SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________________
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
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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 JULY 31, 2003
- --------------------------- ---------------------------------
$3.33 1/3 PAR VALUE 4,976,557
This report contains statements that may be considered forward-looking
statements within the meaning of Section 27A of the Securities Act and Section
21E of the Securities Exchange Act of 1934. You can identify these statements by
forward-looking words such as "may," "could", "should," "would," "intend,"
"will," "expect," "anticipate," "believe," "estimate," "continue" or similar
words. We intend these forward-looking statements to be covered by the safe
harbor provisions for forward-looking statements contained in the Private
Securities Reform Act of 1995 and are including this statement for purposes of
complying with these safe harbor provisions. You should read statements that
contain these words carefully because they discuss the Company's future
expectations, contain projections of the relevant company's future results of
operations or financial condition, or state other "forward-looking" information.
There may be events in the future that we are not able to predict
accurately or control and that may cause actual results to differ materially
from the expectations described in forward-looking statements. Investors are
cautioned that all forward-looking statements involve risks and uncertainties,
and actual results may differ materially from those discussed in this document,
including the documents incorporated by reference in this document. These
differences may be the result of various factors, including changes in general,
national, regional, or local economic conditions, changes in fuel or wholesale
power supply costs, regulatory or legislative action or decisions, and other
risk factors identified from time to time in our periodic filings with the
Securities and Exchange Commission.
The factors referred to above include many, but not all, of the factors
that could impact the Company's ability to achieve the results described in any
forward-looking statements. You should not place undue reliance on
forward-looking statements. You should be aware that the occurrence of the
events described above and elsewhere in this document, including the documents
incorporated by reference, could harm the Company's business, prospects,
operating results or financial condition. We do not undertake any obligation to
update any forward-looking statements as a result of future events or
developments.
AVAILABLE INFORMATION
Our Internet website address is: www.Greenmountainpower.biz. We make
available free of charge through the website our annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended, as soon as reasonably practicable
after such documents are electronically filed with, or furnished to, the SEC.
The information on our website is not, and shall not be deemed to be, a part of
this report or incorporated into any other filings we make with the SEC.
PART I FINANCIAL INFORMATION
GREEN MOUNTAIN POWER CORPORATION
INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
AT AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30,
2003 AND 2002
ITEM 1. FINANCIAL STATEMENTS PAGE
Consolidated Statements of Income and Comprehensive Income 4
Consolidated Statements of Cash Flows 5
Consolidated Balance Sheets 6
Consolidated Statements of Retained Earnings 8
Notes to Consolidated Financial Statements 8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS 19
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 27
ITEM 4. CONTROLS AND PROCEDURES 30
PART II. OTHER INFORMATION 31
Exhibits and Reports on Form 8-K 31
Signatures 32
Certifications 33
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
UNAUDITED
---------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
2003 2002 2003 2002
-------- -------- --------- ---------
(in thousands, except per share data)
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $64,455 $65,135 $137,400 $134,001
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 9,747 8,191 19,285 16,265
Company-owned generation. . . . . . . . . . . . . . . . . . 1,112 617 4,484 1,578
Purchases from others . . . . . . . . . . . . . . . . . . . 36,101 37,588 72,377 75,734
Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,787 3,547 8,187 7,054
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,490 4,002 7,547 7,972
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 1,912 2,059 4,028 4,274
Depreciation and amortization. . . . . . . . . . . . . . . . 3,403 3,408 6,951 6,939
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,940 1,934 3,959 3,905
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 538 975 2,926 3,025
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 62,030 62,321 129,744 126,746
-------- -------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 2,425 2,814 7,656 7,255
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 414 535 826 1,069
Allowance for equity funds used during construction. . . . . 90 49 176 122
Other income (deductions), net . . . . . . . . . . . . . . . (23) 15 113 (53)
-------- -------- --------- ---------
TOTAL OTHER INCOME. . . . . . . . . . . . . . . . . . . . 481 599 1,115 1,138
-------- -------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 2,906 3,413 8,771 8,393
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,755 1,254 3,516 2,613
Other interest . . . . . . . . . . . . . . . . . . . . . . . 90 295 166 508
Allowance for borrowed funds used during construction. . . . (60) (22) (118) (54)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,785 1,527 3,564 3,067
-------- -------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 1,121 1,886 5,207 5,326
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . 1 11 2 95
-------- -------- --------- ---------
Income from continuing operations. . . . . . . . . . . . . . 1,120 1,875 5,205 5,231
Income (loss) from discontinued segment,
including provisions for operating
losses during phaseout period. . . . . . . . . . . . . . . . (8) - (21) -
-------- -------- --------- ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 1,112 $ 1,875 $ 5,184 $ 5,231
======== ======== ========= =========
UNAUDITED
---------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
2003 2002 2003 2002
------ ------ ------ ------
Net income. . . . . . . . . . . . . . . . . . . . . $1,112 $1,875 $5,184 $5,231
Comprehensive income. . . . . . . . . . . . . . . . - - - -
------ ------ ------ ------
Other comprehensive income, net of tax. . . . . . $1,112 $1,875 $5,184 $5,231
====== ====== ====== ======
Basic earnings per share . . . . . . . . . . . . . $ 0.22 $ 0.33 $ 1.04 $ 0.92
Diluted earnings per share . . . . . . . . . . . . 0.22 0.32 1.01 0.89
Cash dividends declared per share. . . . . . . . . $ 0.19 $ 0.14 $ 0.38 $ 0.28
Weighted average common shares outstanding-basic . 4,969 5,711 4,964 5,701
Weighted average common shares outstanding-diluted 5,129 5,877 5,125 5,866
The accompanying notes are an integral part of these consolidated financial
statements.
Unaudited
---------
GREEN MOUNTAIN POWER CORPORATION For the Six Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS June 30
2003 2002
--------------- ---------
OPERATING ACTIVITIES: (in thousands)
Net income before preferred dividends . . . . . . . . . . . . . . $ 5,186 $ 5,326
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . . . . . 6,951 6,939
Dividends from associated companies less equity income. . . . . . (100) 97
Allowance for funds used during construction. . . . . . . . . . . (293) (176)
Amortization of deferred purchased power costs. . . . . . . . . . 2,316 3,611
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . 1,049 988
Deferred purchased power costs. . . . . . . . . . . . . . . . . . (86) (2,075)
Rate levelization liability . . . . . . . . . . . . . . . . . . . 238 (4,309)
Conservation deferrals, net . . . . . . . . . . . . . . . . . . . (207) (176)
Changes in:
Accounts receivable and accrued utility revenues. . . . . . . . . 1,886 2,058
Prepayments, fuel and other current assets. . . . . . . . . . . . (32) 1,843
Accounts payable and other current liabilities. . . . . . . . . . (3,406) (3,043)
Accrued income taxes payable and receivable . . . . . . . . . . . 481 1,359
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 325 152
--------------- ---------
Net cash provided by operating activities . . . . . . . . . . . . 14,308 12,594
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . . . . . (7,718) (8,638)
Environmental expenditures, net . . . . . . . . . . . . . . . . . (2,113) (624)
Invesment in Associated Companies . . . . . . . . . . . . . . . . (108) -
Investment in nonutility property . . . . . . . . . . . . . . . . (73) (100)
--------------- ---------
Net cash used in investing activities . . . . . . . . . . . . . . (10,012) (9,362)
--------------- ---------
FINANCING ACTIVITIES:
Payments to acquire treasury stock. . . . . . . . . . . . . . . . (3) -
Repurchase of preferred stock . . . . . . . . . . . . . . . . . . - (12,325)
Issuance of common stock. . . . . . . . . . . . . . . . . . . . . 192 472
Reduction in long-term debt . . . . . . . . . . . . . . . . . . . - (5,100)
Short-term debt, net. . . . . . . . . . . . . . . . . . . . . . . (2,500) 10,400
Cash dividends. . . . . . . . . . . . . . . . . . . . . . . . . . (1,888) (1,664)
--------------- ---------
Net cash used in financing activities . . . . . . . . . . . . . . (4,199) (8,217)
--------------- ---------
Net increase (decrease) in cash and cash equivalents. . . . . . . 98 (4,985)
Cash and cash equivalents at beginning of period. . . . . . . . . 1,909 5,006
--------------- ---------
Cash and cash equivalents at end of period. . . . . . . . . . . . $ 2,007 $ 21
=============== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for: Interest (net of amounts capitalized) $ 3,542 $ 3,053
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,758 2,349
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
A capital lease obligation of $181 was incurred when the Company entered into a
lease for new office furniture during February 2003.
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
JUNE 30 DECEMBER 31
2003 2002 2002
--------------- -------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost $ 314,275 $306,127 $311,543
Less accumulated depreciation 128,397 122,950 122,197
--------------- -------- --------
Net utility plant 185,878 183,177 189,346
Property under capital lease 5,522 5,959 5,287
Construction work in progress 13,980 10,530 8,896
--------------- -------- --------
Total utility plant, net 205,380 199,666 203,529
--------------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity 14,329 14,019 14,101
Other investments 7,369 7,108 7,451
--------------- -------- --------
Total other investments 21,698 21,127 21,552
--------------- -------- --------
CURRENT ASSETS
Cash and cash equivalents 2,007 21 1,909
Accounts receivable, less allowance for
doubtful accounts of $547, $613 and $547 15,946 15,902 17,253
Accrued utility revenues 6,038 5,015 6,618
Fuel, materials and supplies, at average cost 4,188 3,885 3,349
Prepayments 1,140 413 1,901
Other 356 363 402
--------------- -------- --------
Total current assets 29,675 25,599 31,432
--------------- -------- --------
DEFERRED CHARGES
Demand side management programs 6,471 6,687 6,434
Purchased power costs 114 1,995 2,323
Pine Street Barge Canal 13,019 12,425 13,019
Power supply derivative deferral 21,160 33,694 18,405
Other 10,546 14,612 11,413
--------------- -------- --------
Total deferred charges 51,310 69,413 51,594
--------------- -------- --------
NON-UTILITY
Other current assets 8 8 8
Property and equipment 249 250 249
Other assets 663 775 738
--------------- -------- --------
Total non-utility assets 920 1,033 995
--------------- -------- --------
TOTAL ASSETS $ 308,983 $316,838 $309,102
=============== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
JUNE 30 DECEMBER 31
2003 2002 2002
--------- --------- ---------
(in thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,803,596 ,5,716,975 and 5,782,496) . . . . . . . . $ 19,345 $ 19,110 $ 19,276
Additional paid-in capital. . . . . . . . . . . . . 75,469 74,948 75,347
Retained earnings . . . . . . . . . . . . . . . . . 19,469 11,683 16,171
Accumulated other comprehensive income. . . . . . . (2,374) - (2,374)
Treasury stock, at cost (827,639 and 15,856 shares) (16,701) (378) (16,698)
--------- --------- ---------
Total common stock equity . . . . . . . . . . . . . 95,208 105,363 91,722
Redeemable cumulative preferred stock . . . . . . . 55 85 55
Long-term debt, less current maturities . . . . . . 93,000 71,000 93,000
--------- --------- ---------
Total capitalization. . . . . . . . . . . . . . . . 188,263 176,448 184,777
--------- --------- ---------
CAPITAL LEASE OBLIGATION. . . . . . . . . . . . . . 5,496 5,959 5,287
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock . . . . . . . 30 150 30
Current maturities of long-term debt. . . . . . . . 8,000 8,000 8,000
Short-term debt . . . . . . . . . . . . . . . . . . - 10,400 2,500
Accounts payable, trade and accrued liabilities . . 4,358 6,410 7,431
Accounts payable to associated companies. . . . . . 8,535 6,825 8,940
Rate levelization liability . . . . . . . . . . . . 4,329 4,218 4,091
Accrued income taxes. . . . . . . . . . . . . . . . 5,065 933 4,583
Customer deposits . . . . . . . . . . . . . . . . . 840 838 898
Interest accrued. . . . . . . . . . . . . . . . . . 1,182 1,145 1,081
Other . . . . . . . . . . . . . . . . . . . . . . . 965 1,081 937
--------- --------- ---------
Total current liabilities . . . . . . . . . . . . . 33,304 40,000 38,491
--------- --------- ---------
DEFERRED CREDITS
Power supply derivative liability . . . . . . . . . 21,160 33,694 18,405
Accumulated deferred income taxes . . . . . . . . . 27,662 24,888 26,471
Unamortized investment tax credits. . . . . . . . . 2,989 3,272 3,130
Pine Street Barge Canal cleanup liability . . . . . 6,720 9,436 8,833
Other . . . . . . . . . . . . . . . . . . . . . . . 21,562 20,787 21,767
--------- --------- ---------
Total deferred credits. . . . . . . . . . . . . . . 80,093 92,077 78,606
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Net liabilities of discontinued segment . . . . . . 1,827 2,354 1,941
--------- --------- ---------
Total non-utility liabilities . . . . . . . . . . . 1,827 2,354 1,941
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . $308,983 $316,838 $309,102
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS THREE MONTHS ENDED SIX MONTHS ENDED
In thousands JUNE 30 JUNE 30
2003 2002 2003 2002
-------- -------- -------- --------
Balance - beginning of period. . . . . . . . . . . . $19,300 $10,644 $16,171 $ 8,070
Net Income . . . . . . . . . . . . . . . . . . . . . 1,113 1,886 5,186 5,326
Other (50) (50)
Cash Dividends-redeemable cumulative preferred stock (1) (11) (2) (95)
Cash Dividends-common stock. . . . . . . . . . . . . (943) (786) (1,886) (1,568)
-------- -------- -------- --------
Balance - end of period. . . . . . . . . . . . . . . $19,469 $11,683 $19,469 $11,683
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2003
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 2002 filed on Form 10-K, are adequate to
make the information presented not misleading.
Management believes the most critical accounting policies include the
timing of expense and revenue recognition under the regulatory accounting
framework within which we operate, the manner in which we account for certain
power supply arrangements that qualify as derivatives, and the defined benefit
plan assumptions used to determine plan liabilities for our defined benefit
retirement plans. These accounting policies, among others, affect the Company's
more significant judgments and estimates used in the preparation of its
consolidated financial statements.
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, of which $4.4 million was recognized during 2002. The
remaining $4.1 million will be used to offset increased costs or write off
regulatory assets during 2003 or 2004.
The Company operates under a rate cap which requires the deferral of
revenue in periods where the Company earns more than its allowed rate of return.
Conversely, previously deferred revenue is recognized in periods when the
Company is not achieving its allowed return. During the three months ended June
2002, approximately $2.1 million of previously deferred revenue was recognized
in order for the Company to achieve its allowed rate of return. Due to an
improvement in operating results for the quarter ended June 30, 2003, compared
with the same period in 2002, the Company deferred approximately $271,000 of
revenue based on the expectation that it will exceed its return on equity. For
the six months ended June 30, 2003 the Company did not recognize nor defer any
revenues, compared with $4.3 million of previously deferred revenue recognized
during the six months ended June 30, 2002.
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.
The Company applies Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" and related interpretations in accounting for its
stock option plan and has adopted the disclosure-only provisions of SFAS 123,
"Accounting for Stock-Based Compensation" as amended by SFAS 148, "Accounting
for Stock-Based Compensation - Transition and Disclosure - and amendment of SFAS
123". The following table illustrates the effect on net income and earnings per
share as if the fair value method had been applied to all outstanding and
unvested awards in each period. The fair value of options at date of grant was
estimated using the Black-Scholes option-pricing model. Had the Company
expensed stock-based compensation under SFAS 123, the Company's diluted earnings
would have been reduced by $0.01 and $0.01 per share for the three and six
months ended June 30, 2003, respectively.
Three months ended Six months ended
Pro-forma net income June 30 June 30
2003 2002 2003 2002
------ ------ ------ ------
In thousands, except per share amounts
Net income reported. . . . . . . . . . $1,112 $1,875 $5,184 $5,231
Pro-forma net income . . . . . . . . . 1,072 1,830 5,103 5,140
Net income per share
As reported-basic. . . . . . . . . . 0.22 0.33 1.04 0.92
Pro-forma basic. . . . . . . . . . . 0.22 0.32 1.03 0.90
As reported-diluted. . . . . . . . . 0.22 0.32 1.01 0.89
Pro-forma diluted. . . . . . . . . . 0.21 0.31 1.00 0.88
UNREGULATED OPERATIONS
Our wholly owned subsidiaries are Northern Water Resources, Inc. ("NWR");
Green Mountain Propane Gas Company Limited ("GMPG"); GMP Real Estate
Corporation; Green Mountain Power Investment Company ("GMPIC") and Green
Mountain Resources, Inc. ("GMRI"). We also have a rental water heater program
that is not regulated by the VPSB. The results of these subsidiaries, excluding
NWR, and the Company's unregulated rental water heater program are included in
earnings of affiliates and non-utility operations in the Other (Deductions)
Income section of the Consolidated Statements of Income.
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 Six months ended
June 30 June 30
2003 2002 2003 2002
------- ------- ------- -------
(in thousands)
Gross Revenue. . . . . $49,014 $46,764 $96,982 $85,495
Net Income Applicable. 722 1,462 $ 1,407 2,949
to Common Stock
Equity in Net Income . 140 258 267 571
On July 31, 2002, Vermont Yankee completed the sale of its nuclear power plant
to Entergy Nuclear Vermont Yankee ("Entergy"). In addition to the sale of the
generating plant, the transaction calls for Entergy, through its power contract
with VY, 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 owns approximately 19 percent of the common stock of VY. The
benefits to the Company from the plant sale and the VY power contract with
Entergy include:
VY received cash approximately equal to the book value of the plant assets,
removing the potential for stranded costs associated with the plant.
VY and its owners no longer bear operating risks associated with running
the plant.
VY and its owners no longer bear the risks associated with the eventual
decommissioning of the plant.
Prices under the Power Purchase Agreement between VY and 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 VY. Contract prices ranged from $49 to $55 for 2002, higher than
the forecasted cost of continued ownership for 2002.
The PPA 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.
The Company remains responsible for procuring replacement energy at market
prices during periods of scheduled or unscheduled outages at the Entergy plant.
The Company expects its share of the Vermont Yankee sale proceeds, currently
estimated at between $7.0 and $8.0 million, to be distributed in the latter part
of 2003.
The sale required various regulatory approvals, all of which were granted
on terms acceptable to the parties to the transaction. Certain intervener
parties to the VPSB approval proceeding appealed the VPSB approval to the
Vermont Supreme Court. The Vermont Supreme Court affirmed the VPSB approval in
July 2003.
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 Six months ended
June 30 June 30
2003 2002 2003 2002
------ ------ ------- -------
(in thousands)
Gross Revenue . . . . $5,635 $5,312 $11,270 $11,796
Net Income. . . . . . 349 318 622 513
Equity in Net Income. 91 92 197 169
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 comply 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 June 30, 2003, our total expenditures related to the Pine Street site
since 1982 were approximately $29.5 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 $13.0 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".
On July 13, 2003, the Company and the Department entered into a Memorandum
of Understanding relating primarily to the Company's rates and allowed rate of
return through 2006. This Memorandum of Understanding provides for recovery of
Pine Street costs over a twenty-year period without a return. This Memorandum
of Understanding has not yet been approved by the VPSB. See the discussion
under Retail Rate Case below for further details.
RETAIL RATE CASE
On January 23, 2001, the VPSB approved a final settlement of the Company's
1998 rate case. The VPSB Order approving the settlement 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 replaced 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 was available to be used 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 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, adjusted for inflation; and
The Company's further investment in non-utility operations is restricted.
The Company earned approximately $4.4 million less than its allowed rate of
return during 2002 before including in earnings deferred revenues in the same
amount.
On October 10, 2002, the VPSB issued an order approving the Company's
request 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. The Company used proceeds of a $42 million
long-term debt issue in December 2002 to repurchase equity and to replace all
short-term borrowings, satisfying the conditions in the VPSB final settlement
order and permitting the Company to raise its dividend.
The VPSB, in its order approving VY's sale of its nuclear power plant to
Entergy, ordered the Company and Central Vermont Public Service each to file on
or before April 15, 2003, a cost-of-service study based on actual 2002 data, to
enable the VPSB to determine whether an adjustment to rates is justified in 2003
or 2004. The Company filed its study on April 15, 2003.
On July 11, 2003, after the Department completed its review of the
Company's cost-of-service filing, the Company and the Department entered into a
Memorandum of Understanding (the "Memorandum") regarding the Company's rates and
allowed return on equity through the end of 2006. The Memorandum is subject to
approval by the VPSB, and provides, among other things, the following:
Rate Stability: The Company's rates will remain unchanged until January 1,
2005, when they will increase by 1.9 percent, and an additional rate increase of
0.9 percent will be effective January 1, 2006, subject to the requirement that
the Company file a cost of service filing with the Department and the VPSB 60
days prior to each rate increase that supports such increase. In addition, the
Memorandum permits the Company to carry forward into 2004 any unused deferred
revenue originally allowed in the Company's January 2001 rate order.
Earnings Cap: The Memorandum provides that the Company will reduce its
current 11.25 percent allowed return on equity to 10.50 percent for 2003, 2004,
2005 and 2006. The Memorandum further provides that the Company may carry
forward any remaining deferred revenue at December 31, 2003, through 2004 to
offset increased costs or reduce regulatory assets. If the Company earns in
excess of its earning cap, then any 2003 or 2004 excess earnings shall be
applied to reduce regulatory assets. Excess earnings in 2005 or 2006 shall be
refunded to customers as a credit on customer bills or applied to reduce
regulatory assets as the Department directs.
Redesign of Rates: Within 60 days of the Board's approval of the
Memorandum, the Company shall file with the Board a fully allocated cost of
service study and rate redesign, which will allocate the Company's revenue
requirement among all customer classes on the basis of current costs. Such a
rate redesign will be subject to VPSB approval.
Alternative Regulation Plan: The Company and the Department have agreed to
work cooperatively to develop and propose an alternative regulation plan as
authorized by legislation enacted by the Vermont legislature in 2003, within 120
days after Board approval of the Memorandum. If the Company and the Department
agree on such a plan, and it is approved by the VPSB, the plan would supersede
the terms of the Memorandum.
Amortization of Regulatory Assets: Under the Memorandum, amortization
(recovery) of certain regulatory assets, including Pine Street Barge Canal
environmental site costs, and past demand side management program costs will
begin January 2005 and will be allowed in future rates. Pine Street costs will
be recovered over a twenty-year period without a return.
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 six months of 2003, $2.5 million in power supply expense
was recognized to reflect the cost of option A and B, compared with $1.5 million
during the first half of 2002 for option A only. Hydro-Quebec had previously
agreed not to call option B during the contract year ended October 31, 2002. At
June 30, 2003, the cumulative amount of power purchased by Hydro-Quebec under
option B is approximately 458,000 MWh.
Hydro-Quebec's option to curtail annual 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 annual load factor from 75 percent to 65 percent under the 1987
Contract a total of three times over the life of the contract. Pursuant to the
1987 Contract, Hydro-Quebec reduced its load factor to 65 percent in 2003 and
has notified the Company of its intention to reduce the load factor to 65
percent in 2004. 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.
4. SEGMENTS AND RELATED INFORMATION
The Company's electric utility operation is its only operating segment.
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, GMPIC 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 June 30, 2003, 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 a wind farm and wastewater treatment projects.
5. DERIVATIVE INSTRUMENTS AND RISK MANAGEMENT
The Company records the annual cost of power obtained under long-term
contracts as operating expenses. The Company meets the majority of its customer
demand through a series of long-term physical and financial contracts. There
are occasions when we may experience a short position for electricity needed to
supply customers. During those periods, electricity is purchased at market
prices.
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 contracts with
counter-parties that have at least investment grade ratings. These transactions
are used to mitigate the risk of fossil fuel and spot market electricity price
increases. The Company's risk management policy specifies risk measures and
authorization limits for transactions. Derivative financial instruments held by
the Company are used as hedges or for cost control and not for trading.
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. At June
30, 2003, the Company had a liability reflecting the net negative fair value of
the two derivatives described below, as well as a corresponding regulatory asset
of approximately $21.2 million. The Company believes that the regulatory asset,
determined using the Black's or Black-Scholes option valuation method, is
probable of recovery in future rates. The regulatory liability 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.
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 is effective through December 31, 2006.
Management's estimate of the fair value of the future net benefit of this
contract at June 30, 2003 is approximately $6.6 million.
As described under "Power Contract Commitments", the 9701 arrangement
grants Hydro-Quebec 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 June 30, 2003 is approximately $27.7 million.
We use futures contracts to hedge the 9701 call option.
6. NEW ACCOUNTING STANDARDS
In August 2001, the FASB issued Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), effective
for fiscal years beginning after June 15, 2002, which provides guidance on
accounting for nuclear plant decommissioning and other asset retirement costs.
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 no legal retirement
obligations associated with asset retirement obligations. Other removal costs
related to utility plant, estimated at approximately $20.4 million, are included
in accumulated depreciation. The Company adopted SFAS No. 143 on January 1,
2003 as required. There was no cumulative effect of adopting SFAS No. 143.
In June 2002, the FASB issued Statement of Financial Accounting Standards
No. 146, "Accounting for Costs Associated with Exit or Disposal Activities"
("SFAS 146"). SFAS 146 specifies accounting and reporting for costs associated
with exit or disposal activities. The application of this accounting standard,
which is effective for the three months ended June 30, 2003, did not materially
impact the Company's financial position or results of operations.
In December 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-based Compensation-Transition and
Disclosure" ("SFAS 148"). SFAS 148 amends Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation", to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting and reporting for stock-based employee compensation. The
application of this accounting standard is not expected to materially impact the
Company's financial position or results of operations.
In January 2003, the Financial Accounting Standards Board issued
Interpretation 46, Consolidation of Variable Interest Entities. This standard
will require an enterprise that is the primary beneficiary of a variable
interest entity to consolidate that entity. The Interpretation must be applied
to any existing interests in variable interest entities beginning in the third
quarter of 2003. The Company does not expect to consolidate any existing
interest in unconsolidated entities as a result of Interpretation 46.
In April 2003, the FASB issued Statement of Financial Accounting Standards
No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"("SFAS 149"). SFAS 149 amends Statement 133 for decisions made (1)
as part of the Derivatives Implementation Group process that effectively
required amendments to Statement 133, (2) in connection with other Board
projects dealing with financial instruments, and (3) in connection with
implementation issues raised in relation to the application of the definition of
a derivative, in particular, the meaning of an initial net investment that is
smaller than would be required for other types of contracts that would be
expected to have a similar response to changes in market factors, the meaning of
underlying, and the characteristics of a derivative that contains financing
components. Effective for contracts entered into or modified after June 30,
2003, we do not expect this statement to have a material effect on our financial
position or results of operations.
In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity"(SFAS 150"). SFAS 150 establishes standards for
classifying and measuring financial instruments with characteristics of both
liabilities and equity. Effective for financial instruments entered into or
modified after May 31, 2003, we do not expect this statement to have a material
effect on our financial position or results of operations.
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 Six months ended
June 30 June 30
2003 2002 2003 2002
------ ------ ------ ------
(in thousands)
Net income before preferred dividends . . . . . . $1,113 $1,886 $5,186 $5,326
Preferred stock dividend requirement. . . . . . . 1 11 2 95
------ ------ ------ ------
Net income applicable to common stock . . . . . . $1,112 $1,875 $5,184 $5,231
====== ====== ====== ======
Weighted average number of common shares-basic. . 4,969 5,711 4,964 5,701
Dilutive effect of stock options. . . . . . . . . 159 166 161 165
Anti-dilutive stock options . . . . . . . . . . . - - - -
------ ------ ------ ------
Weighted average number of common shares-diluted. 5,128 5,877 5,125 5,866
====== ====== ====== ======
GREEN MOUNTAIN POWER CORPORATION
PART I-ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
JUNE 30, 2003
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 timing of
expense and revenue recognition under the regulatory accounting framework within
which we operate, the manner in which we account for certain power supply
arrangements that qualify as derivatives, and the defined benefit plan
assumptions used to determine plan liabilities for our defined benefit
retirement plans. These accounting policies, among others, affect the Company's
more significant judgments and estimates used in the preparation of its
consolidated financial statements.
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 Six months ended
June 30 June 30
2003 2002 2003 2002
----- ----- ----- -----
Utility business . . . . $0.20 $0.31 $1.00 $0.89
Unregulated businesses . 0.02 0.02 0.04 0.03
----- ----- ----- -----
Earnings from:
Continuing operations. . 0.22 0.33 1.04 0.92
Discontinued operations. - - - -
----- ----- ----- -----
Basic earnings per share $0.22 $0.33 $1.04 $0.92
===== ===== ===== =====
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.20 in the quarter ended June 30, 2003, compared with utility earnings of
$0.31 per share in the second quarter of 2002. Earnings declined primarily due
to a reduction in the amounts of deferred revenues recognized and increased
interest expenses, partially offset by a decrease in transmission costs.
Basic earnings per share from utility operations for the six months ended
June 30, 2003 were $1.00 compared with basic earnings per share of $0.89 for the
same period in 2002. Earnings improved primarily due to increased wholesale and
retail sales of electricity that more than offset increased power supply costs,
decreased recognition of deferred revenues, and higher interest expense.
UNREGULATED BUSINESSES
Earnings from unregulated businesses, principally from the Company's water
heater rental program, included in results from continuing operations for the
three and six months ended June 30, 2003 were slightly higher than during the
same period in 2002. A financial summary for these businesses follows:
Three Months Ended Six Months Ended
June 30 June 30
2003 2002 2003 2002
--------------- ----- ----- -----
(In thousands)
Revenue. . $ 247 $ 253 $ 497 $ 502
Expense. . 117 150 261 316
--------------- ----- ----- -----
Net Income $ 130 $ 103 $ 236 $ 186
=============== ===== ===== =====
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatt hour ("MWh") sales and average
number of customers for the three and six months ended June 30, 2003 and 2002
are summarized below:
Three months ended Six months ended
June 30 June 30
2003 2002 2003 2002
-------- -------- ---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 45,935 $ 48,256 $ 98,372 $ 100,745
Sales for Resale. . . 17,716 16,092 37,641 31,901
Other . . . . . . . . 804 787 1,387 1,355
-------- -------- ---------- ----------
Total Operating Revenues. $ 64,455 $ 65,135 $ 137,400 $ 134,001
======== ======== ========== ==========
MWh Sales-Retail. . . . . 450,945 457,128 957,220 955,136
MWh Sales for Resale. . . 534,644 517,937 1,080,562 1,036,224
-------- -------- ---------- ----------
Total MWh Sales . . . . . 985,589 975,065 2,037,782 1,991,360
======== ======== ========== ==========
Average Number of Customers
Three months ended Six months ended
June 30 June 30
2003 2002 2003 2002
------ ------ ------ ------
Residential . . . . . . . 74,488 73,730 73,861 73,831
Commercial and Industrial 13,314 13,104 13,194 13,076
Other . . . . . . . . . . 65 67 65 65
------ ------ ------ ------
Total Number of Customers. . 87,867 86,901 87,120 86,972
====== ====== ====== ======
REVENUES
Total revenues from operations in the second quarter of 2003 decreased $0.7
million or 1.0 percent compared with the same period in 2002, primarily as a
result of a decrease of $2.3 million in recognition of deferred revenues, and a
decrease of approximately $1.1 million in commercial and industrial revenues,
partially offset by a $1.7 million increase in sales for resale, and a $602,000
increase in residential revenues.
Retail operating revenues reflected a $2.3 million decline in the
recognition of deferred revenues during the second quarter of 2003, compared
with the same quarter of 2002. Revenues were 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 $8.5 million of revenue be deferred and then
recognized to offset increased costs during 2001, 2002, or 2003. As of June 30,
2003, the Company has $4.1 million in unused remaining deferred revenues, which
will be used to offset increased costs or write off regulatory assets during
2003 or 2004. See Notes-Retail Rate Case for further details.
Total retail MWh sales of electricity in the second quarter of 2003
increased 1.1 percent from the same quarter of 2002, primarily as a result of an
increase in residential sales of 7.6 percent, partially offset by a decrease in
sales of 5.8 percent to commercial customers. Sales to large industrial
customers also declined by 3.2 percent during the same period, reflecting
reduced energy consumption under a load shedding program that we manage.
The Company's major industrial customer, International Business Machines
("IBM"), accounted for 17.3% of retail sales revenue in 2002. The Company
currently estimates, based on a number of projected variables, the retail rate
increase required from all retail customers by a hypothetical shutdown of the
IBM facility to be in the range of five to eight percent, inclusive of projected
related declines in sales to residential and commercial customers.
We sell wholesale electricity to others for resale. Our revenue from
wholesale MWh sales of electricity increased approximately $1.6 million or 10.1
percent in the second quarter of 2003 compared with the same period in 2002.
The increase was due primarily to increased market energy prices.
Retail operating revenues reflected a $4.3 million decline in the
recognition of deferred revenues during the first six months of 2003, compared
with the same period of 2002, partially offset by an increase of $1.9 million or
2.0 percent in residential revenues during the same comparative periods. Strong
operating results during the first half of the year reduce the likelihood that
deferred revenue recognition will be needed to achieve the allowed return on
equity of 10.5 percent in 2003.
Total retail MWh sales of electricity in the first half of 2003 increased
0.5 percent from the same quarter of 2002, primarily as a result of increased
residential sales of 7.1 percent, a decrease in commercial sales of 0.6 percent
and a decline in industrial sales of 4.9 percent. The decrease in industrial
sales arose primarily from reduced snowmaking. These sales have an immaterial
impact on operating results because snowmaking sales are subject to a
dispatchable rate tariff arrangement that significantly reduces the Company's
margin on such sales.
Wholesale revenues increased $5.7 million or 18.0 percent during the first
six months of 2003, compared with the same period in 2002, as a result of
rescheduled power supply deliveries and higher market prices. Wholesale
revenues typically have an insignificant impact on earnings because market
wholesale prices usually approximate our marginal costs for energy, but the
first quarter was an exception. One of the Company's principal energy suppliers
reduces energy deliveries in the event of system limitations. These delivery
deficiencies are typically scheduled at a later time by the Company. During the
first quarter of 2003, the Company scheduled approximately 35,000 MWh of energy
from this supplier to make up for delivery deficiencies in earlier periods, and
sold that energy on the market at unusually high market energy prices. Market
energy prices were higher than normal in the first quarter as a result of the
Venezuelan oil strike, colder than normal temperatures across the U.S and the
threat of war.
OPERATING EXPENSES
POWER SUPPLY EXPENSES
Power supply expenses increased $565,000 or 1.2 percent in the second
quarter of 2003 compared with the same period in 2002, as a result of increased
wholesale sales of electricity that were in part offset by a $1.8 million
decline in costs under the Company's power supply contract with MS.
Power supply expenses at Vermont Yankee increased $1.6 million or 19.0
percent during the second quarter of 2003 compared with the same period of 2002,
primarily due to an increase in energy provided under the Power Purchase
Agreement between VY and Entergy (the "PPA"). An outage in the second quarter
of 2002 reduced energy provided from the Vermont Yankee nuclear power plant.
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 $495,000 or 80.3 percent in the
second quarter of 2003 compared with the same period in 2002, primarily due to
increased fuel costs.
The cost of power that we purchased from other companies decreased $1.5
million or 4.0 percent in the second quarter of 2003 compared with the same
period in 2002, primarily due to a $1.8 million decrease in cost of power
purchased from MS, that was partially offset by increased sales of electricity
and increased 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. 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.
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 second quarter of 2003, $1.1 million in power
supply expense was recognized to reflect the costs of option A and B. During
the second quarter of 2002, $0.8 million in power supply expense was recognized
to reflect the cost of option A. Hydro-Quebec had previously agreed not to call
option B during the 2002 contract year. The cumulative amount of power
purchased or called to date by Hydro-Quebec under option B is approximately
513,000 MWh out of a total of 600,000 MWh which may be called over the life of
the arrangement. Hydro-Quebec has exercised its option to call approximately
107,000 MWh under options A and B for July and August 2003. The Company
previously purchased energy in anticipation of Hydro-Quebec's call.
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 June 30, 2003, the Company had a
regulatory asset of approximately $21.2 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.
Power supply expenses increased $2.6 million or 2.8 percent in the first
half of 2003 compared with the same period in 2002, as a result of increased
wholesale and retail sales of electricity that were in part offset by a $4.2
million decline in costs under the Company's power supply contract with MS.
Power supply expenses at Vermont Yankee increased $3.0 million or 18.6
percent during the first half of 2003 compared with the same period of 2002,
primarily due to an increase in energy provided under the Power Purchase
Agreement between VY and Entergy. 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 $2.9 million or 184 percent in
the first half of 2003 compared with the same period in 2002, primarily due to
increased output and fuel costs at the Stony Brook generating facility in which
we have an 8.8 percent joint ownership interest, and increases in fuel costs
used to operate our other peak generation facilities.
The cost of power that we purchased from other companies decreased $3.4
million or 4.4 percent in the first half of 2003 compared with the same period
in 2002, primarily due to a $4.2 million decrease in the cost of power purchased
from MS, that was partially offset by increased sales of electricity and
increased expenses under the 9701 arrangement with Hydro-Quebec.
OTHER OPERATING EXPENSES
Other operating expenses increased $240,000 or 6.8 percent in the second
quarter of 2003 compared with the same period in 2002, as a result of increases
in employee benefit plan and consulting costs. Other operating expenses
increased $1.1 million or 16.1 percent in the first half of 2003 compared with
the same period in 2002 for the same reasons.
TRANSMISSION EXPENSES
Transmission expenses decreased by approximately $512,000 or 12.8 percent
for the three months ended June 30, 2003 compared with the same period in 2002,
due to a reduction in the amount of pool transmission expense allocated from the
rest of New England as a result of changes in cost allocation methods used by
ISO New England.
Transmission expenses decreased by approximately $425,000 or 5.3 percent
for the six months ended June 30, 2003 compared with the same period in 2002,
for the same reasons.
During 2002, the Federal Energy Regulatory Commission ("FERC") accepted ISO
New England's request to implement a standard market design ("SMD") governing
wholesale energy sales in New England. ISO New England implemented its SMD plan
on March 1, 2003. SMD includes a system of locational marginal pricing of
energy, under which prices are determined by zone, and based in part on
transmission congestion experienced in each zone. Currently, the State of
Vermont constitutes a single pricing zone under the plan, although pricing may
eventually be determined on a more localized ("nodal") basis. The Company does
not expect the implementation of this SMD in its current form to have a material
impact on the Company's power supply or transmission costs. The FERC has
suggested that change to nodal pricing might be appropriate as early as 18
months after the implementation of SMD. Nodal pricing, if implemented, could
have a material adverse impact on our power supply or transmission expense
because certain nodes are expected to be congested absent future investments in
transmission or generation assets.
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 modify
their tariffs to reflect non-discriminatory, standardized transmission service
and standard wholesale electric market design. 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.
Under SMD, the zone experiencing the voltage support problems will pay for
costs of local generation used to maintain voltage support for reliability.
Previously, these costs would have been allocated throughout New England. VELCO
owns certain transmission equipment on a primary transmission line ("PV20 line")
supporting northwestern Vermont. This equipment requires repair and will likely
be unavailable until next summer. We are unable to estimate whether, or to what
degree, VELCO will need to utilize additional generation to replace voltage
support previously provided by the PV20 line. If additional generation were
required, our share of these costs would be material.
VELCO has proposed a project to substantially upgrade Vermont's
transmission system (the "Northwest Reliability Project"), principally to
support reliability and eliminate transmission constraints in northwestern
Vermont, including most of the Company's service territory. The proposed
Northwest Reliability Project must be approved by the VPSB. If approved, the
project is estimated to cost approximately $128 million and is expected to be in
service by December 2007. Under current NEPOOL rules, qualifying large
transmission project costs are shared among all New England utilities as "pooled
transmission facilities" ("PTF"), with Vermont utilities responsible for
approximately five percent of such regionalized costs. NEPOOL has approved the
principal cost components of the Northwest Reliability Project for inclusion as
PTF. ISO New England is in the process of developing a proposal to FERC to
comply with the SMD NOPR, which will include a proposal for future treatment of
transmission investments. ISO New England has issued a preliminary
recommendation that maintains the principle of sharing costs of large
transmission investments throughout the New England region. ISO New England's
recommendation is not yet final and will be subject to approval by FERC.
MAINTENANCE EXPENSES
Maintenance expenses decreased $147,000 or 7.2 percent for the three months
ended June 30, 2003 compared with the same period in 2002, primarily due to a
decrease in scheduled maintenance at peak generation facilities.
Maintenance expenses decreased $247,000 or 5.8 percent for the six months
ended June 30, 2003 compared with the same period in 2002, for the same reasons.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses were essentially unchanged during
the second quarter and first half of 2003 compared with the same periods in
2002.
TAXES OTHER THAN INCOME TAXES
Other tax expense for the second quarter and first half of 2003 was
essentially unchanged compared with the same periods in 2002.
INCOME TAXES
Income taxes decreased $438,000 or 44.9 percent in the second quarter of
2003 compared with the same period in 2002 due to a decrease in pretax book
income from operations.
Income taxes decreased $99,000 or 3.3 percent in the first half of 2003
compared with the same period in 2002 for the same reason.
OTHER INCOME
Other income decreased $127,000 or 21.2 percent during the three months
ended June 30, 2003 compared with the same period in 2002, as earnings from VY
decreased due to the sale of the nuclear power plant to Entergy in 2002. See
Note 2, Investment in Associated Companies, for further information.
Other income decreased by $44,000 or 3.8 percent in first half of 2003
when compared with the same period in 2002, for the same reason.
INTEREST CHARGES
Interest charges increased $258,000 or 16.9 percent in the second quarter
of 2003 compared with the same period in 2002, due to increases in long-term
debt balances arising from the issuance of $42.0 million of first mortgage bonds
in December 2002.
Interest charges increased $498,000 or 16.3 percent in the first half of
2003 compared with the same period in 2002, for the same reason.
PREFERRED STOCK DIVIDENDS
Dividends paid on preferred stock decreased $10,000 for the quarter ended
June 30, 2003 compared with the same period in 2002, due to redemptions of
preferred stock during 2002 as discussed in this section under "Liquidity and
Capital Resources".
Dividends paid on preferred stock decreased $93,000 for the first half 2003
compared with the same period in 2002, for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
In the six months ended June 30, 2003, we spent $9.9 million principally
for expansion and improvements of our transmission, distribution and generation
plant, and environmental expenditures. We expect to spend approximately $12.6
million during the remainder of 2003, principally for improvements to
transmission, distribution and generation plant, and environmental expenditures.
During June 2003, the Company negotiated a 364-day revolving credit
agreement (the "Fleet-Sovereign Agreement") with Fleet Financial Services
("Fleet") joined by Sovereign Bank. The Fleet-Sovereign Agreement is for $20.0
million, unsecured, and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There were no amounts
outstanding on the Fleet-Sovereign Agreement at June 30, 2003. The
Fleet-Sovereign Agreement expires June 16, 2004. There was no non-utility
short-term debt outstanding at June 30, 2003.
The annual dividend was $0.60 per share for the year ended December 31,
2002. The Settlement Order had limited the annual dividend rate at its then
current level of $0.55 per share until our short-term credit facilities were
replaced with long-term debt or equity financing. The Company used proceeds of
a $42 million long-term debt issue in December 2002 to replace all short-term
borrowings, satisfying the conditions in the Settlement Order and permitting the
Company to raise its dividend. The annual dividend rate was increased from
$0.55 per share to $0.76 per share beginning with the $0.19 quarterly dividend
declared in December 2002. The Company intends to increase the dividend in a
measured consistent manner until the payout ratio falls between 50 percent and
60 percent of anticipated earnings. The Company believes this payout ratio to
be consistent with that of other utilities having similar risk profiles.
The Company completed a capital restructuring plan that reduced equity and
high-priced debt during 2002 and resulted in debt and equity ratios closer to
its targets of 50 percent debt and 50 percent equity. Significant transactions
resulting from the restructuring plan included:
On March 15, 2002, the Company redeemed $5.1 million of the 10.0 percent
first mortgage bonds due June 1, 2004;
During March and June 2002, the Company repurchased $11.0 and $1.0 million,
respectively, of the 7.32 percent Class E preferred stock outstanding;
On November 19, 2002, the Company completed a "Dutch Auction" self-tender
offer and repurchased 811,783 common shares, or approximately 14 percent of its
common stock outstanding, for approximately $16.3 million; and
On December 16, 2002, the Company issued $42 million principal amount of
first mortgage bonds bearing interest at 6.04 percent per year and maturing on
December 1, 2017.
The credit ratings of the Company's securities at June 30, 2003 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.
In the event of a change in the Company's first mortgage bond credit rating
to below investment grade, scheduled payments under the Company's first mortgage
bonds would not be affected. Such a change would require the Company to post
what would currently amount to a $4.3 million bond under our remediation
agreement with the EPA regarding the Pine Street Barge Canal site. The MS
contract requires credit assurances if the Company's first mortgage bond credit
ratings are lowered to below investment grade by any two of the three credit
rating agencies listed above.
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;
changes in rules governing wholesale electricity markets; and
increasing volatility of wholesale market prices for electricity.
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. 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.
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
adopted a plan to make pension plan contributions totaling $2.0 million between
September 1, 2002 and June 30, 2003, of which $2.0 million has been contributed
to date. The Company intends to contribute up to an additional $2.8 million by
December 31, 2003. The Company's pension costs and cash funding requirements
are expected to continue at an equivalent or increased rate through 2004.
As a result of our plan asset experience, at December 31, 2002, the Company
was required to recognize an additional minimum liability of $2.4 million, net
of applicable income taxes, as prescribed by SFAS 87. The liability was
recorded as a reduction to common equity through a charge to Other Comprehensive
Income ("OCI"), and did not affect net income for 2002. The charge to OCI may
be restored through common equity in future periods to the extent fair value of
trust assets exceeds the accumulated benefit obligation.
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
Our material power supply contracts and arrangements are principally with
Hydro Quebec, MS and Vermont Yankee. At June 30, 2003, more than 90 percent of
our estimated load requirements through 2006 are expected to be met by these
contracts and arrangements, and by our own generation and other power supply
resources, which reduces the Company's exposure to market prices.
A primary factor affecting future operating results is the volatility of
the wholesale electricity market. Restructuring of the wholesale market for
electricity has brought increased price volatility to our power supply markets.
Inherent in our market risk sensitive instruments and positions are the
potential losses that may result from adverse changes in our commodity prices.
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. The
Company's risk management policy specifies risk measures, the amount of
tolerable risk exposure, and authorization limits for transactions.
A sensitivity analysis has been prepared to estimate the exposure to the
market price risk of our electricity commodity positions. The MS contract is a
derivative under Statement of Financial Accounting Standards No. 133 ("SFAS
133") and is effective through December 31, 2006. Management's estimate of the
fair value of the future net benefit of this arrangement at June 30, 2003 is
approximately $6.6 million. Assumptions used to calculate the future net
benefit using the Blacks option valuation model include a risk-free interest
rate of 3.4 percent, volatility equivalent to a weighted average from NEPOOL,
which varies from 32 percent in the first year to 29 percent in the fourth year,
and locked in forward commitment prices for 2003, with an estimated forward
market price of approximately $43 per MWh for periods beyond 2003. The forward
price for electricity is consistent with the Company's current long-term
wholesale energy price forecast. Actual results may differ materially from the
table below.
A sensitivity analysis has been prepared to estimate exposure to the market
price risk of 9701, using the Black-Scholes model, over the next 13 years.
Management's estimate of the fair value of the future net cost for this
arrangement at June 30, 2003 is approximately $27.7 million. Assumptions used
within the model include a risk-free interest rate of 3.97 percent, volatility
equivalent to the weighted average from NEPOOL, which varies from 48 percent in
the first year to 26 percent in year 13, locked in forward commitment prices for
2003, and an average of approximately 60,000 MWh per year, with an estimated
forward market price of $59.81 per MWh during peak hours for periods beyond
2003. The forward price for electricity is consistent with the Company's
current long-term wholesale energy price forecast. Quoted forward market prices
for monthly peak power rates are not currently available beyond 2004. Actual
results may differ materially from the table below.
The table below presents market risk estimated as the potential loss in
fair value resulting from a hypothetical ten percent adverse change in prices,
which for the Company's derivatives discussed above totals approximately $3.0
million. Actual results may differ materially from the table below. 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.
Commodity Price Risk At June 30, 2003
Fair Value Market Risk
--------------- ------------
(in thousands)
Net short position $ 21,160 $ 2,995
ITEM 4. CONTROLS AND PROCEDURES
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, the
Company carried out an evaluation, with the participation of the Company's
management, including the Company's President and Chief Executive Officer, and
Controller and Treasurer, of the effectiveness of the Company's disclosure
controls and procedures (as defined under Rule 13a-15(e) under the Securities
Exchange Act of 1934) as of the end of the period covered by this report. Based
upon that evaluation, the Company's President and Chief Executive Officer, and
Controller and Treasurer 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. There has been no change in the
Company's internal control over financial reporting during the quarter ended
June 30, 2003 that has materially affected, or is reasonably likely to
materially affect, the Company's internal control over financial reporting.
------
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
JUNE 30, 2003
-------------
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings
See Notes 3, 4 and 5 of Notes to Consolidated Financial Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
At the Annual Shareholders Meeting held May 15, 2003, no items were
voted upon by Shareholders. Voting results for directors are listed below.
Shareholders elected the nominees listed below as Directors of this
company, with votes cast as indicated.
Merrill O. Burns, votes for, 3,912,890; withheld authority, 261,594;
abstentions, 787,473.
Christopher L. Dutton, votes for, 4,104,835; withheld authority,
69,649; abstentions, 787,473.
Directors continuing in office were Elizabeth A. Bankowski, Nordahl L.
Brue, William H. Bruett, Lorraine E. Chickering, John V. Cleary, David R.
Coates, and Euclid A. Irving.
ITEM 5. Other Information NONE
ITEM 6.
(A) EXHIBITS
----------
Exhibit 31.1 and Exhibit 31.2, Certification by Officers of Financial
Information and Disclosure Controls and Procedures required by Section 302 of
the Sarbanes-Oxley Act of 2002 accompanies this quarterly report.
Exhibit 32.1, Certification by Officers of Financial Information and Internal
Controls required by Section 906 of the Sarbanes-Oxley Act of 2002 accompanies
this quarterly report.
(B) REPORTS ON FORM 8-K
---------------
The following filings on Form 8-K were filed by the Company on the topics
and dates indicated:
A Form 8-K was filed July 15, 2003, announcing the Company's agreement with the
Vermont Department of Public Service concerning its cost of service filing, and
allowed rate of return.
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
SIGNATURES
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
---------------------------------------
(Registrant)
Date: August 11, 2003 /s/ Christopher L. Dutton
-----------------------------
Christopher L. Dutton, Chief Executive Officer
and President
Date: August 11, 2003 /s/ Robert J. Griffin
-------------------------
Robert J. Griffin, (as Principal Financial
Officer)
Treasurer and Controller