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, 2004
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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
OR ORGANIZATION) IDENTIFICATION NO.)
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 BY CHECK MARK WHETHER THE REGISTRANT IS AN ACCELERATED FILER (AS
DEFINED IN RULE 12B-2 OF THE EXCHANGE ACT). YES X NO
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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 30, 2004 $3.33 1/3 PAR
- --------------------------- ------------------------------
VALUE 5,086,688
- ---
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 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,
2004 AND 2003
ITEM 1. FINANCIAL STATEMENTS PAGE
Consolidated Statements of Income and Comprehensive Income (unaudited) 4
Consolidated Statements of Cash Flows (unaudited) 5
Consolidated Balance Sheets (unaudited) 6
Consolidated Statements of Retained Earnings (unaudited) 8
Notes to Consolidated Financial Statements (unaudited) 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 28
ITEM 4. CONTROLS AND PROCEDURES 31
PART II. OTHER INFORMATION 32
Exhibits and Reports on Form 8-K 33
Signatures 35
Certifications 66
The accompanying notes are an integral part of the consolidated financial
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
UNAUDITED
---------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
2004 2003 2004 2003
-------- -------- --------- ---------
(in thousands, except per share data)
Retail Revenues. . . . . . . . . . . . . . . . . . . . . . . 48,725 46,739 102,930 99,759
Wholesale Revenues. . . . . . . . . . . . . . . . . . . . . . 5,860 17,716 14,778 37,641
-------- -------- --------- ---------
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $54,585 $64,455 $117,708 $137,400
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 4,631 9,747 14,623 19,285
Company-owned generation. . . . . . . . . . . . . . . . . . 1,214 1,112 3,446 4,484
Purchases from others . . . . . . . . . . . . . . . . . . . 29,136 36,101 57,101 72,377
Other operating. . . . . . . . . . . . . . . . . . . . . . . 4,394 3,663 8,745 7,944
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 4,029 3,490 7,738 7,547
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 2,425 2,150 4,696 4,508
Depreciation and amortization. . . . . . . . . . . . . . . . 3,483 3,403 6,972 6,951
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,713 1,826 3,492 3,722
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 784 538 3,099 2,926
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 51,809 62,030 109,912 129,744
-------- -------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 2,776 2,425 7,796 7,656
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 277 414 533 826
Allowance for equity funds used during construction. . . . . 109 90 224 176
Other income (deductions), net . . . . . . . . . . . . . . . 269 (23) 234 113
-------- -------- --------- ---------
TOTAL OTHER INCOME. . . . . . . . . . . . . . . . . . . . 655 481 991 1,115
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,633 1,755 3,267 3,516
Other interest . . . . . . . . . . . . . . . . . . . . . . . 84 90 141 166
Allowance for borrowed funds used during construction. . . . (69) (60) (143) (118)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,648 1,785 3,265 3,564
-------- -------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 1,783 1,121 5,522 5,207
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . - 1 - 2
-------- -------- --------- ---------
Income from continuing operations. . . . . . . . . . . . . . 1,783 1,120 5,522 5,205
Income (loss) from discontinued segment,
including provisions for operating
losses during phaseout period. . . . . . . . . . . . . . . . (1) (8) (7) (21)
-------- -------- --------- ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 1,782 $ 1,112 $ 5,515 $ 5,184
======== ======== ========= =========
UNAUDITED
---------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
2004 2003 2004 2003
------ ------ ------ ------
Net income. . . . . . . . . . . . . . . . . . . . . $1,782 $1,112 $5,515 $5,184
Other comprehensive income, net of tax. . . . . . - - - -
------ ------ ------ ------
Comprehensive income. . . . . . . . . . . . . . . . $1,782 $1,112 $5,515 $5,184
====== ====== ====== ======
Basic earnings per share . . . . . . . . . . . . . $ 0.35 $ 0.22 $ 1.09 $ 1.04
Diluted earnings per share . . . . . . . . . . . . 0.34 0.22 1.06 1.01
Cash dividends declared per share. . . . . . . . . $ 0.22 $ 0.19 $ 0.44 $ 0.38
Weighted average common shares outstanding-basic . 5,072 4,969 5,058 4,964
Weighted average common shares outstanding-diluted 5,228 5,129 5,219 5,125
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
2004 2003
-------- --------
OPERATING ACTIVITIES:
Income from continuing operations before preferred dividends . . . . . . . . . . . . . . $ 5,522 $ 5,207
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,972 6,951
Dividends from associated companies less equity income . . . . . . . . . . . . . . . . . 38 (130)
Allowance for funds used during construction . . . . . . . . . . . . . . . . . . . . . . (367) (293)
Amortization of deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . 1,681 2,316
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 704 1,049
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (432) (86)
Rate levelization liability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,491) 238
Environmental and conservation deferrals, net. . . . . . . . . . . . . . . . . . . . . . (706) (2,320)
Changes in:
Accounts receivable and accrued utility revenues . . . . . . . . . . . . . . . . . . . . 2,701 1,886
Prepayments, fuel and other current assets . . . . . . . . . . . . . . . . . . . . . . . 978 (32)
Accounts payable and other current liabilities . . . . . . . . . . . . . . . . . . . . . (1,092) (3,406)
Accrued income taxes payable and receivable. . . . . . . . . . . . . . . . . . . . . . . (721) 481
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (343) -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,170 304
-------- --------
Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . . . . 14,615 12,165
INVESTING ACTIVITIES:
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8,536) (7,718)
Investment in associated companies . . . . . . . . . . . . . . . . . . . . . . . . . . . - (108)
Return of Capital from associated companies. . . . . . . . . . . . . . . . . . . . . . . 110 30
Investment in nonutility property. . . . . . . . . . . . . . . . . . . . . . . . . . . . (255) (73)
-------- --------
Net cash used in investing activities. . . . . . . . . . . . . . . . . . . . . . . . . . (8,681) (7,868)
-------- --------
FINANCING ACTIVITIES:
Payments to acquire treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . - (3)
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 828 192
Reduction in long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - -
Short-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (500) (2,500)
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,231) (1,888)
-------- --------
Net cash used in financing activities. . . . . . . . . . . . . . . . . . . . . . . . . . (1,903) (4,199)
-------- --------
Net increase in cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . 4,031 98
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . 786 1,909
-------- --------
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . 4,817 2,007
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized). . . . . . . . . . . . . . . . . . . . . . . . . . 3,364 3,542
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,637 1,758
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
JUNE 30 DECEMBER 31
-------
2004 2003 2003
-------- -------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . $325,737 $314,275 $324,900
Less accumulated depreciation . . . . . . . 115,239 108,020 110,111
-------- -------- --------
Net utility plant . . . . . . . . . . . . . 210,498 206,255 214,789
Property under capital lease. . . . . . . . 5,047 5,522 5,047
Construction work in progress . . . . . . . 15,139 13,980 9,026
-------- -------- --------
Total utility plant, net. . . . . . . . . . 230,684 225,757 228,862
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . 5,732 14,329 5,896
Other investments . . . . . . . . . . . . . 8,240 7,369 7,810
-------- -------- --------
Total other investments . . . . . . . . . . 13,972 21,698 13,706
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . 4,817 2,007 786
Accounts receivable, less allowance for
doubtful accounts of $790, $547 and $690. . 15,742 15,946 17,331
Accrued utility revenues. . . . . . . . . . 5,617 6,038 6,729
Fuel, materials and supplies, average cost. 4,545 4,188 4,498
Prepayments . . . . . . . . . . . . . . . . 659 1,140 1,922
Other . . . . . . . . . . . . . . . . . . . 665 356 422
-------- -------- --------
Total current assets. . . . . . . . . . . . 32,045 29,675 31,688
-------- -------- --------
DEFERRED CHARGES
Demand side management programs . . . . . . 6,994 6,471 6,713
Purchased power costs . . . . . . . . . . . 725 114 2,574
Pine Street Barge Canal . . . . . . . . . . 12,954 13,019 12,954
Net power supply deferral . . . . . . . . . 12,350 21,160 19,734
Power supply derivative asset . . . . . . . 12,210 6,586 3,990
Other deferred charges. . . . . . . . . . . 9,349 10,546 9,625
-------- -------- --------
Total deferred charges. . . . . . . . . . . 54,582 57,896 55,590
-------- -------- --------
NON-UTILITY
Other current assets. . . . . . . . . . . . - 8 217
Property and equipment. . . . . . . . . . . 248 249 248
Other assets. . . . . . . . . . . . . . . . 577 663 640
-------- -------- --------
Total non-utility assets. . . . . . . . . . 825 920 1,105
-------- -------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . $332,108 $335,946 $330,951
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
JUNE 30 DECEMBER 31
2004 2003 2003
--------- --------- ---------
(in thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,905,627, and 5,803,596 and 5,860,854). . . . . $ 19,685 $ 19,345 $ 19,536
Additional paid-in capital . . . . . . . . . . . 76,761 75,469 76,081
Retained earnings. . . . . . . . . . . . . . . . 26,071 19,469 22,786
Accumulated other comprehensive income . . . . . (1,787) (2,374) (1,787)
Treasury stock, at cost (827,639 shares) . . . . (16,701) (16,701) (16,701)
--------- --------- ---------
Total common stock equity. . . . . . . . . . . . 104,029 95,208 99,915
Redeemable cumulative preferred stock. . . . . . - 55 -
Long-term debt, less current maturities. . . . . 93,000 93,000 93,000
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . . 197,029 188,263 192,915
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . 4,898 5,496 4,963
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . - 30 -
Current maturities of long-term debt . . . . . . - 8,000 -
Short-term debt. . . . . . . . . . . . . . . . . - - 500
Accounts payable, trade and accrued liabilities. 8,353 4,358 8,493
Accounts payable to associated companies . . . . 5,305 8,535 6,821
Rate levelization liability. . . . . . . . . . . 1,986 4,329 2,970
Accrued income taxes . . . . . . . . . . . . . . (88) 5,065 633
Customer deposits. . . . . . . . . . . . . . . . 930 840 968
Interest accrued . . . . . . . . . . . . . . . . 1,134 1,182 1,152
Other. . . . . . . . . . . . . . . . . . . . . . 1,796 965 1,178
--------- --------- ---------
Total current liabilities. . . . . . . . . . . . 19,416 33,304 22,715
--------- --------- ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . . 24,560 27,746 23,724
Accumulated deferred income taxes. . . . . . . . 34,508 27,662 34,009
Unamortized investment tax credits . . . . . . . 2,710 2,989 2,848
Pine Street Barge Canal cleanup liability. . . . 6,649 6,720 7,356
Accumulated cost of removal. . . . . . . . . . . 21,907 20,377 21,238
Other deferred liabilities . . . . . . . . . . . 18,939 21,562 19,693
--------- --------- ---------
Total deferred credits . . . . . . . . . . . . . 109,273 107,056 108,868
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES, NOTE 3
NON-UTILITY
Net liabilities of discontinued segment. . . . . 1,492 1,827 1,490
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . . 1,492 1,827 1,490
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . $332,108 $335,946 $330,951
========= ========= =========
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
2004 2003 2004 2003
-------- -------- -------- --------
Balance - beginning of period. . . . . . . . . . . . $25,406 $19,300 $22,786 $16,171
Net Income . . . . . . . . . . . . . . . . . . . . . 1,782 1,113 5,515 5,186
Cash Dividends-redeemable cumulative preferred stock - (1) - (2)
Cash Dividends-common stock. . . . . . . . . . . . . (1,117) (943) (2,230) (1,886)
-------- -------- -------- --------
Balance - end of period. . . . . . . . . . . . . . . $26,071 $19,469 $26,071 $19,469
======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2004
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 periods 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 of America 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 2003 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, of which $1.1 million and $4.4 million were recognized during
2003 and 2002, respectively. The Company recognizes deferred revenues based on
its current forecast of amounts necessary to achieve its allowed rate of return
on equity for its utility operations. For the six months ended June 30, 2004,
the Company recognized deferred revenues of $1.5 million. The remaining $1.5
million will be used to offset increased costs or write off regulatory assets
during 2004. For the three months ended June 30, 2004, the Company recognized
deferred revenues of $742,000 compared with the same period in 2003 when the
Company deferred revenue recognition of $271,000. The Company did not
recognize or defer revenues for the six months ended June 30, 2003.
In December 2003, the VPSB approved a rate plan for the period 2003 through
2006 (the "2003 Rate Plan"), jointly proposed by the Company and the Vermont
Department of Public Service (the "Department" or the "DPS"). The 2003 Rate
Plan is summarized below under the heading "Rates.""
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.
For incentive stock options issued prior to 2003, 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." For
options granted on or after January 1, 2003, the Company applies the accounting
provisions 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 the date of grant was estimated using the Black-Scholes option-pricing model.
Had the Company expensed stock-based compensation under SFAS 123 for options
granted prior to 2003, the Company's diluted earnings would have been reduced by
$0.01 and $0.01 per share for the six months ended June 30, 2004 and 2003,
respectively.
Three Months Ended Six Months Ended
Pro-forma net income June 30 June 30
2004 2003 2004 2003
------ ------ ------ ------
In thousands, except per share amounts
Net income reported. . . . . . . . . . $1,782 $1,112 $5,515 $5,184
Pro-forma net income . . . . . . . . . 1,762 1,072 5,474 5,103
Earnings per share
As reported-basic. . . . . . . . . . 0.35 0.22 1.09 1.04
Pro-forma basic. . . . . . . . . . . 0.35 0.22 1.08 1.03
As reported-diluted. . . . . . . . . 0.34 0.22 1.06 1.01
Pro-forma diluted. . . . . . . . . . 0.34 0.21 1.05 1.00
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"). GMRI and GMPG were dissolved in March and
May 2004, respectively, with no gain or loss resulting from dissolution. We
also have a rental water heater program that is not regulated by the VPSB. The
results of these subsidiaries, and the Company's unregulated rental water heater
program, excluding NWR, are included in earnings of affiliates and non-utility
operations in the Other (Deductions) Income section of the Consolidated
Statements of Income. NWR's results are included in Gain/Loss from Discontinued
Operations.
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).
Three months ended Six Months Ended
June 30 June 30
2004 2003 2004 2003
------- ------- ------- -------
(in thousands)
Gross Revenue. . . . . $25,051 $49,014 $74,197 $96,982
Net Income Applicable. 128 722 $ 271 1,407
to Common Stock
Equity in Net Income . 43 140 91 267
On July 31, 2002, Vermont Yankee Nuclear Power Corporation ("VYNPC") announced
that the sale of its nuclear power plant to Entergy Nuclear Vermont Yankee
("ENVY") had been completed.
On June 18, 2004, a fire in the electrical conduits leading to a
transformer outside the plant resulted in a shutdown of the ENVY plant. The
outage ended on July 7, 2004. In response to the Company's request, the VPSB
issued a preliminary accounting order allowing the Company to defer and amortize
over a three-year period beginning July 1, 2004 its incremental replacement
power costs during the outage totaling approximately $500,000. Since the
Company no longer owns, through VYNPC, an interest in the nuclear plant we are
not responsible for any plant repairs or maintenance costs during outages.
In 2003, ENVY sought PSB approval to increase generation at its Vermont
Yankee plant by approximately 20 percent or 110 megawatts. On November 5, 2003,
the DPS announced that it had agreed to support ENVY's proposed uprate,
including ENVY's agreement to provide outage protection indemnification for the
Company and Central Vermont Public Service Corporation in the event that the
uprate causes temporary reductions in output that would require us to buy
higher-cost replacement power. The outage protection coverage will be in place
for three years for uprate-related outages. Under this Ratepayer Protection
Proposal ("RPP"), we have indemnification rights up to approximately $1.6
million to cover uprate-related reductions in output. In early 2004, the PSB
issued an order approving the uprate subject to certain conditions.
On February 10, 2004, ENVY notified VYNPC that it expects that the plant
output will be reduced beginning after the April 2004 scheduled refueling
outage, and continuing until ENVY receives Nuclear Regulatory Commission ("NRC")
approval for the uprate, which is expected no earlier than November 2004. This
will reduce our 106 MW entitlement by about 5 MW during this period. We believe
such a reduction will be covered by the terms of the RPP discussed above.
In April 2004, in response to a NRC inspection conducted during the ENVY
plant's scheduled refueling outage, ENVY reported that two short spent fuel rod
segments were not in what ENVY believed to be their documented location in the
spent fuel pool. According to ENVY, the rods in 1979 were placed in a special
stainless steel container in the spent fuel pool. After initial review and
visual inspection of the spent fuel pool, ENVY did not locate the fuel rod
segments.
By letter dated May 5, 2004, ENVY notified VYNPC that based on the terms of
the Purchase and Sale Agreement dated August 1, 2001, and facts at that time, it
was ENVY's view that costs associated with the spent fuel rod segment inspection
effort were the responsibility of VYNPC. VYNPC responded that based on the
information at that time, there was no basis for ENVY to claim the inspection
was VYNPC's responsibility. Subsequently, ENVY's continuing documentation
review led to the discovery of the fuel rod segments in a container in the spent
fuel pool. The NRC will begin its own investigation next month into ENVY's
accounting for these segments. We cannot predict the outcome of this matter at
this time.
The Company's ownership share of VYNPC has increased from approximately
19.0 percent in 2002 to approximately 33.6 percent currently, due to VYNPC's
purchase of certain minority shareholders' interests during November 2003. The
Company's entitlement to energy produced by the ENVY nuclear plant remains at
approximately 20 percent of plant production.
VERMONT ELECTRIC POWER COMPANY, INC. ("VELCO")
Percent ownership: 28.4% 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 those using VELCO's transmission system. The Company
is obligated to provide its proportionate share of the equity capital
requirements of VELCO through continuing purchases of its common stock, if
necessary. The Company plans to make capital investments of up to $20 million
in VELCO through 2007 in support of various transmission projects.
Three months ended Six Months Ended
June 30 June 30
2004 2003 2004 2003
------ ------ ------- -------
(in thousands)
Gross Revenue . . . . $6,543 $5,635 $12,876 $11,270
Net Income. . . . . . 308 349 618 622
Equity in Net Income. 85 91 131 197
The Company has evaluated its relationship with VELCO and VYNPC under the
requirements of FIN 46R and has determined that it is not the primary
beneficiary of VELCO or VYNPC. Therefore the financial results of VELCO and
VYNPC have not been consolidated into the Company's financial statements.
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 SUPERFUND SITE - In 1999, the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the United States Environmental Protection Agency ("EPA"), the State of Vermont
and numerous other parties of claims relating to a federal Superfund site in
Burlington, Vermont, known as the "Pine Street Barge Canal." The consent decree
resolves claims by the EPA for past site costs, natural resource damage claims
and claims for past and future remediation costs. The consent decree also
provides for the design and implementation of response actions at the site. We
have estimated total future costs of the Company's future obligations under the
consent decree to be approximately $6.6 million. The estimated liability is not
discounted, and it is possible that our estimate of future costs could change by
a material amount. We have recorded a regulatory asset of $13.0 million to
reflect unrecovered past and future Pine Street costs. Pursuant to the
Company's 2003 Rate Plan, as approved by the VPSB, the Company will begin to
amortize past unrecovered costs in 2005. The Company will amortize the full
amount of incurred costs over 20 years without a return. The amortization will
be allowed in future rates, without disallowance or adjustment, until fully
amortized.
RATES
- -----
RETAIL RATE CASES - On December 22, 2003, the VPSB approved our 2003 Rate Plan,
jointly proposed earlier in the year by the Company and the Department. The
2003 Rate Plan covers the period from 2003 through 2006 and includes the
following principal elements:
The Company's rates will remain unchanged through 2004. The 2003 Rate Plan
allows the Company to raise rates 1.9 percent, effective January 1, 2005,
and an additional 0.9 percent, effective January 1, 2006, if the increases are
supported by cost of service schedules submitted 60 days prior to the effective
dates. If the Company's cost of service filings in 2005 or 2006 establish that
a lesser rate increase is required for the Company to earn its allowed rate of
return, the Company will implement the lesser rate increase.
The Company may seek additional rate increases or deferral of costs in
extraordinary circumstances, such as severe storm repair costs, natural
disasters, extended unanticipated unit outages, or significant losses of
customer load.
The Company's allowed return on equity is reduced from 11.25 percent to
10.5 percent, for the period January 1, 2003 through December 31, 2006. During
the same period, the Company's earnings on utility operations are capped at 10.5
percent. Any excess earnings in 2004 will be applied to reduce regulatory
assets. Excess earnings in 2005 or 2006 will be refunded to customers as a
credit on customer bills or applied to reduce regulatory assets, as the
Department directs.
The Company has carried forward into 2004 $3.0 million in deferred revenue
remaining at December 31, 2003, from the Company's 2001 Settlement Order
(summarized below). These revenues will be applied in 2004 to offset increased
costs or, if applicable, reduce regulatory assets as determined by the DPS.
The Company will amortize (recover) certain regulatory assets, including
Pine Street Barge Canal environmental site costs and past demand-side management
program costs, beginning in January 2005, with those amortizations to be allowed
in future rates. Pine Street costs will be recovered over a twenty-year period
without a return.
As required, the Company filed with the VPSB in early 2004 a new fully
allocated cost of service study and rate re-design, which will allocate the
Company's revenue requirement among all customer classes on the basis of current
costs. The new rate design is subject to VPSB approval and is not expected to
adversely affect operating results.
The Company and the Department have agreed to work cooperatively to develop
and propose an alternative regulation plan as authorized by legislation enacted
in Vermont in 2003. If the Company and Department agree on such a plan, and it
is approved by the VPSB, the alternative regulation plan would supersede the
2003 Rate Plan.
In January 2001, the VPSB approved a rate case settlement (the "2001
Settlement Order") between the Company and the DPS. The 2001 Settlement Order
included a rate increase of 3.42 percent effective January 2001, setting the
Company's rates at levels that recover the Company's Hydro Quebec/Vermont Joint
Owners Contract (the "VJO Contract") costs, and effectively ending regulatory
disallowances experienced by the Company from 1998 through 2000. Under the 2001
Settlement Order, the Company agreed to an earnings cap on core utility
operations of 11.25 percent return on equity, with amounts earned over the limit
being used to write off regulatory assets.
The 2001 Settlement Order also imposed 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, adjusted for inflation;
and
The Company's further investment in non-utility operations is restricted
until new rates go into effect, which will occur in January 2005.
POWER CONTRACT COMMITMENTS
On February 11, 1999, the Company entered into a contract with Morgan
Stanley Capital Group, Inc. (the "Morgan Stanley Contract") designed to manage
price risks associated with changing fossil fuel prices. In August 2002, the
Morgan Stanley Contract was modified and extended to December 31, 2006.
Under the Morgan Stanley Contract, on a daily basis, and at Morgan
Stanley's discretion, we sell power to Morgan Stanley from part of our portfolio
of power resources at predefined operating and pricing parameters, provided that
sales of power from sources other than Company-owned generation comply with the
predefined operating parameters and predefined or indexed pricing parameters.
Morgan Stanley sells to the Company, at a predefined price, power sufficient to
serve pre-established load requirements. We remain responsible for resource
performance and availability. Morgan Stanley provides no coverage against major
unscheduled power supply outages. Beginning January 1, 2004, the Company
reduced the power that it sells to Morgan Stanley. The output of some of our
power-supply resources, including purchases pursuant to our Hydro Quebec and
VYNPC contracts, which were sold to Morgan Stanley through 2003, are no longer
included in the Morgan Stanley Contract. This reduction in sales to Morgan
Stanley is expected to reduce wholesale revenues by approximately $56 million
during 2004 when compared with 2003, and correspondingly to reduce power supply
expense by a similar amount. We do not expect this change to adversely affect
the Company's opportunity to earn its allowed rate of return during 2004.
The Company's current purchases under the VJO Contract with Hydro Quebec
are as follows: (1) Schedule B -- 68 megawatts of firm capacity and associated
energy to be delivered at the Highgate interconnection for twenty years
beginning in September 1995; and (2) Schedule C3 -- 46 megawatts of firm
capacity and associated energy to be delivered at interconnections to be
determined at any time for 20 years, beginning in November 1995.
We sometimes experience energy delivery deficiencies under the VJO Contract as a
result of outages or other problems with the transmission interconnection
facilities over which we schedule deliveries. When such deficiencies occur, we
purchase replacement energy on the wholesale market, usually at prices that are
higher than VJO Contract costs.
Our contracts with Hydro Quebec contain cross default provisions that allow
Hydro Quebec to invoke "step-up" provisions under which the other Vermont
utilities that are also parties to the contract would be required to purchase
their proportionate share of the power supply entitlement of any defaulting
utility. The Company is not aware of any instance where this provision has been
invoked by Hydro Quebec.
Under the Company's 9701 arrangement with Hydro Quebec, Hydro Quebec paid
$8.0 million to the Company in 1997. In return for this payment, we provided
Hydro Quebec options for the purchase of power. Commencing April 1, 1998, and
effective through the term of the VJO Contract, which ends in 2015, Hydro Quebec
may purchase up to 52,500 MWh on an annual basis ("option A") at the VJO
Contract energy price, which is substantially below current market prices. The
cumulative amount of energy that may be purchased under option A may not exceed
950,000 MWh (52,500 MWh in each contract year).
Over the same period, Hydro Quebec may exercise an option to purchase up to
200,000 MWh on an annual basis at the VJO Contract energy price ("option B").
The cumulative amount of energy that may be purchased under option B may not
exceed 600,000 MWh. As of June 30, 2004, Hydro Quebec had purchased 513,000 MWh
under option B. Hydro Quebec has exercised its option to purchase 105,000 MWh
under options A and B during the months of July and August 2004, as anticipated
by the Company. The Company expects Hydro Quebec to call its remaining
entitlements of approximately 35,000 MWh under option B during 2005.
In 2003, Hydro Quebec exercised option A and option B, and called for
delivery to third parties at a net expense to the Company of approximately $4.5
million, including capacity charges.
Hydro Quebec exercised options A and B for 2004, and the Company has
purchased replacement power at a net cost of $3.2 million. The Company has also
covered 54 percent of expected calls during 2005 at a net cost of $1.1 million.
Under the VJO Contract, Hydro Quebec has the right to reduce the load
factor from 75 percent to 65 percent a total three times over the life of the
contract. Hydro Quebec exercised the first of these load reduction options,
effective for the year 2003. The net cost of Hydro Quebec's exercise of this
option increased power supply expense during 2003 by approximately $1.2 million.
During 2003, Hydro Quebec exercised its second option to reduce the load factor
for 2004, which we estimate will increase power supply expense in 2004 by
approximately $1.0 million. Hydro Quebec exercised its third and final option
in 2004 to reduce deliveries occurring principally during 2005, resulting in an
estimated cost of replacement power of $1.0 million to $1.5 million, based on
current wholesale market prices for 2005. The Vermont Joint Owners, including
the Company, retain two options to increase the load factor to 80 percent from
75 percent after 2005.
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 procurement, generation, 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, 2004, most of
NWR's net assets and liabilities have been sold or otherwise disposed. The
remaining net liability reflects expected warranty obligations.
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.
All of the Company's power supply contract costs are currently being recovered
through rates approved by the VPSB. The Company's most significant power supply
contracts are the Hydro Quebec Vermont Joint Owners ("VJO") Contract (the "VJO
Contract") and the VYNPC contract (the "VYNPC Contract"), which together supply
approximately 75 percent of our retail load.
We expect approximately 90 percent of our estimated customer demand
("load") requirements through 2006 to be met by our contracts and generation and
other power supply resources. These contracts and resources significantly
reduce the Company's exposure to volatility in wholesale energy market prices.
A primary factor affecting future operating results is the volatility of
the wholesale electricity market. Implementation of New England's wholesale
market for electricity has increased volatility of wholesale power prices.
Periods frequently occur when weather, availability of power supply resources
and other factors cause significant differences between customer demand and
electricity supply. Because electricity cannot be stored, in these situations
the Company must buy or sell the difference into a marketplace that has
experienced volatile energy prices. Volatility and market price trends also
make it more difficult to extend or enter into new power supply contracts at
prices that avoid the need for rate relief.
The Company has established a risk management program designed 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. These transactions are
used to hedge the risk of fossil fuel and spot market electricity price
increases. Some of these transactions present the risk of potential losses from
adverse changes in commodity prices. Our risk management policy specifies risk
measures, the amount of tolerable risk exposure, and authorization limits for
transactions. Our principal power supply contract counter-parties and
generators, Hydro Quebec, ENVY and Morgan Stanley Capital Group, Inc., all
currently have investment grade credit ratings.
The Morgan Stanley Contract (described above under "Power Contract
Commitments") is used to hedge our power supply costs against increases in
fossil fuel prices. The Morgan Stanley Contract is a derivative under Statement
of Financial Accounting Standards No. 133 ("SFAS 133") and is effective through
December 31, 2006. Management has estimated the fair value of the future net
benefit of this arrangement at June 30, 2004 to be approximately $12.2 million.
The Company's 9701 arrangement with Hydro Quebec (described under "Power
Contract Commitments") grants Hydro Quebec an option to call power at prices
that are expected to be below 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, 2004 is
approximately $24.6 million. We sometimes use forward contracts to hedge
forecasted calls by Hydro Quebec under the 9701 arrangement.
The table below presents assumptions used to estimate the fair value of the
Morgan Stanley Contract and the 9701 arrangement. The forward prices for
electricity used in this analysis are consistent with the Company's current
long-term wholesale energy price forecast.
Option Value Risk Free Price Average Contract
Model Interest Rate Volatility Forward Price Expires
------------- -------------- ----------- -------------- -------
Morgan Stanley Contract Deterministic 1.2% 32%-29% $ 58 2006
9701 Arrangement. . . . Black-Scholes 3.8% 48%-27% $ 62 2015
The table below presents the Company's market risk of the Morgan Stanley and
Hydro Quebec derivatives, estimated as the potential loss in fair value
resulting from a hypothetical ten percent adverse change in wholesale energy
prices, which nets to approximately $882,000. Actual results may differ
materially from the table illustration. Under an accounting order issued by the
VPSB, changes in the fair value of derivatives are deferred.
Commodity Price Risk At June 30, 2004
Fair Value(Cost) Market Risk
----------------- -------------
(in thousands)
Morgan Stanley Contract $ 12,210 $ 2,310
9701 Arrangement. . . . (24,560) (3,192)
----------------- -------------
(12,350) (882)
If a derivative instrument were terminated early because it is probable that a
transaction or forecasted transaction will not occur, any gain or loss would be
recognized in earnings immediately. For derivatives held to maturity, the
earnings impact would be recorded in the period that the derivative is sold or
matures.
6. NEW ACCOUNTING STANDARDS
In January 2003 and December 2003, the Financial Accounting Standards Board
issued Interpretation 46 and 46R (Revised), respectively, Consolidation of
Variable Interest Entities ("VIEs"). This interpretation clarified application
of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," and
replaced current accounting guidance relating to consolidation of certain
special purpose entities. FIN 46 and FIN 46R define VIEs as entities that are
unable to finance their ongoing operations without additional subordinated
financing. FIN 46R requires identification of the Company's participation in
VIEs and consolidation of those VIEs of which the Company is the primary
beneficiary. The Company adopted FIN 46 at December 31, 2003 and FIN 46R at
March 31, 2004, and was not required to consolidate any existing interests
pursuant to the requirements of FIN 46 or FIN 46R.
The Company provides health care, life insurance, prescription drug and
other benefits to retired employees who meet certain age and years of service
requirements. Under certain circumstances, eligible retirees are required to
make contributions for postretirement benefits. On May 19, 2004, the FASB
issued FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003 (the "Act"), ("FAS No. 106-2") which superseded FSP 106-1, which allowed
employers to voluntarily recognize the impact of the Act. This was in response
to a new law regarding prescription drug benefits under Medicare ("Medicare Part
D") and a federal subsidy to sponsors of retiree health care benefit plans that
are at least actuarially equivalent to Medicare Part D. Currently, SFAS No.
106, Employers' Accounting for Postretirement Benefits Other Than Pensions,
("SFAS No. 106") requires that changes in relevant law be considered in current
measurement of postretirement benefit costs. The Company had elected to defer
recognition of any impact under FSP 106-1. FSP 106-2 provides that if the
effect of the Act is not considered a significant event, the measurement date
for adoption of FSP 106-2 is delayed until the next regular measurement date,
which is September 30, 2004 for the Company. The Company has concluded that the
effect is not significant. Therefore, measures of the accumulated
postretirement benefit obligation and the net periodic postretirement benefit
cost do not reflect the effects of the new law.
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. On February 9, 2004, the Board of
Directors of the Company adopted the 2004 Stock Incentive Plan and such plan was
approved by the Company's shareholders at the Company's 2004 Annual Meeting of
Shareholders. Restricted stock units issued under the plans are subject to
vesting schedules of between several months and two years.
Reconciliation of net income available
Three months ended Six months ended
for common shareholders and average shares June 30 June 30
2004 2003 2004 2003
------ ------ ------ ------
(in thousands)
Net income before preferred dividends. . $1,782 $1,113 $5,515 $5,186
Preferred stock dividend requirement . . - 1 - 2
------ ------ ------ ------
Net income applicable to common
stock . . . . . . . . . . . . . . . . $1,782 $1,112 $5,515 $5,184
====== ====== ====== ======
Average number of common shares-basic. . 5,072 4,969 5,058 4,964
Dilutive effect of stock options . . . . 156 160 161 161
------ ------ ------ ------
Average number of common shares-diluted. 5,228 5,129 5,219 5,125
====== ====== ====== ======
GREEN MOUNTAIN POWER CORPORATION
PART I-ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
JUNE 30, 2004
EXECUTIVE OVERVIEW - Green Mountain Power Corporation (the "Company") generates
virtually all of its earnings from retail electricity sales. Our retail
electricity sales grow at an average annual rate of between one and two percent,
about average for most electric utility companies in New England. While
wholesale revenues are significant, they have relatively minor impact on our
operating results and financial condition. The Company is regulated and cannot
adjust prices of retail electricity sales without regulatory approval from the
Vermont Public Service Board ("VPSB").
The Company increased its dividend in February 2004 from an annual rate of
$0.76 per share to $0.88 per share. The Company's dividend payout ratio remains
comparatively low, at less than 45 percent of 2003 earnings. We expect to grow
our dividend payout ratio to between 50 and 70 percent over the next five years,
in line with other electric utilities having similar risk profiles, so long as
financial and operating results permit.
Fair regulatory treatment is fundamental to maintaining the Company's
financial stability. Rates must be set at levels to recover costs, including a
market rate of return to equity and debt holders. In December 2003, the Company
received approval from the VPSB of a new rate plan covering the period 2003
through 2006, which sets rates at levels the Company believes will provide an
improved opportunity to recover our costs, and to earn our allowed rate of
return of 10.5 percent.
Power supply expenses are equivalent to approximately 65 percent of total
revenues. The Company's need to seek rate increases from its customers
frequently moves in tandem with increases in our power supply costs. We have
entered into long-term power supply contracts for most of our energy needs. All
of our power supply contract costs are currently being recovered in the rates we
charge our customers. The risks associated with our power supply resources,
including outage, curtailment, and other delivery risks, the timing of contract
expirations, the volatility of wholesale prices, and other factors impacting our
power supply resources and how they relate to customer demand are discussed
below under Item 3, "Quantitative and Qualitative Disclosure about Market Risk,
and Other Risk Factors."
We also discuss other risks, including load risk related to our largest
customer, International Business Machines Corporation ("IBM"), and contingencies
that could have a significant impact on future operating results and our
financial condition.
Growth opportunities beyond the Company's normal investment in its
infrastructure include a planned increase in our equity investment in Vermont
Electric Power Company, Inc. ("VELCO") and a planned increase in sales of
utility services.
In this section, we explain the general financial condition and the results
of operations for the Company and its subsidiaries. This explanation 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 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 affect 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; the assumptions that we
make regarding defined benefit plans; and revenue recognition, particularly as
it relates to unbilled and deferred revenues. These accounting policies, among
others, affect the Company's significant judgments and estimates used in the
preparation of its consolidated financial statements.
There are statements in this section that contain projections or estimates
that are considered to be "forward-looking" as defined by the Securities and
Exchange Commission (the "SEC"). In these statements, you may find words such
as believes, expects, plans, or similar words. These statements are not
guarantees of our future performance. There are risks, uncertainties and other
factors that could cause actual results to be different from those projected.
Some of the reasons the results may be different include:
regulatory and judicial decisions or legislation
changes in regional market and transmission rules
energy supply and demand and pricing
contractual commitments
availability, terms, and use of capital
general economic and business environment
changes in technology
nuclear and environmental issues
industry restructuring and cost recovery (including stranded costs)
weather
We address these items in more detail below.
These forward-looking statements represent our estimates and assumptions
only as of the date of this report.
AS YOU READ THIS SECTION IT MAY BE HELPFUL TO REFER TO THE CONSOLIDATED
FINANCIAL STATEMENTS AND NOTES IN PART I-ITEM 1.
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
2004 2003 2004 2003
----- ----- ----- -----
Utility business . . . . $0.32 $0.20 $1.03 $1.00
Unregulated businesses . 0.03 0.02 0.06 0.04
----- ----- ----- -----
Earnings from:
Continuing operations. . 0.35 0.22 1.09 1.04
Discontinued operations. - - - -
----- ----- ----- -----
Basic earnings per share $0.35 $0.22 $1.09 $1.04
===== ===== ===== =====
OPERATING RESULTS.
The Company recorded basic earnings per share from utility operations of
$0.32 in the quarter ended June 30, 2004, compared with utility earnings of
$0.20 per share in the same quarter of 2003. Earnings in 2004 were higher than
the second quarter of 2003 principally due to a $0.12 per share increase in
deferred revenues recognized. Higher retail sales and lower power supply
expenses offset increases in other operating, transmission and maintenance
expenses during the quarter. As disclosed in our 2003 Annual Report, a planned
reduction in wholesale sales pursuant to the Morgan Stanley Contract was offset
by a reduction in power purchased to fulfill those sales.
Basic earnings per share for the six months ended June 30, 2004 were
$1.09 compared with basic earnings per share of $1.04 for the same period in
2003. Earnings improved primarily due to increased recognition of deferred
revenues, increased retail sales of electricity and lower power supply expense,
that were partially offset by a one time benefit that occurred during 2003 for
additional energy deliveries that were sold in the wholesale market at unusually
high prices, adding approximately $0.15 per share to 2003 earnings, and by
increased other operating expenses.
Operating results also include earnings of approximately $0.03 per
share and $0.06 per share for the three and six months ended June 30, 2004 from
the Company's rental water heater business and did not change materially when
compared with the same periods in 2003.
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, 2004 and 2003
are summarized below:
Three months ended Six months ended
June 30 June 30
2004 2003 2004 2003
-------- -------- ---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 47,881 $ 45,935 $ 101,229 $ 98,372
Sales for Resale. . . 5,860 17,716 14,778 37,641
Other . . . . . . . . 844 804 1,701 1,387
-------- -------- ---------- ----------
Total Operating Revenues. $ 54,585 $ 64,455 $ 117,708 $ 137,400
======== ======== ========== ==========
MWh Sales-Retail. . . . . 459,796 450,945 974,879 959,409
MWh Sales for Resale. . . 107,919 534,644 253,620 1,080,562
-------- -------- ---------- ----------
Total MWh Sales . . . . . 567,715 985,589 1,228,499 2,039,971
======== ======== ========== ==========
Average Number of Customers
Three months ended Six months ended
June 30 June 30
2004 2003 2004 2003
------ ------ ------ ------
Residential . . . . . . . 75,253 74,488 75,341 73,861
Commercial and Industrial 13,480 13,314 13,476 13,194
Other . . . . . . . . . . 62 65 62 65
------ ------ ------ ------
Total Number of Customers. . 88,795 87,867 88,879 87,120
====== ====== ====== ======
REVENUES
Total operating revenues in the second quarter of 2004 decreased $9.9
million or 15.3 percent compared with the same period in 2003, primarily as a
result of a decrease in wholesale sales to Morgan Stanley under the Morgan
Stanley Contract (described in Part I, Item I, No. 3 under "Power Contract
Commitments"). This decrease was partially offset by an increase of
approximately $1.9 million in retail operating revenues. The increase in retail
revenues had a favorable impact on earnings and resulted principally from a $1.0
million increase in commercial and industrial customer revenues and a $1.0
million increase in deferred revenue recognition. Total retail MWh sales of
electricity in the second quarter of 2004 increased 2.0 percent from the same
quarter of 2003, primarily as a result of an economic recovery and growth
resulting in an increase in commercial and industrial sales of 3.4 percent,
partially offset by a decrease in residential sales of 1.7 percent due to milder
weather in 2004.
Retail operating revenues reflected a $1.0 million increase in the
recognition of deferred revenues during the second quarter of 2004, compared
with the same quarter of 2003. 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 "2001 Settlement Order").
The 2001 Settlement Order resulted in the elimination of seasonal rates,
generating an additional $8.5 million in cash flow in 2001. The VPSB has issued
orders providing that recognition of this additional $8.5 million of revenue be
deferred and then recognized to offset increased costs during 2001, 2002, 2003
and 2004. As of June 30, 2004, the Company has $1.5 million in remaining
unrecognized deferred revenues, which will be used to earn an allowed return or
write off regulatory assets during 2004.
In December 2003, the VPSB approved a rate plan between the Vermont
Department of Public Service and the Company that allows the Company to raise
rates by 1.9 percent, effective January 1, 2005, and an additional 0.9 percent,
effective January 1, 2006, if the increases are supported by cost of service
schedules submitted 60 days prior to the effective dates. The 1.9 percent
increase is expected to provide approximately $4 million in retail operating
revenues during 2005.
The Company's major industrial customer, International Business Machines
("IBM"), accounted for 16.6% of retail sales revenue in 2003. 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 decreased approximately $11.9 million or 66.9
percent in the second quarter of 2004 compared with the same period in 2003,
reflecting decreased sales of electricity to Morgan Stanley under our Morgan
Stanley Contract. We do not expect the reduction in sales to Morgan Stanley to
adversely affect the Company's earnings in 2004 or future years.
Retail operating revenues reflected a $1.5 million increase in the
recognition of deferred revenues during the first six months of 2004, compared
with the same period of 2003, an increase of $1.0 million or 3.5 percent in
commercial and industrial revenues during the same comparative periods, and a
decrease of approximately $88,000 in revenues from residential and other
customers.
Total retail MWh sales of electricity in the first half of 2004 increased
1.8 percent when compared with the first half of 2003, primarily as a result of
an increase in commercial and industrial sales of 2.9 percent and an increase of
0.9 percent in residential sales.
Wholesale revenues decreased $22.9 million or 60.7 percent during the first
six months of 2004, compared with the same period in 2003, as a result of
reduced sales under the Morgan Stanley Contract. Wholesale revenues also
declined as a result of decreased sales of power arising from added deliveries
of electricity under a long-term contract with Hydro Quebec. During the first
quarter of 2003, delivery of past power supply contract deficiencies by Hydro
Quebec resulted in additional energy availability that the Company sold when
market energy prices were unusually high. We estimate that these sales
increased quarterly earnings by approximately $0.15 per share in 2003. There
are no further deficiencies to be rescheduled and the Company does not expect
this benefit to reoccur.
OPERATING EXPENSES
POWER SUPPLY EXPENSES
Power supply expenses decreased $12.0 million or 25.6 percent in the second
quarter of 2004 compared with the same period in 2003, primarily as a result of
an $11.0 million decline in purchases under the Company's power supply contract
with Morgan Stanley (described in Part I, Item I, No. 3 under "Power Contract
Commitments").
Power supply expenses from VYNPC decreased $5.1 million or 52.5 percent
during the second quarter of 2004 compared with the same period of 2003,
primarily due to decreased output at the ENVY nuclear power plant due to planned
and unplanned outages. See Part I, Item 1, Note 2, Investment in Associated
Companies-Vermont Yankee, for a more detailed discussion of the effect of these
outages.
Company-owned generation expenses increased $102,000 or 9.2 percent in the
second quarter of 2004 compared with the same period in 2003, primarily due to
increased fuel prices for production at peak generation facilities. Peak
generation facilities are run only to maintain system reliability or when
wholesale energy prices are extremely high.
The cost of power that we purchased from other companies decreased $7.0
million or 19.3 percent in the second quarter of 2004 compared with the same
period in 2003, primarily due to an $11.0 million decrease in purchases from
Morgan Stanley, partially offset by an increase in costs of power purchased from
NEPOOL and other sources to replace the decreased output at the ENVY plant
during outages, to supply increased retail sales to customers and to replace
reduced deliveries from Hydro Quebec.
During the second quarter of 2004, $751,000 in power supply expense was
recognized to reflect the costs of the Company's 9701 arrangement with Hydro
Quebec compared with $1.1 million in power supply expense for the same quarter
in 2003. The cumulative amount of power purchased at June 30, 2004 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 options A and B for 2004, and the Company has
purchased a forward contract for replacement power at a net cost of $3.2
million. The Company has also covered 54 percent of expected calls during 2005
at a net cost of $1.1 million.
Under the VJO Contract, Hydro Quebec has the right to reduce the load
factor from 75 percent to 65 percent a total three times over the life of the
contract. Hydro Quebec exercised the first of these load reduction options,
effective for the year 2003. The net cost of Hydro Quebec's exercise of this
option increased power supply expense during 2003 by approximately $1.2 million.
During 2003, Hydro Quebec exercised its second option to reduce the load factor
for 2004, which we estimate will increase power supply expense in 2004 by
approximately $1.0 million. Hydro Quebec exercised its final option in 2004 for
deliveries occurring principally during 2005, at an estimated cost of $1.0
million to $1.5 million, based on current wholesale market prices, for 2005.
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 requires 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 affect earnings. The current costs of both the 9701
arrangement and other forward purchase arrangements, including our Morgan
Stanley Contract, are being fully recovered in our retail rates. At June 30,
2004, the Company had a net regulatory asset of approximately $12.4 million
related to derivatives that the Company believes are probable of recovery. The
fair value of the regulatory asset is based on current estimates of future
market prices that are likely to change by material amounts.
Power supply expenses decreased $21.0 million or 21.9 percent in the first
half of 2004 compared with the same period in 2003, as a result of decreased
wholesale sales of electricity that were offset by a $25.9 million decline in
purchases under the Company's power supply contract with Morgan Stanley.
Power supply expenses from Vermont Yankee decreased $4.7 million or 24.2
percent during the first half of 2004 compared with the same period of 2003,
primarily due to a decrease in energy provided under the Power Purchase
Agreement between VY and ENVY, primarily for the outage reasons discussed
earlier. The sale of the VY generating plant is discussed under Part I, Item 1,
Note 2, "Investment in Associated Companies".
Company-owned generation expenses decreased $1.0 million or 23.2 percent in
the first half of 2004 compared with the same period in 2003, primarily due to
decreased output and fuel costs at the Stony Brook generating facility in which
we have an 8.8 percent joint ownership interest, and decreases in output and
fuel costs used to operate our other peak generation facilities.
The cost of power that we purchased from other companies decreased $15.3
million or 21.1 percent in the first half of 2004 compared with the same period
in 2003, primarily due to a $25.9 million decrease in purchases from Morgan
Stanley, that was partially offset by increased expenses to replace the
decreased output at the ENVY plant during outages and to supply increased retail
sales to customers.
OTHER OPERATING EXPENSES
Other operating expenses increased $731,000 or 20.0 percent in the second
quarter of 2004 compared with the same period in 2003 due to increased
administrative and general, customer service, and distribution expenses caused
by benefit and governance expenses. Other operating expenses increased $801,000
or 10.1 percent in the first half of 2004 compared with the same period in 2003
for the same reasons. We expect other operating expenses to grow by less than
10 percent by fiscal year end, when compared with 2003.
TRANSMISSION EXPENSES
Transmission expenses increased by approximately $539,000 or 15.4 percent
for the three months ended June 30, 2004 compared with the same period in 2003,
due to an increase in VELCO's debt service and other expenses for expanded
Vermont transmission facilities.
Transmission expenses increased by approximately $192,000 or 2.5 percent
for the six months ended June 30, 2004 compared with the same period in 2003 for
the same reasons.
The ISO New England (ISO-NE") was created to manage the operations of the
New England Power Pool ("NEPOOL"), effective May 1, 1999. ISO-NE operates a
market for all New England states for purchasers and sellers of electricity in
the deregulated wholesale energy markets. Sellers place bids for the sale of
their generation or purchased power resources and if demand is high enough the
output from those resources is sold.
During 2002, the Federal Energy Regulatory Commission ("FERC") accepted
ISO-NE's request to implement a Standard Market Design ("SMD") governing
wholesale energy sales in New England. ISO-NE 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 zone under the plan, although pricing may eventually be
determined on a more localized ("nodal") basis. ISO-NE and NEPOOL have
committed to facilitation of a stakeholder process to examine alternative
pricing options, including alternatives to nodal pricing, and to file their
report with FERC in July 2004. On July 1, 2004, ISO-NE filed its report
concluding that the existing load zones for energy pricing should not be
modified at this time because energy prices within these load zones, including
Vermont, are relatively uniform. ISO-NE did note, however that the load zones
should and will be reviewed at least every two years, or upon the introduction
of a significant change in circumstances, i.e., the implementation of a new
market, a substantial physical change to the NEPOOL system, or at the direction
of the FERC. We believe that nodal pricing could result in a material adverse
impact on our power supply and/or transmission costs, if adopted, as long as the
transmission facilities in Northwestern Vermont are constrained.
On October 31, 2003, ISO-NE, together with New England's principal
transmission system owners, including VELCO, filed a request for designation of
ISO-NE as a regional transmission organization for New England ("RTO-NE"). On
March 24, 2004, the FERC conditionally approved ISO-NE's designation as an RTO.
ISO-NE will continue to perform all of its current responsibilities and will
also become the transmission provider for the New England region, acquiring
operational authority over daily management of the transmission system. Also on
October 31, 2003, certain transmission owners in New England, including the
Company, reached an agreement to submit a tariff, agreements and other documents
to the FERC to include costs associated with certain transmission facilities,
known as the Highgate Facilities, of which the Company is a part owner, in
region-wide rates as set forth in the RTO-NE proposal. The Company and other
transmission owners are currently working with ISO-NE to make operating
arrangements in advance of making a filing with the FERC.
VELCO, the owner and operator of Vermont's principal electric transmission
system assets, 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. We own
approximately 29 percent of VELCO. The proposed Northwest Reliability Project
must be approved by the VPSB. Several Vermont municipalities, citizen groups
and individuals have intervened in the VPSB proceedings to oppose or request
modifications to the project. If approved, the project is estimated to cost
approximately $130 million through 2007. VELCO intends to finance the costs of
constructing the Northwest Reliability Project in part through increased equity
investment. The Company plans to invest approximately $20 million in VELCO to
support this and other transmission projects through 2007. Under current NEPOOL
and ISO-NE rules, which require qualifying large transmission project costs to
be shared among all New England utilities, most of the costs of the Northwest
Reliability Project will be allocated throughout the New England region, with
Vermont utilities responsible for approximately five percent of allocated costs.
In August 2003, a coalition of New England public utility commissions and
other parties challenged the NEPOOL and ISO-NE transmission cost allocation
rules. On December 18, 2003, FERC rejected this challenge. FERC's order is
subject to pending requests for rehearing and has been appealed to the US Court
of Appeals for the D.C. Circuit. If the current transmission cost allocation
rules are modified or eliminated, Vermont utilities, including the Company,
could be required to bear a greater proportion, and potentially all, of the cost
of the Northwest Reliability Project.
MAINTENANCE EXPENSES
Maintenance expenses increased $275,000 or 12.8 percent for the three
months ended June 30, 2004 compared with the same period in 2003, primarily due
to an increase in scheduled maintenance on distribution and hydro facilities.
The Company is increasing expenditures by approximately $600,000 for tree
clearing in rights of way to improve system reliability during 2004.
Maintenance expenses increased $188,000 or 4.2 percent for the six months ended
June 30, 2004 compared with the same period in 2003 for the same reasons.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses for the quarter ended June 30, 2004
increased $79,000 or 2.3 percent compared with the same period in 2003,
reflecting an increase in the depreciation of utility plant, offset by a
decrease in the amortization of demand side management assets. Depreciation and
amortization expenses increased $21,000 or 0.3 percent for the six months ended
June 30, 2004 compared with the same period in 2003 for the same reasons.
TAXES OTHER THAN INCOME TAXES
Other tax expense for the second quarter of 2004 decreased by $113,000 or
6.2 percent compared with the same period in 2003 due to reductions in property
taxes.
Other tax expense for the first six months of 2004 decreased by $230,000 or
6.2 percent compared with the same period in 2003 due to reductions in property
taxes.
INCOME TAXES
Income taxes increased $246,000 or 45.8 percent in the second quarter of
2004 compared with the same period in 2003 due to an increase in pretax book
income from operations.
Income taxes increased $174,000 or 5.9 percent in the first half of 2004
compared with the same period in 2003 for the same reason.
OTHER INCOME
Other income decreased $181,000 or 38.4 percent during the three months
ended June 30, 2004 compared with the same period in 2003, primarily due to
decreases in earnings of Vermont Yankee and VELCO. The Vermont Yankee decrease
in earnings was caused by a decrease in investments following a return of
capital to the Company arising from the sale of the Vermont Yankee nuclear plant
to ENVY. VELCO's earnings declined due to increases in debt service expense.
Other income decreased by $110,000 or 10.1 percent in first half of 2004
when compared with the same period in 2003, for the same reasons, partially
offset by the 2003 receipt of insurance proceeds.
INTEREST CHARGES
Interest charges decreased $136,000 or 7.6 percent in the second quarter of
2004 compared with the same period in 2003, due to a decrease in long-term debt
balances arising from the maturity of $8.0 million first mortgage bonds in
December 2003.
Interest charges decreased $300,000 or 8.4 percent in the first half of
2004 compared with the same period in 2003, for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
In the six months ended June 30, 2004, we spent $9.2 million principally
for expansion and improvements of our transmission, distribution and generation
plant, and environmental expenditures. We expect to spend approximately $12.4
million during the remainder of 2004, principally for improvements to
transmission, distribution and generation plant, and environmental expenditures.
During June 2004, 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 $30.0
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 no balance
outstanding on the Fleet-Sovereign Agreement at June 30, 2004. The
Fleet-Sovereign Agreement expires June 15, 2005.
The annual dividend was $0.76 per share for the year ended December 31,
2003. On February 9, 2004, the annual dividend rate was increased from $0.76
per share to $0.88 per share, a payout ratio of approximately 44 percent based
on 2003 earnings. The Company expects to increase the dividend on a consistent
basis in the first quarter of each year until the payout ratio falls between 50
percent and 70 percent of anticipated earnings. We believe this payout ratio to
be consistent with that of other electric utilities having similar risk
profiles.
The credit ratings of the Company's first mortgage bonds at June 30, 2004
were:
Fitch Moody's Standard & Poor's
- -------------------- ------- -----------------
First mortgage bonds BBB+ Baa1 BBB
Moody's affirmed the Company's senior secured debt rating at Baa1, with a stable
outlook on June 18, 2004.
Fitch Ratings affirmed the ratings of the Company's first mortgage bonds at
BBB+, with a stable outlook during August 2003; and
Standard and Poor's Ratings Services affirmed its BBB rating of the
Company's senior secured debt, with a stable outlook during August 2003.
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 Morgan
Stanley 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.
OFF-BALANCE SHEET ARRANGEMENTS - The Company does not use off-balance sheet
financing arrangements, such as securitization of receivables or obtaining
access to assets through special purpose entities. We have material power
supply commitments that are discussed in detail under the captions "Power
Contract Commitments" and "Power Supply Expenses." We also own an equity
interest in VELCO, which requires the Company to contribute capital when
required and to pay a portion of VELCO's operating costs, including its debt
service costs.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK AND OTHER
RISK FACTORS
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 restructuring 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.
DEFINED BENEFIT PLANS
Due to sharp declines in the equity markets during 2001 and 2002, the value
of assets held in trusts to satisfy the Company's defined benefit plan
obligations has decreased. The Company's defined benefit 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 defined benefit plan 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
made pension plan contributions totaling $4.5 million between September 1, 2002
and December 31, 2003. The Company intends to contribute between $2.0 million
and $3.0 million to its defined benefit plans by December 31, 2004.
As a result of our plan asset experience, at December 31, 2002, the Company
was required to recognize an additional minimum pension liability of $2.4
million, net of applicable income taxes. The liability was recorded as a
reduction to common equity through a charge to Other Comprehensive Income
("OCI"). Favorable pension plan investment returns during 2003 reduced the OCI
charge and related net liability by $587,000 at December 31, 2003. The 2002 OCI
charge and the 2003 OCI benefit had no effect on net income for either year.
MARKET RISK
We have created a power supply portfolio that meets approximately 90
percent of our estimated customer demand ("load") requirements through 2006.
Our power supply contracts and resources significantly reduce the Company's
exposure to volatility in wholesale energy market prices. The Company's power
supply contracts are described in more detail in Part I, Item 1, No. 3 above
under the heading "Power Contract Commitments."
A primary factor affecting future operating results is the volatility of
the wholesale electricity market. Implementation of New England's wholesale
market for electricity has increased volatility of wholesale power prices.
Periods frequently occur when weather, availability of power supply resources
and other factors cause significant differences between customer demand and
electricity supply. Because electricity cannot be stored, in these situations
the Company must buy or sell the difference into a marketplace that has
experienced volatile energy prices. Volatility and market price trends also
make it more difficult to extend or enter into new power supply contracts at
prices that avoid the need for rate relief.
The Company has established a risk management program designed to stabilize
cash flow and earnings by minimizing power supply risks, including counter party
credit risk. Transactions permitted by the risk management program include
futures, forward contracts, option contracts, swaps and transmission congestion
rights. These transactions are used to hedge the risk of fossil fuel and spot
market electricity price increases. Some of these transactions present the risk
of potential losses from adverse changes in commodity prices. Our risk
management policy specifies risk measures, the amount of tolerable risk
exposure, and authorization limits for transactions. Our principal power supply
contract counter-parties and generators, Hydro Quebec, Entergy Nuclear Vermont
Yankee, LLC and Morgan Stanley Capital Group, Inc., all currently have
investment grade credit ratings.
The Company has a contract with Morgan Stanley Capital Group, Inc. (the
"Morgan Stanley Contract") that is used to hedge our power supply costs against
increases in fossil fuel prices. Morgan Stanley purchases approximately 15
percent of the Company's power supply resources at index prices for fossil fuel
resources and specified prices for contracted resources and then sells power to
the Company at a fixed rate to serve pre-established load requirements. This
contract, along with other power supply commitments, allows us to fix the cost
of most of our power supply requirements, subject to power resource availability
and other risks. The Morgan Stanley Contract is a derivative under Statement of
Financial Accounting Standards No. 133 ("SFAS 133") and is effective through
December 31, 2006. Management has estimated the fair value of the future net
benefit of this arrangement at June 30, 2004, is approximately $12.2 million.
We currently have an arrangement that grants Hydro Quebec an option (the
"9701 arrangement") to call power at prices that are expected to be below
estimated future market rates. The 9701 arrangement is described in more detail
below under the heading "Power Supply Expenses." 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, 2004, is
approximately $24.6 million. We sometimes use forward contracts to hedge
forecasted calls by Hydro Quebec under the 9701 arrangement.
The table below presents the Company's market risk of the Morgan Stanley
and Hydro Quebec derivatives, estimated as the potential loss in fair value
resulting from a hypothetical ten percent adverse change in wholesale energy
prices, which nets to approximately $882,000. Actual results may differ
materially from the table illustration. Under an accounting order issued by the
VPSB, changes in the fair value of derivatives are deferred.
Commodity Price Risk At June 30, 2004
Fair Value(Cost) Market Risk
----------------- -------------
(in thousands)
Morgan Stanley Contract $ 12,210 $ 2,310
9701 Arrangement. . . . (24,560) (3,192)
----------------- -------------
(12,350) (882)
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, if any, 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.
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
Chief Financial Officer 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 Chief Financial Officer 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 three and six months ended June 30, 2004 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, 2004
-------------
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 meeting of shareholders held on May 20, 2004, there
were 5,064,188 shares of common stock outstanding and entitled to vote, of which
4,371,178 were represented in person or by proxy. The following matters were
submitted to a vote of the Company's shareholders at its annual meeting with the
voting results designated below each such matter:
1. Ratification of the appointment of Deloitte and Touche LLP as the
independent auditors for the Company for 2004 with 4,284,514 votes for, 59,709
votes against, and 29,655 votes abstaining.
2. Approval of the 2004 Stock Incentive Plan with 2,481,196 votes for,
904,638 votes against, 69,648 vote abstentions, and 915,696 broker non-votes
votes.
3. Approval of the proposal to amend and restate the Company's Restated
Articles of Association with 2,969,544 votes for, 412,251 votes against, 73,687
votes abstaining, and 915,696 broker non-votes.
4. Election of the nominees listed below as Directors of this Company for a
term of one year, with votes cast as indicated.
Votes
Directors Votes Against or
--------- For Withheld
--------- --------
Elizabeth A. Bankowski 3,915,625 455,553
Nordahl L. Brue, Chair 4,096,180 274,998
William H. Bruett. . . 4,043,870 327,308
Merrill O. Burns . . . 3,991,591 379,587
David R. Coates. . . . 4,073,849 297,329
Christopher L. Dutton. 4,081,553 289,625
Kathleen C. Hoyt . . . 3,961,988 409,190
Euclid A. Irving . . . 4,058,413 312,765
Marc A. vanderHeyden . 3,984,256 386,922
There were no broker non-votes with respect to the election of directors.
ITEM 5. Other Information NONE
ITEM 6.
(A) EXHIBITS
----------
Exhibit 3-A, Amended and Restated Articles of Incorporation.
Exhibit 10-d-64, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director Elizabeth A. Bankowski as of July 19, 2004.
Exhibit 10-d-65, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director Nordahl L. Brue as of July 19, 2004.
Exhibit 10-d-66, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director William H. Bruett as of July 19, 2004.
Exhibit 10-d-67, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director Merrill O. Burns as of July 19, 2004.
Exhibit 10-d-68, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director David R. Coates as of July 19, 2004.
Exhibit 10-d-69, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director Kathleen C. Hoyt as of July 19, 2004.
Exhibit 10-d-70, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director Euclid A. Irving as of July 19, 2004.
Exhibit 10-d-71, Director's Deferred Stock Unit Agreement for the grant of
deferred stock units to Director Marc A. vanderHeyden as of July 19, 2004.
Exhibit 31.1, Certification by Christopher L. Dutton, President and Chief
Executive Officer of Green Mountain Power Corporation, pursuant to Rules
13a-14(a) and Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 31.2, Certification by Robert J. Griffin, Chief Financial Officer, Vice
President and Treasurer of Green Mountain Power Corporation, pursuant to Rules
13a-14(a) and Rule 15d-14(a) promulgated under the Securities Exchange Act of
1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 32.1, Certification by Christopher L. Dutton, President and Chief
Executive Officer of Green Mountain Power Corporation, and Robert J. Griffin,
Chief Financial Officer, Vice President and Treasurer of Green Mountain Power
Corporation, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
(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 report on Form 8-K (Item 12), dated May 4, 2004, was furnished to report that
the Company issued a press release regarding its earnings for the quarter ended
March 31, 2004 (not incorporated by reference).
A report on Form 8-K (Items 5 and 7), dated May 14, 2004, was filed to report
that the Company issued a press release regarding certain corporate governance
matters.
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 6, 2004 /s/ Christopher L. Dutton
----------------------------
Christopher L. Dutton, Chief Executive Officer
and President
Date: August 6, 2004 /s/ Robert J. Griffin
------------------------
Robert J. Griffin, Chief Financial Officer
Vice President and Treasurer