consolidated Financial Statements 7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 17
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 25
ITEM 4. CONTROLS AND PROCEDURES 27
PART II. OTHER INFORMATION 28
Exhibits and Reports on Form 8-K 28
Signatures 29
Certifications 30
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
2002 2001 2002 2001
-------- -------- --------- ---------
In thousands, except per share data
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $73,477 $76,051 $207,478 $218,319
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 10,713 7,645 26,977 21,514
Company-owned generation. . . . . . . . . . . . . . . . . . 1,847 1,625 3,425 3,868
Purchases from others . . . . . . . . . . . . . . . . . . . 40,622 45,495 116,356 129,589
Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,400 3,939 10,455 11,713
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,707 3,431 11,679 10,433
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 2,082 1,739 6,356 5,274
Depreciation and amortization. . . . . . . . . . . . . . . . 3,608 3,491 10,547 10,803
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,964 1,930 5,870 5,833
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 1,789 2,183 4,813 5,870
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 69,732 71,478 196,478 204,897
-------- -------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 3,745 4,573 11,000 13,422
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 1,362 553 2,430 1,688
Allowance for equity funds used during construction. . . . . 53 69 175 128
Other income (deductions), net . . . . . . . . . . . . . . . (612) 90 (664) 16
-------- -------- --------- ---------
TOTAL OTHER INCOME (DEDUCTIONS) . . . . . . . . . . . . . 803 712 1,941 1,832
-------- -------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 4,548 5,285 12,941 15,254
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,253 1,491 3,866 4,586
Other interest . . . . . . . . . . . . . . . . . . . . . . . 272 215 780 925
Allowance for borrowed funds used during construction. . . . (23) (43) (77) (146)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,502 1,663 4,569 5,365
-------- -------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 3,046 3,622 8,372 9,889
DISCONTINUED OPERATIONS
Preferred stock dividend requirement . . . . . . . . . . . . 4 235 99 704
-------- -------- --------- ---------
Income from continuing operations. . . . . . . . . . . . . . 3,042 3,387 8,273 9,185
Loss on disposal, including provisions for
operating losses during phaseout period. . . . . . . . . . . - - - (150)
-------- -------- --------- ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 3,042 $ 3,387 $ 8,273 $ 9,035
======== ======== ========= =========
Common stock data
Basic earnings per share . . . . . . . . . . . . . . . . . . $ 0.53 $ 0.60 $ 1.45 $ 1.61
Diluted earnings per share . . . . . . . . . . . . . . . . . 0.52 0.58 1.41 1.56
Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.41 $ 0.41
Weighted average common shares outstanding-basic . . . . . . 5,723 5,644 5,709 5,615
Weighted average common shares outstanding-diluted . . . . . 5,879 5,814 5,874 5,777
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . $11,683 $ 4,602 $ 8,070 $ 493
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . 3,046 3,622 8,372 9,739
Preferred stock dividend requirement . . . . . . . . . . . . (4) (235) (99) (704)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 -
Cash Dividends-common stock. . . . . . . . . . . . . . . . . (788) (777) (2,356) (2,316)
-------- -------- --------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . $13,987 $ 7,212 $ 13,987 $ 7,212
======== ======== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION UNAUDITED
---------
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED
SEPTEMBER 30
2002 2001
-------------- ---------
OPERATING ACTIVITIES: In thousands
Net income before preferred stock dividend requirement. . . . $ 8,372 $ 9,739
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . . . 10,547 10,803
Dividends from associated companies less equity income. . . . (1,024) 267
Allowance for funds used during construction. . . . . . . . . (253) (274)
Amortization of purchased power costs . . . . . . . . . . . . 2,385 2,607
Deferred income taxes . . . . . . . . . . . . . . . . . . . . 3,068 (2,525)
Arbitration costs recovered . . . . . . . . . . . . . . . . . - 3,229
Deferred purchased power costs. . . . . . . . . . . . . . . . (1,982) (5,254)
Accrued purchase power contract option call . . . . . . . . . - (3,346)
Earnings cap deferral and rate levelization liability . . . . (5,519) 9,663
Environmental and conservation amortization (deferrals), net. (1,414) (2,291)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . 1,258 3,594
Accrued utility revenues. . . . . . . . . . . . . . . . . . . 964 1,335
Fuel, materials and supplies. . . . . . . . . . . . . . . . . 797 37
Prepayments and other current assets. . . . . . . . . . . . . 1,130 713
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . (636) (3,786)
Accrued income taxes payable and receivable . . . . . . . . . 1,458 3,428
Other current liabilities . . . . . . . . . . . . . . . . . . (482) 1,073
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 532 (1,100)
-------------- ---------
Net cash provided by continuing operations. . . . . . . . 19,204 27,912
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . . . (14,127) (9,212)
Investment in nonutility property . . . . . . . . . . . . . . (134) (146)
-------------- ---------
Net cash used in investing activities . . . . . . . . . . (14,261) (9,358)
-------------- ---------
FINANCING ACTIVITIES:
Proceeds from term loan . . . . . . . . . . . . . . . . . . . 12,000
Redemption of preferred stock . . . . . . . . . . . . . . . . (12,325) -
Issuance of common stock. . . . . . . . . . . . . . . . . . . 617 1,283
Reduction in long term debt . . . . . . . . . . . . . . . . . (5,100) (1,700)
Power supply option obligation, net . . . . . . . . . . . . . - 160
Short-term debt, net. . . . . . . . . . . . . . . . . . . . . 11,000 (15,500)
Cash dividends and preferred stock dividend requirement . . . (2,455) (3,020)
-------------- ---------
Net cash used in financing activities . . . . . . . . . . (8,264) (6,777)
-------------- ---------
Net increase(decrease) in cash and cash equivalents . . . . . (3,321) 11,777
Cash and cash equivalents at beginning of period. . . . . . . 5,006 341
-------------- ---------
Cash and cash equivalents at end of period. . . . . . . . . . $ 1,685 $ 12,118
============== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . . . $ 4,738 $ 4,677
Income taxes, net . . . . . . . . . . . . . . . . . . . . . 2,349 5,287
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,
2002 2001 2001
-------- -------- --------
In thousands
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . $308,830 $296,843 $302,489
Less accumulated depreciation . . . . . . . . 124,811 116,540 119,054
-------- -------- --------
Net utility plant . . . . . . . . . . . . . . 184,019 180,303 183,435
Property under capital lease. . . . . . . . . 5,959 6,449 5,959
Construction work in progress . . . . . . . . 12,293 8,208 7,464
-------- -------- --------
Total utility plant, net. . . . . . . . . . 202,271 194,960 196,858
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . 15,469 14,176 14,093
Other investments . . . . . . . . . . . . . . 7,235 6,725 6,852
-------- -------- --------
Total other investments . . . . . . . . . . 22,704 20,901 20,945
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . 845 12,118 5,006
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $613 . . . . . . . . . . . . . . . . . . 15,853 18,771 17,111
Accrued utility revenues. . . . . . . . . . . 4,900 5,758 5,864
Fuel, materials and supplies, at average cost 3,261 4,019 4,058
Prepayments . . . . . . . . . . . . . . . . . 925 1,635 1,976
Income tax receivable . . . . . . . . . . . . - - 1,699
Other . . . . . . . . . . . . . . . . . . . . 389 894 469
-------- -------- --------
Total current assets. . . . . . . . . . . . 26,173 43,195 36,183
-------- -------- --------
DEFERRED CHARGES
Demand side management programs . . . . . . . 6,598 6,676 6,961
Purchased power costs . . . . . . . . . . . . 3,139 6,179 3,504
Pine Street Barge Canal . . . . . . . . . . . 12,425 12,370 12,425
Power supply derivative deferral. . . . . . . 31,776 34,419 37,313
Other . . . . . . . . . . . . . . . . . . . . 13,829 14,697 14,870
-------- -------- --------
Total deferred charges. . . . . . . . . . . 67,767 74,341 75,073
-------- -------- --------
NON-UTILITY
Other current assets. . . . . . . . . . . . . 8 8 8
Property and equipment. . . . . . . . . . . . 250 251 250
Other assets. . . . . . . . . . . . . . . . . 739 822 817
-------- -------- --------
Total non-utility assets. . . . . . . . . . 997 1,081 1,075
-------- -------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . $319,912 $334,478 $330,134
======== ======== ========
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,
2002 2001 2001
--------- --------- ---------
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
5,743,296, 5,656,048 and 5,701,010) . . . . . . $ 19,145 $ 18,907 $ 19,004
Additional paid-in capital . . . . . . . . . . . 75,057 74,306 74,581
Retained earnings. . . . . . . . . . . . . . . . 13,987 7,212 8,070
Treasury stock, at cost (15,856 shares). . . . . (428) (378) (378)
--------- --------- ---------
Total common stock equity. . . . . . . . . . . 107,761 100,047 101,277
Redeemable cumulative preferred stock. . . . . . 85 12,560 12,325
Long-term debt, less current maturities. . . . . 59,000 82,400 74,400
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . 166,846 195,007 188,002
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . 5,959 6,449 5,959
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 150 235 235
Current maturities of long-term debt . . . . . . 8,000 9,700 9,700
Short-term debt. . . . . . . . . . . . . . . . . 23,000 - -
Accounts payable, trade and accrued liabilities. 6,152 5,943 7,237
Accounts payable to associated companies . . . . 8,810 6,536 8,361
Accrued taxes. . . . . . . . . . . . . . . . . . 1,032 - -
Customer deposits. . . . . . . . . . . . . . . . 822 832 971
Interest accrued . . . . . . . . . . . . . . . . 1,327 1,716 1,100
Rate Levelization liability. . . . . . . . . . . 3,008 8,613 8,527
Deferred revenues. . . . . . . . . . . . . . . . - 1,050 -
Other. . . . . . . . . . . . . . . . . . . . . . 1,112 3,289 2,945
--------- --------- ---------
Total current liabilities. . . . . . . . . . . 53,413 37,914 39,076
--------- --------- ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . . 32,616 34,419 37,313
Accumulated deferred income taxes. . . . . . . . 27,040 23,331 23,759
Unamortized investment tax credits . . . . . . . 3,201 3,483 3,413
Pine Street Barge Canal site cleanup . . . . . . 8,957 10,583 10,059
Other. . . . . . . . . . . . . . . . . . . . . . 19,510 21,531 20,852
--------- --------- ---------
Total deferred credits . . . . . . . . . . . . 91,324 93,347 95,396
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Other Liabilities. . . . . . . . . . . . . . . . 2,370 1,761 1,701
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . 2,370 1,761 1,701
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . $319,912 $334,478 $330,134
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2002
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 Green Mountain Power Corporation (the
"Company" or "GMP") annual report for 2001 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. In periods prior to April 2001, we charged our
customers higher rates for billing cycles in December through March and lower
rates for the remaining months. These were called seasonally differentiated
rates. Seasonal rates were eliminated in April 2001, and generated
approximately $8.5 million of revenues deferred in 2001. We estimate that $7.3
million will be used to offset increased costs during 2002, including $5.5
million that was recognized during the first three quarters. The remaining $1.2
million of deferred revenue is expected to be recognized in 2003.
Certain line items on the prior year's 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"); Green Mountain Propane Gas Company Limited ("GMPG");
GMP Real Estate Corporation; and Green Mountain Resources, Inc. ("GMRI").
During 2000 and 2001, we sold most of the assets of NWR. 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,
including NWR during 2002, and the rental water heater program are included in
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
ownership interests) listed below based on our percentage ownership (equity
method).
VERMONT YANKEE NUCLEAR POWER CORPORATION ("VY", OR "VERMONT YANKEE")
Percent ownership: 19.0% common
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
------- ------- -------- --------
(in thousands)
Gross Revenue. . . . . $48,534 $37,868 $134,029 $135,863
Net Income Applicable. 5,911 1,641 8,860 4,765
to Common Stock
Equity in Net Income . 1,111 296 1,682 560
On August 15, 2001, VY agreed to sell its nuclear power plant to Entergy
Corporation for approximately $180 million. On July 31, 2002, Vermont Yankee
announced that the sale of its nuclear power plant to Entergy Nuclear Vermont
Yankee ("Entergy") had been completed. In addition to the sale of the
generating plant, the transaction calls for Entergy to provide 20 percent of the
plant output to the Company through 2012, which represents approximately 35
percent of the Company's energy requirements. The Company continues to own
approximately 19 percent of the common stock of VY. Our benefits of the plant
sale and power contract with Entergy include:
Vermont Yankee receives cash approximately equal to the book value of the
plant assets, removing the potential for stranded costs associated with the
plant.
Vermont Yankee and its owners will no longer bear operating risks
associated with running the plant.
Vermont Yankee and its owners will no longer bear the risks associated with
the eventual decommissioning of the plant.
Prices under the Power Purchase Agreement with Entergy (the "PPA") range
from $39 to $45 per megawatt-hour for the period beginning January 2003,
substantially lower than the forecasted cost of continued ownership and
operation by Vermont Yankee. Contract prices range from $49 to $55 for 2002,
higher than the forecasted cost of continued ownership for the current year.
The PPA with Entergy calls for a downward adjustment in the price if market
prices for electricity fall by defined amounts beginning no later than November
2005. If market prices rise, however, the contract prices are not adjusted
upward.
Payments totaling $0.5 million were made to VY's non-Vermont sponsors in
return for guarantees those sponsors made to Entergy to finalize the VY sale.
Although the sale closed on July 31, 2002, the Company's distribution of the
sale proceeds and final accounting for the sale are pending certain regulatory
approvals and the resolution of certain closing items between the seller and
purchaser. The Company expects its share of the Vermont Yankee sale proceeds to
be distributed in 2003.
The Company remains responsible for procuring replacement energy at market
prices during periods of scheduled or unscheduled outages at the Entergy plant.
The VY plant had fuel rods that required repair during May 2002, a
maintenance requirement that is not unique to VY. VY shutdown the plant for a
twelve-day period, beginning on May 11, 2002, to repair the rods. The Company's
cost for the repair, including incremental replacement energy costs, was
approximately $2.0 million. The Company received an accounting order from the
VPSB on August 2, 2002, allowing it to defer the additional costs related to the
outage, and believes that such amounts are probable of future recovery.
The Company's ownership share of VY has increased from approximately 17.9
percent last year to approximately 19.0 percent currently, due to VY's purchase
of certain minority shareholders' interests. The Company's entitlement to
energy produced by the VY nuclear plant has increased from approximately 18
percent to 20 percent of plant production through a series of transactions in
connection with the sale of the plant to Entergy.
The increase in equity in earnings of VY resulted from VY's recognition of
certain deferred tax assets as a result of the sale of the nuclear plant.
VERMONT ELECTRIC POWER COMPANY, INC. ("VELCO")
Percent ownership: 28.41% common
30.0% preferred
VELCO is a corporation engaged in the transmission of electric power within
the State of Vermont. VELCO has entered into transmission agreements with the
State of Vermont 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.
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
------ ------ ------- -------
(in thousands)
Gross Revenue . . . . $5,012 $6,806 $16,808 $22,524
Net Income. . . . . . 261 230 774 782
Equity in Net Income. 70 75 239 221
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 of Vermont (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 (the "EPA") for past Pine Street site costs, natural resource
damage claims and claims for past and future oversight costs. The Consent
Decree also provides for the design and implementation of response actions at
the site.
As of September 30, 2002, our total expenditures related to the Pine Street site
since 1982 were approximately $26.4 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 waiting 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 $12.4 million through 2033.
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 in such expenditures. In an Order in that case released March 2,
1998, the VPSB suspended the amortization of expenditures associated with the
Pine Street 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
The Company reached a final settlement agreement with the Department in its
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 from 1998 through 2000;
* 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 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 short-term credit facilities with long-term debt or equity
financing;
* Seasonal rates were eliminated in April 2001, which generated
approximately $8.5 million in additional cash flow in 2001 that can be utilized
to offset increased costs during 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;
* The Company agreed to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in a 1997 rate case; and
* The Company agreed to an earnings limitation for its electric operations
in an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned over the limit being used to write off regulatory assets. The Company
earned approximately $30,000 in excess of its allowed rate of return during 2001
before writing off regulatory assets in the same amount.
On January 23, 2001, the VPSB approved the Company's settlement (the
"Settlement Order") with the Department, with two additional conditions:
* The Company and customers shall 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.
In August 2002, the Company petitioned the VPSB for consent to issue long-term
debt, with the proceeds to be used to repay existing intermediate term
indebtedness and short-term debt outstanding under the Company's revolving
credit facility. On October 10, 2002, the VPSB issued an order approving the
Company's request. Pursuant to this order, upon issuance of the new long-term
debt and repayment of existing short and intermediate term indebtedness, the
dividend freeze order will terminate, allowing the Company's Board of Directors
to consider an increase in the Company's common stock dividend rate. The
Company expects the Board of Directors to consider whether an increase in the
dividend level would be appropriate at its December 2002 meeting.
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 nine months of 2002, $2.3 million in power supply expense was
recognized to reflect the cost of option A, which is recognized ratably over the
year. Hydro-Quebec has previously agreed not to call option B during the 2002
contract year. At September 30, 2002, the cumulative amount of power purchased
by Hydro-Quebec under option B is approximately 458,000 MWh.
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 Company recognized $6.0 million in expense during the nine months
ended September 30, 2001 to reflect 9701 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.
If estimated costs of fulfilling the Hydro-Quebec option calls exceed
amounts recovered in rates, the excess cost would be immediately charged against
earnings. No charge for excess cost was required during the first nine months
of 2002 and 2001. No charges in excess of amounts provided in rates or
previously recorded are anticipated for the remainder of 2002.
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, 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. Hydro-Quebec also has the option to reduce
the load factor from 75 percent to 65 percent under the 1987 Contract a total of
three times over the life of the contract. The Company can delay the load factor
reduction by one year under the same contract. During 2001, Hydro-Quebec
exercised the first of its load factor reduction options intended for 2002, and
the Company delayed the effective date of this exercise until 2003. The Company
estimates that the net cost of Hydro-Quebec's exercise of its load factor
reduction option will increase power supply expense during 2003 by approximately
$0.4 million.
It is possible our estimate of future power supply costs could differ materially
from actual results.
COMPETITION
During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase an existing hydro-generation facility from a third party, and the
associated distribution plant owned by the Company within Rockingham. In March
2002, voters in Rockingham authorized Rockingham to create a municipal utility
by acquiring a municipal plant, which would include the Bellows Falls
hydroelectric facility and the electric distribution systems of the Company
and/or Central Vermont Public Service Corporation. The Company receives annual
revenues of approximately $4.0 million from its customers in Rockingham. Should
Rockingham create a municipal system, the Company would vigorously pursue its
right to receive just compensation from Rockingham. Such compensation would
include full reimbursement for Company assets, if acquired, and full
reimbursement of any other costs associated with the loss of customers in
Rockingham, to assure that our remaining customers do not subsidize a Rockingham
municipal utility.
4. SEGMENTS AND RELATED INFORMATION
The Company operated one segment during 2002, the electric utility
operations. 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, NWR and 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 September 30, 2002, most of
NWR's net assets and liabilities have been sold or otherwise disposed. The
remaining net liability reflects expected warranty obligations, net of equity
investments in two wind farms and wastewater treatment projects.
5. DERIVATIVE INSTRUMENTS AND RISK MANAGEMENT
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended ("SFAS 133").
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. SFAS 133, as amended by SFAS 137, was
effective for the Company beginning 2001.
One objective of the Company's risk management program is to stabilize 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 counter-parties that have at least
investment grade ratings. These transactions are used to hedge the risk of
fossil fuel and spot market electricity price increases. Futures, swaps and
forward contracts are used to hedge market prices should option calls by
Hydro-Quebec be considered probable of exercise. The Company's risk management
policy specifies risk measures, the amount of tolerable risk exposure, and
authorization limits for transactions.
On April 11, 2001, the VPSB issued an accounting order that requires the Company
to defer recognition of any earnings effects relating to future periods caused
by application of SFAS 133. At September 30, 2002, the Company had a liability
reflecting the fair value of the two derivatives described below, as well as a
corresponding regulatory asset of approximately $32.6 million. The Company
believes that the regulatory asset is probable of recovery in future rates. The
liability is based on current estimates of future market prices that are subject
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.
The Company has a contract with Morgan Stanley Capital Group, Inc. ("MS") used
to hedge against increases in fossil fuel prices. MS purchases the majority of
the Company's power supply resources at index (fossil fuel resources) or
specified (i.e., contracted resources) prices and then sells to us at a fixed
rate to serve pre-established load requirements. This contract allows
management to fix the cost of much of its power supply requirements, subject to
power resource availability and other risks. The MS contract is a derivative
under SFAS 133 and was scheduled to expire on December 31, 2003. In August
2002, the Company extended the contract with MS through December 31, 2006.
Beginning in 2004, the extended contract includes only our interests in the
Wyman and StonyBrook plants with respective capacities of 7 MW and 45 MW, and
our estimated load requirements not satisfied by contractual arrangements and
other owned generation. The cost of power purchased from MS for 2003 is
expected to be approximately $7.9 million less than the cost of power purchased
from MS during 2002. The remainder of our load requirements are substantially
provided through our power supply contracts and arrangements with Hydro-Quebec,
our entitlements to power generated at the Vermont Yankee nuclear plant now
owned by Entergy, and Company-owned generation. Management's estimate of the
fair value of the future net cost of this contract at September 30, 2002 is
approximately $5.2 million.
We also sometimes use future contracts to hedge forecasted wholesale sales of
electric power, including material sales commitments. We currently have an
arrangement with Hydro-Quebec that grants it an option to call power at prices
below current and estimated future market rates. This arrangement is a
derivative and is effective through 2015. Management's estimate of the fair
value of the future net cost for this arrangement at September 30, 2002 is
approximately $27.4 million.
6. 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 initiated after June 30, 2001 and uses a non-amortization approach
to purchased goodwill and other indefinite-lived intangible assets. Under SFAS
142, effective for fiscal years beginning after December 15, 2001, goodwill and
intangible assets deemed to have indefinite lives, will no longer be amortized,
and will be subject to annual impairment tests. The adoption of these
accounting standards did not impact the Company's financial position or results
of operations as of September 30, 2002.
In 2001, the FASB issued Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), effective for
the Company's 2003 fiscal year. SFAS 143 prescribes fair value accounting for
asset retirement liabilities, including nuclear decommissioning obligations, and
requires recognition of such liabilities at the time incurred. The Company has
not yet determined what impact, if any, the accounting standard will have on its
financial position or results of operations.
In 2001, the FASB issued Statement of Financial Accounting Standards No.
144, "Accounting for the Impairment or Disposal of Long-lived Assets" ("SFAS
144"), effective for fiscal years beginning after December 15, 2001. SFAS 144
specifies accounting and reporting for the impairment or disposal of long-lived
assets. The adoption of SFAS 144 did not impact the Company's financial
position or results of operations as of September 30, 2002.
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 year. The Company established a
stock incentive plan for all directors and 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
2002 2001 2002 2001
------ ------ ------ ------
(in thousands)
Net income before preferred dividends. . $3,046 $3,622 $8,372 $9,739
Preferred stock dividend requirement . . 4 235 99 704
------ ------ ------ ------
Net income applicable to common stock. . $3,042 $3,387 $8,273 $9,035
====== ====== ====== ======
Average number of common shares-basic. . 5,723 5,644 5,709 5,615
Dilutive effect of stock options . . . . 156 170 166 162
Anti-dilutive stock options. . . . . . . - - - -
------ ------ ------ ------
Average number of common shares-diluted. 5,879 5,814 5,875 5,777
====== ====== ====== ======
GREEN MOUNTAIN POWER CORPORATION
PART I-ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
SEPTEMBER 30, 2002
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.
Management believes the most critical accounting policies include the regulatory
accounting framework within which we operate, the method by which we recognized
deferred revenues, the expected returns selected for our defined benefit
retirement plans, the probability assigned by management for recovery of our
regulatory assets, and the manner in which we account for certain power supply
arrangements that qualify as derivatives. These accounting policies, among
others, affect the Company's significant judgments and estimates used in the
preparation of its consolidated financial statements, including estimates and
judgments used in determining the current period recognition of revenues
deferred in 2001, as discussed further under the caption "Operating Revenues and
MWh Sales-Revenues, in this section.
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 materially 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 per share of Common Stock*
Three months ended Nine months ended
September 30 September 30
2002 2001 2002 2001
----- ----- ----- -------
Utility business . . . . $0.51 $0.58 $1.40 $ 1.57
Unregulated businesses . 0.02 0.02 0.05 0.07
----- ----- ----- -------
Earnings from:
Continuing operations. . 0.53 0.60 1.45 1.64
Discontinued operations. - - - (0.03)
----- ----- ----- -------
Basic earnings per share $0.53 $0.60 $1.45 $ 1.61
===== ===== ===== =======
*The three and nine months ended September 30, 2002 include recognition of $1.2
million and
$5.5 million of deferred revenues, respectively.
*The three and nine months ended September 30, 2002 include recognition of $1.2
million and
$5.5 million of deferred revenues, respectively.
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.51 in the quarter ended September 30, 2002, compared with utility earnings of
$0.58 per share in the third quarter of 2001. Earnings declined in the third
quarter of 2002 as a result of increased power supply costs to serve retail
sales. These additional costs were partially offset by increased retail
revenues and income recognized as a result of the sale of the Vermont Yankee
("VY") nuclear power plant.
Retail operating revenues increased by $1.7 million during the third quarter of
2002, compared with the same quarter of 2001, primarily due to the recognition
of $1.2 million in revenues deferred during 2001 in accordance with the
settlement of the Company's retail rate case approved by the Vermont Public
Service Board (the "VPSB") in January 2001(the "Settlement Order"). The
Settlement Order resulted in the elimination of seasonal rates, generating an
additional $8.5 million in cash flow in 2001. The Settlement Order provided
that recognition of this additional revenue be deferred and then recognized to
offset increased costs during 2001, 2002, or 2003. Management expects the
Settlement Order to provide the Company a better opportunity to earn its allowed
rate of return for these time periods.
Basic earnings per share from utility operations for the nine months ended
September 30, 2002 were $1.40 compared with basic earnings per share of $1.57
for the same period in 2001, due to the same factors influencing third quarter
results.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from continuing
operations for the three months ended September 30, 2002 were slightly lower
than during the same period in 2001. A financial summary for these businesses
follows:
Three Months Ended Nine Months Ended
September 30 September 30
2002 2001 2002 2001
----- ----- ----- -----
In thousands
Revenue. . . $ 326 $ 251 $ 828 $ 761
Expense. . . 218 139 $ 535 395
----- ----- ----- -----
Net Income . $ 108 $ 112 $ 293 $ 366
===== ===== ===== =====
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, 2002 and 2001 are
summarized below:
Three months ended Nine months ended
September 30 September 30
2002 2001 2002 2001
---------- ---------- ---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 51,053 $ 49,009 $ 151,798 $ 146,548
Sales for Resale. . . 21,588 25,579 53,489 68,177
Other . . . . . . . . 836 1,463 2,191 3,594
---------- ---------- ---------- ----------
Total Operating Revenues. $ 73,477 $ 76,051 $ 207,478 $ 218,319
========== ========== ========== ==========
MWh sales-Retail. . . . . 496,964 499,671 1,448,326 1,479,586
MWh sales for Resale. . . 619,057 673,868 1,655,281 1,857,252
---------- ---------- ---------- ----------
Total MWh Sales . . . . . 1,116,021 1,173,539 3,103,607 3,336,838
========== ========== ========== ==========
Average Number of Customers
Three months ended Nine months ended
September 30 September 30
2002 2001 2002 2001
------ ------ ------ ------
Residential . . . . . . . 73,734 73,213 73,740 73,146
Commercial and Industrial 13,206 13,033 13,140 12,988
Other . . . . . . . . . . 67 65 65 65
------ ------ ------ ------
Total Number of Customers. . 87,007 86,311 86,945 86,199
====== ====== ====== ======
REVENUES
Total revenues from operations in the third quarter of 2002 decreased $2.6
million or 3.4 percent compared with the same period in 2001, primarily as a
result of a decrease of $4.0 million in revenues from wholesale sales of
electricity, offset in part by a $2.0 million increase in retail revenues.
While operating revenues result from retail and wholesale sales of electricity,
substantially all of the Company's profits arise from retail sales.
Retail revenues in the third quarter of 2002 were $2.0 million or 4.1 percent
higher compared with the same period in 2001, primarily as a result of the
recognition of $1.2 million of revenues deferred during 2001 under the
Settlement Order.
Total retail MWh sales of electricity in the third quarter of 2002 decreased by
0.5 percent from the same quarter of 2001, reflecting a decrease in sales to
industrial customers of 3.8 percent that was partially offset by increased sales
of 0.3 percent to small commercial and industrial customers and 2.8 percent to
residential customers. Other operating revenue decreased $0.6 million in the
third quarter of 2002 compared with the same period of 2001, primarily due to
$0.4 million in settlement proceeds received in 2001, arising from our partial
ownership of the W.F. Wyman oil-fired generating unit.
The Company's major industrial customer, International Business Machines
("IBM"), accounting for 19.2% of retail sales revenue in 2001, has reduced its
Vermont workforce by 1,500 this year, to a level of approximately 7,000
employees. Company sales of electricity to IBM for the nine months ended
September 30, 2002 declined by approximately four percent compared to sales for
the same period of the prior year, and are primarily responsible for the decline
in Company sales to industrial customers. If future significant losses in
electricity sales to IBM were to occur, the Company's earnings could be impacted
adversely. If earnings were materially reduced as a result of lower retail
sales, the Company would seek a retail rate increase from the VPSB.
Retail revenues for the nine months ended September 30, 2002 were $5.3 million
or 3.6 percent higher when compared with the same period in 2001, reflecting the
recognition of $5.5 million of deferred revenues, partially offset by decreased
retail MWh sales of approximately 2.1 percent due to warmer than normal winter
temperatures and a softening economy in 2002.
The Company currently estimates that its earnings for 2002 will approximate its
allowed rate of return of 11.25% percent, and that in 2002 it will recognize
approximately $7.3 million of revenues deferred under the Settlement Order
during 2001. The Company also expects that in 2003 it will recognize the
remaining $1.2 million of revenues deferred under the Settlement Order.
We sell wholesale electricity to others for resale. Our revenue from wholesale
MWh sales of electricity decreased approximately $4.0 million or 15.6 percent in
the third quarter of 2002 compared with the same period in 2001. The decrease
was due primarily to decreased sales under various arrangements with
Hydro-Quebec. Revenue from wholesale MWh sales for the nine months ended
September 30, 2002 decreased $14.7 million or 21.5 percent when compared with
the same period in 2001 due to decreased sales under arrangements with
Hydro-Quebec and Morgan Stanley Capital Group, Inc. ("MS").
OPERATING EXPENSES
POWER SUPPLY EXPENSES
Power supply expenses decreased 2.9 percent or $1.6 million in the third
quarter of 2002 when compared with the same period in 2001, as a result of a
decrease of $4.0 million of wholesale sales of electricity and reduced costs
under a 1997 arrangement with Hydro-Quebec (the "9701 arrangement", or "9701"),
offset in part by a $1.4 million increase in the cost of power under our
contract with MS and an approximate $2.3 million net increase in the costs of
power that we purchase from VY.
Power supply expenses at Vermont Yankee increased 40.1 percent or $3.1 million
during the third quarter of 2002 compared with the third quarter of 2001,
primarily due to an increase in energy costs under the Power Purchase Agreement
between VY and Entergy (the "PPA"), offset in part by an increase of
approximately 20,000 MWh in the Company's entitlement to power generated at the
Entergy nuclear plant in the third quarter of 2002. The Company estimates that
its net increase in total power supply costs arising from VY's sale of its
nuclear plant to Entergy to be approximately $2.3 million, after accounting for
the value of the Company's added entitlement to VY power in the third quarter of
2002, when compared with the same period in 2001. The sale of the VY generating
plant is discussed under Part I, Item 1, Note 2, "Investment in Associated
Companies".
Company-owned generation expenses increased $0.2 million in the third quarter of
2002 compared with the same period in 2001, primarily due to increased output
and fuel costs at the Stony Brook generating facility in which the Company has a
8.8 percent joint ownership interest.
The cost of power that we purchased from other companies decreased 10.7 percent
or $4.9 million in the third quarter of 2002 compared with the same period in
2001, primarily due to a $4.0 million reduction of wholesale sales of
electricity revenues, and decreased expenses under the 9701 arrangement with
Hydro-Quebec, pursuant to which Hydro-Quebec has the right to purchase
electricity from the Company at rates below current market prices. These
decreases were partially offset by higher power supply costs of $1.4 million
under the MS contract. See the discussion under Part I, Item 1, Note 3
"Commitments and Contingencies-Power Contract Commitments" for more detail
regarding the 9701 arrangement, and Part I, Item 1, Note 5, "Derivative
Instruments and Risk Management" for further information regarding the MS
contract, including the recent renegotiation of the MS contract.
The 9701 arrangement allows Hydro-Quebec to exercise an option to purchase power
from the Company at energy prices based on a 1987 contract, and below current
market prices. During the third quarter of 2002, $0.8 million in power supply
expense was recognized to reflect the costs of option A, which are recognized
ratably over the year. During the third quarter of 2001, $1.6 million in power
supply expense was recognized to reflect the costs of options A and B.
Hydro-Quebec has previously agreed not to call option B during the 2002 contract
year. The cumulative amount of power purchased to date by Hydro-Quebec under
option B is approximately 458,000 MWh out of a total of 600,000 MWh which may be
called over the life of the of the arrangement.
Power supply expenses for the first nine months of 2002 decreased 5.3 percent or
$8.2 million compared with the same period in 2001, primarily due to a reduction
in wholesale sales of electricity and lower retail sales of electricity, offset
in part by increased expense under our contract with MS and increased costs of
power we purchased from VY.
Power supply expense at Vermont Yankee increased $5.5 million or 25.4 percent
for the first nine months of 2002 compared with the same period in 2001,
primarily due to increased energy costs under the PPA between VY and Entergy
during 2002, and due to the deferred maintenance and repair costs associated
with a scheduled refueling outage in 2001. Vermont Yankee scheduled outage
costs were deferred and amortized over an eighteen-month refueling cycle.
Company-owned generation expenses decreased $0.4 million or 11.5 percent in
the first nine months of 2002 compared with the same period in 2001, primarily
due to lower fuel costs and reduced need to run peak generation facilities for
system reliability.
Purchased power expense decreased $13.2 million or 10.2 percent in the
first nine months of 2002 compared with the first nine months of 2001, primarily
due to decreased wholesale electric sales, decreased expenses under the 9701
arrangement with Hydro-Quebec and reductions in retail MWh sales of electricity,
which were in part offset by higher power supply costs under both the MS and
small power producer contracts
Both the 9701 arrangement and any related 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, 2002, the Company had a
regulatory asset of approximately $32.6 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.
The cost of power purchased from MS for 2003 is expected to be approximately
$7.9 million less than the cost of power purchased from MS during 2002, due
primarily to reductions in energy prices under the renegotiated MS contract.
The remainder of our load requirements are substantially provided through our
power supply contracts and arrangements with Hydro-Quebec and our entitlements
to power generated at the Vermont Yankee nuclear plant now owned by Entergy.
OTHER OPERATING EXPENSES
Other operating expenses decreased 13.7 percent or $0.5 million in the
third quarter of 2002 compared with the same period in 2001, as a result of
reductions in consulting costs and decreases in pole treatment costs.
Other operating expenses decreased 10.7 percent or $1.3 million in the
first nine months of 2002 compared with the same period in 2001 primarily due to
reductions in consulting costs in 2002, while 2001 included expenses of hiring
replacement workers during a union strike in January 2001.
TRANSMISSION EXPENSES
Transmission expenses increased by approximately $0.3 million or 8.1% for
the three months ended September 30, 2002, compared with the same period in
2001. The Company's relative share of transmission costs varies with the peak
demand recorded on Vermont's transmission system. The Company's share of those
costs has increased due to its increased load growth, relative to other Vermont
utilities, experienced during the previous twelve months, and also because of
increased transmission investment by VELCO, and increased congestion charges.
Transmission expenses increased by approximately $1.2 million or 10.7 percent
for the nine months ended September 30, 2002, compared with the same period in
2001 for the same reasons mentioned in the three-month comparison. Congestion
charges recorded in the first nine months of 2002 and 2001 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.
On July 31, 2002, FERC issued a Notice of Proposed Rulemaking to amend its
regulations and modify its existing pro forma open access transmission tariff to
require that all public utilities with open access transmission tariffs to
modify these tariffs to reflect non-discriminatory, standardized transmission
service and standard wholesale electric market design ("SMD"). This rulemaking,
known as the "SMD NOPR", proposes to implement standard market design and
locational marginal pricing in all regions of the United States, including New
England. The SMD NOPR is currently in the rulemaking comment period. It is
uncertain whether or how implementation of FERC's SMD NOPR, if and when
approved, may differ from the ISO New England SMD plan, or how implementation of
the SMD NOPR could impact the Company's power supply or transmission costs,
although the impacts could be material.
On August 23, 2002, ISO New England and the New York Independent System
Operator filed a petition with the FERC proposing to establish a single
Northeastern Regional Transmission Organization ("NERTO") encompassing the six
New England states and New York. If approved and established, NERTO would
replace ISO New England as the entity responsible for reliability of the bulk
power system, operation of the region's wholesale markets and provision of
transmission throughout the region. The Company has filed comments opposing the
NERTO petition, which remains pending before FERC. If the NERTO proposal is
approved and implemented, the potential impacts on the Company's power supply
and transmission costs are uncertain, but could be material.
On September 20, 2002, the FERC accepted in part ISO New England's request
to implement a standard market design ("SMD") governing wholesale energy sales
in New England. The ISO currently plans to implement its SMD plan in early
2003. SMD will include a system of locational marginal pricing of energy, under
which prices will be determined by zone, and based in part on transmission
congestion experienced in each zone. Initially, the State of Vermont is
expected to comprise a single zone under the plan, although pricing may
eventually be determined on a more localized basis. The effect of
implementation of this SMD on the Company's power supply or transmission costs
remains uncertain, but could be material.
MAINTENANCE EXPENSES
Maintenance expenses increased 19.7 percent or $0.3 million for the three
months ended September 30, 2002 compared with the same period in 2001, primarily
due to increased repair costs arising from storm damage.
Maintenance expenses increased by approximately $1.1 million or 20.5
percent during the first nine months of 2002 compared with the same period in
2001, primarily due to the costs of repair from a series of minor storms in 2002
and increases in maintenance costs at our wind generation facility located in
Searsburg, Vermont.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses increased $0.1 million or 3.4
percent during the third quarter of 2002 compared with the same period in 2001
primarily due to increases in capital expenditures in 2001.
Depreciation and amortization expenses decreased $0.3 million or 2.4
percent during the first nine months of 2002 compared with the same period in
2001 primarily due to decreased amortization in 2002 of demand side management
assets, partially offset by increased depreciation from capital expenditures in
2001.
TAXES OTHER THAN INCOME TAXES
Other taxes expense for the third quarter and the first nine months of 2002
were essentially unchanged compared with the same respective periods in 2001.
INCOME TAXES
Income taxes decreased $0.4 million in the third quarter of 2002 compared
with the same period in 2001 due to a decrease in pretax book income from core
electric operations.
Income taxes decreased $1.1 million or 18 percent for the first nine months
of 2002 compared with the same period in 2001 for the same reason.
OTHER INCOME
Other income increased $0.1 million during the three months ended September
30, 2002 when compared with the same period in 2001. Our equity in earnings
from VY increased approximately $0.8 million due primarily to tax benefits
arising as a result of the sale of the nuclear power plant to Entergy. This
increase was substantially offset by a payment of $0.5 million made to VY's
non-Vermont sponsors in return for guarantees those sponsors made to Entergy to
finalize the VY sale. Other income for the nine months ended September 30, 2002
was essentially unchanged from the same period in 2001.
INTEREST CHARGES
Interest charges decreased $0.2 million or 9.7 percent in the third quarter
of 2002 compared with the same period in 2001, primarily due to the redemption
of $8.0 million first mortgage bonds in December 2001 and $5.1 million first
mortgage bonds in May 2002, partially offset by increased short-term borrowings
and related interest costs.
Interest charges decreased $0.8 million or 14.8 percent in the first nine
months of 2002 compared with the same period in 2001 for the same reasons.
PREFERRED STOCK DIVIDENDS
Dividends paid on preferred stock decreased $0.2 million for the quarter
ended September 30, 2002 when compared with the same period in 2001, due to
redemptions of preferred stock during 2002 as discussed in this section under
"Liquidity and Capital Resources". Dividends paid on preferred stock decreased
$0.6 million for the nine-month period ended September 30, 2002 compared with
the same period in 2001, for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
In the nine months ended September 30, 2002, we spent $15.3 million
principally for expansion and improvements of our transmission, distribution and
generation plant, and environmental expenditures. We expect to spend
approximately $4.4 million during the remainder of 2002.
The Company renegotiated a 364-day revolving credit agreement with Fleet
Financial Services ("Fleet") joined by KeyBank National Association, ("KeyBank")
with the renegotiated agreement expiring June 18, 2003 (the "Fleet-Key
Agreement"). The Fleet-Key Agreement is for $35.0 million, unsecured, and
allows the Company to choose any blend of a daily variable prime rate and a
fixed term LIBOR-based rate. There was $11.0 million outstanding with a
weighted average rate of 4.0 percent on the Fleet-Key Agreement at September 30,
2002. There was no non-utility short-term debt outstanding at September 30,
2002.
On July 27, 2001, the VPSB approved a $12.0 million two-year unsecured loan
agreement, with Fleet, joined by KeyBank, and the loan was made to the Company
on August 24, 2001. At September 30, 2002, there was $12.0 million outstanding
under the two-year loan agreement.
In its January, 2001 Order approving a 3.49% rate increase for the Company,
the VPSB ordered that the Company freeze its common stock dividend rate until it
had successfully replaced short-term and intermediate-term credit facilities
with long-term debt or equity financing. In August 2002, the Company petitioned
the VPSB for consent to issue long-term debt, with the proceeds to be used, in
part, to repay existing short and intermediate-term indebtedness. On October
10, 2002, the VPSB issued an order approving the Company's petition. Pursuant
to this order, upon issuance of new long-term debt and repayment of existing
borrowings under the Fleet-Key Agreement and the $12.0 million two-year
unsecured term loan, the dividend freeze order will terminate, allowing the
Company's Board of Directors to consider an increase in the Company's common
stock dividend rate. The Company expects the Board of Directors to consider
whether changes in the dividend level are appropriate at its December 2002
meeting.
On October 18, 2002, the Company commenced a "Dutch Auction" self-tender
offer to repurchase up to 800,000, or approximately 14%, of its common shares
outstanding. The Company has also reserved the right to purchase additional
shares totaling up to 2% of the outstanding shares. Shareholders may offer to
sell all or a portion of the shares they own within a price range of $17.00 to
$21.00. Upon completion of the tender offer, the Company will select the lowest
purchase price that will allow it to purchase 800,000 shares, or such lesser
number of shares actually tendered, if the total number tendered is less than
800,000 shares.
The Company is making the offer because the Board of Directors believes
that the equity component of its capital structure exceeds its needs given the
present outlook of the Company. The Company has adopted an average capital
structure target of approximately fifty percent debt and fifty percent equity,
and completion of the offer will help the Company achieve that target over time.
On March 15, 2002, the Company paid $5.3 million to redeem 10.0% first
mortgage bonds due 2004. During March and June 2002, the Company paid $11.0 and
$1.0 million, respectively, to redeem the 7.32 percent Class E preferred stock
outstanding. On May 1, 2002, the Company paid $0.3 million to redeem the 7.0
percent Class C preferred stock outstanding.
The credit ratings of the Company's securities at September 30, 2002 were:
Fitch Moody's Standard & Poor's
- -------------------- ------- -----------------
First mortgage bonds BBB+ Baa1 BBB
Preferred stock. . . BBB Ba1 BB
On August 29, 2002, Moody's upgraded the Company's senior secured debt rating to
Baa1 from Baa2. The outlook for the ratings is stable. On September 29, 2002
Fitch Ratings upgraded the ratings of the Company's first mortgage bonds to BBB+
from BBB, with a stable outlook. On September 23, 2002, Standard and Poor's
Ratings Services affirmed its BBB rating of the Company's senior secured debt,
with a stable outlook.
The following table presents payments contractually due by category:
In thousands
Contractual Obligations Less
at September 30, 2002 than 1 1-3 4-5 After
Total year years years 5 years
------------------------------------ ---------- -------- -------- --------
Long-term Debt . . . . . . . . . . . $ 79,000 $ 20,000 $ 8,000 $ 14,000 $ 37,000
Revolving Credit . . . . . . . . . . 11,000 11,000 -
Interest on Long Term Debt . . . . . 61,672 5,457 9,020 7,994 39,201
Capital Lease. . . . . . . . . . . . 5,640 107 852 852 3,829
Preferred Stock. . . . . . . . . . . 235 150 60 25
Hydro-Quebec power supply contracts. 667,106 47,405 100,396 63,834 455,471
MS power supply contract . . . . . . 200,042 57,847 87,347 54,849 -
Vermont Yankee power supply contract 333,966 37,058 72,750 57,655 166,504
Total Contractual Cash Obligations . $1,358,661 $179,023 $278,424 $199,209 $702,005
========== ======== ======== ======== ========
Certain amounts included in contractual obligations for Hydro-Quebec and Vermont
Yankee power supply contracts include estimates of future power supply costs
that could change by a material amount.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FUTURE OUTLOOK-COMPETITION AND RESTRUCTURING-The electric utility business
continues to experience rapid and substantial changes. These changes are the
result of the following trends:
disparity in electric rates, transmission, and generating capacity among
and within various regions of the country;
improvements in generation efficiency;
increasing demand for customer choice;
consolidation through business combinations;
new regulations and legislation intended to foster competition, also known
as restructuring; and
increasing volatility of wholesale market prices for electricity.
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. Recent power supply difficulties in some regulatory jurisdictions,
such as California, and proposed changes in regional and national wholesale
markets appear to have dampened any immediate push towards de-regulation in
Vermont.
During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase an existing hydro-generation facility from a third party, and the
associated distribution plant owned by the Company within Rockingham. In March
2002, voters in Rockingham authorized Rockingham to create a municipal utility
by acquiring a municipal plant, which would include the Bellows Falls
hydroelectric facility and the electric distribution systems of the Company
and/or Central Vermont Public Service Corporation. The Company receives annual
revenues of approximately $4.0 million from its customers in Rockingham. Should
Rockingham create a municipal system, the Company would vigorously pursue its
right to receive just compensation from Rockingham. Such compensation would
include full reimbursement for Company assets, if acquired, and full
reimbursement of any other costs associated with the loss of customers in
Rockingham, to assure that our remaining customers do not subsidize a Rockingham
municipal utility.
In a series of Vermont regulatory proceedings, the Company has agreed to
undertake a process known as "distributed utility planning" as part of its
transmission and distribution planning process. Distributed utility planning
requires the Company to evaluate conservation-related alternatives and
distributed generation alternatives to typical transmission and distribution
capital investments. In certain circumstances, the Company may be required to
implement conservation or distributed generation alternatives in lieu of, or in
addition to, traditional transmission and distribution capital investments,
where societal cost savings associated with conservation or distributed
generation, including the costs associated with avoided electricity sales,
justify the expenditures. The Company is uncertain of the potential magnitude
of future spending requirements for this program, but note they could be
material. Costs associated with conservation measures or distributed generation
facilities not owned by the Company would be deferred as regulatory assets
pending future rate proceedings.
PENSION
Due to sharp declines in the equity markets during 2001 and 2002, the value
of assets held in trusts to satisfy the Company's pension plan obligations has
decreased. The Company's pension plan assets are primarily made up of public
equity and fixed income investments. Fluctuations in actual equity market
returns as well as changes in general interest rates may result in increased or
decreased pension costs in future periods.
The Company's funding policy is to make voluntary contributions to its
defined benefit plans before ERISA or Pension Benefit Guaranty Corporation
requirements mandate such contributions under minimum funding rules, and so long
as the Company's liquidity needs do not preclude such investments. The Company
plans to make voluntary pension plan contributions totaling $2 million between
September 1, 2002 and June 30, 2003, of which $500,000 has been contributed to
date. The Company's pension costs and cash funding requirements could increase
in future years in the absence of recovery in the equity markets.
As a result of GMP's retirement plan asset return experience, at December
31, 2002, the Company could be required to recognize an additional minimum
liability as prescribed by generally accepted accounting principles. The
liability would be recorded as a reduction to common equity through a charge to
other comprehensive income and would not affect net income for 2002.
NEW ACCOUNTING STANDARDS
See Part I-Item 1, Note 6, "New Accounting Standards" for more information
on the adoption of new accounting standards and the impact, or lack thereof, on
the Company's financial position and operating results.
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 both 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
A sensitivity analysis has been prepared to estimate the exposure to the market
price risk of our electricity commodity positions. Assumptions used in the
Blacks-Scholes model include a risk free rate of 5.02 percent, locked in forward
commitment prices for 2002 and 2003, a forward market price averaging
approximately $60 per MWh for periods beyond 2003 with an average of
approximately 60,000 MWh per year. Under an accounting order issued by the
VPSB, changes in the fair value of derivatives are not recognized in earnings
until the derivative positions are settled. 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 the
table.
Commodity Price Risk At September 30, 2002
Fair Value Market Risk
--------------- ------------
(in thousands)
Net short position $ 32,615 $ 3,000
ITEM 4. CONTROLS AND PROCEDURES
Within the 90 days prior to the filing date of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Company's Chief Executive Officer and
its Treasurer and Controller (principal financial officer), of the effectiveness
of the design and operation of the Company's disclosure controls and procedures
pursuant to Rule 13a-14 under the Securities Exchange Act of 1934. Based upon
that evaluation, the Company's Chief Executive Officer and its Treasurer and
Controller concluded that the Company's disclosure controls and procedures are
effective in timely alerting them to material information relating to the
Company (including its consolidated subsidiaries) required to be included in the
Company's periodic SEC filings.
Since the date of the evaluation, there have been no significant changes in
the Company's internal controls or in other factors that could significantly
affect these controls.
------
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SEPTEMBER 30,2002
-----------------
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
The Company's Chief Executive Officer and the Company's Treasurer and
Controller (principal financial officer) have furnished to the SEC the
certification with respect to this Form 10-Q that is required by Section 906 of
the Sarbanes-Oxley Act of 2002.
ITEM 6.
(A) EXHIBITS
----------
NONE
(B) REPORTS ON FORM 8-K
---------------
The following filings on Form 8-K were filed by the Company on the topics
and dates indicated:
August 14, 2002 Form 8-K announced the certification of financial statements
filed with the SEC by the Chief Executive Officer and President, and the
Treasurer and Controller (principal financial officer).
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 13, 2002 /s/Christopher L. Dutton
--------------------------
Christopher L. Dutton, Chief Executive Officer
and President
Date: November 13, 2002 /s/Robert J. Griffin
----------------------
Robert J. Griffin, (as Principal Financial
Officer)
Treasurer and Controller
I, Christopher L. Dutton, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Green Mountain Power
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or person performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifiying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses
Date: November 13, 2002
/s/Christopher L. Dutton
- --------------------------
Christopher L. Dutton, Chief Executive Officer and President
I, Robert J. Griffin, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Green Mountain Power
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or person performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses
Date:November 13, 2002
/s/Robert J. Griffin
Robert J. Griffin, Treasurer and Controller (Principal Financial Officer)