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, 2002
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OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO ___________
COMMISSION FILE NUMBER 1-8291
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GREEN MOUNTAIN POWER CORPORATION
--------------------------------
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
VERMONT 03-0127430
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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
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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 AUGUST 9, 2002
- --------------------------- ----------------------------------
$3.33 1/3 PAR VALUE 5,723,540
GREEN MOUNTAIN POWER CORPORATION
INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
AT AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30,
2002 AND 2001
Financial Statements Page
Consolidated Statements of Income 3
Consolidated Statements of Cash Flows 4
Consolidated Balance Sheets 5
Notes to Consolidated Financial Statements 7
Management's Discussion and Analysis of Financial Condition 16
And Results of Operations
Other Information 25
Exhibits and Reports on Form 8-K 25
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED COMPARATIVE INCOME STATEMENTS
UNAUDITED
----------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30 JUNE 30
2002 2001 2002 2001
-------- -------- --------- ---------
In thousands, except per share data
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $65,135 $67,471 $134,001 $142,267
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 8,191 5,737 16,265 19,422
Company-owned generation. . . . . . . . . . . . . . . . . . 617 (133) 1,578 2,243
Purchases from others . . . . . . . . . . . . . . . . . . . 37,588 40,166 75,734 78,541
Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,547 4,405 7,054 7,773
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 4,002 3,544 7,972 7,002
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 2,059 2,078 4,274 3,535
Depreciation and amortization. . . . . . . . . . . . . . . . 3,408 3,623 6,939 7,312
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,934 1,915 3,905 3,903
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 975 1,861 3,025 3,687
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 62,321 63,196 126,746 133,418
-------- -------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 2,814 4,275 7,255 8,849
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 535 584 1,069 1,135
Allowance for equity funds used during construction. . . . . 49 45 122 59
Other income (deductions), net . . . . . . . . . . . . . . . 15 (47) (53) (74)
-------- -------- --------- ---------
TOTAL OTHER INCOME (DEDUCTIONS) . . . . . . . . . . . . . 599 582 1,138 1,120
-------- -------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 3,413 4,857 8,393 9,969
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,254 1,547 2,613 3,095
Other interest . . . . . . . . . . . . . . . . . . . . . . . 295 232 508 710
Allowance for borrowed funds used during construction. . . . (22) (41) (54) (103)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,527 1,738 3,067 3,702
-------- -------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 1,886 3,119 5,326 6,267
DISCONTINUED OPERATIONS
Preferred stock dividend requirement . . . . . . . . . . . . 11 235 95 469
-------- -------- --------- ---------
Income from continuing operations. . . . . . . . . . . . . . 1,875 2,884 5,231 5,798
Net income from discontinued segment
operations . . . . . . . . . . . . . . . . . . . . . . . . . -
Loss on disposal, including provisions for
operating losses during phaseout period. . . . . . . . . . . - (150) - (150)
-------- -------- --------- ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 1,875 $ 2,734 $ 5,231 $ 5,648
======== ======== ========= =========
Common stock data
Basic earnings per share . . . . . . . . . . . . . . . . . . $ 0.33 $ 0.49 $ 0.92 $ 1.01
Diluted earnings per share . . . . . . . . . . . . . . . . . 0.32 0.47 0.89 0.98
Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.28 $ 0.28
Weighted average common shares outstanding-basic . . . . . . 5,711 5,615 5,701 5,602
Weighted average common shares outstanding-diluted . . . . . 5,877 5,777 5,866 5,759
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . $10,644 $ 2,639 $ 8,070 $ 493
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . 1,886 2,969 5,326 6,117
Preferred stock dividend requirement . . . . . . . . . . . . (11) (235) (95) (469)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . (50) - (50) -
Cash Dividends-common stock. . . . . . . . . . . . . . . . . (786) (771) (1,568) (1,539)
-------- -------- --------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . $11,683 $ 4,602 $ 11,683 $ 4,602
======== ======== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION UNAUDITED
---------
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED
JUNE 30
2002 2001
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OPERATING ACTIVITIES: In thousands
Net income before preferred stock dividend requirement $ 5,326 $ 6,117
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 6,939 7,312
Dividends from associated companies less equity income 97 21
Allowance for funds used during construction (176) (162)
Amortization of purchased power costs 3,611 2,008
Deferred income taxes 988 (1,714)
Deferred revenues - 3,158
Deferred purchased power costs (2,075) (1,966)
Accrued purchase power contract option call - (2,376)
Earnings cap deferral and rate levelization liability (4,309) 4,869
Environmental and conservation amortization (deferrals), net (800) (1,377)
Changes in:
Accounts receivable 1,209 1,034
Accrued utility revenues 849 708
Fuel, materials and supplies 173 (261)
Prepayments and other current assets 1,670 1,578
Accounts payable (2,363) (1,346)
Accrued income taxes payable and receivable 1,359 2,125
Other current liabilities (680) 389
Other 152 (1,856)
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Net cash provided by continuing operations 11,970 18,261
INVESTING ACTIVITIES:
Construction expenditures (8,638) (5,224)
Investment in nonutility property (100) (101)
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Net cash used in investing activities (8,738) (5,325)
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FINANCING ACTIVITIES:
Redemption of preferred stock (12,325) -
Issuance of common stock 472 806
Reduction in long term debt (5,100) (1,700)
Power supply option obligation, net - 244
Short-term debt, net 10,400 (10,608)
Cash dividends and preferred stock dividend requirement (1,664) (2,008)
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Net cash used in financing activities (8,217) (13,266)
-------------- ---------
Net increase(decrease) in cash and cash equivalents (4,985) (330)
Cash and cash equivalents at beginning of period 5,006 341
-------------- ---------
Cash and cash equivalents at end of period $ 21 $ 11
============== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) $ 3,053 $ 1,354
Income taxes, net 2,349 -
The accompanying notes are an integral part of these consolidated financial
statements.
PART I, ITEM 1
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
AT JUNE 30, DECEMBER 31,
2002 2001 2001
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In thousands
ASSETS
UTILITY PLANT
Utility plant, at original cost $ 306,127 $295,133 $302,489
Less accumulated depreciation 122,950 114,380 119,054
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Net utility plant 183,177 180,753 183,435
Property under capital lease 5,959 6,449 5,959
Construction work in progress 10,530 6,955 7,464
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Total utility plant, net 199,666 194,157 196,858
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OTHER INVESTMENTS
Associated companies, at equity 14,019 14,322 14,093
Other investments 7,108 6,598 6,852
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Total other investments 21,127 20,920 20,945
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CURRENT ASSETS
Cash and cash equivalents 21 11 5,006
Certficate of deposit, pledged as collateral - 15,936 -
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $613, $613, and $613 15,902 24,560 17,111
Accrued utility revenues 5,015 6,385 5,864
Fuel, materials and supplies, at average cost 3,885 4,316 4,058
Prepayments 413 889 1,976
Income tax receivable - - 1,699
Other 363 278 469
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Total current assets 25,599 52,375 36,183
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DEFERRED CHARGES
Demand side management programs 6,687 6,485 6,961
Purchased power costs 1,995 8,604 3,504
Pine Street Barge Canal 12,425 12,370 12,425
Power supply derivative deferral 33,694 15,714 37,313
Other 14,612 15,749 14,870
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Total deferred charges 69,413 58,922 75,073
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NON-UTILITY
Cash and cash equivalents - - -
Other current assets 8 8 8
Property and equipment 250 251 250
Other assets 775 847 817
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Total non-utility assets 1,033 1,106 1,075
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TOTAL ASSETS $ 316,838 $327,480 $330,134
============= ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
AT JUNE 30, DECEMBER 31,
2002 2001 2001
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In thousands except share data
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock equity
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,716,975, 5,641,009 and 5,701,010) $ 19,110 $ 18,802 $ 19,004
Additional paid-in capital 74,948 73,933 74,581
Retained earnings 11,683 4,602 8,070
Treasury stock, at cost (15,856 shares) (378) (378) (378)
--------- --------- ---------
Total common stock equity 105,363 96,959 101,277
Redeemable cumulative preferred stock 85 12,560 12,325
Long-term debt, less current maturities 71,000 70,400 74,400
--------- --------- ---------
Total capitalization 176,448 179,919 188,002
--------- --------- ---------
CAPITAL LEASE OBLIGATION 5,959 6,449 5,959
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock 150 235 235
Current maturities of long-term debt 8,000 9,700 9,700
Short-term debt 10,400 4,892 -
Accounts payable, trade and accrued liabilities 6,410 8,985 7,237
Accounts payable to associated companies 6,825 5,932 8,361
Accrued taxes 933 - -
Customer deposits 838 816 971
Purchased power call option liability - 5,901 -
Interest accrued 1,145 1,075 1,100
Energy East power supply obligation - 16,163 -
Rate Levelization liability 4,218 4,869 8,527
Deferred revenues - 3,158 -
Other 1,081 1,959 2,945
--------- --------- ---------
Total current liabilities 40,000 63,685 39,076
--------- --------- ---------
DEFERRED CREDITS
Power supply derivative liability 33,694 15,714 37,313
Accumulated deferred income taxes 24,888 24,071 23,759
Unamortized investment tax credits 3,272 3,554 3,413
Pine Street Barge Canal site cleanup 9,436 11,080 10,059
Other 20,787 21,374 20,852
--------- --------- ---------
Total deferred credits 92,077 75,793 95,396
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COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Other Liabilities 2,354 1,634 1,701
--------- --------- ---------
Total non-utility liabilities 2,354 1,634 1,701
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TOTAL CAPITALIZATION AND LIABILITIES $316,838 $327,480 $330,134
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2002
PART I-ITEM 1
1. SIGNIFICANT ACCOUNTING POLICIES
It is our opinion that the financial information contained in this report
reflects all normal, recurring adjustments necessary to present a fair statement
of results for the period reported, but such results are not necessarily
indicative of results to be expected for the year due to the seasonal nature of
our business and include other adjustments discussed elsewhere in this report
necessary to reflect fairly the results of the interim periods. Certain
information and footnote disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the
United States have been condensed or omitted in this Form 10-Q pursuant to the
rules and regulations of the Securities and Exchange Commission. However, the
disclosures herein, when read with the annual report for 2001 filed on Form
10-K, are adequate to make the information presented not misleading.
The Vermont Public Service Board ("VPSB"), the regulatory commission in Vermont,
sets the rates we charge our customers for their electricity. In periods prior
to April 2001, we charged our customers higher rates for billing cycles in
December through March and lower rates for the remaining months. These were
called seasonally differentiated rates. Seasonal rates were eliminated in
April 2001, and generated approximately $8.5 million of revenues deferred in
2001 that we estimate will be used to offset increased costs during 2002,
including $2.2 million that was recognized during the first quarter, and $2.1
million recognized in the second quarter.
Certain line items on the prior year's financial statements have been
reclassified for consistent presentation with the current year.
The preparation of financial statements in conformity with generally accepted
accounting principles requires the use of estimates and assumptions that affect
assets and liabilities, and revenues and expenses. Actual results could differ
from those estimates.
UNREGULATED OPERATIONS
We have or have had unregulated, wholly owned subsidiaries: Northern Water
Resources, Inc. ("NWR"); Green Mountain Propane Gas Company Limited ("GMPG");
GMP Real Estate Corporation; and Green Mountain Resources, Inc. ("GMRI").
During 2000 and 2001, we sold most of the assets of NWR, and reported its
results as income (loss) from operations of a discontinued segment. See the
disclosure under the caption "Segments and Related Information" for a more
detailed discussion. We also have a rental water heater program that is not
regulated by the VPSB. The results of the operations of these subsidiaries,
including NWR during 2002, and the rental water heater program are included in
equity in earnings of affiliates and non-utility operations in the Other Income
section of the Consolidated Comparative Income Statements.
2. INVESTMENT IN ASSOCIATED COMPANIES
We recognize net income from our affiliates (companies in which we have
ownership interests) listed below based on our percentage ownership (equity
method).
VERMONT YANKEE NUCLEAR POWER CORPORATION ("VY", OR "VERMONT YANKEE")
Percent ownership: 19.0% common
Three Months Ended Six Months Ended
June 30 June 30
2002 2001 2002 2001
------- ------- ------- -------
(in thousands)
Gross Revenue. . . . . $46,764 $57,031 $85,495 $97,995
Net Income Applicable. 1,462 1,574 2,949 3,124
to Common Stock
Equity in Net Income . 258 287 571 560
On August 15, 2001, VY agreed to sell its nuclear power plant to Entergy
Corporation for approximately $180 million. On July 31, 2002, Vermont Yankee
announced that the sale of its nuclear power plant to Entergy Nuclear Vermont
Yankee ("Entergy") had been completed. In addition to the sale of the
generating plant, the transaction calls for Entergy to provide 20 percent of the
plant output to the Company through 2012, which represents approximately 35
percent of the Company's energy requirements. The Company continues to own
approximately 19 percent of the common stock of VY. The benefits to Green
Mountain Power of the plant sale and power contract with Entergy include:
Vermont Yankee receives cash approximately equal to the book value of the
plant assets, removing the potential for stranded costs associated with the
plant.
Vermont Yankee and its owners will no longer bear operating risks
associated with running the plant.
Vermont Yankee and its owners will no longer bear the risks associated with
the eventual decommissioning of the plant.
Prices under the power contract with Entergy range from $39 to $45 per
megawatt-hour, substantially lower than the forecasted cost of continued
ownership and operation by Vermont Yankee.
The power contract with Entergy calls for a downward adjustment in the
price if market prices for electricity fall by defined amounts beginning no
later than November 2005. If market prices rise, however, the contract prices
are not adjusted upward.
The Company remains responsible for procuring replacement energy at market
prices during periods of scheduled or unscheduled outages at the Entergy plant.
The VY plant had fuel rods that required repair during May 2002, a
maintenance requirement that is not unique to VY. VY shutdown the plant for a
twelve-day period, beginning on May 11, 2002, to repair the rods. The Company
estimates its portion of the cost for repair, including incremental replacement
energy costs, to be approximately $2.0 million. The Company received an
accounting order from the Vermont Public Service Board on August 2, 2002,
allowing it to defer the additional costs related to the outage, and believes
that such amounts are probable of future recovery.
The Company's ownership share of VY has increased from approximately 17.9
percent last year to approximately 19.0 percent currently, due to VY's purchase
of certain minority shareholders' interests.
VERMONT ELECTRIC POWER COMPANY, INC. ("VELCO")
Percent ownership: 29.5% common
30.0% preferred
VELCO is a corporation engaged in the transmission of electric power within
the State of Vermont. VELCO has entered into transmission agreements with the
State of Vermont and various electric utilities, including the Company, and
under these agreements, VELCO bills all costs, including interest on debt and a
fixed return on equity, to the State and others using VELCO's transmission
system.
Three Months Ended Six Months Ended
June 30 June 30
2002 2001 2002 2001
------ ------ ------- -------
(in thousands)
Gross Revenue . . . . $5,312 $8,548 $11,796 $15,718
Net Income. . . . . . 318 309 513 552
Equity in Net Income. 92 91 169 146
3. COMMITMENTS AND CONTINGENCIES
ENVIRONMENTAL MATTERS
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air
and aesthetic requirements as administered by local, state and federal
regulatory agencies. We believe that we are in substantial compliance with
these requirements and that there are no outstanding material complaints about
the Company's compliance with present environmental protection regulations,
except for developments related to the Pine Street Barge Canal site.
PINE STREET BARGE CANAL SITE
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. We are one of
several potentially responsible parties ("PRPs") for cleanup of the Pine Street
Barge Canal ("Pine Street") site in Burlington, Vermont, where coal tar and
other industrial materials were deposited.
In September 1999, we negotiated a final settlement with the United States,
the State of Vermont (the "State"), and other parties to a Consent Decree that
covers claims with respect to the site and implementation of the selected site
cleanup remedy. In November 1999, the Consent Decree was filed in the federal
district court. The Consent Decree addresses claims by the Environmental
Protection Agency (the "EPA") for past Pine Street site costs, natural resource
damage claims and claims for past and future oversight costs. The Consent
Decree also provides for the design and implementation of response actions at
the site.
As of June 30, 2002, our total expenditures related to the Pine Street site
since 1982 were approximately $25.9 million. This includes amounts not
recovered in rates, amounts recovered in rates, and amounts for which rate
recovery has been sought but which are presently waiting further VPSB action.
The bulk of these expenditures consisted of transaction costs. Transaction
costs include legal and consulting costs associated with the Company's
opposition to the EPA's earlier proposals of a more expensive remedy at the
site, litigation and related costs necessary to obtain settlements with insurers
and other PRPs to provide amounts required to fund the clean up ("remediation
costs"), and to address liability claims at the site. A smaller amount of past
expenditures was for site-related response costs, including costs incurred
pursuant to EPA and State orders that resulted in funding response activities at
the site, and to reimbursing the EPA and the State for oversight and related
response costs. The EPA and the State have asserted and affirmed that all costs
related to these orders are appropriate costs of response under CERCLA for which
the Company and other PRPs were legally responsible.
We estimate that we have recovered or secured, or will recover, through
settlements of litigation claims against insurers and other parties, amounts
that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We currently estimate
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $12.4 million over the next 32
years. The estimated liability is not discounted, and it is possible that our
estimate of future costs could change by a material amount. We also have
recorded an offsetting regulatory asset, and we believe that it is probable that
we will receive future revenues to recover these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and received
recovery for ongoing expenses associated with the Pine Street site. While
reserving the right to argue in the future about the appropriateness of full
rate recovery of the site-related costs, the Company and the Vermont Department
of Public Service (the "Department"), and as applicable, other parties, reached
agreements in these cases that the full amount of the site-related costs
reflected in those rate cases should be recovered in rates.
We proposed in our rate filing made on June 16, 1997 recovery of an additional
$3.0 million in such expenditures. In an Order in that case released March 2,
1998, the VPSB suspended the amortization of expenditures associated with the
Pine Street site pending further proceedings. Although it did not eliminate the
rate base deferral of these expenditures, or make any specific order in this
regard, the VPSB indicated that it was inclined to agree with other parties in
the case that the ultimate costs associated with the Pine Street site, taking
into account recoveries from insurance carriers and other PRPs, should be shared
between customers and shareholders of the Company. In response to our Motion
for Reconsideration, the VPSB on June 8, 1998 stated its intent was "to reserve
for a future docket issues pertaining to the sharing of remediation-related
costs between the Company and its customers". The VPSB Order released January
23, 2001 and discussed below did not change the status of Pine Street cost
recovery.
RETAIL RATE CASE
The Company reached a final settlement agreement with the Department in its
1998 rate case during November 2000. The final settlement agreement contained
the following provisions:
* The Company received a rate increase of 3.42 percent above existing rates,
beginning with bills rendered January 23, 2001, and prior temporary rate
increases became permanent;
* Rates were set at levels that recover the Company's Hydro-Quebec VJO
contract costs, effectively ending the regulatory disallowances experienced by
the Company from 1998 through 2000;
* The Company agreed not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a request
for additional rate relief if power supply costs increase in excess of $3.75
million over forecasted levels;
* The Company agreed to write off in 2000 approximately $3.2 million in
unrecovered rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
* Seasonal rates were eliminated in April 2001, which generated
approximately $8.5 million in additional cash flow in 2001 that can be utilized
to offset increased costs during 2002 and 2003;
* The Company agreed to consult extensively with the Department regarding
capital spending commitments for upgrading our electric distribution system and
to adopt customer care and reliability performance standards, in a first step
toward possible development of performance-based rate-making;
* The Company agreed to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in a 1997 rate case; and
* The Company agreed to an earnings limitation for its electric operations
in an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned over the limit being used to write off regulatory assets. The Company
earned approximately $30,000 in excess of its allowed rate of return during 2001
before writing off regulatory assets in the same amount.
On January 23, 2001, the VPSB approved the Company's settlement (the
"Settlement Order") with the Department, with two additional conditions:
* The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to an $8.0 million limit on the customers' share; and
* The Company's further investment in non-utility operations is restricted.
POWER CONTRACT COMMITMENTS
Under an arrangement established on December 5, 1997 ("9701"), Hydro-Quebec
paid $8.0 million to the Company. In return for this payment, we provided
Hydro-Quebec options for the purchase of power. Commencing April 1, 1998 and
effective through 2015, the term of a previous contract with Hydro-Quebec (the
"1987 Contract"), Hydro-Quebec may purchase up to 52,500 MWh ("option A") on an
annual basis, at the 1987 Contract energy prices, which are substantially below
current market prices. The cumulative amount of energy that may be purchased
under option A shall not exceed 950,000 MWh.
Over the same period, Hydro-Quebec may exercise an option to purchase a total of
600,000 MWh ("option B") at the 1987 Contract energy prices. Under option B,
Hydro-Quebec may purchase no more than 200,000 MWh in any year.
During the first half of 2002, $1.5 million in power supply expense was
recognized to reflect the cost of option A, which is recognized ratably over the
year. Hydro-Quebec has previously agreed not to call option B during the 2002
contract year. At June 30, 2002, the cumulative amount of power purchased by
Hydro-Quebec under option B is approximately 432,000 MWh.
During the first quarter of 2001, Hydro-Quebec exercised option A and
option B, calling for deliveries of 134,592 MWh during June, July and August of
2001. The Company recognized $3.3 million in expense during the six months
ended June 30, 2001 to reflect 9701 estimated costs. A regulatory asset of $3.3
million was established for the remaining estimated difference between the
option exercise price and the expected cost of replacement power for 2001.
If estimated costs of fulfilling the Hydro-Quebec option calls exceed
amounts recovered in rates, the excess cost would be immediately charged against
earnings. No charge for excess cost was required during the first half of 2002
and 2001. No charges in excess of amounts provided in rates or previously
recorded are anticipated for the remainder of 2002.
Hydro-Quebec's option to curtail energy deliveries pursuant to a July 1994
Agreement can be exercised in addition to these purchase options if documented
drought conditions exist. The exercise of this curtailment option is limited to
five times, requiring notice four months in advance of any contract year, and
cannot reduce deliveries by more than approximately 13 percent. The Company may
defer the curtailment by one year. Hydro-Quebec also has the option to reduce
the load factor from 75 percent to 65 percent under the 1987 Contract a total of
three times over the life of the contract. The Company can delay the load factor
reduction by one year under the same contract. During 2001, Hydro-Quebec
exercised the first of its load factor reduction options intended for 2002, and
the Company delayed the effective date of this exercise until 2003. The Company
estimates that the net cost of Hydro-Quebec's exercise of its load factor
reduction option will increase power supply expense during 2003 by approximately
$0.4 million.
It is possible our estimate of future power supply costs could differ materially
from actual results.
COMPETITION
During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase an existing hydro-generation facility from a third party, and the
associated distribution plant owned by the Company within Rockingham. In March
2002, voters in Rockingham authorized Rockingham to create a municipal utility
by acquiring a municipal plant, which would include the Bellows Falls
hydroelectric facility and the electric distribution systems of the Company
and/or Central Vermont Public Service Corporation. The Company receives annual
revenues of approximately $4.0 million from its customers in Rockingham. Should
Rockingham create a municipal system, the Company would vigorously pursue its
right to receive just compensation from Rockingham. Such compensation would
include full reimbursement for Company assets, if acquired, and full
reimbursement of any other costs associated with the loss of customers in
Rockingham, to assure that our remaining customers do not subsidize a Rockingham
municipal utility.
4. SEGMENTS AND RELATED INFORMATION
The Company has two reportable segments during 2002, the electric utility
and NWR. NWR was reported as discontinued operations in 2001. The Company was
unable to sell all of the NWR investments and believes that classification and
reporting as discontinued operations is no longer appropriate. The electric
utility is engaged in the distribution and sale of electrical energy in the
State of Vermont and also reports the results of its wholly owned unregulated
subsidiaries (GMPG, GMRI, NWR and GMP Real Estate) and the rental water heater
program as a separate line item in the Other Income section in the Consolidated
Statement of Income.
NWR is an unregulated business that invested in energy generation, energy
efficiency and wastewater treatment projects. As of June 30, 2002, most of
NWR's net assets and liabilities have been sold or otherwise disposed. The
remaining net liability reflects expected warranty obligations, net of equity
investments in two wind farms and wastewater treatment projects.
In 2001, the Company reported NWR results as discontinued operations. The
provisions for loss from discontinued operations reflected the Company's most
recent estimate at that time. The ultimate loss remains subject to the
disposition of NWR's remaining liabilities, primarily wastewater treatment
warranty obligations, and could exceed amounts recorded. Results of operations
for NWR for the three and six months ended June 30, 2002 are now reported as
continuing operations under the caption Equity in earnings of affiliates and
non-utility operations. Segment information compared with the Company's results
includes the following:
Three months ended Six months ended
June 30 June 30
2002 2001 2002 2001
-------- -------- --------- ---------
(in thousands, except per share data)
External revenues
Electric utility . . . . . . . . . . $65,135 $74,796 $134,001 $142,267
NWR segment. . . . . . . . . . . . . 62 35 62 104
Net income from
operations
Electric utility . . . . . . . . . . $ 1,890 $ 2,884 $ 5,272 $ 5,798
NWR segment. . . . . . . . . . . . . (15) (150) (41) (150)
-------- -------- --------- ---------
Consolidated net income . . . . . . . $ 1,875 $ 2,914 $ 5,231 $ 5,648
======== ======== ========= =========
Basic earnings per share
Discontinued operations. . . . . . $ - $ (0.03) $ - $ (0.03)
Continuing operations. . . . . . . 0.33 0.51 0.92 1.04
Diluted earnings per share
Discontinued operations. . . . . . $ - $ (0.03) $ - $ (0.03)
Continuing operations. . . . . . . 0.32 0.47 0.89 0.98
5. DERIVATIVE INSTRUMENTS AND RISK MANAGEMENT
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended ("SFAS 133").
SFAS 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded on the balance sheet as either an asset or
liability measured at its fair value. SFAS 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. SFAS 133, as amended by SFAS 137, was
effective for the Company beginning 2001.
One objective of the Company's risk management program is to stabilize cash flow
and earnings by minimizing power supply risks. Transactions permitted by the
risk management program include futures, forward contracts, option contracts,
swaps and transmission congestion rights with counter-parties that have at least
investment grade ratings. These transactions are used to hedge the risk of
fossil fuel and spot market electricity price increases. Futures, swaps and
forward contracts are used to hedge market prices should option calls by
Hydro-Quebec be exercised. The Company's risk management policy specifies risk
measures, the amount of tolerable risk exposure, and authorization limits for
transactions.
On April 11, 2001, the VPSB issued an accounting order that requires the Company
to defer recognition of any earnings effects relating to future periods caused
by application of SFAS 133. At June 30, 2002, the Company had a liability
reflecting the fair value of the two derivatives described below, as well as a
corresponding regulatory asset of approximately $33.7 million. The Company
believes that the regulatory asset is probable of recovery in future rates. The
liability is based on current estimates of future market prices that are subject
to change by material amounts.
If a derivative instrument is terminated early because it is probable that a
transaction or forecasted transaction will not occur, any gain or loss would be
recognized in earnings immediately. For derivatives held to maturity, the
earnings impact would be recorded in the period that the derivative is sold or
matures.
The Company has a contract with Morgan Stanley Capital Group, Inc. ("MS") used
to hedge against increases in fossil fuel prices. MS purchases the majority of
the Company's power supply resources at index (fossil fuel resources) or
specified (i.e., contracted resources) prices and then sells to us at a fixed
rate to serve pre-established load requirements. This contract allows
management to fix the cost of much of its power supply requirements, subject to
power resource availability and other risks. The MS contract is a derivative
under SFAS 133 and was scheduled to expire on December 31, 2003. In August
2002, the Company extended the contract with MS through December 31, 2006.
Beginning in 2004, the extended contract includes only our interests in the
Wyman and Stonybrook plants with respective capacities of 7 MW and 45 MW, and
our estimated load requirements not satisfied by contractual arrangements and
other owned generation. The cost of power purchased from MS for 2003 is
expected to be approximately $6.0 million less than the cost of power purchased
from MS during 2002. The remainder of our load requirements are substantially
provided through our power supply contracts and arrangements with Hydro-Quebec
and our entitlements to power generated at the Vermont Yankee nuclear plant now
owned by Entergy.
Management's estimate of the fair value of the future net cost of this
contract at June 30, 2002 is approximately $5.1 million.
We also sometimes use future contracts to hedge forecasted wholesale sales
of electric power, including material sales commitments. We currently have an
arrangement with Hydro-Quebec that grants it an option to call power at prices
below current and estimated future market rates. This arrangement is a
derivative and is effective through 2015. Management's estimate of the fair
value of the future net cost for this arrangement at June 30, 2002 is
approximately $28.6 million.
6. NEW ACCOUNTING STANDARDS
In June 2001, the FASB issued Statement of Financial Accounting Standards
No. 141, Business Combinations ("SFAS 141"), and Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS 142").
SFAS 141 requires the use of the purchase method to account for business
combinations initiated after June 30, 2001 and uses a non-amortization approach
to purchased goodwill and other indefinite-lived intangible assets. Under SFAS
142, effective for fiscal years beginning after December 15, 2001, goodwill and
intangible assets deemed to have indefinite lives, will no longer be amortized,
and will be subject to annual impairment tests. The adoption of these
accounting standards did not impact the Company's financial position or results
of operations as of June 30, 2002.
In 2001, the FASB issued Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), effective for
the Company's 2003 fiscal year, which provides guidance on accounting for
nuclear plant decommissioning costs. SFAS 143 prescribes fair value accounting
for asset retirement liabilities, including nuclear decommissioning obligations,
and requires recognition of such liabilities at the time incurred. The Company
has not yet determined what impact, if any, the accounting standard will have on
its financial position or results of operations.
In 2001, the FASB issued Statement of Financial Accounting Standards No.
144, "Accounting for the Impairment or Disposal of Long-lived Assets" ("SFAS
144"). SFAS 144 specifies accounting and reporting for the impairment or
disposal of long-lived assets. The adoption of SFAS 144 did not impact the
Company's financial position or results of operations as of June 30, 2002.
7. COMPUTATION OF EARNINGS PER SHARE
Earnings per share are based on the weighted average number of common and common
stock equivalent shares outstanding during each year. The Company established a
stock incentive plan for all directors and employees during the year ended
December 31, 2000, and options granted are exercisable over vesting schedules of
between one and four years.
Three months ended Six months ended
June 30 June 30
2002 2001 2002 2001
------ ------ ------ ------
(in thousands)
Net income before preferred dividends. . $1,886 $2,969 $5,326 $6,117
Preferred stock dividend requirement . . 11 235 95 469
------ ------ ------ ------
Net income applicable to common stock. . $1,875 $2,734 $5,231 $5,648
====== ====== ====== ======
Average number of common shares-basic. . 5,711 5,615 5,701 5,602
Dilutive effect of stock options . . . . 166 162 165 157
Anti-dilutive stock options. . . . . . . - - - -
------ ------ ------ ------
Average number of common shares-diluted. 5,877 5,777 5,866 5,759
====== ====== ====== ======
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
JUNE 30, 2002
PART I-ITEM 2
In this section, we explain the general financial condition and the results
of operations for Green Mountain Power Corporation (the "Company") and its
subsidiaries. This includes:
Factors that affect our business;
Our earnings and costs in the periods presented and why they changed
between periods;
The source of our earnings;
Our expenditures for capital projects year-to-date and what we expect they
will be in the future;
Where we expect to get cash for future capital expenditures; and
How all of the above affects our overall financial condition.
Management believes the most critical accounting policies include the regulatory
accounting framework within which we operate and the manner in which we account
for certain power supply arrangements that qualify as derivatives. These
accounting policies, among others, affect the Company's more significant
judgments and estimates used in the preparation of its consolidated financial
statements, including estimates and judgments used in determining the current
period recognition of revenues deferred in 2001, as discussed further under the
caption "Operating Revenues and MWh Sales-Revenues", in this section.
As you read this section it may be helpful to refer to the consolidated
financial statements and notes in Part I-Item 1.
There are statements in this section that contain projections or estimates and
are considered to be "forward-looking" as defined by the Securities and Exchange
Commission. In these statements, you may find words such as "believes,"
"estimates", "expects," "plans," or similar words. These statements are not
guarantees of our future performance. There are risks, uncertainties and other
factors that could cause actual results to be materially different from those
projected. Some of the reasons the results may be different are listed below
and are discussed under "Competition and Restructuring" in this section:
Regulatory and judicial decisions or legislation;
Weather;
Energy supply and demand and pricing;
Availability, terms, and use of capital;
General economic and business risk;
Nuclear and environmental issues;
Changes in technology; and
Industry restructuring and cost recovery (including stranded costs).
These forward-looking statements represent only our estimates and
assumptions as of the date of this report.
RESULTS OF OPERATIONS
EARNINGS SUMMARY - OVERVIEW
In this section, we discuss our earnings and the principal factors affecting
them. We separately discuss earnings for the utility business and for our
unregulated businesses.
Total basic earnings per share of Common Stock*
Three months ended Six months ended
June 30 June 30
2002 2001 2002 2001
----- ------- ----- -------
Utility business . . . . $0.31 $ 0.51 $0.89 $ 0.99
Unregulated businesses . 0.02 0.01 0.03 0.05
----- ------- ----- -------
Earnings from:
Continuing operations. . 0.33 0.52 0.92 1.04
Discontinued segment . . - (0.03) - (0.03)
----- ------- ----- -------
Basic earnings per share $0.33 $ 0.49 $0.92 $ 1.01
===== ======= ===== =======
*The three and six months ended June 30, 2002 include recognition of $2.1
million and
$4.2 million of deferred revenues, respectively
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.31 in the quarter ended June 30, 2002, compared with utility earnings of
$0.51 per share in the second quarter of 2001. Earnings declined as a result of
increased power supply costs during the second quarter of 2002, compared with
the same quarter of 2001. Power supply costs rose as a result of increased costs
under our power supply agreement with Morgan Stanley, capacity cost increases at
the Vermont Yankee nuclear plant and reimbursement of approximately $1.0 million
received in 2001 for power supply costs incurred during previous periods. The
increases in power supply costs in the second quarter of 2002 were partially
offset by a reduction in costs arising from decreased sales of electricity to
wholesale customers.
Retail operating revenues increased by $2.7 million during the second
quarter of 2002, compared with the same quarter of 2001, primarily due to the
recognition of $2.1 million in revenues deferred during 2001 in accordance with
the settlement of the Company's retail rate case approved by the Vermont Public
Service Board in January 2001.
Basic earnings per share from utility operations for the six months ended
June 30, 2002 were $0.89 compared with basic earnings per share of $0.99 for the
same period in 2001, due to the same factors influencing second quarter results.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from continuing
operations for the three months ended June 30, 2002 were lower than during the
same period in 2001. A financial summary for these businesses follows:
Three Months Ended Six Months Ended
June 30 June 30
2002 2001 2002 2001
------------- ----- ----- -----
In thousands
Revenue. . $ 253 $ 251 $ 502 $ 510
Expense. . 150 131 $ 316 256
------------- ----- ----- -----
Net Income $ 103 $ 120 $ 186 $ 254
============= ===== ===== =====
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatthour ("MWh") sales and average number of
customers for the three and six months ended June 30, 2002 and 2001 are
summarized below:
Three months ended Six months ended
June 30 June 30
2002 2001 2002 2001
-------- ---------- ---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 48,256 $ 45,586 $ 100,745 $ 97,539
Sales for Resale. . . 16,092 20,760 31,901 42,598
Other . . . . . . . . 787 1,126 1,355 2,131
-------- ---------- ---------- ----------
Total Operating Revenues. $ 65,135 $ 67,472 $ 134,001 $ 142,268
======== ========== ========== ==========
MWh sales-Retail. . . . . 457,128 459,144 952,622 977,405
MWh sales for Resale. . . 517,937 545,288 1,036,224 1,183,384
-------- ---------- ---------- ----------
Total MWh Sales . . . . . 975,065 1,004,432 1,988,846 2,160,789
======== ========== ========== ==========
Average Number of Customers
Three months ended Six months ended
June 30 June 30
2002 2001 2002 2001
------ ------ ------ ------
Residential . . . . . . . 73,730 73,075 73,831 73,112
Commercial and Industrial 13,104 12,998 13,076 12,966
Other . . . . . . . . . . 64 66 65 66
------ ------ ------ ------
Total Number of Customers. . 86,898 86,139 86,972 86,143
====== ====== ====== ======
REVENUES
Total revenues from operations in the second quarter of 2002 decreased
$2.3 million or 3.5 percent compared with the same period in 2001. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the second quarter of 2002 were $2.7 million or 5.9 percent
higher compared with the same period in 2001, primarily as a result of the
recognition of $2.1 million of revenues deferred during 2001 under a settlement
order in the Company's retail rate filing that was approved by the Vermont
Public Service Board in January 2001. Total retail MWh sales of electricity in
the second quarter of 2002 decreased by 0.4 percent from the same quarter of
2001, reflecting a decrease in sales to industrial customers of 5.5 percent that
was substantially offset by increased sales of 3.4 percent to small commercial
and industrial customers and 1.5 percent to residential customers.
Retail revenues for the six months ended June 30, 2002 were $3.2 million or 3.3
percent higher when compared with the same period in 2001, reflecting the
recognition of $4.3 million of deferred revenues, partially offset by decreased
retail MWh sales of approximately 2.5 percent due to warmer than normal winter
temperatures and a softening economy in 2002.
The Company currently estimates that its earnings for 2002 will approximate its
allowed rate of return of 11.25% percent, and that it will recognize the
remaining balance of $4.2 million of deferred revenues during 2002.
We sell wholesale electricity to others for resale. Our revenue from wholesale
MWh sales of electricity decreased $4.7 million or 22.5 percent in the second
quarter of 2002 compared with the same period in 2001. The decrease was due
primarily to decreased sales under various arrangements with Hydro-Quebec.
OPERATING EXPENSES
POWER SUPPLY EXPENSES
Power supply expenses increased 1.4 percent or $0.6 million in the second
quarter of 2002 over the same period in 2001, as a result of increased costs
under our power supply agreement with Morgan Stanley, capacity cost increases at
the Vermont Yankee nuclear plant and reimbursement of approximately $1.0 million
received in 2001 for power supply costs incurred during previous periods. The
increases in power supply costs in the second quarter of 2002 were partially
offset by a reduction in costs arising from decreased sales of electricity to
wholesale customers.
Power supply expenses at Vermont Yankee increased 42.8 percent or $2.5 million
during the second quarter of 2002 compared with the second quarter of 2001, due
to the deferral of maintenance and repair costs associated with a scheduled
refueling outage in 2001. The sale of the VY generating plant is discussed
under Part I, Item 2, "Investment in Associated Companies".
Company-owned generation expenses increased $0.7 million in the second quarter
of 2002 compared with the same period in 2001 primarily due to a 2001
reimbursement of fuel costs expended in periods prior to 2001 to support system
reliability. The Company received reimbursement of its costs of running its
generating units for system reliability from the Independent System Operator of
New England ("ISO") during the second quarter of 2001.
The cost of power that we purchased from other companies decreased 6.4 percent
or $2.6 million in the second quarter of 2002 compared with the same period in
2001. This was primarily due to a $4.7 million reduction in wholesale electric
revenues, and decreased expenses under the 9701 arrangement with Hydro-Quebec,
pursuant to which Hydro-Quebec has the right to purchase electricity from the
Company at rates below current market prices. These decreases were partially
offset by higher power supply costs under both the MS contract and small power
producer contracts. See the discussion under "Commitments and
Contingencies-Power Contract Commitments" for more detail regarding the 9701
arrangement and the MS contract, including the recent renegotiation of the MS
contract.
The 9701 arrangement allows Hydro-Quebec to exercise an option to purchase power
from the Company at energy prices based on a 1987 contract. During the second
quarter of 2002, $0.8 million in power supply expense was recognized to reflect
the costs of option A, which are recognized ratably over the year. During the
second quarter of 2001, $1.6 million in power supply expense was recognized to
reflect the costs of options A and B. Hydro-Quebec has previously agreed not to
call option B during the 2002 contract year. The cumulative amount of power
purchased to date by Hydro-Quebec under option B is approximately 432,000 MWh
out of a total of 600,000 MWh which may be called over the life of the of the
arrangement.
Power supply expenses for the first half of 2002 decreased 6.6 percent or $6.6
million compared with the first half of 2001, primarily due to a reduction in
low margin wholesale purchases and lower retail sales of electricity.
Power supply expense at Vermont Yankee increased $2.4 million or 17.3 percent
for the first half of 2002 compared with the first half of 2001, primarily due
to the deferral of maintenance and repair costs associated with a scheduled
refueling outage in 2001. Vermont Yankee scheduled outage costs are deferred
and amortized over an eighteen-month refueling cycle.
Company-owned generation expenses decreased $0.7 million or 29.7 percent in
the first half of 2002 compared with the same period in 2001, primarily due to
lower fuel costs and reduced need to run peak generation facilities for system
reliability. During 2001, the Company recorded a reduction of generation
expense of approximately $1.9 million for its costs of running peak generation
facilities for system reliability and we received reimbursement of these amounts
from the ISO in July 2001. This reduction was partially offset by increased
generation expense in the first quarter of 2001 caused by higher fuel costs.
Purchased power expense decreased $8.4 million or 9.9 percent in the first half
of 2002 compared with the first half of 2001, primarily due to a $10.7 million
decrease in wholesale electric revenues, decreased expenses under the 9701
arrangement with Hydro-Quebec and reductions in retail MWh sales of electricity.
Both the 9701 arrangement and any related forward purchase contracts are
considered derivative instruments as defined by SFAS 133. On April 11, 2001,
the VPSB issued an accounting order that allows the Company to defer recognition
of any earnings or other comprehensive income effect relating to future periods
caused by application of SFAS 133, and as a result, we do not anticipate SFAS
133 to cause earnings volatility. At June 30, 2002, the Company had a
regulatory asset of approximately $33.7 million related to derivatives that the
Company believes is probable of recovery. The regulatory asset is based on
current estimates of future market prices that are likely to change by material
amounts.
The cost of power purchased from MS for 2003 is expected to be approximately
$6.0 million less than the cost of power purchased from MS during 2002. The
remainder of our load requirements are substantially provided through our power
supply contracts and arrangements with Hydro-Quebec and our entitlements to
power generated at the Vermont Yankee nuclear plant now owned by Entergy.
OTHER OPERATING EXPENSES
Other operating expenses decreased 19.4 percent or $0.8 million in the
second quarter of 2002 compared with the same period in 2001, as a result of
increased reserves for medical benefits and vendor claims expensed in 2001.
Other operating expenses decreased 9.3 percent or $0.7 million in the first
six months of 2002 compared with the same period in 2001 for the same reasons.
TRANSMISSION EXPENSES
Transmission expenses increased by approximately $0.5 million or 12.9% for
the three months ended June 30, 2002 compared with the same period in 2001. The
Company's relative share of transmission costs varies with the peak demand
recorded on Vermont's transmission system. The Company's share of those costs
has increased due to its increased load growth, relative to other Vermont
utilities, experienced during the previous twelve months.
Transmission expenses increased by approximately $0.9 million or 13.8 percent
for the six months ended June 30, 2002, compared with the same period in 2001
for the same reasons mentioned in the three month comparison. Congestion
charges recorded in the first six months of 2002 and 2001 reflect the lack of
adequate transmission or generation capacity in certain locations within New
England, and these charges are allocated to all ISO New England members.
Congestion charges recorded in the first quarter of 2001 reflect the lack
of adequate transmission or generation capacity in certain locations within New
England, and these charges are allocated to all ISO New England members.
A system of locational pricing is likely to be adopted by ISO New England, as
early as January 2003. Currently, it is expected that the Vermont zone will be
set at state boundaries. The intent of locational pricing is to encourage
generation and transmission solutions in areas experiencing constraints
(congestion). The Company is unable to predict the magnitude or duration of
future congestion charge allocations, but amounts could be material.
MAINTENANCE EXPENSES
Maintenance expenses were substantially unchanged during the second quarter
of 2002 compared with the same period in 2001.
Maintenance expenses increased by approximately $0.7 million or 20.9%
during the first half of 2002 compared with the same period in 2001, primarily
due to the costs of repair from a series of minor storms in 2002 and increases
in maintenance costs at our wind generation facility located in Searsburg,
Vermont.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses decreased $0.2 million or 6.0
percent during the second quarter of 2002 compared with the same period in 2001
primarily due to decreased amortization of demand side management assets.
Depreciation and amortization expenses decreased $0.4 million or 5.1
percent during the first six months of 2002 compared with the same period in
2001 for the same reason.
TAXES OTHER THAN INCOME TAXES
Other taxes expense for the second quarter and the first six months of 2002
were essentially unchanged compared with the same respective periods in 2001.
INCOME TAXES
Income taxes decreased $0.9 million in the second quarter of 2002 compared
with the same period in 2001 due to a decrease in pretax book income for core
electric operations.
Income taxes decreased $0.7 million for the first six months of 2002
compared with the same period in 2001 for the same reason.
OTHER INCOME
Other income for the three and six months ended June 30, 2002 was
essentially unchanged from the same period in 2001.
INTEREST CHARGES
Interest charges decreased $0.2 million or 12.2 percent in the second
quarter of 2002 compared with the same period in 2001 primarily due to the
redemption of first mortgage bonds in December 2001 and May 2002, partially
offset by increased short-term borrowings and related interest costs.
Interest charges decreased $0.6 million or 17.2 percent in the first half
of 2002 compared with the same period in 2001 for the same reasons.
LIQUIDITY AND CAPITAL RESOURCES
In the six months ended June 30, 2002, we spent $9.3 million principally
for expansion and improvements of our transmission, distribution and generation
plant. We expect to spend approximately $10.4 million during the remainder of
2002.
The Company renegotiated a 364-day revolving credit agreement with Fleet
Financial Services ("Fleet") joined by KeyBank National Association, ("KeyBank")
with the renegotiated agreement expiring June 18, 2003 (the "Fleet-Key
Agreement"). The Fleet-Key Agreement is for $35.0 million, unsecured, and
allows the Company to choose either a daily variable prime rate, or a fixed term
LIBOR-based rate. There was $10.4 million outstanding with an interest rate of
4.75 percent on the Fleet-Key Agreement at June 30, 2002. There was no
non-utility short-term debt outstanding at June 30, 2002.
On July 27, 2001, the VPSB approved a $12.0 million two-year unsecured loan
agreement, with Fleet, joined by KeyBank, and the loan was made to the Company
on August 24, 2001. At June 30, 2002, there was $12.0 million outstanding under
the two-year loan agreement.
On June 21, 2002, the Company paid $1.0 million to redeem the remaining
7.32 percent Class E preferred stock outstanding.
In August 2002, the Company submitted a request to the Vermont Public
Service Board to approve an issuance of first mortgage bonds sufficient to
retire the Company's short and intermediate term debt.
The credit ratings of the Company's securities at June 30, 2002 are:
Fitch Moody's Standard & Poor's
----- ------- -----------------
First mortgage bonds BBB Baa2 BBB
Preferred stock. . . BBB- Ba2 BB
The following table presents payments contractually due by category:
In thousands
Contractual Obligations Less
at June 30, 2002 than 1 1-3 4-5 After
Total year years years 5 years
-------- ------- -------- -------- --------
Long-term Debt. . . . . . . . . . . $ 79,000 $ 8,000 $ 20,000 $ 14,000 $ 37,000
Revolving Credit. . . . . . . . . . 10,400 10,400 -
Interest on Long Term Debt. . . . . 60,013 5,123 8,208 6,681 40,001
Capital Lease . . . . . . . . . . . 5,959 426 852 852 3,829
Preferred Stock . . . . . . . . . . 235 150 60 25
Hydro-Quebec power supply contracts 691,343 47,977 96,360 100,836 446,170
MS power supply contract. . . . . . 18,874 13,744 5,130 - -
-
Total Contractual Cash Obligations. $865,823 $85,819 $130,610 $122,394 $527,000
======== ======= ======== ======== ========
FUTURE OUTLOOK
COMPETITION AND RESTRUCTURING-The electric utility business continues to
experience rapid and substantial changes. These changes are the result of the
following trends:
disparity in electric rates, transmission, and generating capacity among
and within various regions of the country;
improvements in generation efficiency;
increasing demand for customer choice;
consolidation through business combinations;
new regulations and legislation intended to foster competition, also known
as restructuring; and
increasing volatility of wholesale market prices for electricity.
We are unable to predict what form future restructuring legislation, if
adopted, will take and what impact that might have on the Company, but it could
be material.
During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase an existing hydro-generation facility from a third party, and the
associated distribution plant owned by the Company within Rockingham. In March
2002, voters in Rockingham authorized Rockingham to create a municipal utility
by acquiring a municipal plant, which would include the Bellows Falls
hydroelectric facility and the electric distribution systems of the Company
and/or Central Vermont Public Service Corporation. The Company receives annual
revenues of approximately $4.0 million from its customers in Rockingham. Should
Rockingham create a municipal system, the Company would vigorously pursue its
right to receive just compensation from Rockingham. Such compensation would
include full reimbursement for Company assets, if acquired, and full
reimbursement of any other costs associated with the loss of customers in
Rockingham, to assure that our remaining customers do not subsidize a Rockingham
municipal utility.
NEW ACCOUNTING STANDARDS
See Part I-Item 1, Note 6, "New Accounting Standards" for more information
on the adoption of new accounting standards and the impact, or lack thereof, on
the Company's financial position and operating results.
EFFECTS OF INFLATION
Financial statements are prepared in accordance with generally accepted
accounting principles and report operating results in terms of historic costs.
This accounting provides reasonable financial statements but does not always
take inflation into consideration. As rate recovery is based on these
historical costs and known and measurable changes, the Company is able to
receive some rate relief for inflation. It does not receive immediate rate
recovery relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation on
plant costs are generally offset by the fact that these assets are financed
through long-term debt.
MARKET RISK
A sensitivity analysis has been prepared to estimate the exposure to the market
price risk of our electricity commodity positions. Assumptions used in the
Blacks-Scholes model include a risk free rate of 5.02 percent, locked in forward
commitment prices for 2002 and 2003, a forward market price averaging
approximately $60 per MWh for periods beyond 2003 with an average of
approximately 60,000 MWh per year. Under an accounting order issued by the
VPSB, changes in the fair value of derivatives are not recognized in earnings
until the derivative positions are settled. Our daily net commodity position
consists of purchased electric capacity. The table below presents market risk,
estimated as the potential loss in fair value resulting from a hypothetical 10
percent adverse change in prices. Actual prices may differ materially from the
table.
Commodity Price Risk At June 30, 2002
Fair Value Market Risk
--------------- ------------
(in thousands)
Net short position $ 33,694 $ 2,341
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
JUNE 30,2002
------------
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings
See Notes 3, 4 and 5 of Notes to Consolidated Financial Statements
ITEM 2. Changes in Securities
NONE
ITEM 3. Defaults Upon Senior Securities
NONE
ITEM 4. Submission of Matters to a Vote of Security Holders
At the Annual Shareholders Meeting held May 16, 2002, one item was
voted upon by Shareholders. Shareholders elected the nominees listed below as
Directors of the Company, with votes cast as indicated.
Elizabeth A. Bankowski, votes for, 4,834,640; withheld authority,
174,615; abstentions, 683,412.
William H. Bruett, votes for, 4,955,998; withheld authority, 53,257;
abstentions, 683,412.
David R. Coates, votes for, 4,953,316; withheld authority, 55,939;
abstentions, 683,412.
Directors continuing in office were Nordahl L. Brue, Merrill O. Burns,
Lorraine E. Chickering, John V. Cleary, Christopher L. Dutton, and Euclid A.
Irving. Thomas P. Salmon retired as Director and Chairman of the Board at the
conclusion of the Annual Shareholders Meeting.
ITEM 5. Other Information
NONE
ITEM 6.
(A) EXHIBITS
----------
Exhibit 10-b-90 Purchase Power Agreement between Entergy Nuclear Vermont Yankee
LLC and Vermont Yankee Nuclear Power Corporation is attached and incorporated by
reference herein.
Exhibit 10-b-91 First Amendment to Purchase Power Agreement, Exhibit 10-b-90 is
attached and incorporated by reference herein.
(B) REPORTS ON FORM 8-K
---------------
The following filings on Form 8-K were filed by the Company on the topics
and dates indicated:
May 16, 2002 Form 8-K announced the election of Nordahl Brue as Chairman of the
Board of Directors of the Company, replacing the retiring Thomas P. Salmon.
June 27, 2002 Form 8-K announced the dismissal of Arthur Andersen as the
Company's independent public accountants, with no disagreements cited.
July 17, 2002 Form 8-K announced the engagement of Deloitte & Touche LLP as the
Company's independent certifying public accountants.
July 31, 2002 Form 8-K announced the completion of the sale of Vermont Yankee's
nuclear generating plant to Entergy.
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 14, 2002 /s/Christopher L. Dutton
--------------------------
Christopher L. Dutton, Chief Executive Officer
and President
Date: August 14, 2002 /s/Robert J. Griffin
----------------------
Robert J. Griffin, (as Principal Financial
Officer)
Controller and Treasurer