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 MARCH 31, 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
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(STATE OR OTHER JURISDICTION OF INCORPORATION (I.R.S. EMPLOYER
IDENTIFICATION NO.)
OR ORGANIZATION)
163 ACORN LANE
COLCHESTER, VT 05446
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ADDRESS OF PRINCIPAL EXECUTIVE OFFICES (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (802) 864-5731
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INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES X NO
---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
CLASS - COMMON STOCK OUTSTANDING AT APRIL 30, 2004 $3.33 1/3 PAR
--------------------------- ------------------------------
VALUE 5,068,688
--
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 MONTHS ENDED MARCH 31,
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 27
ITEM 4. CONTROLS AND PROCEDURES 29
PART II. OTHER INFORMATION 31
Exhibits and Reports on Form 8-K 31
Signatures 32
Certifications 33
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
UNAUDITED
---------
THREE MONTHS ENDED
MARCH 31
2004 2003
-------- --------
(in thousands, except per share data)
Retail Revenues. . . . . . . . . . . . . . . . . . . . . . . 54,205 53,020
Whoesale Revenues. . . . . . . . . . . . . . . . . . . . . . 8,918 19,925
-------- --------
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $63,123 $72,945
-------- --------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 9,993 9,539
Company-owned generation. . . . . . . . . . . . . . . . . . 2,231 3,372
Purchases from others . . . . . . . . . . . . . . . . . . . 27,965 36,276
Other operating. . . . . . . . . . . . . . . . . . . . . . . 4,352 4,400
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,710 4,057
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 2,271 2,115
Depreciation and amortization. . . . . . . . . . . . . . . . 3,489 3,548
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,778 2,019
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 2,315 2,388
-------- --------
Total operating expenses. . . . . . . . . . . . . . . . . 58,104 67,714
-------- --------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 5,019 5,231
-------- --------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 256 413
Allowance for equity funds used during construction. . . . . 115 85
Other income (deductions), net . . . . . . . . . . . . . . . (35) 136
-------- --------
TOTAL OTHER INCOME. . . . . . . . . . . . . . . . . . . . 336 634
-------- --------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,633 1,762
Other interest . . . . . . . . . . . . . . . . . . . . . . . 56 76
Allowance for borrowed funds used during construction. . . . (74) (58)
-------- --------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,615 1,780
-------- --------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 3,740 4,085
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . - 1
-------- --------
Income from continuing operations. . . . . . . . . . . . . . 3,740 4,084
Income (loss) from discontinued segment,
including provisions for operating
losses during phaseout period. . . . . . . . . . . . . . . . (6) (13)
-------- --------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 3,734 $ 4,071
======== ========
UNAUDITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME THREE MONTHS
ENDED
MARCH 31
2004 2003
------ ------
Net income. . . . . . . . . . . . . . . . . . . . . $3,734 $4,071
Other comprehensive income, net of tax. . . . . . - -
------ ------
Comprehensive income. . . . . . . . . . . . . . . . $3,734 $4,071
====== ======
Basic earnings per share . . . . . . . . . . . . . $ 0.74 $ 0.82
Diluted earnings per share . . . . . . . . . . . . 0.72 0.80
Cash dividends declared per share. . . . . . . . . $ 0.22 $ 0.19
Weighted average common shares outstanding-basic . 5,046 4,959
Weighted average common shares outstanding-diluted 5,205 5,118
The accompanying notes are an integral part of these consolidated financial
statements.
Unaudited
GREEN MOUNTAIN POWER CORPORATION For the Three Months Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS March 31
2004 2003
-------- --------
OPERATING ACTIVITIES:
Income from continuing operations before preferred dividends . . . . . . . . . . . . . . $ 3,739 $ 4,073
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,489 3,548
Dividends from associated companies less equity income . . . . . . . . . . . . . . . . . 46 35
Allowance for funds used during construction . . . . . . . . . . . . . . . . . . . . . . (189) (143)
Amortization of deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . 851 1,120
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 361 570
Benefit plan contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (250) -
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (46) (42)
Arbitration costs recovered (deferred) . . . . . . . . . . . . . . . . . . . . . . . . . - -
Rate levelization liability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (742) 87
Environmental and conservation deferrals, net. . . . . . . . . . . . . . . . . . . . . . (384) (1,711)
Changes in:
Accounts receivable and accrued utility revenues . . . . . . . . . . . . . . . . . . . . 1,311 186
Prepayments, fuel and other current assets . . . . . . . . . . . . . . . . . . . . . . . 403 (264)
Accounts payable and other current liabilities . . . . . . . . . . . . . . . . . . . . . (420) (1,788)
Accrued income taxes payable and receivable. . . . . . . . . . . . . . . . . . . . . . . 2,184 2,067
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,322 273
-------- --------
Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . . . . 11,675 8,011
INVESTING ACTIVITIES:
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,216) (3,460)
Investment in associated companies . . . . . . . . . . . . . . . . . . . . . . . . . . . - -
Return of Capital from associated companies. . . . . . . . . . . . . . . . . . . . . . . 80 15
Investment in nonutility property. . . . . . . . . . . . . . . . . . . . . . . . . . . . (40) (66)
-------- --------
Net cash used in investing activities. . . . . . . . . . . . . . . . . . . . . . . . . . (4,176) (3,510)
-------- --------
FINANCING ACTIVITIES:
Payments to acquire treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . - (3)
Repurchase of preferred stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - -
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 377 71
Reduction in long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - -
Short-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (500) (2,250)
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,111) (944)
-------- --------
Net cash used in financing activities. . . . . . . . . . . . . . . . . . . . . . . . . . (1,234) (3,126)
-------- --------
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . 6,265 1,375
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . 786 1,909
-------- --------
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . 7,051 3,284
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized). . . . . . . . . . . . . . . . . . . . . . . . . . 1,022 1,024
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,193 -
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
MARCH 31 DECEMBER 31
--------
2004 2003 2003
-------- -------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . $324,685 $312,867 $324,900
Less accumulated depreciation . . . . . . . 112,589 105,340 110,111
-------- -------- --------
Net utility plant . . . . . . . . . . . . . 212,096 207,527 214,789
Property under capital lease. . . . . . . . 5,047 5,467 5,047
Construction work in progress . . . . . . . 12,494 11,032 9,026
-------- -------- --------
Total utility plant, net. . . . . . . . . . 229,637 224,026 228,862
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . 5,771 14,067 5,896
Other investments . . . . . . . . . . . . . 7,954 7,241 7,810
-------- -------- --------
Total other investments . . . . . . . . . . 13,725 21,308 13,706
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . 7,045 3,284 786
Accounts receivable, less allowance for
doubtful accounts of $690, $547 and $690. . 17,131 17,527 17,331
Accrued utility revenues. . . . . . . . . . 5,618 6,158 6,729
Fuel, materials and supplies, average cost. 4,301 3,567 4,498
Prepayments . . . . . . . . . . . . . . . . 1,640 1,924 1,922
Other . . . . . . . . . . . . . . . . . . . 504 425 422
-------- -------- --------
Total current assets. . . . . . . . . . . . 36,239 32,885 31,688
-------- -------- --------
DEFERRED CHARGES
Demand side management programs . . . . . . 6,853 6,379 6,713
Purchased power costs . . . . . . . . . . . 1,769 1,253 2,574
Pine Street Barge Canal . . . . . . . . . . 12,954 13,019 12,954
Net power supply deferral . . . . . . . . . 16,438 19,778 19,734
Power supply derivative asset . . . . . . . 9,382 7,790 3,990
Other deferred charges. . . . . . . . . . . 9,561 11,009 9,625
-------- -------- --------
Total deferred charges. . . . . . . . . . . 56,957 59,228 55,590
-------- -------- --------
NON-UTILITY
Other current assets. . . . . . . . . . . . 256 8 217
Property and equipment. . . . . . . . . . . 248 249 248
Other assets. . . . . . . . . . . . . . . . 605 730 640
-------- -------- --------
Total non-utility assets. . . . . . . . . . 1,109 987 1,105
-------- -------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . $337,667 $338,434 $330,951
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
MARCH 31 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
5,891,827, and 5,789,596 and 5,860,854). . . . . $ 19,640 $ 19,300 $ 19,536
Additional paid-in capital . . . . . . . . . . . 76,355 75,394 76,081
Retained earnings. . . . . . . . . . . . . . . . 25,406 19,300 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. . . . . . . . . . . . 102,913 94,919 99,915
Redeemable cumulative preferred stock. . . . . . - 55 -
Long-term debt, less current maturities. . . . . 93,000 93,000 93,000
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . . 195,913 187,974 192,915
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . 4,930 5,458 4,963
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . - 30 -
Current maturities of long-term debt . . . . . . - 8,000 -
Short-term debt. . . . . . . . . . . . . . . . . - 250 500
Accounts payable, trade and accrued liabilities. 6,436 5,149 8,493
Accounts payable to associated companies . . . . 7,512 8,668 6,821
Rate levelization liability. . . . . . . . . . . 2,228 4,177 2,970
Accrued income taxes . . . . . . . . . . . . . . 2,817 6,650 633
Customer deposits. . . . . . . . . . . . . . . . 969 904 968
Interest accrued . . . . . . . . . . . . . . . . 1,788 1,873 1,152
Other. . . . . . . . . . . . . . . . . . . . . . 1,486 904 1,178
--------- --------- ---------
Total current liabilities. . . . . . . . . . . . 23,236 36,605 22,715
--------- --------- ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . . 25,820 27,568 23,724
Accumulated deferred income taxes. . . . . . . . 34,438 27,112 34,009
Unamortized investment tax credits . . . . . . . 2,780 3,060 2,848
Pine Street Barge Canal cleanup liability. . . . 6,972 7,192 7,356
Accumulated cost of removal. . . . . . . . . . . 21,521 19,947 21,238
Other deferred liabilities . . . . . . . . . . . 20,575 21,703 19,693
--------- --------- ---------
Total deferred credits . . . . . . . . . . . . . 112,106 106,582 108,868
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Net liabilities of discontinued segment. . . . . 1,482 1,815 1,490
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . . 1,482 1,815 1,490
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . $337,667 $338,434 $330,951
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
UNAUDITED
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS THREE MONTHS ENDED
In thousands MARCH 31
2004 2003
-------- --------
Balance - beginning of period. . . . . . . . . . . . $22,786 $16,171
Net Income . . . . . . . . . . . . . . . . . . . . . 3,734 4,072
Cash Dividends-redeemable cumulative preferred stock - (1)
Other. . . . . . . . . . . . . . . . . . . . . . . . (2) -
Cash Dividends-common stock. . . . . . . . . . . . . (1,112) (942)
-------- --------
Balance - end of period. . . . . . . . . . . . . . . $25,406 $19,300
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 remaining $2.2 million will be used to offset
increased costs or write off regulatory assets during 2004. For the three
months ended March 31, 2004 and 2003, the Company recognized deferred revenues
of $749,000 and $271,000, respectively.
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 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 three months ended March 31, 2004 and 2003,
respectively.
Three Months Ended
Pro-forma net income March 31
2004 2003
------ ------
In thousands, except per share amounts
Net income reported. . . . . . . . . . $3,734 $4,071
Pro-forma net income . . . . . . . . . 3,714 4,034
Earnings per share
As reported-basic. . . . . . . . . . 0.74 0.82
Pro-forma basic. . . . . . . . . . . 0.74 0.81
As reported-diluted. . . . . . . . . 0.72 0.80
Pro-forma diluted. . . . . . . . . . 0.71 0.79
UNREGULATED OPERATIONS
Our wholly owned subsidiaries are Northern Water Resources, Inc. ("NWR");
Green Mountain Propane Gas Company Limited ("GMPG"); GMP Real Estate
Corporation; Green Mountain Power Investment Company ("GMPIC"); and Green
Mountain Resources, Inc. ("GMRI"). We also have a rental water heater program
that is not regulated by the VPSB. The results of these subsidiaries, excluding
NWR, and the Company's unregulated rental water heater program are included in
earnings of affiliates and non-utility operations in the Other (Deductions)
Income section of the Consolidated Statements of Income.
2. INVESTMENT IN ASSOCIATED COMPANIES
We recognize net income from our affiliates (companies in which we have
ownership interests) listed below based on our percentage ownership (equity
method).
VERMONT YANKEE NUCLEAR POWER CORPORATION
PERCENT OWNERSHIP: 33.6% COMMON
Three months ended
March 31
2004 2003
------- -------
(in thousands)
Gross Revenue. . . . . $49,146 $47,968
Net Income Applicable. 143 685
to Common Stock
Equity in Net Income . 48 127
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. See Note K for further information concerning our
long-term power contract with VYNPC.
During May 2002, prior to the sale of the plant to ENVY, the VYNPC plant
had fuel rods that required repair, a maintenance requirement that is not unique
to VYNPC. VYNPC closed the plant for a twelve-day period, beginning on May 11,
2002, to repair the rods. The Company's share of the cost for the repair,
including incremental replacement energy costs, was approximately $2.0 million.
The Company received an accounting order from the VPSB on August 2, 2002,
allowing it to defer the additional costs related to the outage, and believes
that such amounts are probable of future recovery. In 2003, the Company
received a credit of $600,000 from VYNPC and in April 2004, the Company received
permission from the VPSB to apply the credit to reduce the $2.0 million
regulatory asset.
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.
In response to a recent NRC inspection, ENVY has determined that two spent
fuel rod segments are not in their documented location in the spent fuel pool.
ENVY engineers are reviewing storage records and performing an inspection of the
spent fuel pool to determine the location of the rod segments, which are about
the diameter of a pencil. One segment is about the length of a pencil, the
other segment is about 17 inches long. According to station documentation, in
1979, the radioactive rods were placed in a special stainless steel container in
the spent fuel pool after a fuel inspection to address fuel-cladding
deficiencies.
On May 5, 2004, ENVY informed VYNPC that it believes that VYNPC is
responsible under the Purchase and Sale Agreement between VNYPC and ENVY, for
all costs arising in connection with ENVY's inspection. VYNPC has informed us
that it is reviewing ENVY's May 5, 2004 communication and studying its options.
We cannot predict the outcome of this matter at this time.
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
March 31
2004 2003
------ ------
(in thousands)
Gross Revenue . . . . $6,333 $5,635
Net Income. . . . . . 310 273
Equity in Net Income. 46 106
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 $8.1 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 Vermont Department
of Public Service. 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 meet its revenue
requirements, the Company will implement the lesser rate increase.
The Company may seek additional rate increases 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 core 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 either (i) all or
part of our portfolio of power resources at predefined operating and pricing
parameters or (ii) any power resources available to us, provided that sales of
power from sources other than Company-owned generation comply with the
predefined operating and pricing parameters. Morgan Stanley sells to the
Company, at a predefined price, power sufficient to serve pre-established load
requirements. Morgan Stanley is also responsible for scheduling supply
resources. 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. 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 $64 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 March 31, 2004, Hydro Quebec had purchased 513,000
MWh under option B. The Company expects Hydro Quebec to call its remaining
entitlements under option B during 2004 and 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.
We believe that it is probable that Hydro Quebec will exercise options A
and B for 2004, and the Company has purchased replacement power at a net cost of
$3.2 million. Hydro Quebec has exercised its option to purchase 52,000 MWh
during July 2004 as anticipated by the Company. 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. We expect Hydro Quebec to exercise its third 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.
It is possible our estimate of future power supply costs could differ materially
from actual results.
4. SEGMENTS AND RELATED INFORMATION
The Company's electric utility operation is its only operating segment.
The electric utility is engaged in the distribution and sale of electrical
energy in the State of Vermont and also reports the results of its wholly owned
unregulated subsidiaries (GMPG, GMRI, GMPIC and GMP Real Estate) and the rental
water heater program as a separate line item in the Other Income section in the
Consolidated Statement of Income.
NWR is an unregulated business that invested in energy generation, energy
efficiency and wastewater treatment projects. As of March 31, 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.
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 80 percent
of our retail load.
All of the Company's power supply contract costs are currently being
recovered through rates approved by the VPSB.
We expect approximately 90 percent of our estimated customer demand
("load") requirements through 2006 to be met by these contracts and by our
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, Entergy Nuclear Vermont Yankee, LLC ("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 March 31, 2004, to be approximately $9.4 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 March 31, 2004 is
approximately $25.8 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% $ 52 2006
9701 Arrangement. . . . Black-Scholes 3.8% 48%-27% $ 65 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 $1.2 million. 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 March 31, 2004
Fair Value(Cost) Market Risk
----------------- -------------
(in thousands)
Morgan Stanley Contract $ 9,382 $ 2,440
9701 Arrangement. . . . (25,820) (3,615)
----------------- -------------
(16,438) (1,175)
If a derivative instrument is terminated early because it is probable that a
transaction or forecasted transaction will not occur, any gain or loss would be
recognized in earnings immediately. For derivatives held to maturity, the
earnings impact would be recorded in the period that the derivative is sold or
matures.
6. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS 143") prescribes fair value accounting for asset
retirement liabilities, including nuclear decommissioning obligations, and
requires recognition of such liabilities at the time incurred. The Company has
recognized, as a liability, an asset retirement obligation for accumulated costs
of removal, which totaled approximately $21.2 million and $19.9 million at March
31, 2004 and 2003, respectively, and increased plant and equipment balances by
the same amount as a result of this accounting pronouncement.
In December 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-based Compensation-Transition and
Disclosure" ("SFAS 148"). SFAS 148 amends Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation", to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting and reporting for stock-based employee compensation and
amended disclosure provisions for stock-based compensation. The application of
this accounting standard is not expected to materially impact the Company's
financial position or results of operations.
In January 2003 and December 2003, the Financial Accounting Standards Board
issued Interpretation 46 and 46R (Revised), Consolidation of Variable Interest
Entities. This standard will require an enterprise that is the primary
beneficiary of a variable interest entity to consolidate that entity. The
Interpretation must be applied to any existing interests in variable interest
entities beginning in 2004. The Company does not expect to consolidate any
existing interest in unconsolidated entities as a result of Interpretation 46.
In December 2003, the FASB issued Statement of Financial Accounting
Standards No. 132 (revised 2003), "Employers" Disclosures about Pensions and
Other Postretirement Benefits ("SFAS 132"). In an effort to provide the public
with better and more complete information, the standard requires that companies
provide more details about their plan assets, benefit obligations, cash flows,
benefit costs and other relevant information. The guidance is effective for
fiscal years ending December 15, 2003 and for quarters beginning after December
15, 2003. We have adopted the disclosures required by the standard.
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. In December 2003, the FASB
issued Staff Position ("FSP") 106-1, "Accounting and Disclosure Requirements
related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003" (the "Act"). The Act provides for drug benefits for certain retirees
under a new Medicare Part D program. For employers like the Company there are
subsidies available which are inherent in the Act. The FASB allowed, and the
Company elected, a one-time deferral of the recognition of the impact of the Act
in the employer's accounting until formal guidance is issued. As a result, the
provisions of the Act are not yet reflected in financial statements or benefits
disclosure. The issuance of formal accounting guidance may require a change to
previously reported information.
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.
Reconciliation of net income available Three months ended
for common shareholders and average shares December 31,
2004 2003
------ ------
(in thousands)
Net income before preferred dividends. . $3,734 $4,072
Preferred stock dividend requirement . . - 1
------ ------
Net income applicable to common
stock . . . . . . . . . . . . . . . . $3,734 $4,071
====== ======
Average number of common shares-basic. . 5,046 4,959
Dilutive effect of stock options . . . . 159 159
------ ------
Average number of common shares-diluted. 5,205 5,118
====== ======
GREEN MOUNTAIN POWER CORPORATION
PART I-ITEM 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
MARCH 31, 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 70 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
March 31
2004 2003
----- -----
Utility business . . . . $0.72 $0.80
Unregulated businesses . 0.02 0.02
----- -----
Earnings from:
Continuing operations. . 0.74 0.82
Discontinued operations. - -
----- -----
Basic earnings per share $0.74 $0.82
===== =====
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.72 in the quarter ended March 31, 2004, compared with utility earnings of
$0.80 per share in the first quarter of 2003. Earnings in 2004 were lower than
the first quarter of 2003 due to a one time benefit from additional energy
deliveries in 2003 that occurred at a time when we could sell that excess power
in the wholesale market at unusually high prices. The Company estimates that
the increase in energy deliveries added approximately $0.15 per share to 2003
earnings.
UNREGULATED BUSINESSES
Earnings from unregulated businesses, principally from the Company's water
heater rental program, included in results from continuing operations for the
three ended March 31, 2004 did not change materially when compared with the same
periods in 2003. A financial summary for these businesses follows:
Three Months Ended
March 31
2004 2003
----- -----
(In thousands)
Revenue. . . . $ 243 $ 250
Expense. . . . 150 144
----- -----
Net Income . . $ 93 $ 106
===== =====
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatt hour ("MWh") sales and average
number of customers for the three months ended March 31, 2004 and 2003 are
summarized below:
Three months ended
March 31
2004 2003
-------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 53,348 $ 52,437
Sales for Resale. . . 8,918 19,925
Other . . . . . . . . 857 583
-------- ----------
Total Operating Revenues. $ 63,123 $ 72,945
======== ==========
MWh Sales-Retail. . . . . 517,231 508,464
MWh Sales for Resale. . . 145,701 545,918
-------- ----------
Total MWh Sales . . . . . 662,932 1,054,382
======== ==========
Average Number of Customers
Three months ended
March 31
2004 2003
------ ------
Residential . . . . . . . 75,461 74,583
Commercial and Industrial 13,466 13,263
Other . . . . . . . . . . 61 65
------ ------
Total Number of Customers. . 88,988 87,911
====== ======
REVENUES
Total operating revenues in the first quarter of 2004 decreased $9.8
million or 13.5 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 $910,000 in retail operating revenue. The increase in retail
revenues had a favorable impact on earnings and resulted principally from
customer growth and an increase in deferred revenue recognition. Total retail
MWh sales of electricity in the first quarter of 2004 increased 1.7 percent from
the same quarter of 2003, primarily as a result of an increase in commercial and
industrial sales of 1.8 percent and a 1.5 percent increase in residential sales.
Retail operating revenues reflected a $478,000 increase in the recognition
of deferred revenues during the first 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 March 31, 2004, the Company has $2.2 million in remaining
unrecognized deferred revenues, which will be used to offset increased costs 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. IBM has
recently announced plans to add 100 positions to its local workforce.
We sell wholesale electricity to others for resale. Our revenue from
wholesale MWh sales of electricity decreased approximately $11.0 million or 55.2
percent in the first 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. 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 $9.0 million or 14.5 percent in the first
quarter of 2004 compared with the same period in 2003, as a result of an $11.9
million decline in costs under the Company's power supply contract with Morgan
Stanley, and a $1.1 million decrease in company-owned generation expenses,
partially offset by increases in power purchased from NEPOOL and power purchased
to supply increased retail sales.
Power supply expenses from VYNPC increased $450,000 or 4.8 percent during
the first quarter of 2004 compared with the same period of 2003, primarily due
to increased output at the Entergy nuclear power plant.
Company-owned generation expenses decreased $1.1 million or 33.9 percent in
the first quarter of 2004 compared with the same period in 2003, primarily due
to decreased 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 $8.3
million or 22.9 percent in the first quarter of 2004 compared with the same
period in 2003, primarily due to an $11.9 million decrease in cost of power
purchased from Morgan Stanley, partially offset by an increase in costs of power
purchased from NEPOOL and other sources.
During the first quarter of 2004, $771,000 in power supply expense was
recognized to reflect the costs associated with the Company's 9701 arrangement
with Hydro Quebec compared with $1.4 million in power supply expense for the
same quarter in 2003. The cumulative amount of power purchased to date by Hydro
Quebec under option B is approximately 513,000 MWh, out of a total of 600,000
MWh which may be called over the life of the arrangement.
We believe that it is probable that Hydro Quebec will exercise 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. Hydro Quebec has exercised its option to
purchase 52,000 MWh during July 2004 as anticipated by the Company. The Company
has also covered 54 percent of expected calls during 2005 at a net cost of $1.1
million.
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 March 31,
2004, the Company had a net regulatory asset of approximately $16.4 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.
OTHER OPERATING EXPENSES
Other operating expenses did not change materially in the first quarter of
2004 compared with the same period in 2003.
TRANSMISSION EXPENSES
Transmission expenses decreased by approximately $347,000 or 8.6 percent
for the three months ended March 31, 2004 compared with the same period in 2003,
due to a reduction in the amount of pool transmission expense allocated from the
rest of New England as a result of changes in cost allocation methods used by
the Independent System Operator of New England ("ISO-NE" or "ISO New England").
The ISO New England 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. We believe that nodal pricing could result in a
material adverse impact on our power supply and/or transmission costs, if
adopted.
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 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.
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 $156,000 or 7.4 percent for the three months
ended March 31, 2004 compared with the same period in 2003, primarily due to an
increase in scheduled maintenance on distribution and hydro facilities.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses for the quarter ended March 31, 2004
decreased $59,000 or 1.7 percent compared with the same period in 2003,
reflecting a decrease in the amortization of demand side management assets.
TAXES OTHER THAN INCOME TAXES
Other tax expense for the first quarter of 2004 decreased by $241,000 or
11.9 percent compared with the same period in 2003 due to reductions in property
taxes.
INCOME TAXES
Income taxes decreased $73,000 or 3.06 percent in the first quarter of 2004
compared with the same period in 2003 due to a decrease in pretax book income
from operations.
OTHER INCOME
Other income decreased $298,000 or 47.0 percent during the three months
ended March 31, 2004 compared with the same period in 2003, primarily due to the
2003 receipt of insurance proceeds.
INTEREST CHARGES
Interest charges decreased $165,000 or 9.21 percent in the first 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.
LIQUIDITY AND CAPITAL RESOURCES
In the three months ended March 31, 2004, we spent $4.8 million principally
for expansion and improvements of our transmission, distribution and generation
plant, and environmental expenditures. We expect to spend approximately $16.8
million during the remainder of 2004, principally for improvements to
transmission, distribution and generation plant, and environmental expenditures.
During June 2003, the Company negotiated a 364-day revolving credit
agreement (the "Fleet-Sovereign Agreement") with Fleet Financial Services
("Fleet") joined by Sovereign Bank. The Fleet-Sovereign Agreement is for $20.0
million, unsecured, and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There was no balance
outstanding on the Fleet-Sovereign Agreement at March 31, 2004. The
Fleet-Sovereign Agreement expires June 16, 2004. There was no non-utility
short-term debt outstanding at March 31, 2004. The Company expects to obtain or
renew revolving credit arrangements with similar terms prior to June 16, 2004.
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 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 March 31, 2004
were:
Fitch Moody's Standard & Poor's
-------------------- ------- -----------------
First mortgage bonds BBB+ Baa1 BBB
During August 2003, the three credit rating agencies reviewed the Company's
financial position and concluded the following:
Moody's affirmed the Company's senior secured debt rating at Baa1, with a
stable outlook.
Fitch Ratings affirmed the ratings of the Company's first mortgage bonds at
BBB+, with a stable outlook; and
Standard and Poor's Ratings Services affirmed its BBB rating of the
Company's senior secured debt, with a stable outlook.
In the event of a change in the Company's first mortgage bond credit rating
to below investment grade, scheduled payments under the Company's first mortgage
bonds would not be affected. Such a change would require the Company to post
what would currently amount to a $4.3 million bond under our remediation
agreement with the EPA regarding the Pine Street Barge Canal site. The 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 expect approximately 90 percent of our estimated customer demand
("load") requirements through 2006 to be met by our existing power supply
contracts and by our generation and other power supply resources. These
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. 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 the majority 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 March 31, 2004, is approximately $9.4 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 March 31, 2004, is
approximately $25.8 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 $1.2 million. 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 March 31, 2004
Fair Value(Cost) Market Risk
----------------- -------------
(in thousands)
Morgan Stanley Contract $ 9,382 $ 2,440
9701 Arrangement. . . . (25,820) (3,615)
----------------- -------------
(16,438) (1,175)
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 Controller and Treasurer concluded that the Company's disclosure
controls and procedures are effective in timely alerting them to material
information relating to the Company (including its consolidated subsidiaries)
required to be included in the Company's periodic SEC filings. There has been
no change in the Company's internal control over financial reporting during the
quarter ended March 31, 2004 that has materially affected, or is reasonably
likely to materially affect, the Company's internal control over financial
reporting.
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
MARCH 31, 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
NONE
ITEM 5. Other Information NONE
ITEM 6.
(A) EXHIBITS
----------
Exhibit 31.1 and Exhibit 31.2, Certification by Officers of Financial
Information and Disclosure Controls and Procedures required by Section 302 of
the Sarbanes-Oxley Act of 2002 accompanies this quarterly report.
Exhibit 32.1, Certification by Officers of Financial Information and Internal
Controls required by Section 906 of the Sarbanes-Oxley Act of 2002 accompanies
this quarterly report.
(B) REPORTS ON FORM 8-K
---------------
The following filings on Form 8-K were filed by the Company on the topics
and dates indicated:
NONE
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: May 10, 2004 /s/ Christopher L. Dutton
----------------------------
Christopher L. Dutton, Chief Executive Officer
and President
Date: May 10, 2004 /s/ Robert J. Griffin
------------------------
Robert J. Griffin, Chief Financial Officer
Vice President and Treasurer