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, 2001
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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 MAY 2, 2001
--------------------------- -------------------------------
$3.33 1/3 PAR VALUE 5,623,848
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
AT AND FOR THE THREE MONTHS ENDED MARCH 31,
2001 AND 2000
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
Exhibits and Reports on Form 8-K 23
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
2001 2000
-------- --------
In thousands, except per share data
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $74,796 $67,712
-------- --------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 8,044 8,060
Company-owned generation. . . . . . . . . . . . . . . . . . 2,376 1,204
Purchases from others . . . . . . . . . . . . . . . . . . . 44,016 36,646
Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,368 3,627
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,459 3,483
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 1,457 1,626
Depreciation and amortization. . . . . . . . . . . . . . . . 3,689 4,167
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,988 2,027
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 1,824 2,259
-------- --------
Total operating expenses. . . . . . . . . . . . . . . . . 70,221 63,099
-------- --------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 4,575 4,613
-------- --------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 550 624
Allowance for equity funds used during construction. . . . . 14 62
Other income (deductions), net . . . . . . . . . . . . . . . (27) 185
-------- --------
TOTAL OTHER INCOME (DEDUCTIONS) . . . . . . . . . . . . . 537 871
-------- --------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 5,112 5,484
-------- --------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,547 1,661
Other interest . . . . . . . . . . . . . . . . . . . . . . . 478 144
Allowance for borrowed funds used during construction. . . . (62) (40)
-------- --------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,963 1,765
-------- --------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 3,149 3,719
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . 235 270
-------- --------
Income from continuing operations. . . . . . . . . . . . . . 2,914 3,449
Net income from discontinued segment
operations . . . . . . . . . . . . . . . . . . . . . . . . . - -
Loss on disposal, including provisions for
operating losses during phaseout period. . . . . . . . . . . - -
-------- --------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 2,914 $ 3,449
======== ========
Common stock data
Basic earnings per share . . . . . . . . . . . . . . . . . . $ 0.52 $ 0.63
Diluted earnings per share . . . . . . . . . . . . . . . . . 0.51 0.63
Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14
Weighted average common shares outstanding-basic . . . . . . 5,588 5,437
Weighted average common shares outstanding-diluted . . . . . 5,741 5,437
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . $ 493 $10,344
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . 3,149 3,719
Cash Dividends-redeemable cumulative preferred stock . . . . (235) (270)
Cash Dividends-common stock. . . . . . . . . . . . . . . . . (768) (747)
-------- --------
Balance - end of period. . . . . . . . . . . . . . . . . . . $ 2,639 $13,046
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS
ENDED
MARCH 31
2001 2000
-------------- --------
OPERATING ACTIVITIES: In thousands
Net income before preferred dividends . . . . . . . . . . . $ 3,149 $ 3,719
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . 3,689 4,167
Dividends from associated companies less equity income. . 41 (111)
Allowance for funds used during construction. . . . . . . (76) (102)
Amortization of purchased power costs . . . . . . . . . . 1,015 1,500
Deferred income taxes . . . . . . . . . . . . . . . . . . (173) 447
Deferred revenues . . . . . . . . . . . . . . . . . . . . 7,218 7,163
Deferred purchased power costs. . . . . . . . . . . . . . 551 54
Accrued purchase power contract option call . . . . . . . (1,580) -
Deferred arbitration costs. . . . . . . . . . . . . . . . 61 (457)
Environmental and conservation deferrals, net . . . . . . (840) (542)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . . (2,821) (1,836)
Accrued utility revenues. . . . . . . . . . . . . . . . 214 (50)
Fuel, materials and supplies. . . . . . . . . . . . . . 926 18
Prepayments and other current assets. . . . . . . . . . 1,122 1,487
Accounts payable. . . . . . . . . . . . . . . . . . . . (5,138) 611
Accrued income taxes payable and receivable . . . . . . 1,868 1,997
Other current liabilities . . . . . . . . . . . . . . . 1,063 (1,671)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . (755) 1,297
-------------- --------
Net cash provided by continuing operations. . . . . . . . 9,532 17,691
Net change in discontinued segment. . . . . . . . . . . . - (320)
-------------- --------
Net cash provided by operating activities . . . . . . . . 9,532 17,371
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . . (2,350) (1,852)
Investment in nonutility property . . . . . . . . . . . . . (46) (44)
-------------- --------
Net cash used in investing activities . . . . . . . . . . (2,397) (1,896)
-------------- --------
FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . . 461 301
Investment in certificate of deposit, pledged for revolver. (245) -
Power supply option obligation. . . . . . . . . . . . . . . 370 -
Short-term debt, net. . . . . . . . . . . . . . . . . . . . (6,600) (7,900)
Cash dividends. . . . . . . . . . . . . . . . . . . . . . . (1,003) (1,017)
-------------- --------
Net cash used in financing activities . . . . . . . . . . (7,017) (8,616)
-------------- --------
Net increase(decrease) in cash and cash equivalents . . . . 119 6,859
Cash and cash equivalents at beginning of period. . . . . . 341 696
-------------- --------
Cash and cash equivalents at end of period. . . . . . . . . $ 460 $ 7,555
============== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . . $ 1,354 $ 1,029
Income taxes, net . . . . . . . . . . . . . . . . . . . . - -
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 MARCH 31, DECEMBER 31,
2001 2000 2000
-------- -------- --------
In thousands
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . $291,034 $285,071 $291,107
Less accumulated depreciation . . . . . . . . 111,877 105,490 110,273
-------- -------- --------
Net utility plant . . . . . . . . . . . . . . 179,157 179,581 180,834
Property under capital lease. . . . . . . . . 6,449 7,038 6,449
Construction work in progress . . . . . . . . 8,567 5,310 7,389
-------- -------- --------
Total utility plant, net. . . . . . . . . . 194,173 191,929 194,672
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . 14,332 14,653 14,373
Other investments . . . . . . . . . . . . . . 6,485 5,990 6,357
-------- -------- --------
Total other investments . . . . . . . . . . 20,817 20,643 20,730
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . 460 7,514 341
Certficate of deposit, pledged as collateral. 15,681 - 15,437
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $463, $398, and $463 . . . . . . . . . . 25,186 20,339 22,365
Accrued utility revenues. . . . . . . . . . . 6,880 7,019 7,093
Fuel, materials and supplies, at average cost 3,130 3,272 4,056
Prepayments . . . . . . . . . . . . . . . . . 1,375 1,591 2,525
Income tax receivable . . . . . . . . . . . . - - 1,613
Other . . . . . . . . . . . . . . . . . . . . 249 217 222
-------- -------- --------
Total current assets. . . . . . . . . . . . 52,961 39,952 53,652
-------- -------- --------
DEFERRED CHARGES
Demand side management programs . . . . . . . 6,363 7,158 6,358
Purchased power costs . . . . . . . . . . . . 41,692 11,281 11,789
Pine Street Barge Canal . . . . . . . . . . . 12,370 8,700 12,370
Other . . . . . . . . . . . . . . . . . . . . 15,901 17,456 15,519
-------- -------- --------
Total deferred charges. . . . . . . . . . . 76,326 44,595 46,036
-------- -------- --------
NON-UTILITY
Cash and cash equivalents . . . . . . . . . . - 41 -
Other current assets. . . . . . . . . . . . . 8 8 8
Property and equipment. . . . . . . . . . . . 251 253 252
Business segment held for disposal. . . . . . - 9,797 -
Other assets. . . . . . . . . . . . . . . . . 862 1,306 1,258
-------- -------- --------
Total non-utility assets. . . . . . . . . . 1,121 11,405 1,518
-------- -------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . $345,398 $308,524 $316,608
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS UNAUDITED
---------
AT MARCH 31, DECEMBER 31,
2001 2000 2000
--------- --------- ---------
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
5,617,116, 5,463,948 and 5,582,552) . . . . . . $ 18,723 $ 18,215 $ 18,608
Additional paid-in capital . . . . . . . . . . . 73,668 72,766 73,321
Retained earnings. . . . . . . . . . . . . . . . 2,639 13,046 493
Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378)
--------- --------- ---------
Total common stock equity. . . . . . . . . . . 94,652 103,649 92,044
Redeemable cumulative preferred stock. . . . . . 12,560 12,795 12,560
Long-term debt, less current maturities. . . . . 72,100 81,800 72,100
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . 179,312 198,244 176,704
--------- --------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 6,449 7,038 6,449
--------- --------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 235 1,640 235
Current maturities of long-term debt . . . . . . 9,700 6,700 9,700
Short-term debt. . . . . . . . . . . . . . . . . 8,900 - 15,500
Accounts payable, trade and accrued liabilities. 4,566 6,814 7,755
Accounts payable to associated companies . . . . 6,561 7,057 8,510
Dividends declared . . . . . . . . . . . . . . . 229 285 229
Customer deposits. . . . . . . . . . . . . . . . 753 351 696
Purchased power call option liability. . . . . . 6,696 - 8,276
Interest accrued . . . . . . . . . . . . . . . . 1,753 1,883 1,150
Energy East power supply obligation. . . . . . . 15,789 - 15,419
Deferred revenues. . . . . . . . . . . . . . . . 7,218 7,163 -
Other. . . . . . . . . . . . . . . . . . . . . . 1,532 6,127 874
--------- --------- ---------
Total current liabilities. . . . . . . . . . . 63,932 38,020 68,344
--------- --------- ---------
DEFERRED CREDITS
SFAS 133 liability . . . . . . . . . . . . . . . 31,517 - -
Accumulated deferred income taxes. . . . . . . . 25,541 25,718 25,644
Unamortized investment tax credits . . . . . . . 3,625 3,907 3,695
Pine Street Barge Canal site cleanup . . . . . . 11,140 8,985 11,554
Other. . . . . . . . . . . . . . . . . . . . . . 20,565 26,612 20,901
--------- --------- ---------
Total deferred credits . . . . . . . . . . . . 92,388 65,222 61,794
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Liabilities of discontinued segment, net . . . . 3,317 - 3,317
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . 3,317 - 3,317
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $345,398 $308,524 $316,608
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2001
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 2000 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.
Historically we have charged our customers higher rates for billing cycles in
December through March and lower rates for the remaining months. These are
called seasonally differentiated rates. In order to eliminate the impact of the
seasonally differentiated rates, we defer some of the revenues from those four
months and account for them in later periods when we have lower revenues or
higher costs. By deferring certain revenues we are able to better match our
revenues to our costs. On March 31, 2001 and 2000, there was deferred revenue
of $7.2 million. These deferred revenues are accreted into revenue throughout
the current year. Seasonal rates will be eliminated in April 2001, which is
expected to generate approximately $6.0 million in additional cash flow in 2001
that can be used to offset increased costs during 2001, 2002 and 2003. See the
discussion under "Commitments and Contingencies - Retail Rate Cases" for further
information.
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", formerly known as Mountain Energy, Inc.); Green Mountain
Propane Gas Company Limited ("GMPG"); GMP Real Estate Corporation; and Green
Mountain Resources, Inc. ("GMRI"). On June 30, 1999, we decided to sell the
assets of NWR, and report 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 (excluding NWR) and the rental water heater
program are included 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")
Percent ownership: 17.9% common
Three months ended
March 31
2001 2000
------- -------
(in thousands)
Gross Revenue. . . . . $40,964 $40,692
Net Income Applicable. 1,550 1,744
to Common Stock
Equity in Net Income . 273 314
On October 15, 1999, the owners of VY accepted a bid from AmerGen Energy Company
for the VY generating plant, intending to complete the sale before December
2000. AmerGen and the Vermont Department of Public Service ("DPS" or the
"Department") negotiated a revised offer in November 2000, which was
subsequently dismissed as insufficient by the VPSB in February 2001. Entergy
Nuclear Inc. has also made an offer, secured by a bond which has been approved
by the VPSB, and two other companies have indicated they would participate in an
auction, if held. The plant is likely to be sold at auction, the terms and
conditions of which are unknown at this time.
If the plant is auctioned, then the Company would continue equity ownership
of VY until sold, and would enter into a power supply agreement with the new
plant owners.
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
March 31
2001 2000
------ ------
(in thousands)
Gross Revenue . . . . $7,170 $6,715
Net Income. . . . . . 243 273
Equity in Net Income. 55 84
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("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 March 31, 2001, our total expenditures related to the Pine Street
site since 1982 were approximately $23.9 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 awaiting 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 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
On May 8, 1998, we filed a request with the VPSB to increase our retail
rates by 12.93 percent due to higher power costs, the cost of the January 1998
ice storm, and investments in new plant and equipment (the "1998 rate case").
The Company reached a final settlement agreement with the Department in the
1998 rate case during November 2000. The final settlement agreement contains
the following provisions:
* The Company receives 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 are set at levels that recover the Company's Hydro-Quebec VJO
contract costs, effectively ending the regulatory disallowances experienced by
the Company over the past three years;
* The Company agrees 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 all or substantially all of its short-term credit
facilities with long-term debt or equity financing;
* Seasonal rates will be eliminated in April 2001, which is expected to
generate approximately $6.0 million in additional cash flow in 2001 that can be
utilized to offset potential increased costs during 2001, 2002 and 2003;
* The Company agrees 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; and
* The Company agrees to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in the Company's 1997 rate case.
On January 23, 2001, the VPSB Order (the "Settlement Order") approved the
Company's settlement with the Department, with two additional conditions:
* The VPSB Order requires the Company and its customers to 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 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 cumulative amount of power purchased or called to purchase by
Hydro-Quebec under option B, is approximately 432,000 MWh. Approximately $6.6
million is currently being provided annually in rates to cover the net cost of
9701 calls by Hydro-Quebec, and is recognized ratably over 2001. The Company
recognized $1.7 million in expense during the quarter ended March 31, 2001 to
reflect these estimated costs. A regulatory asset of $4.9 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 and/or amounts previously recorded, the excess cost would be
immediately charged against earnings. No charge for excess cost was required
during the first quarter of 2001. The Company has purchased power sufficient to
fulfill the 9701 option calls for this summer, and no charges in excess of
amounts provided in rates or previously recorded are anticipated for the
remainder of 2001.
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. It is possible our estimate of future power
supply costs could differ materially from actual results.
During 1999, the Company had accrued expected losses for 2000 for
disallowed Hydro-Quebec power supply contracts pursuant to VPSB orders. Results
for the three months ended March 31, 2000 do not reflect any disallowed
Hydro-Quebec power supply costs. If the 1999 accruals, consistent with
generally accepted accounting principles, had not been made, power supply costs
would have been $1.9 million higher for the three months ended March 31, 2000.
POWER SUPPLY AND TRANSMISSION
Company-owned generation expenses increased $1.2 million in the first
quarter of 2001 compared with the same period in 2000 primarily due to the
higher cost of fuels and the unavailability of unique replacement equipment
connecting Vermont's transmission system to that of New York. The lack of such
equipment required running generation to support system reliability. The
Company has requested reimbursement of its costs of running its units for system
reliability from the Independent System Operator of New England ("ISO"). The
Company recorded a regulatory asset and reduced Company-owned generation expense
by $1.0 million, representing incremental fuel and operation and maintenance
costs due from ISO. If the ISO were to reject a portion of the Company's costs,
the Company believes it could recover these costs from ratepayers under the
Settlement Order.
A FERC ruling in December 2000 required ISO to revise its installed
capability ("ICAP") deficiency charge of $0.17 per kw month to $8.75 per kw
month retroactive to August 1, 2000. On January 10, 2001, FERC stayed its order
"to ensure that bills for past periods will not be assessed until the Commission
has considered the pending requests for rehearing, which, if successful, would
then require extensive refunds and surcharges." On March 6, 2001, FERC issued
an Order on Rehearing in which it partly reversed itself on the ICAP charge.
Although the FERC first concluded that a $8.75 charge is reasonable and that the
charge would remain in place until the ISO supports an acceptable superseding
proposal, the FERC then concluded that reinstating the $8.75 would have a large
cost impact. As a result, the $0.17 per kW month charge was reinstated from
August 1, 2000 until April 1, 2001. The FERC allowed the $8.75 charge to become
effective on April 1, 2001 until the effective date of any superseding charge
that the FERC might accept.
On March 16, 2001, an ISO participant filed a request for re-hearing the FERC's
March 6, 2001 Order on Rehearing. The request asks for a reversal of the
lowered ICAP charge for the period from August 1, 2000 until April 1, 2001. If
the lowered ICAP charge is increased to $8.75 per kw month for the period from
August 1, 2000 to March 31, 2001, then the Company would be required to pay ISO
approximately $1.4 million. Also, in March 2001, a federal court issued a stay
preventing reinstatement of the $8.75 charge, after sixteen New England
utilities and energy companies protested the increased penalty. The U.S. Court
of Appeals for the First Circuit in Boston is tentatively scheduled to hear oral
arguments from the utilities and FERC on May 8, 2001, according to the court
order. Management cannot determine the ultimate impact of these actions at this
time.
The Company has purchased ICAP associated with 2001 obligations for its
9701 arrangement with Hydro-Quebec at an average price of approximately $4 per
MWh. The Company has also arranged to purchase 50 percent of its anticipated
9701 ICAP needs during 2002 at an average cost of $2.60 per MWh.
As of March 31, 2001, the Company had deferred a total of $4.6 million, its
share of arbitration costs related to the pursuit of claims against Hydro-Quebec
arising from its suspension of deliveries during and after the 1998 ice storm.
The Company has received an accounting order from the VPSB providing for the
deferral of these charges, subject to final determination in a future rate
proceeding.
On April 17, 2001, an Arbitration Tribunal issued its decision in the
arbitration brought by a group of Vermont electric companies and municipal
utilities, known as the Vermont Joint Owners (VJO), against Hydro-Quebec for its
failure to deliver electricity pursuant to the VJO/Hydro-Quebec power supply
contract during the 1998 ice storm. The Company is a member of the VJO.
In its award, the Arbitration Tribunal agreed partially with Hydro-Quebec
and partially with the VJO. In the split decision, (i) the VJO/Hydro-Quebec
power supply contract remains in effect and Hydro-Quebec is required to continue
to provide capacity and energy to the Company under the terms of the VJO
contract, which expires in 2015 and (ii) Hydro-Quebec is required to return
certain capacity payments to the VJO. Any proceeds ultimately received would
reduce related deferred assets. We believe it is probable that the arbitration
costs, should they exceed any recovery from the arbitration decision, will
ultimately be recovered in rates.
4. SEGMENTS AND RELATED INFORMATION
The Company has two reportable segments, the electric utility and NWR. 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, 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, 1999, we
classified NWR's net assets and liabilities as "Business Segment Held for Sale",
reflecting the Company's intent to sell NWR's assets. Previously, investment in
NWR appeared as a separate caption, "Equity Investment in Energy Related
Business" in the nonutility section of the consolidated balance sheet.
During 2000, the Company recorded losses of $6.5 million, or $1.19 per
share to reflect revised estimates and actual sales of most of NWR's energy
generation and energy efficiency assets. The provisions for loss from
discontinued operations reflect the Company's most recent estimate. The
ultimate loss remains subject to the consummation of the sale or other
disposition of NWR's remaining assets and liabilities, primarily waste-water
treatment projects, and could exceed amounts recorded. Results of operations
for NWR are now reported under "Loss on disposal of discontinued segment, net of
applicable income taxes". Provisions for loss on disposal are reported under
"Loss on disposal of discontinued segment, net of applicable income taxes".
Segment information compared with the Company's results includes the following:
Three months ended
March 31
2001 2000
------- -------
In thousands, except per share data
External revenues
Electric utility. . . . . . . . . . $74,796 $67,712
NWR segment . . . . . . . . . . . . 35 97
Net income (loss) from
operations
Electric utility. . . . . . . . . . $ 2,914 $ 3,449
NWR segment . . . . . . . . . . . . - -
------- -------
Consolidated net income (loss) . . . $ 2,914 $ 3,449
======= =======
Basic earnings (loss) per share
Discontinued operations . . . . . $ - $ -
Continuing operations . . . . . . 0.52 0.63
Diluted earnings per share
Discontinued operations . . . . . - -
Continuing operations . . . . . . $ 0.51 $ 0.63
5. NEW ACCOUNTING STANDARD - SFAS 133
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative
Instruments and Hedging Activities. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in 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. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SFAS 133, as amended by SFAS
137, is effective for the Company beginning the first quarter of 2001. SFAS 133
must be applied to (a) derivative instruments and (b) either all derivative
instruments embedded in hybrid contracts or those embedded instruments that were
issued, acquired, or substantively modified on or after January 1, 1998 or
January 1, 1999 (as elected by the Company).
The Company's 9701 arrangement with Hydro-Quebec that grants Hydro-Quebec
an option to call for energy deliveries at prices currently below estimated
future market rates through 2015 is a derivative under SFAS 133. We sometimes
use future contracts (derivatives) to hedge forecasted wholesale sales of
electric power, including the 9701 arrangement. The Company also has a power
purchase and supply agreement with Morgan Stanley Capital Group, Inc. ("MS") to
hedge the fair value of fossil fuel prices that is a derivative under 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
effects 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 March
31, 2001, the Company had a regulatory asset of approximately $31.5 million
related to the derivatives discussed above. The Company believes that the
regulatory asset is probable of recovery. The regulatory asset is based on
current estimates of future market prices that are likely to change by material
amounts.
If a derivative instrument is terminated early because it is probable that
a transaction or forecasted transaction will not occur, any gain or loss would
be recognized in earnings immediately. For derivatives held to maturity, the
earnings impact would be recorded in the period that the derivative is sold or
matures.
6. 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 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
March 31
2001 2000
------ ------
In thousands
Net income. . . . . . . . . . . . . . . $2,914 $3,449
Preferred stock dividend requirement. . 235 270
------ ------
Net income applicable to common
stock. . . . . . . . . . . . . . . . $3,149 $3,719
====== ======
Average number of common shares-basic . 5,588 5,437
Dilutive effect of stock options. . . . 153 -
Anti-dilutive stock options . . . . . . - -
------ ------
Average number of common shares-diluted 5,741 5,437
====== ======
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
MARCH 31, 2001
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.
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 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 (loss) per share of Common Stock
Three months ended
March 31
2001 2000
----- -----
Utility business . . . $0.50 $0.60
Unregulated businesses 0.02 0.03
----- -----
Earnings(loss) from: . 0.52 0.63
Continuing operations
Discontinued segment . 0.00 0.00
----- -----
Basic earnings
(loss) per share . . $0.52 $0.63
===== =====
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.50 in the quarter ended March 31, 2001, compared with utility earnings of
$0.60 per share in the first quarter of 2000. Increased retail revenues
resulting from a 3.42 percent rate increase approved by the Vermont Public
Service Board ("VPSB") on January 23, 2001 (the "Settlement Order") were more
than offset by higher power supply costs to serve customers.
The Company has previously accrued losses for disallowed Hydro-Quebec power
supply costs pursuant to VPSB orders. Results for the three months ended March
31, 2000 do not reflect any disallowed Hydro-Quebec power supply costs. If
these accruals, consistent with generally accepted accounting principles, had
not been made in prior periods, power supply costs would have been $1.9 million
higher for the three months ended March 31, 2000. Power supply costs were also
higher in the first quarter of 2001 due to increased regional energy prices,
reduced availability of some Company hydroelectric generation capacity, energy
purchases to cover potential shortages due to transmission system operating
requirements, and scheduled increases in our long-term power supply contract
with MS.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from
continuing operations for the three months ended March 31, 2001 were slightly
lower than during the same period in 2000. A financial summary for these
businesses, excluding NWR, follows:
Three months ended
March 31
2001 2000
----- -----
In thousands
Revenue. . . $ 259 $ 262
Expense. . . 125 125
----- -----
Net Income . $ 134 $ 137
===== =====
DISCONTINUED SEGMENT OPERATIONS
As of June 30, 1999, the Company decided to sell or dispose of NWR, a
wholly owned subsidiary that invested in energy generation, energy efficiency
and wastewater treatment businesses. Its results are reported separately after
income (loss) from continuing operations. NWR's operating loss for the three
months ended March 31, 2001 has been previously recognized as provision for
operating loss during phase-out period. The ultimate loss remains subject to
the sale or other disposition of NWR's remaining assets and liabilities,
primarily waste-water treatment projects, and could exceed amounts recorded.
Most of NWR's energy generation and energy efficiency assets have been sold.
The operating loss for the three months ended March 31, 2001 would have been
approximately $486,000 compared with a loss of $879,000 for the same period a
year ago.
OPERATING REVENUES AND MWH SALES
Our revenues from operations, megawatthour ("MWh") sales and average number of
customers for the three months ended March 31, 2001 and 2000 are summarized
below:
Three months ended
March 31
2001 2000
---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 51,953 $ 49,550
Sales for Resale. . . 21,838 17,300
Other . . . . . . . . 1,005 862
---------- ----------
Total Operating Revenues. $ 74,796 $ 67,712
========== ==========
MWh sales-Retail. . . . . 520,771 520,222
MWh sales for Resale. . . 638,096 567,685
---------- ----------
Total MWh Sales . . . . . 1,158,867 1,087,907
========== ==========
Average Number of Customers
Three months ended
March 31
2001 2000
------ ------
Residential . . . . . . . 73,149 72,165
Commercial and Industrial 12,933 12,574
Other . . . . . . . . . . 65 64
------ ------
Total Number of Customers. . 86,147 84,803
====== ======
REVENUES
Revenues from operations in the first quarter of 2001 increased 10.5
percent or $7.1 million compared with the same period in 2000. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the first quarter of 2001 were $2.4 million or 4.8
percent higher compared with the same period in 2000, reflecting a 3.42 percent
rate increase effective January 2001, and a 0.1 percent increase in retail MWh
sales. Sales of electricity increased by 1.6 percent to small commercial and
industrial customers, and decreased by 2.0 percent to residential customers and
1.1 percent to lower margin industrial customers during the first quarter of
2001 compared with the same period in 2000.
We sell wholesale electricity to others for resale. Our revenue from
wholesale sales of electricity increased $4.5 million in the first quarter of
2001 compared with the same period in 2000. The increase was due primarily to
increased sales under a power purchase and supply agreement between the Company
and MS, and increased sales under various arrangements with Hydro-Quebec. Under
the MS agreement, we sell power to MS at predefined operating and pricing
parameters. MS then sells to us, at a predefined price, power sufficient to
serve pre-established load requirements.
OPERATING EXPENSES
POWER SUPPLY EXPENSES - THREE MONTHS ENDED MARCH 31, 2001
Power supply expenses increased 18.6 percent or $8.5 million in the first
quarter of 2001 over the same period in 2000.
Power supply expenses at Vermont Yankee ("VY") decreased 0.2% or $16,000
during the first quarter of 2001 compared with the first quarter of 2000. A
proposed sale of the generating plant is discussed under Part I, Item 2,
"Investment in Associated Companies".
Company-owned generation expenses increased $1.2 million in the first
quarter of 2001 compared with the same period in 2000 primarily due to the
higher cost of fuels and the unavailability of unique replacement equipment
connecting Vermont's transmission system to that of New York. The lack of
replacement equipment required running generation to support system reliability.
The Company has requested reimbursement of its costs of running its units for
system reliability from the Independent System Operator of New England ("ISO").
The Company recorded a regulatory asset and reduced Company-owned generation
expense by $1.0 million, representing incremental fuel and operation and
maintenance costs due from ISO.
The cost of power that we purchased from other companies increased 16.5
percent or $7.4 million in the first quarter of 2001 compared with the same
period in 2000. This was primarily due to power supply costs for increased
wholesale electric sales of $4.5 million to replace power sold to Hydro-Quebec
under a previous arrangement ("9701"), to buy energy that could potentially have
been curtailed due to transmission system operating requirements, and for power
sold to MS under the power purchase and supply agreement.
Power supply costs were also higher during the first quarter of 2001
compared with the same period in 2000 due to higher energy clearing prices in
the New England market, the unavailability of hydroelectric capacity that is
estimated to have cost the Company an additional $850,000, and scheduled
increases in the cost of power under our long-term contract with MS.
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
first quarter of 2001, Hydro-Quebec exercised its purchase option for delivery
of 134,592 MWh during the months of June, July and August of 2001. The
Settlement Order approved by the VPSB includes revenues in 2001 sufficient to
provide for net costs of replacing power purchased by Hydro-Quebec of
approximately $6.6 million annually. The Company recognized $1.7 million in
expense during the quarter ended March 31, 2001 to reflect these estimated
costs. A regulatory asset of $4.9 million was established for the remaining
estimated difference between the option exercise price and the expected cost of
replacement power for 2000 to be recovered during 2001. If the estimated costs
of power purchased to supply Hydro-Quebec option calls exceed amounts recovered
in rates and/or amounts previously recorded, the excess cost would be
immediately charged against earnings. No charge for excess cost was required
during the first quarter of 2001. The Company has purchased power sufficient to
fulfill the 9701 calls for this summer, and no charges in excess of amounts
provided in rates or previously recorded are anticipated for the remainder of
2001. The net cost of power to supply all 9701 option calls during 2001 is
estimated at approximately $8.4 million. It is possible our estimate of future
power supply costs could differ materially from actual results.
Both the 9701 arrangement and the 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 March 31, 2001, the Company had a regulatory
asset of approximately $31.5 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.
OTHER OPERATING EXPENSES
Other operating expenses decreased 7.2 percent or $259,000 in the first
quarter of 2001 compared with the same period in 2000. The reduction reflects
decreased amortization due to the write-off of state regulatory commission costs
coincident with the Settlement Order.
TRANSMISSION EXPENSES
Transmission expenses decreased by approximately $24,000 or 0.7% for the
three months ended March 31, 2001 compared with the same period in 2000.
Congestion charges recorded in the first quarter of 2001 and 2000 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.
The Company is unable to predict the magnitude or duration of future congestion
charge allocations, but amounts could be material.
DEPRECIATION AND AMORTIZATION EXPENSES
Depreciation and amortization expenses decreased $478,000 or 11.5 percent
during the first quarter of 2001 compared with the same period in 2000. The
reduction is primarily due to decreased amortization of demand side management
assets.
TAXES OTHER THAN INCOME TAXES
Other taxes decreased 1.9 percent or $39,000 in the first quarter of 2001
compared with the same period in 2000, reflecting payroll tax decreases that
were partially offset by gross revenue tax increases.
INCOME TAXES
Income taxes decreased $435,000 in the first quarter of 2001 compared with
the same period in 2000 due to a decrease in pretax book income for core
electric operations.
OTHER INCOME
Other income for the three months ended March 31, 2001 decreased
approximately $334,000 or 38.3 percent compared with the same period in 2000 due
primarily to decreases in capitalized interest costs and decreased earnings from
subsidiaries.
INTEREST CHARGES
Interest charges increased 11.24 percent or $198,000 in the first quarter
of 2001 over the same period in 2000 primarily due to costs associated with the
revolving lines of credit discussed under "Liquidity and Capital Resources".
LIQUIDITY AND CAPITAL RESOURCES
In the three months ended March 31, 2001, we spent $2.8 million principally
for expansion and improvements of our transmission and distribution plant. We
expect to spend an additional $13.0 million during the remainder of 2001.
On June 21, 2000, we renewed a revolving credit agreement with Fleet
National Bank and Citizens Bank of Massachusetts (the "Fleet Agreement"). The
Fleet Agreement is for a period of 364 days, will expire on June 20, 2001, and
is secured by granting the banks a second priority mortgage, lien and security
interest in the collateral pledged under the Company's first mortgage bond
indenture. We had no borrowings outstanding on the Fleet Agreement at March 31,
2001.
On September 20, 2000, we established a $15.0 million revolving credit
agreement with KeyBank National Association ("KeyBank"). The agreement will
expire on September 19, 2001. Pursuant to a one year power supply option
agreement between the Company and Energy East Corporation ("EE"), EE made a
payment of $15.0 million to the Company. In exchange, the Company gave EE an
option to purchase energy from certain wholly owned production facilities, for a
period not to exceed 15 years, if the funds are not returned to EE upon request
after September 2001. The Company was required to invest the funds provided by
EE in a certificate of deposit at KeyBank pledged by the Company to secure the
repayment of the Keybank revolving credit facility. At March 31, 2001, there
was $8.9 million outstanding on the KeyBank revolving credit agreement.
The Company anticipates that it will secure financing that replaces some or
all of its expiring facilities during 2001 and that amounts financed will be
sufficient to meet our forecasted borrowing requirements during 2001.
The credit ratings of the Company's securities are:
Fitch Moody's Standard & Poor's
----- ------- -------------------
First mortgage bonds BBB Baa2 BBB
Preferred stock BBB- baa3 BB
During the first quarter of 2001, Moody's Investors Service and Fitch upgraded
the Company's first mortgage bond and preferred stock ratings. The rating
actions reflected the rating agencies' earnings and cash flow expectations for
the Company following the Settlement Order. Standard & Poor's has favorably
changed its outlook, which already rated the first mortgage bonds at investment
grade, relative to the ratings direction for the Company.
COMPETITION AND RESTRUCTURING
The electric utility business is experiencing rapid and substantial
changes. These changes are the result of the following trends:
* Disparity in electric rates among and within various regions of the
country;
* Improvements in generation efficiency;
* Alternative energy sources;
* Increasing demand for customer choice;
* The deregulation of the energy market and the establishment of an
independent system operator; and
* The contemplated restructuring of the Vermont electric industry to
introduce competition.
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.
NUCLEAR DECOMMISSIONING
The staff of the SEC has questioned certain current accounting practices of
the electric utility industry regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating units in
financial statements. In response to these questions, the Financial Accounting
Standards Board had agreed to review the accounting for closure and removal
costs, including decommissioning. We do not believe that changes in such
accounting, if required, would have an adverse effect on the results of
operations due to our current and future ability to recover decommissioning
costs through rates.
EFFECTS OF INFLATION
Financial statements are prepared in accordance with generally accepted
accounting principles and report operating results in terms of historic costs.
This method of 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. 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.
At March 31, 2001
Fair value Market risk
------------------- -------------
In thousands
Highest long position . $ 86,993 $ 8,699
Highest short position. $ 116,841 $ 11,684
Average position(short) $ (29,848) $ (2,985)
PART II
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
The following filings on Form 8-K were filed by the Company on the topics and
dates indicated:
April 17, 2001 Form 8-K announced the decision reached by the arbitration
tribunal in the Company's arbitration with Hydro-Quebec regarding ice-storm
related delivery failure. The arbitration tribunal decided the VJO/Hydro-Quebec
power supply contract remains in effect and Hydro-Quebec is required to continue
to provide capacity and energy to the Company under the terms of the VJO
contract, which expires in 2015, and Hydro-Quebec is required to return certain
capacity payments to the Company.
May 1, 2001 Form 8-K announced the upgrade in credit rating by Fitch. Fitch
upgraded credit ratings for the company's first mortgage bonds from BB+ to BBB,
and preferred stock from B+ to BBB- following the favorable rate order approved
by the VPSB in January 2001.
------
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, 2001 /s/ NANCY ROWDEN BROCK
-------------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer, Secretary,
and Treasurer
Date: May 10, 2001 /s/ROBERT J. GRIFFIN
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Robert J. Griffin, Controller