August 9, 2001
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, 2001
-------------
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
------
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
VERMONT 03-0127430
------------------ ----------
(STATE OR OTHER JURISDICTION OF INCORPORATION (I.R.S. EMPLOYER
IDENTIFICATION NO.)
OR ORGANIZATION)
163 ACORN LANE
COLCHESTER, VT 05446
--------------------- -----------
ADDRESS OF PRINCIPAL EXECUTIVE OFFICES (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (802) 864-5731
---------------
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES X NO
---
INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE ISSUER'S CLASSES
OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.
CLASS - COMMON STOCK OUTSTANDING AT JULY 31, 2001
--------------------------- ---------------------------------
$3.33 1/3 PAR VALUE 5,634,840
2
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
AT AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30,
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 17
And Results of Operations
Exhibits and Reports on Form 8-K 26
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
2001 2000 2001 2000
-------- -------- --------- ---------
(in thousands, except per share data)
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $67,471 $61,927 $142,267 $129,639
-------- -------- --------- ---------
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 5,737 8,726 19,422 17,911
Company-owned generation. . . . . . . . . . . . . . . . . . (133) 1,710 2,243 2,914
Purchases from others . . . . . . . . . . . . . . . . . . . 40,166 42,987 78,541 78,508
Other operating. . . . . . . . . . . . . . . . . . . . . . . 4,405 3,671 7,773 7,299
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,544 3,604 7,002 7,088
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 2,078 1,553 3,535 3,179
Depreciation and amortization. . . . . . . . . . . . . . . . 3,623 3,977 7,312 8,144
Taxes other than income. . . . . . . . . . . . . . . . . . . 1,915 1,765 3,903 3,791
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 1,861 (3,069) 3,687 (811)
-------- -------- --------- ---------
Total operating expenses. . . . . . . . . . . . . . . . . 63,196 64,924 133,418 128,023
-------- -------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 4,275 (2,997) 8,849 1,616
-------- -------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 584 620 1,135 1,244
Allowance for equity funds used during construction. . . . . 45 79 59 141
Other income (deductions), net . . . . . . . . . . . . . . . (47) (91) (74) 94
-------- -------- --------- ---------
TOTAL OTHER INCOME. . . . . . . . . . . . . . . . . . . . 582 608 1,120 1,479
-------- -------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 4,857 (2,389) 9,969 3,095
-------- -------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,547 1,647 3,095 3,308
Other interest . . . . . . . . . . . . . . . . . . . . . . . 232 111 710 255
Allowance for borrowed funds used during construction. . . . (41) (42) (103) (82)
-------- -------- --------- ---------
TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,738 1,716 3,702 3,481
-------- -------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 3,119 (4,105) 6,267 (386)
DISCONTINUED OPERATIONS
Dividends on preferred stock . . . . . . . . . . . . . . . . 235 270 469 539
-------- -------- --------- ---------
Income from continuing operations. . . . . . . . . . . . . . 2,884 (4,375) 5,798 (925)
Loss on disposal of discontinued segment,
including provisions for operating
losses during phaseout period. . . . . . . . . . . . . . . . (150) (1,530) (150) (1,530)
-------- -------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . $ 2,734 $(5,905) $ 5,648 $ (2,455)
======== ======== ========= =========
Common stock data
Basic earnings (loss) per share. . . . . . . . . . . . . . . $ 0.49 $ (1.08) $ 1.01 $ (0.45)
Diluted earnings (loss) per share. . . . . . . . . . . . . . 0.47 (1.08) 0.98 (0.45)
Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.55 $ 0.55
Weighted average common shares outstanding-basic . . . . . . 5,615 5,472 5,602 5,455
Weighted average common shares outstanding-diluted . . . . . 5,777 5,472 5,759 5,455
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . $ 2,639 $13,046 $ 493 $ 10,344
Net Income (loss). . . . . . . . . . . . . . . . . . . . . . 2,969 (5,635) 6,117 (1,916)
Cash Dividends-redeemable cumulative preferred stock . . . . (235) (270) (469) (539)
Cash Dividends-common stock. . . . . . . . . . . . . . . . . (771) (752) (1,539) (1,500)
-------- -------- --------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . $ 4,602 $ 6,389 $ 4,602 $ 6,389
======== ======== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED
JUNE 30,
2001 2000
--------------- ---------
OPERATING ACTIVITIES: (in thousands)
Net income (loss) before preferred dividends. . . . . . . . $ 6,117 $ (1,916)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . 7,312 8,144
Dividends from associated companies less equity income. . 21 (57)
Allowance for funds used during construction. . . . . . . (162) (223)
Amortization of purchased power costs . . . . . . . . . . 2,008 3,058
Deferred income taxes . . . . . . . . . . . . . . . . . . (1,714) 1,145
Deferred revenues . . . . . . . . . . . . . . . . . . . . 3,158 3,580
Deferred purchased power costs. . . . . . . . . . . . . . (1,966) (3,103)
Accrued purchase power contract option call . . . . . . . (2,376) 12,478
Provision for loss on segment disposal. . . . . . . . . . 150 1,530
Deferred arbitration costs. . . . . . . . . . . . . . . . 108 (2,157)
Earnings cap deferral and rate levelization liability . . 4,869 -
Environmental and conservation deferrals, net . . . . . . (1,377) (826)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . . 1,034 1,347
Accrued utility revenues. . . . . . . . . . . . . . . . 708 597
Fuel, materials and supplies. . . . . . . . . . . . . . (261) 226
Prepayments and other current assets. . . . . . . . . . 1,578 2,064
Accounts payable. . . . . . . . . . . . . . . . . . . . (1,346) 1,947
Accrued income taxes payable and receivable . . . . . . 2,125 (2,801)
Other current liabilities . . . . . . . . . . . . . . . 389 (3,888)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . (583) 196
--------------- ---------
Net cash provided by continuing operations. . . . . . . . 19,793 21,341
Net change in discontinued segment. . . . . . . . . . . . (1,533) (86)
--------------- ---------
Net cash provided by operating activities . . . . . . . . 18,260 21,255
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . . (5,224) (5,983)
Investment in nonutility property . . . . . . . . . . . . . (101) (97)
--------------- ---------
Net cash used in investing activities . . . . . . . . . . (5,325) (6,080)
--------------- ---------
FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . . 806 561
Investment in certificate of deposit, pledged for revolver. (500) -
Power supply option obligation. . . . . . . . . . . . . . . 744 -
Reduction in long-term debt . . . . . . . . . . . . . . . . (1,700) (1,700)
Short-term debt, net. . . . . . . . . . . . . . . . . . . . (10,608) (7,900)
Cash dividends. . . . . . . . . . . . . . . . . . . . . . . (2,008) (2,039)
--------------- ---------
Net cash used in financing activities . . . . . . . . . . (13,266) (11,078)
--------------- ---------
Net increase(decrease) in cash and cash equivalents . . . . (330) 4,097
Cash and cash equivalents at beginning of period. . . . . . 341 696
--------------- ---------
Cash and cash equivalents at end of period. . . . . . . . . $ 11 $ 4,793
=============== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . . $ 3,720 $ 3,258
Income taxes, net . . . . . . . . . . . . . . . . . . . . 3,292 1,191
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,
2001 2000 2000
-------- -------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost. . . . . . . . $295,133 $287,105 $291,107
Less accumulated depreciation. . . . . . . . . 114,380 107,934 110,273
-------- -------- --------
Net utility plant. . . . . . . . . . . . . . . 180,753 179,171 180,834
Property under capital lease . . . . . . . . . 6,449 7,038 6,449
Construction work in progress. . . . . . . . . 6,955 7,037 7,389
-------- -------- --------
Total utility plant, net . . . . . . . . . . 194,157 193,246 194,672
-------- -------- --------
OTHER INVESTMENTS
Associated companies, at equity. . . . . . . . 14,322 14,708 14,373
Other investments. . . . . . . . . . . . . . . 6,598 6,043 6,357
-------- -------- --------
Total other investments. . . . . . . . . . . 20,920 20,751 20,730
-------- -------- --------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . 11 4,755 341
Certficate of deposit, pledged as collateral . 15,936 - 15,437
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $613, $398, and $463. . . . . . . . . . . 24,560 17,155 22,365
Accrued utility revenues . . . . . . . . . . . 6,385 6,371 7,093
Fuel, materials and supplies, at average cost. 4,316 3,063 4,056
Prepayments. . . . . . . . . . . . . . . . . . 889 340 2,525
Income tax receivable. . . . . . . . . . . . . - 4,042 1,613
Other. . . . . . . . . . . . . . . . . . . . . 278 178 222
-------- -------- --------
Total current assets . . . . . . . . . . . . 52,375 35,904 53,652
-------- -------- --------
DEFERRED CHARGES
Demand side management programs. . . . . . . . 6,485 6,586 6,358
Purchased power costs. . . . . . . . . . . . . 24,318 9,663 11,789
Pine Street Barge Canal. . . . . . . . . . . . 12,370 8,700 12,370
Other. . . . . . . . . . . . . . . . . . . . . 15,749 16,598 15,519
-------- -------- --------
Total deferred charges . . . . . . . . . . . 58,922 41,547 46,036
-------- -------- --------
NON-UTILITY
Cash and cash equivalents. . . . . . . . . . . - 39 -
Other current assets . . . . . . . . . . . . . 8 8 8
Property and equipment . . . . . . . . . . . . 251 253 252
Business segment held for disposal . . . . . . - 8,033 -
Other assets . . . . . . . . . . . . . . . . . 847 1,294 1,258
-------- -------- --------
Total non-utility assets . . . . . . . . . . 1,106 9,627 1,518
-------- -------- --------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . $327,480 $301,075 $316,608
======== ======== ========
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,
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
5,641,009, 5,498,037and 5,582,552). . . . . . . $ 18,802 $ 18,327 $ 18,608
Additional paid-in capital . . . . . . . . . . . 73,933 72,913 73,321
Retained earnings. . . . . . . . . . . . . . . . 4,602 6,389 493
Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378)
--------- --------- ---------
Total common stock equity. . . . . . . . . . . 96,959 97,251 92,044
Redeemable cumulative preferred stock. . . . . . 12,560 12,795 12,560
Long-term debt, less current maturities. . . . . 70,400 80,100 72,100
--------- --------- ---------
Total capitalization . . . . . . . . . . . . . 179,919 190,146 176,704
--------- --------- ---------
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. . . . . . . . . . . . . . . . . 4,892 - 15,500
Accounts payable, trade and accrued liabilities. 8,985 6,400 7,755
Accounts payable to associated companies . . . . 5,932 8,808 8,510
Earnings cap deferral. . . . . . . . . . . . . . 925 - -
Customer deposits. . . . . . . . . . . . . . . . 816 379 696
Purchased power call option liability. . . . . . 5,901 12,478 8,276
Interest accrued . . . . . . . . . . . . . . . . 1,075 1,151 1,150
Energy East power supply obligation. . . . . . . 16,163 - 15,419
Deferred revenues. . . . . . . . . . . . . . . . 3,158 3,580 -
Other. . . . . . . . . . . . . . . . . . . . . . 1,959 3,430 1,103
--------- --------- ---------
Total current liabilities. . . . . . . . . . . 59,741 44,566 68,344
--------- --------- ---------
DEFERRED CREDITS
SFAS 133 liability . . . . . . . . . . . . . . . 15,714 - -
Accumulated deferred income taxes. . . . . . . . 24,071 26,487 25,644
Unamortized investment tax credits . . . . . . . 3,554 3,836 3,695
Pine Street Barge Canal site cleanup . . . . . . 11,080 8,910 11,554
Other. . . . . . . . . . . . . . . . . . . . . . 21,374 20,092 20,901
Rate levelization liability. . . . . . . . . . . 3,944 - -
--------- --------- ---------
Total deferred credits . . . . . . . . . . . . 79,737 59,325 61,794
--------- --------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Liabilities of discontinued segment, net . . . . 1,634 - 3,317
--------- --------- ---------
Total non-utility liabilities. . . . . . . . . 1,634 - 3,317
--------- --------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $327,480 $301,075 $316,608
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 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 includes 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 recognize 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 June 30, 2001, there was deferred revenue of $3.2 million,
compared with $3.6 million at June 30, 2000.
In the Company's most recent rate case settlement the VPSB ordered that seasonal
rates be eliminated in April 2001, which is expected to generate approximately
$7.0 million in additional cash flow in 2001. Such deferred revenue was intended
by the VPSB to be used to offset increased costs during 2001, 2002 and 2003,
increasing the likelihood of the Company earning its allowed rate of return in
those years. Approximately $3.9 million of revenue arising as a result of the
elimination of seasonal rates was deferred during the second quarter of 2001.
The Company's earnings from electric operations are subject to an earnings cap
equal to its allowed rate of return of 11.25%. The Company's policy is to
review its quarterly results and to defer any revenues that are probable of
causing earnings to exceed an 11.25% rate of return ("excess earnings") for the
year. As a result of our review, we deferred $0.9 million of revenue and
recorded a regulatory liability for excess earnings in the same amount during
the quarter ended June 2001. Under a settlement agreement with the Vermont
Department of Public Service ("DPS" or the "Department"), and approved by the
VPSB, any excess earnings amounts will be used to write off regulatory assets.
The Company reviews its deferred revenue balances arising from excess earnings
and rate levelization each quarter and adjusts those balances as necessary to
reflect the Company's current estimate of its ultimate regulatory liability. See
the discussion under "Commitments and Contingencies - Retail Rate Cases" for
further information.
Certain line items on the prior years' 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 unregulated 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 Six months ended
June 30 June 30
2001 2000 2001 2000
------- ------- ------- -------
(in thousands)
Gross Revenue. . . . . $57,031 $44,702 $97,995 $85,394
Net Income Applicable. 1,574 1,639 3,124 3,383
to Common Stock
Equity in Net Income . 287 301 560 615
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 DPS negotiated a revised offer in November 2000, which
was subsequently dismissed as insufficient by the VPSB in February 2001. Prior
to the dismissal of the AmerGen offer, Entergy Nuclear Inc. had also made an
offer, secured by a bond which was acceptable to the VPSB, and two other
companies indicated they would participate in an auction, if held. VY has
initiated an auction of the plant. The terms and conditions of a sale of the
plant by auction, if any, are unknown at this time.
If the plant is sold, the Company would continue equity ownership of VY,
and would expect to 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
Three months ended Six months ended
June 30 June 30
2001 2000 2001 2000
------ ------ ------- -------
(in thousands)
Gross Revenue . . . . $8,548 $7,425 $15,718 $14,140
Net Income. . . . . . 309 310 552 583
Equity in Net Income. 91 90 146 174
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.
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 June 30, 2001, our total expenditures related to the Pine Street
site since 1982 were approximately $24.0 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 recovery 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 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 over the past three years;
* 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 annual 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 were eliminated in April 2001, which is expected to
generate approximately $7.0 million in additional cash flow in 2001 that can be
utilized to offset potential increased costs during 2001, 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; and
* The Company agreed to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in the Company's 1997 rate case. The Company agreed to an earnings
cap for its electric operations in an amount equal to its allowed rate of return
of 11.25 percent. Amounts earned over the cap will be used to write-off
regulatory assets.
On January 23, 2001, the VPSB Order (the "Settlement Order") approved the
Company's settlement with the Department, with two additional conditions:
* The Settlement Order provided that the Company and its customers 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 be purchased 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 $3.3 million in expense during the six months ended June 30, 2001 to
reflect these 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. In conjunction with
the Settlement Order, Hydro-Quebec agreed not to call option B during 2002.
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 half 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. It is possible our estimate of future power supply costs
could differ materially from actual results.
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 through 2015, 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.
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 and six months ended June 30, 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 and $3.8 million higher for the three and six months ended
June 30, 2000, respectively.
POWER SUPPLY AND TRANSMISSION
Company-owned generation expenses decreased $1.8 million in the second
quarter of 2001 compared with the same period in 2000 primarily due to a
reimbursement by the New England Independent System Operator ("ISO") of
Company-owned generation expenses recorded in previous periods and because of
the unavailability of transmission equipment beginning in the second quarter of
2000 that required running generation to maintain system reliability. The
Company requested reimbursement of its costs of running its units for system
reliability from the ISO. During the first quarter of 2001, the Company
recorded a receivable and reduced Company-owned generation expense by $1.0
million, representing such fuel and operation and maintenance costs due from the
ISO. The Company received $1.9 million from the ISO in July 2001 and recorded
the additional $0.9 million as a reduction to Company-owned generation expense
in the second quarter of 2001.
A FERC ruling in December 2000 required the 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 an
adverse cost impact, and should be effective only as of 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.
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 federal court lifted the stay but ordered FERC to
further justify its decision and said that a $5 per kW month rate might be more
appropriate. Management cannot determine the ultimate outcome of these
regulatory and judicial proceedings at this time.
The Company's generation and entitlements cover the majority of its ICAP
requirements, except for its obligations under the 9701 arrangement with
Hydro-Quebec. The Company has purchased ICAP associated with 2001 obligations
for its 9701 arrangement at an average price of approximately $4.00 per kW
month. The Company has also arranged to purchase its anticipated 9701 ICAP
needs during 2002 at an average cost of $2.60 per kW month, and approximately 50
percent of its anticipated 9701 ICAP needs during 2003 at a cost of $2.85 per kW
month.
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 decision, the Tribunal concluded (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.
As of June 30, 2001, the Company had deferred a total of $4.6 million,
representing its share of costs related to the pursuit of arbitration against
Hydro-Quebec. 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 July 23, 2001, the Company received approximately $3.2 million
representing its share of refunded capacity payments from Hydro-Quebec. These
proceeds reduced related deferred assets at June 30, 2001, leaving a balance of
unrecovered arbitration costs of approximately $1.4 million. We believe it is
probable that this balance 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. During the quarter ended June 30,
2001, the Company recorded a provision for loss of $0.2 million or 3 cents per
share related to a revision to its estimate of the ultimate costs of warranty
obligations on its waste-water investments. The provisions for loss from
discontinued operations reflect the Company's most recent estimate. The
ultimate loss remains subject to the sale or other disposition of NWR's
remaining assets and liabilities, primarily patents and warranty claims, and tax
liabilities, 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 Six months ended
June 30 June 30
2001 2000 2001 2000
-------- -------- --------- ---------
(in thousands, except per share data)
External revenues
Electric utility . . . . . . . . . . $67,471 $61,927 $142,267 $129,639
NWR segment. . . . . . . . . . . . . 35 521 104 618
Net income (loss) from
operations
Electric utility . . . . . . . . . . $ 2,884 $(4,375) $ 5,798 $ (925)
NWR segment. . . . . . . . . . . . . (150) (1,530) (150) (1,530)
-------- -------- --------- ---------
Consolidated net income (loss). . . . $ 2,734 $(5,905) $ 5,648 $ (2,455)
======== ======== ========= =========
Basic earnings (loss) per share
Discontinued operations. . . . . . $ (0.03) $ (0.28) $ (0.03) $ (0.28)
Continuing operations. . . . . . . 0.52 (0.80) 1.04 (0.17)
Diluted earnings per share
Discontinued operations. . . . . . $ (0.03) $ (0.28) $ (0.03) $ (0.28)
Continuing operations. . . . . . . 0.47 (1.08) 0.98 (0.45)
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 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. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement or other
comprehensive income, 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, was 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 objective of the Company's risk management program is to protect cash
flow and earnings by minimizing risk. Permitted transactions 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 risk of fossil fuel price increases as well as
the risk of 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 limits to transaction authority.
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 futures 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 requires 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 June 30,
2001, the Company had a liability reflecting the negative market position of the
two derivatives described above, as well as a corresponding regulatory asset of
approximately $15.7 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. OTHER NEW ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board ("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 and uses a nonamortization
approach to purchased goodwill. SFAS 142 establishes requirements for
evaluating goodwill and other intangible assets for impairment and provides
further guidance on accounting for intangible assets. The Company does not
expect the application of these accounting standards, when adopted, to
materially impact its financial position or results of operations.
The FASB is expected to issue a new statement on accounting standards in
August 2001 for "Accounting for the Impairment or Disposal of Long-lived Assets
and for Obligations Associated with Disposal Activities", which will provide
guidance on accounting for nuclear plant decommissioning costs. The Company has
not yet determined what impact, if any, the proposed accounting standard will
have on its investment in VY.
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 period presented. 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 Six months ended
June 30 June 30
2001 2000 2001 2000
------ -------- ------ --------
(in thousands)
Net income (loss) before preferred dividends. $2,969 $(5,635) $6,117 $(1,916)
Preferred stock dividend requirement. . . . . 235 270 469 539
------ -------- ------ --------
Net income (loss) applicable to common
stock. . . . . . . . . . . . . . . . . . . $2,734 $(5,905) $5,648 $(2,455)
====== ======== ====== ========
Average number of common shares-basic . . . . 5,615 5,472 5,602 5,455
Dilutive effect of stock options. . . . . . . 162 - 158 -
Anti-dilutive stock options . . . . . . . . . - - - -
------ -------- ------ --------
Average number of common shares-diluted . . . 5,777 5,472 5,760 5,455
====== ======== ====== ========
GREEN MOUNTAIN POWER CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
JUNE 30, 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 Six months ended
June 30 June 30
2001 2000 2001 2000
------- ------- ------- -------
Utility business . . . $ 0.51 $(0.83) $ 0.99 $(0.22)
Unregulated businesses 0.02 0.03 0.05 0.05
------- ------- ------- -------
Earnings(loss) from: . 0.52 (0.80) 1.04 (0.17)
Continuing operations
Discontinued segment . (0.03) (0.28) (0.03) (0.28)
------- ------- ------- -------
Basic earnings
(loss) per share . . $ 0.49 $(1.08) $ 1.01 $(0.45)
======= ======= ======= =======
UTILITY BUSINESS
The Company recorded basic earnings per share from utility operations of
$0.51 in the quarter ended June 30, 2001, compared with a loss of $0.83 per
share in the second quarter of 2000.
The second quarter earnings improvement, compared with the same period for 2000,
reflects a significant reduction in power supply costs and higher operating
revenues. Power supply costs were $7.7 million lower in the second quarter of
2001, primarily due to decreased costs associated with the management of the
Company's long-term power supply sale commitment to Hydro-Quebec. Retail
operating revenues for the quarter increased $2.0 million compared with the
same period in 2000, reflecting a 3.42 percent retail rate increase approved by
the Vermont Public Service Board (the "VPSB") in January 2001 and a 0.6 percent
increase in retail electricity sales.
Basic earnings per share from utility operations for the six months ended June
30, 2001 were $0.99 compared with a loss per share of $0.22 for the same period
in 2000, due to the same factors influencing second quarter results.
The Company had previously accrued losses for disallowed Hydro-Quebec power
supply costs pursuant to VPSB orders. Results for the six months ended June 30,
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 and $3.8 million
higher, respectively, for the three and six months ended June 30, 2000.
UNREGULATED BUSINESSES
Earnings from unregulated businesses included in results from
continuing operations for the three and six months ended June 30, 2001 were
slightly lower than during the same period in 2000. A financial summary for
these businesses, excluding NWR, follows:
Three months ended Six months ended
June 30 June 30
2001 2000 2001 2000
----- ----- ----- -----
(in thousands)
Revenue. . . . $ 251 $ 258 $ 510 $ 521
Expense. . . . 131 117 256 242
----- ----- ----- -----
Net Income . . $ 120 $ 141 $ 254 $ 279
===== ===== ===== =====
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 recognized an additional $0.2
million as a provision for loss for the three and six months ended June 30,
2001 reflecting revised estimates of losses on warranty liabilities. The
ultimate loss remains subject to the sale or other disposition of NWR's
remaining assets and liabilities, primarily patents and warranty claims and tax
liabilities, 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 June 30, 2001 would have been approximately $0.3 million compared
with a loss of $0.2 million for the same period a year ago. The operating loss
for the six months ended June 30, 2001 would have been approximately $0.4
million compared with a loss of $1.1 million for the same period in 2000.
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, 2001 and 2000 are
summarized below:
Three months ended Six months ended
June 30 June 30
2001 2000 2001 2000
---------- ---------- ---------- ----------
(dollars in thousands)
Operating revenues
Retail. . . . . . . . $ 50,453 $ 43,535 $ 102,406 $ 93,085
Sales for Resale. . . 20,760 17,630 42,598 $ 34,930
Other . . . . . . . . 1,126 762 2,131 $ 1,624
---------- ---------- ---------- ----------
Total Operating Revenues. $ 72,339 $ 61,927 $ 147,135 $ 129,639
========== ========== ========== ==========
MWh sales-Retail. . . . . 459,144 456,550 977,405 974,316
MWh sales for Resale. . . 545,288 588,275 1,183,384 1,155,960
---------- ---------- ---------- ----------
Total MWh Sales . . . . . 1,004,432 1,044,825 2,160,789 2,130,276
========== ========== ========== ==========
Average Number of Customers
Three months ended Six months ended
June 30 June 30
2001 2000 2001 2000
------ ------ ------ ------
Residential . . . . . . . 73,075 72,093 73,130 72,127
Commercial and Industrial 12,998 12,672 12,957 12,603
Other . . . . . . . . . . 66 64 65 64
------ ------ ------ ------
Total Number of Customers. . 86,139 84,829 86,152 84,794
====== ====== ====== ======
REVENUES
Revenues from operations in the second quarter of 2001 increased 9.0
percent or $5.5 million compared with the same period in 2000. Operating
revenues result from retail and wholesale sales of electricity.
Retail revenues in the second quarter of 2001 were $2.1 million or 4.7
percent higher compared with the same period in 2000, reflecting a 3.42 percent
rate increase effective January 2001, and a 0.6 percent increase in retail MWh
sales. Sales of electricity decreased by 0.4 percent to small commercial and
industrial customers, decreased by 2.6 percent to residential customers and
increased 3.9 percent to lower margin industrial customers during the second
quarter of 2001 compared with the same period in 2000.
Retail revenues for the six months ended June 30, 2001 were $4.5 million or 4.8
percent higher when compared with the same period in 2000, reflecting the
Settlement Order rate increase and increased retail MWh sales of approximately
0.3 percent.
We sell wholesale electricity to others for resale. Our revenue from
wholesale sales of electricity increased $3.1 million in the second quarter of
2001 compared with the same period in 2000, and increased $7.7 million for the
first half of 2001 compared with the same period in 2000. The increases were
due primarily to increased sales under a power purchase and supply agreement
between the Company and Morgan Stanley Capital Group, Inc. ("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
Power supply expenses decreased 15.0 percent or $7.7 million in the second
quarter of 2001 over the same period in 2000.
Power supply expenses at Vermont Yankee decreased 34.3% or $3.0 million
during the second quarter of 2001 compared with the second quarter of 2000,
primarily due to a scheduled outage during 2001. Vermont Yankee scheduled
outage costs are deferred and amortized over an eighteen month refueling cycle.
A proposed sale of the generating plant is discussed under Part I, Item 2,
"Investment in Associated Companies".
Company-owned generation expenses decreased $1.8 million in the second
quarter of 2001 compared with the same period in 2000 primarily due to a
reimbursement by the New England Independent System Operator ("ISO") of
Company-owned generation expenses recorded in previous periods and because of
the unavailability of transmission equipment beginning in the second quarter of
2000 that required running generation to maintain system reliability.
The cost of power that we purchased from other companies decreased 6.6
percent or $2.8 million in the second quarter of 2001 compared with the same
period in 2000. This was primarily due to increased power supply costs of $2.9
million during 2000 to replace power sold to Hydro-Quebec under a previous
arrangement ("9701"), and increased costs of $4.0 million during 2000 due to
changes in power supply market conditions that resulted in a decline in the
value of energy resources, partially offset by increases in costs during 2001
for power sold to MS under the power purchase and supply agreement.
Power supply costs were also lower during the second quarter of 2001
compared with the same period in 2000 due to a refund of certain administrative
costs from New England Power Pool, the former wholesale electricity market
clearinghouse replaced by the ISO, and lower costs from independent power
producers reflecting declines in precipitation during the quarter.
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 June 30, 2001 to reflect these 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 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 half 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.
Power supply expenses for the first half of 2001 were unchanged compared with
the first half of 2000.
Power supply expense at Vermont Yankee decreased $3.5 million or 20.2 percent
for the first half of 2001 compared with the first half of 2000, primarily due
to a scheduled outage at the plant during 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 29.9 percent in
the first half of 2001 compared with the same period in 2000. 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 increased $4.6 million or 5.8 percent in the first
half of 2001 compared with the first half of 2000. Power supply costs to supply
increased wholesale sales of electricity under arrangements with MS and
Hydro-Quebec, and for energy purchased to cover potential shortfalls due to
transmission system operating requirements caused the increase. Higher energy
prices also contributed to the increase in power supply costs. These increases
were offset in part by decreased costs of managing the 9701 arrangement during
2001. Both the 9701 arrangement and our 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, 2001, the Company had a regulatory
asset of approximately $15.7 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.
OTHER OPERATING EXPENSES
Other operating expenses increased 20.0 percent or $0.7 million in the
second quarter of 2001 compared with the same period in 2000. The increase
reflects higher benefit costs and increased reserves for medical benefits and
contingencies. Other operating expenses increased 6.5 percent or $0.5 million
in the first six months of 2001 compared with the same period in 2000 for the
same reasons, offset in part by reduced regulatory commission expense.
TRANSMISSION EXPENSES
Transmission expenses decreased by approximately $0.1 million or 1.7
percent for the three months ended June 30, 2001 compared with the same period
in 2000 due to minor reductions in congestion charges. Transmission expenses
decreased by approximately $0.1 million or 1.2 percent for the six months ended
June 30, 2001, compared with the same period in 2000 for the same reason.
Congestion charges recorded in the first six months 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 $0.4 million or 8.9
percent during the second quarter of 2001 compared with the same period in 2000.
The reduction is primarily due to decreased amortization of demand side
management regulatory assets.
Depreciation and amortization expenses decreased $0.8 million or 10.2
percent during the first six months of 2001 compared with the same period in
2000 for the same reason.
TAXES OTHER THAN INCOME TAXES
Other taxes increased 8.5 percent or $0.2 million in the second quarter of
2001 compared with the same period in 2000, primarily due to increases in gross
revenue tax. Other taxes increased 3.0 percent or $0.1 million for the first six
months of 2001 compared with the same period in 2000 for the same reason.
INCOME TAXES
Income taxes increased $4.9 million in the second quarter of 2001 compared
with the same period in 2000 due to an increase in pretax book income. Income
taxes increased $4.5 million for the first six months of 2001 compared with the
same period in 2000 for the same reason.
OTHER INCOME
Other income did not change significantly for the three months ended June
30, 2001 compared with the same period in 2000. Other income decreased 24.3
percent or $0.4 million for the six months ended June 30, 2001, compared with
the same period in 2000 due primarily to a favorable settlement of a claim in
the first quarter of 2000 and reductions in interest income during 2001 due to
lower temporary cash investments.
INTEREST CHARGES
Interest charges increased 1.3 percent or $23,000 in the second quarter of
2001 compared with the same period in 2000 primarily due to increased costs
associated with the revolving lines of credit discussed under "Liquidity and
Capital Resources", offset in part by reductions in interest on long-term debt
due to sinking fund redemption.
Interest charges increased 6.3 percent or $0.2 million for the six months
ended June 30, 2001 compared with the same period in 2000 for the same reason.
LIQUIDITY AND CAPITAL RESOURCES
In the three months ended June 30, 2001, we spent $5.7 million principally
for expansion and improvements of our transmission and distribution plant. We
expect to spend an additional $10.0 million during the remainder of 2001.
On June 20, 2001, we renewed a revolving credit agreement (the "Fleet
Agreement") with Fleet National Bank ("Fleet"), joined by KeyBank National
Association ("KeyBank"). The Fleet Agreement is for a period of 364 days, will
expire on June 19, 2002, and is unsecured. We had $4.9 million in borrowings
outstanding on the Fleet Agreement at June 30, 2001.
On September 20, 2000, we established a $15.0 million revolving credit
agreement with KeyBank (the "KeyBank Agreement") which 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. 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 loans made pursuant to the Keybank Agreement.
At June 30, 2001, there were no amounts outstanding on the KeyBank Agreement.
On June 20, 2001, the Company executed and delivered a $12.0 million
two-year loan agreement with Fleet, joined by KeyBank. Funding of this facility
was contingent upon VPSB approval. On July 27, 2001 the VPSB approved the
financing arrangement. The Company plans to use this facility to terminate the
KeyBank Agreement, and repay the $15.0 million it received from EE pursuant to a
power supply option agreement as soon as is practicable.
The credit ratings of the Company's securities are:
Fitch Moody's Standard & Poor's
----- ------- -------------------
First mortgage bonds BBB Baa2 BBB
Preferred stock BBB- Ba2 BB
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, transmission, and generation capacity among
and within various regions of the country;
* Improvements in generation efficiency;
* Alternative energy sources;
* The deregulation of the wholesale energy market and the establishment of
an independent system operator; and
* New regulations and legislation in some states intended to foster
competition, also known as restructuring.
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 ("FASB") had agreed to review the accounting for closure and
removal costs, including decommissioning. The FASB is expected to issue a new
statement on accounting standards in August 2001 for "Accounting for the
Impairment or Disposal of Long-lived Assets and for Obligations Associated with
Disposal Activities", which will provide guidance on accounting for nuclear
plant decommissioning costs. The Company has not yet determined what impact, if
any, the proposed accounting standard will have on its investment in VY.
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
In June 1998, the FASB 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 objective of the Company's risk management program is to protect cash
flow and earnings by minimizing risk. Permitted transactions 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 risk of fossil fuel price increases as well as
the risk of spot market electricity price increases. Futures, swaps and forward
contracts are used to hedge the impact of market prices on the Company should
option calls by Hydro-Quebec be exercised by Hydro-Quebec. The Company's risk
management policy specifies risk measures, the amount of tolerable risk
exposure, and limits to transaction authority.
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 June 30, 2001
Fair value Market risk
---------- -----------
(in thousands)
Highest long position $ 26,205 $ 2,621
Highest short position $ 43,180 $ 4,318
Average position(short) $ (16,975) $ (1,698)
26
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
JUNE 30,2001
------------
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 17, 2001, one item was
voted upon by Shareholders. Voting results for directors are listed below.
Shareholders elected the nominees listed below as Directors of this
company, with votes cast as indicated.
Nordahl L. Brue, votes for, 4,713,579; withheld authority, 70,201;
abstentions, 799,937.
Lorraine E. Chickering, votes for, 4,687,768; withheld authority, 96,012;
abstentions, 799,937.
John V. Cleary, votes for, 4,698,695; withheld authority, 85,085;
abstentions, 799,937.
Euclid A. Irving, votes for, 4,683,381; withheld authority, 100,399;
abstentions, 799,937.
Directors continuing in office were Merrill O. Burns, William Bruett, David
R. Coates, Christopher L. Dutton, and Thomas P. Salmon.
ITEM 5. Other Information
NONE
ITEM 6. (B) REPORTS ON FORM 8-K
----------------------
None
27
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 10, 2001 /s/Nancy Rowden Brock
-----------------------
Nancy Rowden Brock, Vice President,
Chief Financial Officer, Secretary,
and Treasurer
Date: August 10, 2001 /s/Nancy Rowden Brock
-----------------------
Nancy Rowden Brock, (as Principal Financial
Officer)
Vice President, Chief Financial Officer,
Secretary, and Treasurer